Form 10Q June 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 June 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
|
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, Pennsylvania Power Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light
Company, Metropolitan Edison Company, and Pennsylvania Electric
Company
|
Indicate
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
AUGUST 7, 2006
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FirstEnergy
Corp., $.10 par value
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329,836,276
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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, Pennsylvania
Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison
Company, Jersey Central Power & Light Company, Metropolitan Edison Company
and Pennsylvania Electric Company. Information contained herein relating to
any
individual registrant is filed by such registrant on its own behalf. No
registrant makes any representation as to information relating to any other
registrant, except that information relating to any of the FirstEnergy
subsidiary registrants is also attributed to FirstEnergy Corp.
This
Form 10-Q
includes forward-looking statements based on information currently available
to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
"anticipate," "potential," "expect," "believe," "estimate" and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, replacement power
costs being higher than anticipated or inadequately hedged, 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 PUCO by
the
Ohio Supreme Court regarding the RSP) 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 implementation of the share repurchase program approved
by the Board of Directors in June 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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1-26
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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27
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Consolidated
Statements of Comprehensive Income
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28
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Consolidated
Balance Sheets
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29
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Consolidated
Statements of Cash Flows
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30
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Report
of
Independent Registered Public Accounting Firm
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31
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Management's
Discussion and Analysis of Results of Operations and
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32-70
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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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71
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Consolidated
Balance Sheets
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72
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Consolidated
Statements of Cash Flows
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73
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Report
of
Independent Registered Public Accounting Firm
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74
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Management's
Discussion and Analysis of Results of Operations and
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75-87
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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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88
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Consolidated
Balance Sheets
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89
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Consolidated
Statements of Cash Flows
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90
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Report
of
Independent Registered Public Accounting Firm
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91
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Management's
Discussion and Analysis of Results of Operations and
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92-102
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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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103
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Consolidated
Balance Sheets
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104
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Consolidated
Statements of Cash Flows
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105
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Report
of
Independent Registered Public Accounting Firm
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106
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Management's
Discussion and Analysis of Results of Operations and
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107-118
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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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119
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Consolidated
Balance
Sheets
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120
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Consolidated
Statements of
Cash Flows
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121
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Report
of
Independent Registered Public Accounting Firm
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122
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Management's
Discussion and Analysis of Results of Operations and
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123-130
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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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131
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Consolidated
Balance Sheets
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132
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Consolidated
Statements of Cash Flows
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133
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Report
of
Independent Registered Public Accounting Firm
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134
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Management's
Discussion and Analysis of Results of Operations and
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135-143
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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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144
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Consolidated
Balance Sheets
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145
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Consolidated
Statements of Cash Flows
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146
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Report
of
Independent Registered Public Accounting Firm
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147
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Management's
Discussion and Analysis of Results of Operations and
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148-157
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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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158
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Consolidated
Balance Sheets
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159
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Consolidated
Statements of Cash Flows
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160
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Report
of
Independent Registered Public Accounting Firm
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161
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Management's
Discussion and Analysis of Results of Operations and
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162-170
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Financial
Condition
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk.
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171
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Item
4. Controls
and Procedures.
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171
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Part
II. Other
Information
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Item
1. Legal
Proceedings.
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172
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Item
1A. Risk
Factors.
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172
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Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds.
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172
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Item
4. Submission
of Matters to a Vote of Security Holders.
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172
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Item
6. Exhibits.
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173-174
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The
following
abbreviations and acronyms are used in this report to identify FirstEnergy
Corp.
and its current and former subsidiaries:
ATSI
|
American
Transmission Systems, Inc., owns and operates transmission
facilities
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CEI
|
The
Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
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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
|
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
|
FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
|
FSG
|
FirstEnergy
Facilities Services Group, LLC, the parent company of several heating,
ventilation,
air
conditioning and energy management companies
|
GPU
|
GPU,
Inc.,
former parent of JCP&L, Met-Ed and Penelec, which merged with
FirstEnergy on
November 7,
2001
|
JCP&L
|
Jersey
Central
Power & Light Company, a New Jersey electric utility operating
subsidiary
|
JCP&L
Transition
|
JCP&L
Transition Funding LLC, a Delaware limited liability company and
issuer of
transition bonds
|
JCP&L
Transition Funding II
|
JCP&L
Transition Funding II LLC, a Delaware limited liability company and
issuer
of transition bonds
|
Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
|
MYR
|
MYR
Group,
Inc., a utility infrastructure construction service
company
|
NGC
|
FirstEnergy
Nuclear Generation Corp., owns nuclear generating
facilities
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OE
|
Ohio
Edison
Company, an Ohio electric utility operating subsidiary
|
OE
Companies
|
OE
and
Penn
|
Ohio
Companies
|
CEI,
OE and
TE
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Penelec
|
Pennsylvania
Electric Company, a Pennsylvania electric utility operating
subsidiary
|
Penn
|
Pennsylvania
Power Company, a Pennsylvania electric utility operating subsidiary
of
OE
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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
|
TE
|
The
Toledo
Edison Company, an Ohio electric utility operating
subsidiary
|
TEBSA
|
Termobarranquilla
S.A., Empresa de Servicios Publicos
|
|
|
The
following
abbreviations and acronyms are used to identify frequently used terms
in
this report:
|
|
|
ALJ
|
Administrative
Law Judge
|
AOCL
|
Accumulated
Other Comprehensive Loss
|
APB
|
Accounting
Principles Board
|
APB
25
|
APB
Opinion
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
|
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”
|
DOJ
|
United
States
Department of Justice
|
GLOSSARY
OF
TERMS, Cont'd.
DRA
|
Division
of
the Ratepayer Advocate
|
ECAR
|
East
Central
Area Reliability Coordination Agreement
|
EDCP
|
Executive
Deferred Compensation Plan
|
EITF
|
Emerging
Issues Task Force
|
EITF
04-13
|
EITF
Issue No.
04-13, “Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
|
EPA
|
Environmental
Protection Agency
|
EPACT
|
Energy
Policy
Act of 2005
|
ERO
|
Electric
Reliability Organization
|
ESOP
|
Employee
Stock
Ownership Plan
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
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
|
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
|
MTC
|
Market
Transition Charge
|
MW
|
Megawatts
|
NAAQS
|
National
Ambient Air Quality Standards
|
NERC
|
North
American
Electric Reliability Council
|
NJBPU
|
New
Jersey
Board of Public Utilities
|
NOAC
|
Northwest
Ohio
Aggregation Coalition
|
NOPR
|
Notice
of
Proposed Rulemaking
|
NOV
|
Notices
of
Violation
|
NOX
|
Nitrogen
Oxide
|
NRC
|
Nuclear
Regulatory Commission
|
NUG
|
Non-Utility
Generation
|
NUGC
|
Non-Utility
Generation Charge
|
OCA
|
Office
of
Consumer Advocate
|
OCC
|
Office
of the
Ohio Consumers' Counsel
|
OCI
|
Other
Comprehensive Income
|
OPEB
|
Other
Post-Employment Benefits
|
OSBA
|
Office
of
Small Business Advocate
|
OTS
|
Office
of
Trial Staff
|
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
|
RTC
|
Regulatory
Transition Charge
|
RTO
|
Regional
Transmission Organization
|
RTOR
|
Through
and
Out Rates
|
S&P
|
Standard
&
Poor’s Ratings Service
|
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
140
|
SFAS
No. 140,
“Accounting for Transfers and Servicing of Financial Assets and
Extinguishment
of Liabilities”
|
SFAS
143
|
SFAS
No. 143,
"Accounting for Asset Retirement Obligations"
|
SFAS
144
|
SFAS
No. 144,
"Accounting for the Impairment or Disposal of Long-Lived
Assets"
|
SO2
|
Sulfur
Dioxide
|
SRM
|
Special
Reliablity 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 first and second quarters of 2005 have been classified as discontinued
operations on the Consolidated Statements of Income (see Note 4). As discussed
in Note 13, interim period segment reporting in 2005 was reclassified to conform
with the current year business segment organizations and operations.
FirstEnergy
and its
subsidiaries consolidate all majority-owned subsidiaries over which they
exercise control and, when applicable, entities for which they have a
controlling financial interest. Intercompany transactions and balances are
eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 9) when
it
is determined to be the VIE's primary beneficiary. Investments in
nonconsolidated affiliates over which FirstEnergy and its subsidiaries have
the
ability to exercise significant influence, but not control, (20-50 percent
owned
companies, joint ventures and partnerships) are accounted for under the equity
method. Under the equity method, the interest in the entity is reported as
an
investment in the Consolidated Balance Sheet and the percentage share of the
entity’s earnings is reported in the Consolidated Statement of Income. Certain
prior year amounts have been reclassified to conform to the current
presentation.
FirstEnergy's
and
the Companies' independent registered public accounting firm has performed
reviews of, and issued reports on, these consolidated interim financial
statements in accordance with standards established by the PCAOB. Pursuant
to
Rule 436(c) under the Securities Act of 1933, their reports of those reviews
should not be considered a report within the meaning of Section 7 and 11 of
that
Act, and the independent registered public accounting firm’s liability under
Section 11 does not extend to them.
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.
The following table reconciles the computation of basic and diluted earnings
per
share of common stock before discontinued operations:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Reconciliation
of Basic and Diluted Earnings per Share
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before
Discontinued Operations
|
|
$
|
304
|
|
$
|
179
|
|
$
|
525
|
|
$
|
320
|
|
Less:
Redemption premium on subsidiary preferred stock
|
|
|
(3
|
)
|
|
-
|
|
|
(3
|
)
|
|
-
|
|
Earnings
on
Common Stock Before Discontinued Operations
|
|
$
|
301
|
|
$
|
179
|
|
$
|
522
|
|
$
|
320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares of Common Stock Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for basic earnings per share
|
|
|
328
|
|
|
328
|
|
|
328
|
|
|
328
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
2
|
|
Denominator
for diluted earnings per share
|
|
|
330
|
|
|
330
|
|
|
330
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Before Discontinued Operations per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.92
|
|
$
|
0.54
|
|
$
|
1.59
|
|
$
|
0.98
|
|
Diluted
|
|
$
|
0.91
|
|
$
|
0.54
|
|
$
|
1.58
|
|
$
|
0.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.
-
GOODWILL
FirstEnergy's
goodwill primarily relates to its regulated services segment. In the six months
ended June 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 an adjustment to the former
GPU
companies due to the realization of a tax benefit that had been reserved in
purchase accounting. Adjustments to goodwill in the second quarter of 2006
were
immaterial. The following table reconciles
changes to goodwill
for the six months ended June 30, 2006.
Goodwill
Reconciliation
|
|
FirstEnergy
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance
as of
January 1, 2006
|
|
$
|
6,010
|
|
$
|
1,689
|
|
$
|
501
|
|
$
|
1,986
|
|
$
|
864
|
|
$
|
882
|
|
Non-core
assets sale
|
|
|
(53
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
related to Centerior acquisition
|
|
|
(1
|
)
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
related to GPU acquisition
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
(8
|
)
|
|
(4
|
)
|
|
(4
|
)
|
Balance
as of
June 30, 2006
|
|
$
|
5,940
|
|
$
|
1,688
|
|
$
|
501
|
|
$
|
1,978
|
|
$
|
860
|
|
$
|
878
|
|
4.
-
DIVESTITURES AND DISCONTINUED OPERATIONS
In
March 2006,
FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2
million. 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 six
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. 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 remaining FSG assets, with a net carrying
value of $48 million as of June 30, 2006, will qualify for recognition
as completed sales within one year. As of June 30, 2006, the FSG
subsidiaries classified as held for sale did not meet the criteria for
discontinued operations. The carrying amounts of FSG's assets and liabilities
held for sale are not material and have not been classified as assets held
for
sale on FirstEnergy's Consolidated Balance Sheets. See Note 13 for FSG's
segment financial information.
Net
results
(including the gains on sales of assets discussed above) for Cranston,
Elliott-Lewis, Power Piping and FES' retail natural gas business of $(1) million
and $18 million for the three months and six months ended June 30, 2005,
respectively, are reported as discontinued operations on FirstEnergy's
Consolidated Statements of Income. Pre-tax operating results for these entities
were $(2) million and $2 million for the three months and six months ended
June 30, 2005, respectively. Revenues associated with discontinued
operations for the three months and six months ended June 30, 2005 were $11
million and $206 million, respectively. The following table summarizes the
sources of income from discontinued operations for the three months and six
months ended June 30, 2005:
|
|
Three
Months
|
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Discontinued
Operations (Net of tax)
|
|
|
|
|
|
|
Gain
on
sale:
|
|
|
|
|
|
|
Natural
gas
business
|
|
$
|
-
|
|
$
|
5
|
|
FSG
and MYR
subsidiaries
|
|
|
-
|
|
|
12
|
|
Reclassification
of operating income (loss)
|
|
|
(1
|
)
|
|
1
|
|
Total
|
|
$
|
(1
|
)
|
$
|
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 $30 million included in AOCL as of June 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 $35 million decrease
related to current hedging activity and a $13 million decrease due to net hedge
losses included in earnings during the six months ended June 30, 2006.
Approximately $9 million (after tax) of the net deferred losses on derivative
instruments in AOCL as of June 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 first six months of 2006,
FirstEnergy unwound swaps with a total notional amount of $350 million for
which it paid $1 million in cash. The losses will be recognized in earnings
over the remaining maturity of each respective hedged security as increased
interest expense. As of June 30, 2006, the aggregate notional value of interest
rate swap agreements outstanding was $750 million.
During
2005 and the
first six 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 six months of 2006. FirstEnergy
terminated and revised its forward swaps, ultimately terminating swaps with
an
aggregate notional value of $600 million as its subsidiaries issued long term
debt in the second quarter. As required by SFAS 133, FirstEnergy assessed the
amount of ineffectiveness of the hedges at each termination. FirstEnergy
received cash gains of $41 million, of which approximately $6 million ($4
million net of tax) was deemed ineffective and recognized in earnings in the
first six months of 2006. The remaining gain deemed effective in the amount
of
approximately $35 million ($22 million net of tax) was recorded in other
comprehensive income and will subsequently be recognized in earnings over the
terms of the respective forward swaps. As of June 30, 2006, FirstEnergy had
forward swaps with an aggregate notional amount of $550million and a long-term
debt securities fair value of $29 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 second quarter and six months ended June 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) 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 second quarter and six
months ended June 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 six months ended June 30, 2005, as if FirstEnergy had adopted SFAS
123(R) as of January 1, 2005:
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
Net
Income, as
reported
|
|
$
|
178
|
|
$
|
338
|
|
|
|
|
|
|
|
|
|
Add
back
compensation expense
|
|
|
|
|
|
|
|
reported
in
net income, net of tax (based on
|
|
|
|
|
|
|
|
APB
25)*
|
|
|
14
|
|
|
22
|
|
|
|
|
|
|
|
|
|
Deduct
compensation expense based
|
|
|
|
|
|
|
|
upon
estimated
fair value, net of tax*
|
|
|
(17
|
)
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
Pro
forma net
income
|
|
$
|
175
|
|
$
|
332
|
|
Earnings
Per
Share of Common Stock -
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
As
Reported
|
|
$
|
0.54
|
|
$
|
1.03
|
|
ProForma
|
|
$
|
0.53
|
|
$
|
1.01
|
|
Diluted
|
|
|
|
|
|
|
|
As
Reported
|
|
$
|
0.54
|
|
$
|
1.02
|
|
Pro
Forma
|
|
$
|
0.53
|
|
$
|
1.01
|
|
* 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 six months ended June 30, 2005, the impact on earnings would
have been immaterial.
The
ARO liability of
$1.2
billion
as of June 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
June
30, 2006, the fair value of the decommissioning trust assets was $1.8 billion.
The
following tables
analyze changes to the ARO balances during the three months and six months
ended
June 30, 2006 and 2005, respectively.
Three
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
Penn
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
April
1, 2006
|
|
$
|
1,148
|
|
$
|
84
|
|
$
|
8
|
|
$
|
25
|
|
$
|
-
|
|
$
|
81
|
|
$
|
144
|
|
$
|
73
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
(6
|
)
|
|
-
|
|
|
(6
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
June
30, 2006
|
|
$
|
1,160
|
|
$
|
85
|
|
$
|
2
|
|
$
|
26
|
|
$
|
-
|
|
$
|
82
|
|
$
|
146
|
|
$
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
April
1, 2005
|
|
$
|
1,095
|
|
$
|
204
|
|
$
|
276
|
|
$
|
198
|
|
$
|
141
|
|
$
|
74
|
|
$
|
135
|
|
$
|
67
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
4
|
|
|
5
|
|
|
3
|
|
|
2
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
June
30, 2005
|
|
$
|
1,113
|
|
$
|
208
|
|
$
|
281
|
|
$
|
201
|
|
$
|
143
|
|
$
|
75
|
|
$
|
137
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
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
|
|
|
36
|
|
|
2
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
2
|
|
|
4
|
|
|
2
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
June
30, 2006
|
|
$
|
1,160
|
|
$
|
85
|
|
$
|
2
|
|
$
|
26
|
|
$
|
-
|
|
$
|
82
|
|
$
|
146
|
|
$
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2005
|
|
$
|
1,078
|
|
$
|
201
|
|
$
|
272
|
|
$
|
195
|
|
$
|
138
|
|
$
|
72
|
|
$
|
133
|
|
$
|
67
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
35
|
|
|
7
|
|
|
9
|
|
|
6
|
|
|
5
|
|
|
3
|
|
|
4
|
|
|
1
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
June
30, 2005
|
|
$
|
1,113
|
|
$
|
208
|
|
$
|
281
|
|
$
|
201
|
|
$
|
143
|
|
$
|
75
|
|
$
|
137
|
|
$
|
68
|
|
8.
- PENSION
AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy
provides noncontributory defined benefit pension plans that cover substantially
all of its employees. The trusteed plans provide defined benefits based on
years
of service and compensation levels. FirstEnergy also provides a minimum amount
of noncontributory life insurance to retired employees in addition to optional
contributory insurance. Health care benefits, which include certain employee
contributions, deductibles and co-payments, are available upon retirement to
employees hired prior to January 1, 2005, their dependents and, under
certain circumstances, their survivors. FirstEnergy recognizes the expected
cost
of providing other postretirement benefits to employees, their beneficiaries
and
covered dependents from the time employees are hired until they become eligible
to receive those benefits.
The
components of
FirstEnergy's net periodic pension and other postretirement benefit costs
(including amounts capitalized) for the three months and six months ended June
30, 2006 and 2005 consisted of the following:
|
|
Three
Months Ended
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Pension
Benefits
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
21
|
|
$
|
19
|
|
$
|
41
|
|
$
|
38
|
|
Interest
cost
|
|
|
66
|
|
|
64
|
|
|
133
|
|
|
128
|
|
Expected
return on plan assets
|
|
|
(99
|
)
|
|
(86
|
)
|
|
(198
|
)
|
|
(173
|
)
|
Amortization
of prior service cost
|
|
|
2
|
|
|
2
|
|
|
5
|
|
|
4
|
|
Recognized
net
actuarial loss
|
|
|
15
|
|
|
9
|
|
|
29
|
|
|
18
|
|
Net
periodic
cost
|
|
$
|
5
|
|
$
|
8
|
|
$
|
10
|
|
$
|
15
|
|
|
|
Three
Months Ended
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Other
Postretirement Benefits
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
9
|
|
$
|
10
|
|
$
|
17
|
|
$
|
20
|
|
Interest
cost
|
|
|
26
|
|
|
27
|
|
|
52
|
|
|
55
|
|
Expected
return on plan assets
|
|
|
(12
|
)
|
|
(11
|
)
|
|
(23
|
)
|
|
(22
|
)
|
Amortization
of prior service cost
|
|
|
(19
|
)
|
|
(11
|
)
|
|
(37
|
)
|
|
(22
|
)
|
Recognized
net
actuarial loss
|
|
|
14
|
|
|
10
|
|
|
27
|
|
|
20
|
|
Net
periodic
cost
|
|
$
|
18
|
|
$
|
25
|
|
$
|
36
|
|
$
|
51
|
|
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 six
months ended June 30, 2006 and 2005 were as follows:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Pension
Benefit Cost (Credit)
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
(1.1
|
)
|
$
|
0.2
|
|
$
|
(2.1
|
)
|
$
|
0.4
|
|
Penn
|
|
|
(0.4
|
)
|
|
(0.2
|
)
|
|
(0.8
|
)
|
|
(0.4
|
)
|
CEI
|
|
|
1.0
|
|
|
0.3
|
|
|
1.9
|
|
|
0.7
|
|
TE
|
|
|
0.2
|
|
|
0.3
|
|
|
0.4
|
|
|
0.6
|
|
JCP&L
|
|
|
(1.4
|
)
|
|
(0.3
|
)
|
|
(2.7
|
)
|
|
(0.5
|
)
|
Met-Ed
|
|
|
(1.7
|
)
|
|
(1.1
|
)
|
|
(3.5
|
)
|
|
(2.2
|
)
|
Penelec
|
|
|
(1.3
|
)
|
|
(1.3
|
)
|
|
(2.7
|
)
|
|
(2.7
|
)
|
Other
FirstEnergy subsidiaries
|
|
|
9.9
|
|
|
9.6
|
|
|
20.0
|
|
|
19.1
|
|
|
|
$
|
5.2
|
|
$
|
7.5
|
|
$
|
10.5
|
|
$
|
15.0
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Other
Postretirement Benefit Cost
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
3.4
|
|
$
|
5.8
|
|
$
|
6.8
|
|
$
|
11.5
|
|
Penn
|
|
|
0.8
|
|
|
1.2
|
|
|
1.6
|
|
|
2.4
|
|
CEI
|
|
|
2.8
|
|
|
3.8
|
|
|
5.5
|
|
|
7.6
|
|
TE
|
|
|
2.0
|
|
|
2.2
|
|
|
4.0
|
|
|
4.3
|
|
JCP&L
|
|
|
0.6
|
|
|
1.5
|
|
|
1.2
|
|
|
4.2
|
|
Met-Ed
|
|
|
0.7
|
|
|
0.4
|
|
|
1.5
|
|
|
0.8
|
|
Penelec
|
|
|
1.8
|
|
|
2.0
|
|
|
3.6
|
|
|
4.0
|
|
Other
FirstEnergy subsidiaries
|
|
|
6.1
|
|
|
8.1
|
|
|
12.1
|
|
|
16.2
|
|
|
|
$
|
18.2
|
|
$
|
25.0
|
|
$
|
36.3
|
|
$
|
51.0
|
|
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 $640 million, $98 million and $498 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 June 30, 2006, the net above-market loss liability projected
for these eight NUG agreements was $74 million. Purchased power costs from
these entities during the three months and six months ended June 30, 2006 and
2005 are shown in the following table:
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
June
30,
|
|
June
30,
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
(In
millions)
|
JCP&L
|
$
|
19
|
|
$
|
21
|
|
$
|
34
|
|
$
|
42
|
|
Met-Ed
|
|
16
|
|
|
14
|
|
|
33
|
|
|
30
|
|
Penelec
|
|
7
|
|
|
7
|
|
|
14
|
|
|
14
|
|
Total
|
$
|
42
|
|
$
|
42
|
|
$
|
81
|
|
$
|
86
|
|
Securitized
Transition Bonds
The
consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition, a wholly owned limited liability company of JCP&L. In
June 2002, JCP&L Transition sold $320 million of transition bonds to
securitize the recovery of JCP&L's bondable stranded costs associated with
the previously divested Oyster Creek Nuclear Generating Station.
JCP&L
did not
purchase and does not own any of the transition bonds, which are included as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The
transition bonds are obligations of JCP&L Transition only and are
collateralized solely by the equity and assets of JCP&L Transition, which
consist primarily of bondable transition property. The bondable transition
property is solely the property of JCP&L Transition.
Bondable
transition
property represents the irrevocable right under New Jersey law of a utility
company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on the transition bonds
and other fees and expenses associated with their issuance. JCP&L sold the
bondable transition property to JCP&L Transition and, as servicer, manages
and administers the bondable transition property, including the billing,
collection and remittance of the TBC, pursuant to a servicing agreement with
JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of
$100,000 that is payable from TBC collections.
10.
-
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A)
GUARANTEES
AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various
agreements on behalf of its subsidiaries to provide financial or performance
assurances to third parties. These agreements include contract guarantees,
surety bonds and LOCs. As of June 30, 2006, outstanding guarantees and other
assurances totaled approximately $3.5 billion consisting of contract
guarantees ($1.9 billion), surety bonds ($0.1 billion) and LOCs
($1.5 billion).
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved
in
energy commodity activities principally to facilitate normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy to fulfill the obligations of
those subsidiaries directly involved in energy and energy-related transactions
or financing where the law might otherwise limit the counterparties' claims.
If
demands of a counterparty were to exceed the ability of a subsidiary to satisfy
existing obligations, FirstEnergy's guarantee enables the counterparty's legal
claim to be satisfied by other FirstEnergy assets. The likelihood is remote
that
such parental guarantees of $0.8 billion (included in the $1.9 billion discussed
above) as of June 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
June
30, 2006, FirstEnergy's maximum exposure under these collateral provisions
was
$501 million.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of $146
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
June 30, 2006), which is renewable and declines yearly based upon the senior
outstanding debt of TEBSA.
(B) ENVIRONMENTAL
MATTERS
Various
federal,
state and local authorities regulate 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
regulations.
Violations of such regulations can result in shutdown of the generating unit
involved and/or civil or criminal penalties of up to $32,500 for each day the
unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio
that allows for compliance based on a 30-day averaging period. FirstEnergy
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.
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 has been scheduled for August 8, 2006 to discuss the alleged
violations with the EPA.
FirstEnergy believes it is complying with SO2
reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX
reductions required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX
reductions from
FirstEnergy's facilities. The EPA's NOX
Transport Rule
imposes uniform reductions of NOX
emissions (an
approximate 85% reduction in utility plant NOX
emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX
emissions are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX
budgets established
under State Implementation Plans through combustion controls and post-combustion
controls, including Selective Catalytic Reduction and Selective Non-Catalytic
Reduction systems, and/or using emission allowances.
National
Ambient
Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and 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 this
approach is based on output, new and non-emitting generating facilities,
including renewables and nuclear, would be entitled to their proportionate
share
of the allowances. Consequently, FirstEnergy would be disadvantaged if these
model rules were implemented because FirstEnergy’s substantial reliance on
non-emitting (largely nuclear) generation is not recognized under the
input-based allocation.
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 (the primary portion of which is expected to be spent in the
2008 to 2011 time period). On August 26, 2005, FGCO entered into an
agreement with Bechtel Power Corporation under which Bechtel will engineer,
procure, and construct air quality control systems for the reduction of sulfur
dioxide emissions. The settlement agreement also requires OE and Penn to spend
up to $25 million toward environmentally beneficial projects, which include
wind energy purchased power agreements over a 20-year term. OE and Penn agreed
to pay a civil penalty of $8.5 million. Results for the first quarter of
2005 included the penalties paid by OE and Penn of $7.8 million and
$0.7 million, respectively. OE and Penn also recognized liabilities in the
first quarter of 2005 of $9.2 million and $0.8 million, respectively,
for probable future cash contributions toward environmentally beneficial
projects.
Climate
Change
In December 1997, delegates to the United Nations' climate summit in Japan
adopted an agreement, the Kyoto Protocol, to address global warming by reducing
the amount of man-made GHG emitted by developed countries by 5.2% from 1990
levels between 2008 and 2012. The United States signed the Kyoto Protocol in
1998 but it failed to receive the two-thirds vote required for ratification
by
the United States Senate. However, the Bush administration has committed the
United States to a voluntary climate change strategy to reduce domestic GHG
intensity - the ratio of emissions to economic output - by 18% through 2012.
The
EPACT established a Committee on Climate Change Technology to coordinate federal
climate change activities and promote the development and deployment of GHG
reducing technologies.
FirstEnergy cannot currently estimate the financial impact of climate change
policies, although the potential restrictions on CO2
emissions could
require significant capital and other expenditures. The CO2
emissions per 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 June
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 $70 million (JCP&L -
$55 million,
CEI -
$2 million,
and other subsidiaries-
$13 million)
have been accrued through June 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. On September 8, 2004, the New Jersey Supreme Court
denied the motions filed by plaintiffs and JCP&L for leave to appeal the
decision of the Appellate Division. In December 2005, JCP&L argued its
motion for summary judgment before the New Jersey Superior Court on its renewed
motion to decertify the class and on remaining plaintiffs' negligence and breach
of contract claims. These motions remain pending. FirstEnergy is unable to
predict the outcome of these matters and no liability has been accrued as of
June 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 the 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 outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class action
complaints. 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. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
is currently expected that this case will be summarily dismissed, although
the
Motion is still pending. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of the
Ohio operating companies; dismissed FirstEnergy 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. These motions are pending. Additionally, on June 23, 2006, one of the
insurance carrier complainants filed an appeal with the Ohio Supreme Court
over
the PUCO’s denial of motion for rehearing on the issue of the admissibility of
the Task Force Report and the dismissal of FirstEnergy Corp. as a respondent.
Briefing is expected to be completed on this appeal by mid-September. It is
unknown when the Supreme Court will rule on the appeal. No estimate of potential
liability is available for any of these cases.
In
addition to the above proceedings, FirstEnergy was named in a complaint filed
in
Michigan State Court by an individual who is not a customer of any FirstEnergy
company. FirstEnergy's motion to dismiss the matter was denied on June 2,
2006. FirstEnergy has since filed an appeal, which is pending. A responsive
pleading to this matter has been filed. Also, the complaint has been amended
to
include an additional party. No estimate of potential liability has been
undertaken in this matter.
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 Plant and stated
that the CAL would remain open until substantial improvement was demonstrated.
The CAL was anticipated as part of the NRC's Reactor Oversight Process. In
the
NRC's 2005 annual assessment letter dated March 2, 2006 and associated
meetings to discuss the performance of Perry on March 14, 2006, the NRC
again stated that the Perry Plant continued to operate in a manner that
"preserved public health and safety." However, the NRC also stated that
increased levels of regulatory oversight would continue until sustained
improvement in the performance of the facility was realized. If performance
does
not improve, the NRC has a range of options under the Reactor Oversight Process,
from increased oversight to possible impact to the plant’s operating authority.
Although FirstEnergy is unable to predict the impact of the ultimate disposition
of this matter, it could have a material adverse effect on FirstEnergy's or
its
subsidiaries' financial condition, results of operations and cash
flows.
As of December 16, 2005, NGC acquired ownership of the nuclear generation
assets transferred from OE, CEI, TE and Penn with the exception of leasehold
interests of OE and TE in certain of the nuclear plants that are subject to
sale
and leaseback arrangements with non-affiliates.
Other
Legal
Matters
There are various lawsuits, claims (including claims for asbestos exposure)
and
proceedings related to FirstEnergy's normal business operations pending against
FirstEnergy and its subsidiaries. The other 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.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's
2002 call-out procedure that required bargaining unit employees to respond
to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16 million to the bargaining unit employees. On February 6, 2006, the
federal court granted a Union motion to dismiss JCP&L's appeal of the award
as premature. JCP&L will file its appeal again in federal district court
once the damages associated with this case are identified at an individual
employee level. JCP&L recognized a liability for the potential
$16 million award in 2005.
The City of Huron filed a complaint against OE with the PUCO challenging the
ability of electric distribution utilities to collect transition charges from
a
customer of a newly-formed municipal electric utility. The complaint was filed
on May 28, 2003, and OE timely filed its response on June 30, 2003. In
a related filing, the Ohio Companies filed for approval with the PUCO of a
tariff that would specifically allow the collection of transition charges from
customers of municipal electric utilities formed after 1998. Both filings were
consolidated for hearing and decision described above. 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 60 days from the denial of rehearing to appeal the PUCO’s
decision.
If it were ultimately determined that FirstEnergy or its subsidiaries have
legal
liability or are otherwise made subject to liability based on the above matters,
it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
11.
-
REGULATORY MATTERS
RELIABILITY
INITIATIVES
In
late 2003 and early 2004, a series of letters, reports and recommendations
were
issued from various entities, including governmental, industry and ad hoc
reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage
Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy
completed implementation of all actions and initiatives related to enhancing
area reliability, improving voltage and reactive management, operator readiness
and training and emergency response preparedness recommended for completion
in
2004. On July 14, 2004, NERC independently verified that FirstEnergy had
implemented the various initiatives to be completed by June 30 or summer
2004, with minor exceptions noted by FirstEnergy, which exceptions are now
essentially complete. FirstEnergy is proceeding with the implementation of
the
recommendations that were to be completed subsequent to 2004 and will continue
to periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new, or material upgrades to existing
equipment. The FERC or other applicable government agencies and reliability
coordinators may, however, take a different view as to recommended enhancements
or may recommend additional enhancements in the future as the result of adoption
of mandatory reliability standards pursuant to the EPACT that could require
additional, material expenditures.
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 review. On
February 3, 2006, the FERC adopted a rule establishing certification
requirements for the ERO, as well as regional entities envisioned to assume
monitoring responsibility for the new reliability standards. The FERC issued
an
order on rehearing on March 30, 2006, providing certain clarifications and
essentially affirming the rule.
The
NERC has been preparing the implementation aspects of reorganizing its structure
to meet the FERC’s certification requirements for the ERO. The NERC made a
filing with the FERC on April 4, 2006 to obtain certification as the ERO
and to obtain FERC approval of delegation agreements with regional entities.
The
new FERC rule referred to above, further provides for reorganizing regional
reliability organizations (regional entities) that would replace the current
regional councils and for rearranging the relationship with the ERO. The
“regional entity” may be delegated authority by the ERO, subject to FERC
approval, for enforcing reliability standards adopted by the ERO and approved
by
the FERC. 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 NERC as the ERO to implement the provisions of Section 215 of the
Federal Power Act. The FERC directed NERC to make a compliance filing within
ninety days addressing such issues as the regional delegation
agreements.
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, on the current NERC Version O reliability standards with
some additional 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 chairman has indicated that the FERC intends
to
act on the proposed reliability standards by issuing a NOPR in September of
this
year. Interested parties will be given the opportunity to comment on the NOPR.
NERC has requested an effective date of January 1, 2007 for the proposed
reliability standards.
The
ECAR,
Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
councils have completed the consolidation of these regions into a single new
regional reliability organization known as ReliabilityFirst Corporation.
ReliabilityFirst began operations as a regional reliability council under NERC
on January 1, 2006 and intends to file and obtain certification consistent
with the final rule as a “regional entity” under the ERO during 2006. All of
FirstEnergy’s facilities are located within the ReliabilityFirst
region.
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.
FirstEnergy
believes
it is in compliance with all current NERC reliability standards. However, it
is
expected that the FERC will adopt stricter reliability standards than those
contained in the current NERC standards. The financial impact of complying
with
the new standards cannot be determined at this time. However, the EPACT required
that all prudent costs incurred to comply with the new reliability standards
be
recovered in rates.
OHIO
On
October 21, 2003
the Ohio Companies filed 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 September 28, 2005, the Supreme Court of Ohio heard oral arguments
on the appeals. 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 one matter back to the PUCO
for further consideration of the issue as to whether the RSP, as adopted by
the
PUCO, provided for sufficient means for customer participation in the
competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
for
Reconsideration with the Supreme Court of Ohio which was denied by the Court
on
June 21, 2006. 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.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP. 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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●
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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.
|
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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●
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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.
|
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 are due on August 4, 2006.
Appellants’ Reply Briefs will then be due on August 24, 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 May 1,
2006, the Ohio Companies filed a modification to the rider to determine revenues
($141 million) from July 2006 through June 2007.
The second application sought authority to defer costs associated with
transmission and ancillary service related costs incurred during the period
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
unable to predict when a decision may be issued.
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 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.
As
of June 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 $335 million and
$57 million, respectively. Penelec's $57 million is subject to the
pending resolution of taxable income issues associated with NUG trust fund
proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s
NUG purchase power stranded cost accounting methodology. If the PPUC orders
Met-Ed and Penelec to reverse the change in accounting methodology, this would
result in a pre-tax loss of $10.3 million for Met-Ed.
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 below. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Met-Ed and Penelec have deferred
approximately $46 million and $12 million, respectively, representing
transmission costs that were incurred from January 1, 2006 through June 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 below.
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.
The wholesale power sales agreement, as modified by the Tolling Agreement,
requires Met-Ed and Penelec to satisfy the portion of their PLR obligations
currently supplied by FES from unaffiliated suppliers at prevailing prices,
which are likely to be higher than the current price charged by FES under the
current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs
could materially increase. If Met-Ed and Penelec were to replace the entire
FES
supply at current market power prices without corresponding regulatory
authorization to increase their generation prices to customers, each company
would likely incur a significant increase in operating expenses and experience
a
material deterioration in credit quality metrics. Under such a scenario, each
company's credit profile would no longer be expected to support an investment
grade rating for its fixed income securities. There can be no assurance,
however, that if FES ultimately determines to terminate, or significantly modify
the agreement, timely regulatory relief will be granted by the PPUC pursuant
to
the April 10, 2006 comprehensive rate filing discussed below, or, to the
extent granted, adequate to mitigate such adverse consequences.
Met-Ed and Penelec made a comprehensive rate filing with the PPUC on
April 10, 2006 that addresses a number of transmission, distribution and
supply issues. If Met-Ed's and Penelec's preferred approach involving accounting
deferrals is approved, the filing would increase annual revenues by
$216 million and $157 million, respectively. That filing includes,
among other things, a request to charge customers for an increasing amount
of
market priced power procured through a 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 are scheduled for late August 2006 and a
PPUC decision is expected early in the first quarter of 2007.
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. To the
extent that an affiliate of Penn supplies a portion of the PLR load included
in
the RFP, authorization to make the affiliate sale must be obtained from the
FERC. 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 to
obtain Penn's power supply requirements after 2006 through two separate
solicitations. An initial solicitation was held for Penn in May 2006 with all
tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
for the first solicitation. 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 only acquired for three of the five
tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
the
submissions for the second bid. A residual solicitation is scheduled to be
held
on August 15, 2006 for the two remaining Large Commercial Group tranches.
Acceptance of the winning bids is subject to approval by the PPUC.
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 its recovery of certain
PLR costs via a reconciliation mechanism and its 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 June 30, 2006, the accumulated deferred
cost balance totaled approximately $638 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 4, 2006, JCP&L Transition Funding II, a
wholly owned subsidiary of JCP&L, secured pricing on the issuance of $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. A schedule for the proceeding was
established, including a discovery period and evidentiary hearings scheduled
for
September 2006.
An NJBPU Decision and Order approving a Phase II Stipulation of Settlement
and
resolving the Motion for Reconsideration of the Phase I Order was issued on
May
31, 2005. The Phase II Settlement includes a performance standard pilot program
with potential penalties of up to 0.25% of allowable equity return. The Order
requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI
information related to the performance pilot program) through December 2006
and
updates to reliability related project expenditures until all projects are
completed. The last of the quarterly reliability reports was submitted on June
12, 2006. As of June 30, 2006, there were no performance penalties issued
by the NJBPU.
In a reaction to the higher closing prices of the 2006 BGS fixed rate auction,
the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate
the auction process and potential options for the future. On April 6, 2006,
initial comments were submitted. A public meeting was held on April 21, 2006
and
a legislative-type hearing was held on April 28, 2006. On June 21, 2006,
the NJBPU approved the continued use of a descending block auction for the
Fixed
Price Residential Class. A final decision as to the procurement method for
the
Commercial Industrial Energy Price Class is expected in October
2006.
In
accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on
June 7, 2004 supporting a continuation of the current level and duration of
the funding of TMI-2 decommissioning costs by New Jersey customers without
a
reduction, termination or capping of the funding. On September 30, 2004,
JCP&L filed an updated TMI-2 decommissioning study. This study resulted in
an updated total decommissioning cost estimate of $729 million (in 2003
dollars) compared to the estimated $528 million (in 2003 dollars) from the
prior
1995 decommissioning study. The DRA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. A schedule for further proceedings
has not yet been set.
On
August 1,
2005, the NJBPU established a proceeding to determine whether additional
ratepayer protections are required at the state level in light of the 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. The NJBPU Staff issued a draft proposal on March 31, 2006
addressing various issues including access to books and records, ring-fencing,
cross subsidization, corporate governance and related matters. 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. JCP&L is unable to predict the outcome of this
proceeding.
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 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 $33 million has been
deferred as of June 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 21, 2006, the FERC issued an order stating
that it needs more time to consider the matter. In light of that order, there
is
no time period by which the FERC must act on the pending rehearing request.
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.
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 FERC has ordered the Presiding Judge to issue an initial decision
by August 11, 2006.
On
January 31, 2005,
certain PJM transmission owners made three filings with the FERC pursuant to
a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In
the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. In the second
filing, the settling transmission owners proposed a revised Schedule 12 to
the PJM tariff designed to harmonize the rate treatment of new and existing
transmission facilities. Interventions and protests were filed on
February 22, 2005. In the third filing, Baltimore Gas and Electric Company
and Pepco Holdings, Inc. requested a formula rate for transmission service
provided within their respective zones. On May 31, 2005, the FERC issued an
order on these cases. First, it set for hearing the existing rate design and
indicated that it will issue a final order within six months. American Electric
Power Company, Inc. filed
in opposition
proposing to create a "postage stamp" rate for high voltage transmission
facilities across PJM.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to 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. The
Companies, as part of the Responsible Pricing Alliance, intend to submit a
brief
on exceptions within thirty days of the initial decision. Following submission
of reply exceptions, the case is expected to 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. The PPUC approved Penn's plan with modifications
on April 20, 2006 to use an RFP process to obtain its power supply requirements
after 2006 through two separate solicitations. An initial solicitation was
held
for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the
PPUC approved the bid results for the first solicitation. 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
only
acquired for three of the five tranches for the Large Commercial Group. On
July
20, 2006, the PPUC approved the submission for the second bid. A residual
solicitation is scheduled to be held on August 15, 2006 for the two remaining
Large Commercial Group tranches. Acceptance of the winning bids is subject
to
approval by the PPUC.
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. The procedural schedule has been suspended pending
settlement discussions among the parties.
12.
- NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
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 June 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 all of the electric power
needs of FirstEnergy’s end-use customers through retail and wholesale
arrangements, including regulated retail sales to meet the PLR requirements
of
FirstEnergy's Ohio and Pennsylvania companies and competitive retail sales
to
customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business
segment owns and operates FirstEnergy's generating facilities and purchases
electricity from the wholesale market when needed to meet sales obligations.
The
segment's net income is primarily derived from all electric generation sales
revenues less the related costs of electricity generation, including purchased
power and net transmission, congestion and ancillary costs charged by PJM and
MISO to deliver energy to retail customers.
Segment reporting for interim periods in 2005 was 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)
|
|
June
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,045
|
|
$
|
1,678
|
|
$
|
58
|
|
$
|
16
|
|
$
|
(11
|
)
|
$
|
2,786
|
|
Internal
revenues
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
revenues
|
|
|
1,045
|
|
|
1,678
|
|
|
58
|
|
|
16
|
|
|
(11
|
)
|
|
2,786
|
|
Depreciation
and amortization
|
|
|
228
|
|
|
(36
|
)
|
|
-
|
|
|
1
|
|
|
5
|
|
|
198
|
|
Investment
Income
|
|
|
75
|
|
|
2
|
|
|
-
|
|
|
1
|
|
|
(47
|
)
|
|
31
|
|
Net
interest
charges
|
|
|
96
|
|
|
54
|
|
|
1
|
|
|
1
|
|
|
21
|
|
|
173
|
|
Income
taxes
|
|
|
155
|
|
|
90
|
|
|
1
|
|
|
2
|
|
|
(31
|
)
|
|
217
|
|
Net
income
|
|
|
229
|
|
|
135
|
|
|
(11
|
)
|
|
(4
|
)
|
|
(45
|
)
|
|
304
|
|
Total
assets
|
|
|
24,630
|
|
|
6,740
|
|
|
56
|
|
|
299
|
|
|
853
|
|
|
32,578
|
|
Total
goodwill
|
|
|
5,916
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,940
|
|
Property
additions
|
|
|
161
|
|
|
103
|
|
|
-
|
|
|
1
|
|
|
13
|
|
|
278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,226
|
|
$
|
1,416
|
|
$
|
59
|
|
$
|
135
|
|
$
|
7
|
|
$
|
2,843
|
|
Internal
revenues
|
|
|
80
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(80
|
)
|
|
-
|
|
Total
revenues
|
|
|
1,306
|
|
|
1,416
|
|
|
59
|
|
|
135
|
|
|
(73
|
)
|
|
2,843
|
|
Depreciation
and amortization
|
|
|
344
|
|
|
(16
|
)
|
|
-
|
|
|
-
|
|
|
7
|
|
|
335
|
|
Investment
income
|
|
|
47
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
47
|
|
Net
interest
charges
|
|
|
99
|
|
|
9
|
|
|
-
|
|
|
2
|
|
|
51
|
|
|
161
|
|
Income
taxes
|
|
|
193
|
|
|
(5
|
)
|
|
5
|
|
|
1
|
|
|
47
|
|
|
241
|
|
Income
before
discontinued operations
|
|
|
288
|
|
|
(5
|
)
|
|
(2
|
)
|
|
6
|
|
|
(108
|
)
|
|
179
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(1
|
)
|
|
-
|
|
|
(1
|
)
|
Net
income
|
|
|
288
|
|
|
(5
|
)
|
|
(2
|
)
|
|
5
|
|
|
(108
|
)
|
|
178
|
|
Total
assets
|
|
|
28,454
|
|
|
1,601
|
|
|
78
|
|
|
512
|
|
|
566
|
|
|
31,211
|
|
Total
goodwill
|
|
|
5,946
|
|
|
24
|
|
|
-
|
|
|
63
|
|
|
-
|
|
|
6,033
|
|
Property
additions
|
|
|
158
|
|
|
66
|
|
|
-
|
|
|
2
|
|
|
7
|
|
|
233
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
2,128
|
|
$
|
3,297
|
|
$
|
104
|
|
$
|
136
|
|
$
|
(34
|
)
|
$
|
5,631
|
|
Internal
revenues
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
revenues
|
|
|
2,128
|
|
|
3,297
|
|
|
104
|
|
|
136
|
|
|
(34
|
)
|
|
5,631
|
|
Depreciation
and amortization
|
|
|
486
|
|
|
(11
|
)
|
|
-
|
|
|
2
|
|
|
10
|
|
|
487
|
|
Investment
Income
|
|
|
137
|
|
|
17
|
|
|
-
|
|
|
1
|
|
|
(81
|
)
|
|
74
|
|
Net
interest
charges
|
|
|
189
|
|
|
103
|
|
|
1
|
|
|
2
|
|
|
38
|
|
|
333
|
|
Income
taxes
|
|
|
299
|
|
|
117
|
|
|
1
|
|
|
(5
|
)
|
|
(61
|
)
|
|
351
|
|
Net
income
|
|
|
440
|
|
|
175
|
|
|
(12
|
)
|
|
11
|
|
|
(89
|
)
|
|
525
|
|
Total
assets
|
|
|
24,630
|
|
|
6,740
|
|
|
56
|
|
|
299
|
|
|
853
|
|
|
32,578
|
|
Total
goodwill
|
|
|
5,916
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,940
|
|
Property
additions
|
|
|
356
|
|
|
347
|
|
|
-
|
|
|
2
|
|
|
20
|
|
|
725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
2,442
|
|
$
|
2,793
|
|
$
|
102
|
|
$
|
247
|
|
$
|
9
|
|
$
|
5,593
|
|
Internal
revenues
|
|
|
158
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(158
|
)
|
|
-
|
|
Total
revenues
|
|
|
2,600
|
|
|
2,793
|
|
|
102
|
|
|
247
|
|
|
(149
|
)
|
|
5,593
|
|
Depreciation
and amortization
|
|
|
718
|
|
|
(3
|
)
|
|
-
|
|
|
1
|
|
|
13
|
|
|
729
|
|
Investment
income
|
|
|
88
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
88
|
|
Net
interest
charges
|
|
|
197
|
|
|
19
|
|
|
-
|
|
|
3
|
|
|
113
|
|
|
332
|
|
Income
taxes
|
|
|
350
|
|
|
(35
|
)
|
|
2
|
|
|
11
|
|
|
34
|
|
|
362
|
|
Income
before
discontinued operations
|
|
|
524
|
|
|
(51
|
)
|
|
(4
|
)
|
|
11
|
|
|
(160
|
)
|
|
320
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
13
|
|
|
5
|
|
|
-
|
|
|
18
|
|
Net
income
|
|
|
524
|
|
|
(51
|
)
|
|
9
|
|
|
16
|
|
|
(160
|
)
|
|
338
|
|
Total
assets
|
|
|
28,454
|
|
|
1,601
|
|
|
78
|
|
|
512
|
|
|
566
|
|
|
31,211
|
|
Total
goodwill
|
|
|
5,946
|
|
|
24
|
|
|
-
|
|
|
63
|
|
|
-
|
|
|
6,033
|
|
Property
additions
|
|
|
299
|
|
|
147
|
|
|
1
|
|
|
4
|
|
|
11
|
|
|
462
|
|
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 six months ended June 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
$0.4 million and $0.6 million, respectively, in the second quarter of 2005
and understated by $0.9 million and $1.2 million, respectively, in the
first six months of 2005. The effects of these adjustments on JCP&L's
Consolidated Statements of Income for the three months and six months ended
June
30, 2005 are as follows:
|
|
Three
Months
|
|
Six
Months
|
|
|
As
Previously
|
|
|
As
|
|
As
Previously
|
|
As
|
|
|
Reported
|
|
|
Restated
|
|
Reported
|
|
Restated
|
|
|
(In
millions)
|
Operating
Revenues
|
$
|
595.3
|
|
$
|
595.3
|
|
$
|
1,124.4
|
|
$
|
1,124.4
|
Operating
Expenses and
|
|
|
|
|
|
|
|
|
|
|
|
Taxes
|
|
521.2
|
|
|
521.6
|
|
|
1,015.9
|
|
|
1,016.8
|
Operating
Income
|
|
74.1
|
|
|
73.7
|
|
|
108.5
|
|
|
107.6
|
Other
Income
|
|
0.3
|
|
|
0.3
|
|
|
0.3
|
|
|
0.3
|
Net
Interest
Charges
|
|
19.1
|
|
|
19.7
|
|
|
39.0
|
|
|
40.2
|
Net
Income
|
$
|
55.3
|
|
$
|
54.3
|
|
$
|
69.8
|
|
$
|
67.7
|
Earnings
Applicable
|
|
|
|
|
|
|
|
|
|
|
|
to
Common
Stock
|
$
|
55.2
|
|
$
|
54.2
|
|
$
|
69.6
|
|
$
|
67.5
|
These
adjustments
were not material to FirstEnergy's consolidated financial statements, nor
JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash
Flows.
16.
-
SUBSEQUENT EVENTS
Pennsylvania
Law Change
On
July 12, 2006,
the Governor of Pennsylvania signed House Bill 859, which increases the net
operating loss deduction allowed for the corporate net income tax from
$2 million to $3 million, or the greater of 12.5% of taxable income.
As a result, FirstEnergy expects to recognize a net operating loss benefit
of
$2.2 million (net of federal tax benefit) in the third quarter of
2006.
New
Jersey
Law Change
On
July 8, 2006, the
Governor of New Jersey signed tax legislation that increased the current New
Jersey Corporate Business tax by an additional 4% surtax, which increases the
effective tax rate from 9% to 9.36%. This increase applies to JCP&L’s 2006
through 2008 tax years and is not expected to have a material impact on
FirstEnergy’s or JCP&L’s results of operations.
FIRSTENERGY
CORP.
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Electric
utilities
|
|
$
|
2,341
|
|
$
|
2,283
|
|
$
|
4,681
|
|
$
|
4,550
|
|
Unregulated
businesses
|
|
|
445
|
|
|
560
|
|
|
950
|
|
|
1,043
|
|
Total
revenues
|
|
|
2,786
|
|
|
2,843
|
|
|
5,631
|
|
|
5,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
992
|
|
|
933
|
|
|
1,990
|
|
|
1,828
|
|
Other
operating expenses
|
|
|
760
|
|
|
873
|
|
|
1,653
|
|
|
1,757
|
|
Provision
for
depreciation
|
|
|
144
|
|
|
149
|
|
|
292
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
|
199
|
|
|
306
|
|
|
421
|
|
|
617
|
|
Deferral
of
new regulatory assets
|
|
|
(145
|
)
|
|
(120
|
)
|
|
(226
|
)
|
|
(180
|
)
|
General
taxes
|
|
|
173
|
|
|
168
|
|
|
366
|
|
|
353
|
|
Total
expenses
|
|
|
2,123
|
|
|
2,309
|
|
|
4,496
|
|
|
4,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
663
|
|
|
534
|
|
|
1,135
|
|
|
926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
31
|
|
|
47
|
|
|
74
|
|
|
88
|
|
Interest
expense
|
|
|
(178
|
)
|
|
(162
|
)
|
|
(343
|
)
|
|
(326
|
)
|
Capitalized
interest
|
|
|
7
|
|
|
5
|
|
|
14
|
|
|
4
|
|
Subsidiaries’
preferred stock dividends
|
|
|
(2
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|
(10
|
)
|
Net
interest
charges
|
|
|
(142
|
)
|
|
(114
|
)
|
|
(259
|
)
|
|
(244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
217
|
|
|
241
|
|
|
351
|
|
|
362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
|
304
|
|
|
179
|
|
|
525
|
|
|
320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income tax benefits of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1
million and
$9 million in the three months and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
six
months
ended June 30, 2005, respectively) (Note 4)
|
|
|
-
|
|
|
(1
|
)
|
|
-
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
304
|
|
$
|
178
|
|
$
|
525
|
|
$
|
338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations (Note 2)
|
|
$
|
0.92
|
|
$
|
0.54
|
|
$
|
1.59
|
|
$
|
0.98
|
|
Discontinued
operations (Note 4)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
Net
earnings
per basic share
|
|
$
|
0.92
|
|
$
|
0.54
|
|
$
|
1.59
|
|
$
|
1.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OUTSTANDING
|
|
|
328
|
|
|
328
|
|
|
328
|
|
|
328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations (Note 2)
|
|
$
|
0.91
|
|
$
|
0.54
|
|
$
|
1.58
|
|
$
|
0.97
|
|
Discontinued
operations (Note 4)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
Net
earnings
per diluted share
|
|
$
|
0.91
|
|
$
|
0.54
|
|
$
|
1.58
|
|
$
|
1.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OUTSTANDING
|
|
|
330
|
|
|
330
|
|
|
330
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$
|
0.45
|
|
$
|
0.4125
|
|
$
|
0.90
|
|
$
|
0.825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
304
|
|
$
|
178
|
|
$
|
525
|
|
$
|
338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
36
|
|
|
(6
|
)
|
|
73
|
|
|
1
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
(24
|
)
|
|
(16
|
)
|
|
13
|
|
|
(24
|
)
|
Other
comprehensive income (loss)
|
|
|
12
|
|
|
(22
|
)
|
|
86
|
|
|
(23
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
4
|
|
|
(6
|
)
|
|
31
|
|
|
(6
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
8
|
|
|
(16
|
)
|
|
55
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
$
|
312
|
|
$
|
162
|
|
$
|
580
|
|
$
|
321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
millions)
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
$
|
583
|
|
$
|
64
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $36 million and
|
|
|
|
|
|
|
|
|
$38
million,
respectively, for uncollectible accounts)
|
|
1,173
|
|
|
1,293
|
|
|
Other
(less
accumulated provisions of $27 million
|
|
|
|
|
|
|
|
|
for
uncollectible accounts in both periods)
|
|
173
|
|
|
205
|
|
Materials
and
supplies, at average cost
|
|
629
|
|
|
518
|
|
Prepayments
and other
|
|
254
|
|
|
237
|
|
|
|
|
|
|
2,812
|
|
|
2,317
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
In
service
|
|
23,661
|
|
|
22,893
|
|
Less
-
Accumulated provision for depreciation
|
|
9,883
|
|
|
9,792
|
|
|
|
|
|
|
13,778
|
|
|
13,101
|
|
Construction
work in progress
|
|
642
|
|
|
897
|
|
|
|
|
|
|
14,420
|
|
|
13,998
|
INVESTMENTS:
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
1,796
|
|
|
1,752
|
|
Investments
in
lease obligation bonds
|
|
830
|
|
|
890
|
|
Other
|
|
|
745
|
|
|
709
|
|
|
|
|
|
|
3,371
|
|
|
3,351
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
Goodwill
|
|
5,940
|
|
|
6,010
|
|
Regulatory
assets
|
|
4,396
|
|
|
4,486
|
|
Prepaid
pension costs
|
|
1,013
|
|
|
1,023
|
|
Other
|
|
|
626
|
|
|
656
|
|
|
|
|
|
|
11,975
|
|
|
12,175
|
|
|
|
|
|
$
|
32,578
|
|
$
|
31,841
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Currently
payable long-term debt
|
$
|
2,004
|
|
$
|
2,043
|
|
Short-term
borrowings
|
|
1,101
|
|
|
731
|
|
Accounts
payable
|
|
682
|
|
|
727
|
|
Accrued
taxes
|
|
750
|
|
|
800
|
|
Other
|
|
|
852
|
|
|
1,152
|
|
|
|
|
|
|
5,389
|
|
|
5,453
|
CAPITALIZATION:
|
|
|
|
|
|
|
Common
stockholders’ equity -
|
|
|
|
|
|
|
|
Common
stock,
$.10 par value, authorized 375,000,000 shares -
|
|
|
|
|
|
|
|
|
329,836,276
shares outstanding
|
|
33
|
|
|
33
|
|
|
Other
paid-in
capital
|
|
7,052
|
|
|
7,043
|
|
|
Accumulated
other comprehensive income (loss)
|
|
35
|
|
|
(20)
|
|
|
Retained
earnings
|
|
2,385
|
|
|
2,159
|
|
|
Unallocated
employee stock ownership plan common stock -
|
|
|
|
|
|
|
|
|
960,651
and
1,444,796 shares, respectively
|
|
(17)
|
|
|
(27)
|
|
|
|
|
Total
common
stockholders' equity
|
|
9,488
|
|
|
9,188
|
|
Preferred
stock of consolidated subsidiaries
|
|
154
|
|
|
184
|
|
Long-term
debt
and other long-term obligations
|
|
8,729
|
|
|
8,155
|
|
|
|
|
|
|
18,371
|
|
|
17,527
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
2,792
|
|
|
2,726
|
|
Asset
retirement obligations
|
|
1,160
|
|
|
1,126
|
|
Power
purchase
contract loss liability
|
|
1,123
|
|
|
1,226
|
|
Retirement
benefits
|
|
1,355
|
|
|
1,316
|
|
Lease
market
valuation liability
|
|
809
|
|
|
851
|
|
Other
|
|
|
1,579
|
|
|
1,616
|
|
|
|
|
|
|
8,818
|
|
|
8,861
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$
|
32,578
|
|
$
|
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)
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
June
30,
|
|
|
2006
|
|
2005
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
$
|
525
|
|
$
|
338
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
292
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
421
|
|
|
617
|
|
Deferral
of
new regulatory assets
|
|
(226
|
)
|
|
(180
|
)
|
Nuclear
fuel
and lease amortization
|
|
30
|
|
|
38
|
|
Deferred
purchased power and other costs
|
|
(239
|
)
|
|
(210
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
32
|
|
|
62
|
|
Deferred
rents
and lease market valuation liability
|
|
(105
|
)
|
|
(101
|
)
|
Accrued
compensation and retirement benefits
|
|
33
|
|
|
11
|
|
Commodity
derivative transactions, net
|
|
25
|
|
|
(6
|
)
|
Income
from
discontinued operations
|
|
-
|
|
|
(18
|
)
|
Cash
collateral
|
|
(55
|
)
|
|
22
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
Receivables
|
|
83
|
|
|
(135
|
)
|
Materials
and
supplies
|
|
(71
|
)
|
|
(52
|
)
|
Prepayments
and other current assets
|
|
(81
|
)
|
|
(159
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
Accounts
payable
|
|
(40
|
)
|
|
104
|
|
Accrued
taxes
|
|
(45
|
)
|
|
39
|
|
Accrued
interest
|
|
-
|
|
|
(4
|
)
|
Electric
service prepayment programs
|
|
(29
|
)
|
|
226
|
|
Other
|
|
1
|
|
|
37
|
|
Net
cash
provided from operating activities
|
|
551
|
|
|
921
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
Long-term
debt
|
|
1,053
|
|
|
245
|
|
Short-term
borrowings, net
|
|
371
|
|
|
386
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
Preferred
stock
|
|
(30
|
)
|
|
(140
|
)
|
Long-term
debt
|
|
(487
|
)
|
|
(689
|
)
|
Net
controlled
disbursement activity
|
|
5
|
|
|
-
|
|
Common
stock
dividend payments
|
|
(296
|
)
|
|
(270
|
)
|
Net
cash
provided from (used for) financing activities
|
|
616
|
|
|
(468
|
)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
Property
additions
|
|
(725
|
)
|
|
(462
|
)
|
Proceeds
from
asset sales
|
|
59
|
|
|
61
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
925
|
|
|
608
|
|
Investments
in
nuclear decommissioning trust funds
|
|
(932
|
)
|
|
(659
|
)
|
Cash
investments
|
|
40
|
|
|
35
|
|
Other
|
|
(15
|
)
|
|
(39
|
)
|
Net
cash used
for investing activities
|
|
(648
|
)
|
|
(456
|
)
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
519
|
|
|
(3
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
64
|
|
|
53
|
|
Cash
and cash
equivalents at end of period
|
$
|
583
|
|
$
|
50
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of these
statements.
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholders
and Board of
Directors
of
FirstEnergy Corp.:
We
have reviewed the
accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of June 30, 2006, and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2006 and 2005 and the consolidated statement of cash
flows for the six-month period ended June 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
August
4,
2006
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE
SUMMARY
Reconciliation
of non-GAAP to GAAP
|
|
2006
|
|
2005
|
|
|
|
After-tax
|
|
Basic
|
|
After-tax
|
|
Basic
|
|
|
|
Amount
|
|
Earnings
|
|
Amount
|
|
Earnings
|
|
Three
Months Ended June 30,
|
|
(Millions)
|
|
Per
Share
|
|
(Millions)
|
|
Per
Share
|
|
Earnings
Before Unusual Items (Non-GAAP)
|
|
$
|
313
|
|
$
|
0.95
|
|
$
|
233
|
|
$
|
0.71
|
|
Unusual
Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-core
asset
sales/impairments
|
|
|
(9
|
)
|
|
(0.03
|
)
|
|
-
|
|
|
-
|
|
New
regulatory
assets - JCP&L rate settlement
|
|
|
-
|
|
|
-
|
|
|
16
|
|
|
0.05
|
|
Ohio
tax
write-off
|
|
|
-
|
|
|
-
|
|
|
(71
|
)
|
|
(0.22
|
)
|
Net
Income
(GAAP)
|
|
$
|
304
|
|
$
|
0.92
|
|
$
|
178
|
|
$
|
0.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Before Unusual Items (Non-GAAP)
|
|
$
|
536
|
|
$
|
1.62
|
|
$
|
388
|
|
$
|
1.18
|
|
Unusual
Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-core
asset
sales/impairments
|
|
|
(11
|
)
|
|
(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
|
|
Ohio
tax
write-off
|
|
|
-
|
|
|
-
|
|
|
(71
|
)
|
|
(0.22
|
)
|
Net
Income
(GAAP)
|
|
$
|
525
|
|
$
|
1.59
|
|
$
|
338
|
|
$
|
1.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 item refers to a finite set of
energy-related assets that had been previously disclosed as held for sale,
a
substantial portion of which has already been sold. Similarly, the NRC fine
in
2005 and further litigation settlements similar to the class action settlements
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.
Total
electric
generation sales were up by 3.9% over last year’s second quarter. For the six
months ended June 30, 2006, electric generation sales rose 3.0% compared to
the
same period last year. The increase for both periods was primarily due to the
return of customers to the Ohio Companies from third-party suppliers that exited
the Ohio marketplace. Electric distribution deliveries were down 1.8% and 2.2%
for the quarter and year-to-date periods ending June 30, reflecting milder
weather conditions in 2006.
FirstEnergy's
generating fleet produced a second quarter record 20.3 billion KWH during
the second quarter of 2006 compared to 19.1 billion KWH in the second
quarter of 2005. FirstEnergy's non-nuclear fleet produced a record
13.4 billion KWH, while its nuclear facilities produced 6.9 billion
KWH.
Ohio Supreme Court Decision - On May 3, 2006, the Ohio Supreme Court affirmed,
in all but one aspect, the provisions of FirstEnergy's RSP for its Ohio
customers. An issue related to customer pricing options was remanded to the
PUCO
for further consideration. The Court found that FirstEnergy must provide an
alternative market-based offering to customers in addition to that which they
already have through their rate stabilization price, even if the alternative
is
higher than that offered through the RSP. On July 20, 2006, FirstEnergy filed
a
notice with the PUCO to address this issue through a proposed RFP program under
which Ohio customers would have the opportunity to switch to alternative
generation suppliers at prices established through the RFP program. FirstEnergy
also provided notice of potential termination of certain portions of the RSP
in
the event that the issue is not resolved within a reasonable time frame or
if
modifications to the RSP are not acceptable. On July 26, 2006, the PUCO directed
FirstEnergy to file within 45 days its plan to address the Court’s
concern.
Pennsylvania
Rate
Matters - On May 31, 2006, the ALJ in the Met-Ed and Penelec rate transition
plan filing established a procedural schedule with a goal of reaching a
recommended decision in this proceeding by November 8, 2006. In accordance
with this schedule, intervening parties submitted their written testimony by
July 10, 2006. Ten public input hearings were held in various locations
throughout the Met-Ed and Penelec service areas between June 20, 2006 and
July 20, 2006.
Met-Ed
and Penelec
Transmission Charges - On May 4, 2006, the PPUC granted authority for Met-Ed
and
Penelec to defer, for accounting and financial reporting purposes, certain
incremental transmission charges during 2006. The PPUC order allows Met-Ed
and
Penelec to defer, commencing January 1, 2006, the costs that are incremental
to
the levels currently reflected in the transmission component of Met-Ed’s and
Penelec’s base rate tariffs. Recovery of the deferred costs will be considered
in their pending comprehensive rate transition plan filing.
Penn RFP - On June 2, 2006, the PPUC approved the bid results for the first
bid.
On July 18, 2006, the second PLR bid process was held for Penn. On July 20,
2006, the PPUC approved the submissions for the second bid. As a result of
bids
one and two, supply has been successfully acquired for all seven tranches of
the
Residential Group and all six of the Small Commercial Group. However, supply
has
only been acquired for three of the five tranches for the Large Commercial
Group. Therefore, a residual third bid is scheduled to be held on August 15,
2006 for the two remaining Large Commercial Group tranches.
Environmental
Update - In
June 2006,
FirstEnergy finalized its air quality compliance strategy for 2006 through
2011.
The program, which is expected to cost approximately $1.7 billion with the
majority of those expenditures occurring between 2007 and 2009, is consistent
with previous estimates and assumptions reflected in FirstEnergy’s long-term
financial planning for air and water quality and other environmental
matters.
Share Repurchase Program - On
June 20, 2006,
FirstEnergy's Board of Directors authorized a share repurchase program for
up to
12 million shares of common stock. At management’s discretion, shares may
be acquired 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 purchase any shares and
the
program may be terminated at any time. The 12 million shares represent 3.6%
of the approximately 330 million shares of common stock currently
outstanding.
OE Senior Notes Offering - On
June 26, 2006, OE
issued $600 million of unsecured senior notes, comprised of $250 million due
2016 and $350 million due 2036. Proceeds from these offerings were used in
July
2006 to repurchase $500 million of OE’s common stock from FirstEnergy, to redeem
$61 million of OE’s preferred stock and to reduce short-term debt. FirstEnergy
primarily used the proceeds to redeem, on July 31, 2006, $400 million
principal amount of its $1 billion, 5.5% Notes, Series A, in advance of the
November 15, 2006 maturity date. This represents an important part of
FirstEnergy’s 2006 financing strategy to obtain additional financing flexibility
at the holding company level and to capitalize its regulated utilities more
appropriately from a regulatory context.
JCP&L Senior Notes Offering - 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.
JCP&L
Securitization - On June 8, 2006, the NJBPU approved JCP&L's request to
issue securitization bonds associated with BGS stranded cost deferrals. On
August 4, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of
JCP&L, secured pricing on the issuance of $182 million of transition bonds
with a weighted average interest rate of 5.5%.
New
Coal Supply Agreement -
On June 22, 2006,
FGCO entered into a new coal supply agreement with CONSOL Energy, Inc. under
which CONSOL will supply a total of more than 128 million tons of high-Btu
coal
to FirstEnergy for a 20-year period beginning in 2009. The new agreement
replaces an existing coal supply agreement that took effect in January 2003
and
ran through 2020. Under the new agreement, CONSOL will increase its coal
shipments by approximately 2 million tons per year.
Ratified Contract Agreements - On May 11, 2006, employees represented by Local
270 of the Utility Workers Union of America (UWUA) voted to ratify a five-year
contract agreement. UWUA Local 270 represents approximately 1,075 linemen,
substation electricians, meter readers, and support personnel in the greater
Cleveland area. On May 26, 2006, employees of Penelec represented by the
International Brotherhood of Electrical Workers (IBEW) Local 459 ratified a
three-year collective bargaining agreement. IBEW Local 459 includes 482 linemen,
substation electricians, meter readers and support personnel.
FIRSTENERGY’S
BUSINESS
FirstEnergy
is a public utility holding company headquartered in Akron, Ohio that operates
primarily through two core business segments (see Results of
Operations).
-
Regulated
Services
transmits and
distributes electricity through FirstEnergy's eight utility operating
companies that collectively comprise the nation’s fifth largest investor-owned
electric system, serving 4.5 million customers within 36,100 square miles
of Ohio, Pennsylvania and New Jersey. This business segment derives its
revenue principally from the delivery of electricity generated or purchased
by
the Power Supply Management Services segment in the states where the utility
subsidiaries operate.
-
Power
Supply Management Services
supplies all of
the electric power needs of end-use customers through retail and wholesale
arrangements, including regulated retail sales to meet the PLR requirements
of
FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive
retail sales to customers primarily in Ohio, Pennsylvania, Maryland and
Michigan. This business segment owns and operates FirstEnergy's generating
facilities and purchases electricity from the wholesale market to meet
sales
obligations. The segment's net income is primarily derived from electric
generation sales revenues less the related costs of electricity generation,
including purchased power, and net transmission, congestion and ancillary
costs charged by PJM and MISO to deliver energy to retail customers.
Other operating segments provide a wide range of services, including heating,
ventilation, air-conditioning, refrigeration, electrical and facility control
systems, high-efficiency electrotechnologies and telecommunication services.
FirstEnergy is in the process of divesting its remaining non-core businesses
(see Note 4). The assets and revenues for the other business operations are
below the quantifiable threshold for separate disclosure as “reportable
operating segments”.
FIRSTENERGY
INTRA-SYSTEM GENERATION ASSET TRANSFERS
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 June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
Increase
|
|
|
|
Increase
|
|
|
|
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
|
|
(In
millions, except per share amounts)
|
|
Net
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By
Business Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Services
|
|
|
|
|
$
|
229
|
|
$
|
288
|
|
$
|
(59
|
)
|
$
|
440
|
|
$
|
524
|
|
$
|
(84
|
)
|
Power
supply
management services
|
|
|
|
|
|
135
|
|
|
(5
|
)
|
|
140
|
|
|
175
|
|
|
(51
|
)
|
|
226
|
|
Other
and
reconciling adjustments*
|
|
|
|
|
|
(60
|
)
|
|
(105
|
)
|
|
45
|
|
|
(90
|
)
|
|
(135
|
)
|
|
45
|
|
Total
|
|
|
|
|
$
|
304
|
|
$
|
178
|
|
$
|
126
|
|
$
|
525
|
|
$
|
338
|
|
$
|
187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
|
|
|
$
|
0.92
|
|
$
|
0.54
|
|
$
|
0.38
|
|
$
|
1.59
|
|
$
|
0.98
|
|
$
|
0.61
|
|
Discontinued
operations
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
|
(0.05
|
)
|
Net
earnings
per basic share
|
|
|
|
|
$
|
0.92
|
|
$
|
0.54
|
|
$
|
0.38
|
|
$
|
1.59
|
|
$
|
1.03
|
|
$
|
0.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
|
|
|
$
|
0.91
|
|
$
|
0.54
|
|
$
|
0.37
|
|
$
|
1.58
|
|
$
|
0.97
|
|
$
|
0.61
|
|
Discontinued
operations
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.05
|
|
|
(0.05
|
)
|
Net
earnings
per diluted share
|
|
|
|
|
$
|
0.91
|
|
$
|
0.54
|
|
$
|
0.37
|
|
$
|
1.58
|
|
$
|
1.02
|
|
$
|
0.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
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
second quarter and the first six months of 2006 included net losses associated
with the sale and impairment of non-core assets of $9 million (or $0.03 per
share) and $11 million (or $0.03 per share), respectively.
Net income in the second quarter of 2005 included a net gain resulting from
the
JCP&L rate settlement of $16 million (or $0.05 per share) and
additional income tax expense of $71 million (or $0.22 per share) from the
enactment of tax legislation in Ohio. In the first six months of 2005, net
income was also increased by $0.02 per share from the combined impact of $0.07
per share of gains from the sale of non-core assets, offset by $0.04 per share
of expense associated with the W. H. Sammis Plant New Source Review settlement
and $0.01 per share of expense related to the fine by the NRC regarding the
Davis-Besse Nuclear Power Station.
Summary
of Results of Operations - Second Quarter of 2006 Compared with the Second
Quarter of 2005
Financial
results
for FirstEnergy's major business segments in the second quarter of 2006 and
2005
were as follows:
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
2nd
Quarter 2006 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
913
|
|
$
|
1,640
|
|
$
|
-
|
|
$
|
2,553
|
|
Other
|
|
|
132
|
|
|
38
|
|
|
63
|
|
|
233
|
|
Internal
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
Revenues
|
|
|
1,045
|
|
|
1,678
|
|
|
63
|
|
|
2,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
992
|
|
|
-
|
|
|
992
|
|
Other
operating expenses
|
|
|
283
|
|
|
406
|
|
|
71
|
|
|
760
|
|
Provision
for
depreciation
|
|
|
88
|
|
|
50
|
|
|
6
|
|
|
144
|
|
Amortization
of regulatory assets
|
|
|
195
|
|
|
4
|
|
|
-
|
|
|
199
|
|
Deferral
of
new regulatory assets
|
|
|
(55
|
)
|
|
(90
|
)
|
|
-
|
|
|
(145
|
)
|
General
taxes
|
|
|
129
|
|
|
39
|
|
|
5
|
|
|
173
|
|
Total
Expenses
|
|
|
640
|
|
|
1.401
|
|
|
82
|
|
|
2,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
405
|
|
|
277
|
|
|
(19
|
)
|
|
663
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
75
|
|
|
2
|
|
|
(46
|
)
|
|
31
|
|
Interest
expense
|
|
|
(96
|
)
|
|
(56
|
)
|
|
(26
|
)
|
|
(178
|
)
|
Capitalized
interest
|
|
|
5
|
|
|
2
|
|
|
-
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(5
|
)
|
|
-
|
|
|
3
|
|
|
(2
|
)
|
Total
Other
Income (Expense)
|
|
|
(21
|
)
|
|
(52
|
)
|
|
(69
|
)
|
|
(142
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
(benefit)
|
|
|
155
|
|
|
90
|
|
|
(28
|
)
|
|
217
|
|
Income
before
discontinued operations
|
|
|
229
|
|
|
135
|
|
|
(60
|
)
|
|
304
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
Income
(Loss)
|
|
$
|
229
|
|
$
|
135
|
|
$
|
(60
|
)
|
$
|
304
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
2nd
Quarter 2005 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,087
|
|
$
|
1,391
|
|
$
|
-
|
|
$
|
2,478
|
|
Other
|
|
|
139
|
|
|
25
|
|
|
201
|
|
|
365
|
|
Internal
|
|
|
80
|
|
|
-
|
|
|
(80
|
)
|
|
-
|
|
Total
Revenues
|
|
|
1,306
|
|
|
1,416
|
|
|
121
|
|
|
2,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
933
|
|
|
-
|
|
|
933
|
|
Other
operating expenses
|
|
|
297
|
|
|
469
|
|
|
107
|
|
|
873
|
|
Provision
for
depreciation
|
|
|
138
|
|
|
4
|
|
|
7
|
|
|
149
|
|
Amortization
of regulatory assets
|
|
|
306
|
|
|
-
|
|
|
-
|
|
|
306
|
|
Deferral
of
new regulatory assets
|
|
|
(100
|
)
|
|
(20
|
)
|
|
-
|
|
|
(120
|
)
|
General
taxes
|
|
|
132
|
|
|
31
|
|
|
5
|
|
|
168
|
|
Total
Expenses
|
|
|
773
|
|
|
1,417
|
|
|
119
|
|
|
2,309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
533
|
|
|
(1
|
)
|
|
2
|
|
|
534
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
47
|
|
|
-
|
|
|
-
|
|
|
47
|
|
Interest
expense
|
|
|
(99
|
)
|
|
(10
|
)
|
|
(53
|
)
|
|
(162
|
)
|
Capitalized
interest
|
|
|
4
|
|
|
1
|
|
|
-
|
|
|
5
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(4
|
)
|
|
-
|
|
|
-
|
|
|
(4
|
)
|
Total
Other
Income (Expense)
|
|
|
(52
|
)
|
|
(9
|
)
|
|
(53
|
)
|
|
(114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
(benefit)
|
|
|
193
|
|
|
(5
|
)
|
|
53
|
|
|
241
|
|
Income
before
discontinued operations
|
|
|
288
|
|
|
(5
|
)
|
|
(104
|
)
|
|
179
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
(1
|
)
|
|
(1
|
)
|
Net
Income
(Loss)
|
|
$
|
288
|
|
$
|
(5
|
)
|
$
|
(105
|
)
|
$
|
178
|
|
|
|
|
|
Power
|
|
|
|
|
|
Change
Between 2nd Quarter 2006 and
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
2nd
Quarter 2005 Financial Results
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Increase
(Decrease)
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
(174
|
)
|
$
|
249
|
|
$
|
-
|
|
$
|
75
|
|
Other
|
|
|
(7
|
)
|
|
13
|
|
|
(138
|
)
|
|
(132
|
)
|
Internal
|
|
|
(80
|
)
|
|
-
|
|
|
80
|
|
|
-
|
|
Total
Revenues
|
|
|
(261
|
)
|
|
262
|
|
|
(58
|
)
|
|
(57
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
59
|
|
|
-
|
|
|
59
|
|
Other
operating expenses
|
|
|
(14
|
)
|
|
(63
|
)
|
|
(36
|
)
|
|
(113
|
)
|
Provision
for
depreciation
|
|
|
(50
|
)
|
|
46
|
|
|
(1
|
)
|
|
(5
|
)
|
Amortization
of regulatory assets
|
|
|
(111
|
)
|
|
4
|
|
|
-
|
|
|
(107
|
)
|
Deferral
of
new regulatory assets
|
|
|
45
|
|
|
(70
|
)
|
|
-
|
|
|
(25
|
)
|
General
taxes
|
|
|
(3
|
)
|
|
8
|
|
|
-
|
|
|
5
|
|
Total
Expenses
|
|
|
(133
|
)
|
|
(16
|
)
|
|
(37
|
)
|
|
(186
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(128
|
)
|
|
278
|
|
|
(21
|
)
|
|
129
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
28
|
|
|
2
|
|
|
(46
|
)
|
|
(16
|
)
|
Interest
expense
|
|
|
3
|
|
|
(46
|
)
|
|
27
|
|
|
(16
|
)
|
Capitalized
interest
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
2
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(1
|
)
|
|
-
|
|
|
3
|
|
|
2
|
|
Total
Other
Income (Expense)
|
|
|
31
|
|
|
(43
|
)
|
|
(16
|
)
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
(38
|
)
|
|
95
|
|
|
(81
|
)
|
|
(24
|
)
|
Income
before
discontinued operations
|
|
|
(59
|
)
|
|
140
|
|
|
44
|
|
|
125
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
Net
Income
|
|
$
|
(59
|
)
|
$
|
140
|
|
$
|
45
|
|
$
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Services - Second Quarter 2006 Compared to Second Quarter 2005
Net
income decreased
$59 million (20.5%) to $229 million in the second quarter of 2006 compared
to
$288 million in the second quarter of 2005, primarily due to decreased
operating revenues partially offset by lower operating expenses and
taxes.
Revenues
-
The
decrease in
total revenues resulted from the following sources:
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Distribution
services
|
|
$
|
913
|
|
$
|
1,087
|
|
$
|
(174
|
)
|
Transmission
services
|
|
|
87
|
|
|
105
|
|
|
(18
|
)
|
Internal
lease
revenues
|
|
|
-
|
|
|
80
|
|
|
(80
|
)
|
Other
|
|
|
45
|
|
|
34
|
|
|
11
|
|
Total
Revenues
|
|
$
|
1,045
|
|
$
|
1,306
|
|
$
|
(261
|
)
|
Changes
in
distribution deliveries by customer class are summarized in the following
table:
Electric
Distribution Deliveries
|
|
|
|
Residential
|
|
|
(4.8
|
)%
|
Commercial
|
|
|
(1.1
|
)%
|
Industrial
|
|
|
0.4
|
%
|
Total
Distribution Deliveries
|
|
|
(1.8
|
)%
|
The
completion of
the Ohio Companies' generation transition cost recovery under their respective
transition plans and Penn's transition plan in 2005 was the primary reason
for
lower distribution unit prices, which, in conjunction with
lower KWH
deliveries, resulted in lower distribution delivery revenues. The decrease
in deliveries to customers was primarily due to unseasonably milder weather
during the second quarter of 2006. The following table summarizes major
factors contributing to the $174 million decrease in distribution service
revenues in the second quarter of 2006:
Sources
of Change in Distribution Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Changes
in
customer usage
|
|
$
|
(54
|
)
|
Ohio
shopping
incentives
|
|
|
58
|
|
Changes
in
prices:
|
|
|
|
|
Rate
mix and
other
|
|
|
(178
|
)
|
|
|
|
|
|
Net
Decrease
in Distribution Revenues
|
|
$
|
(174
|
)
|
The
decrease in
internal revenues reflected the effect of the generation asset transfers
discussed above. The 2005 generation assets lease revenue from affiliates ceased
as a result of the transfers.
Expenses-
The
decrease in
revenues discussed above was partially offset by the following decreases in
total expenses:
|
·
|
Other
operating expenses were $14 million lower in 2006 due, in part, to
the
following factors:
|
1) |
The
absence in
2006 of expenses for ancillary service refunds to third parties of
$6 million in 2005 due to the RCP, which provides that alternate
suppliers of ancillary services now bill customers directly for those
services;
|
2) |
A
$27 million decrease in employee and contractor costs resulting from
lower storm-related expenses, 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
|
3) |
An
$18 million increase due in part to insurance premium costs,
financing fees and other administrative
costs.
|
|
·
|
Lower
depreciation expense of $50 million that resulted from the impact
of the
generation asset transfers;
|
|
·
|
Reduced
amortization of regulatory assets of $111 million principally due
to the
completion of Ohio generation transition cost recovery and Penn's
transition plan in 2005; and
|
|
·
|
General
taxes
decreased by $3 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 the 2005
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
-
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 second quarter of 2006 was partially offset
by the absence in 2006 of the majority of nuclear decommissioning trust income
which is now included in the power supply management services
segment.
Power
Supply Management Services - Second Quarter 2006 Compared to Second Quarter
2005
Net
income for this
segment was $135 million in the second quarter of 2006 compared to a net loss
of
$5 million in the same period last year. An improvement in the gross
generation margin was partially offset by higher depreciation, general taxes
and
interest expense resulting from the generation asset
transfers.
Revenues
-
Electric generation sales revenues increased $224 million in the second 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 Ohio marketplace, and higher
unit prices resulting from the 2006 rate stabilization and fuel recovery
charges. Additional retail sales reduced energy available for sale to the
wholesale market. Increased transmission revenues reflected new revenues of
approximately $27 million under the MISO transmission rider that began in the
first quarter of 2006.
An
increase in
reported segment revenues resulted from the following sources:
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Electric
Generation Sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
1,285
|
|
$
|
989
|
|
$
|
296
|
|
Wholesale
|
|
|
253
|
|
|
325
|
|
|
(72
|
)
|
Total
Electric
Generation Sales
|
|
|
1,538
|
|
|
1,314
|
|
|
224
|
|
Transmission
|
|
|
134
|
|
|
93
|
|
|
41
|
|
Other
|
|
|
6
|
|
|
9
|
|
|
(3
|
)
|
Total
Revenues
|
|
$
|
1,678
|
|
$
|
1,416
|
|
$
|
262
|
|
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
|
|
$
|
76
|
|
Increased
prices
|
|
|
220
|
|
|
|
|
296
|
|
Wholesale:
|
|
|
|
|
Effect
of 8.4%
decrease in KWH sales
|
|
|
(27
|
)
|
Lower
prices
|
|
|
(45
|
)
|
|
|
|
(72
|
)
|
Net
Increase
in Electric Generation Sales
|
|
$
|
224
|
|
Expenses
-
Total
operating
expenses decreased by $16
million.
The
decrease was due to the following factors:
|
·
|
Lower
non-fuel
operating expenses of $63 million reflect the absence in 2006 of
generating lease rents of $80 million in 2005 due to the generation
asset transfers, partially offset by higher transmission expenses
of
$11 million related to the transmission revenues discussed above;
and
|
|
·
|
The
$70 million increase in the deferral of new regulatory assets
represents 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 deferrals in
2006
also include the Ohio RCP fuel deferral of
$29 million.
|
The
above decreases
were partially offset by the following:
|
·
|
Higher
fuel
and purchased power costs of $59 million,
including increased fuel costs of $23 million
- coal
costs increased $40 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
$20 million. Purchased power costs increased $36 million
due to
higher prices and increased 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
|
|
$
|
5
|
|
Change
due to
volume consumed
|
|
|
18
|
|
|
|
|
23
|
|
Purchased
Power:
|
|
|
|
|
Change
due to
increased unit costs
|
|
|
53
|
|
Change
due to
volume purchased
|
|
|
2
|
|
Increase
in
NUG costs deferred
|
|
|
(19
|
)
|
|
|
|
36
|
|
|
|
|
|
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
$
|
59
|
|
|
·
|
Increased
depreciation expenses of $46 million resulted principally from the
generation asset transfers; and
|
|
·
|
Higher
general
taxes of $8 million
due to
additional property taxes resulting from the generation asset
transfers.
|
Other
Income and
Expense -
|
·
|
Investment
income in the second quarter of 2006 increased by $2 million over
the
prior year period primarily due to nuclear decommissioning trust
investments acquired through the generation asset transfers;
and
|
|
·
|
Interest
expense increased by $46 million, primarily due to the interest
expense in
2006 on associated company notes payable that financed the generation
asset transfers.
|
Other
-
Second Quarter 2006 Compared to Second 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 $45 million increase to
FirstEnergy’s net income in the second quarter of 2006 compared to the same
quarter of 2005. The increase was primarily due to the absence of an adjustment
from the effect of Ohio tax legislation in June 2005, which resulted in
additional 2005 tax expenses of $71 million, and a $3 million gain
related to interest rate swap financing arrangements. These increases were
partially offset by a $5 million reduction in investment income, non-core
asset sales gains/impairments of $9 million and a $7 million reduction
in gas commodity trading results.
Summary
of Results of Operations - First Six Months of 2006 Compared with the First
Six
Months of 2005
Financial
results
for FirstEnergy's major business segments in the first six months of 2006 and
2005 were as follows:
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Six Months of 2006 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,848
|
|
$
|
3,216
|
|
$
|
-
|
|
$
|
5,064
|
|
Other
|
|
|
280
|
|
|
81
|
|
|
206
|
|
|
567
|
|
Internal
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
Revenues
|
|
|
2,128
|
|
|
3,297
|
|
|
206
|
|
|
5,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
1,990
|
|
|
-
|
|
|
1,990
|
|
Other
operating expenses
|
|
|
582
|
|
|
856
|
|
|
215
|
|
|
1,653
|
|
Provision
for
depreciation
|
|
|
184
|
|
|
96
|
|
|
12
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
|
412
|
|
|
9
|
|
|
-
|
|
|
421
|
|
Deferral
of
new regulatory assets
|
|
|
(110
|
)
|
|
(116
|
)
|
|
-
|
|
|
(226
|
)
|
General
taxes
|
|
|
269
|
|
|
84
|
|
|
13
|
|
|
366
|
|
Total
Expenses
|
|
|
1,337
|
|
|
2,919
|
|
|
240
|
|
|
4,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
791
|
|
|
378
|
|
|
(34
|
)
|
|
1,135
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
137
|
|
|
17
|
|
|
(80
|
)
|
|
74
|
|
Interest
expense
|
|
|
(190
|
)
|
|
(109
|
)
|
|
(44
|
)
|
|
(343
|
)
|
Capitalized
interest
|
|
|
8
|
|
|
6
|
|
|
-
|
|
|
14
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(7
|
)
|
|
-
|
|
|
3
|
|
|
(4
|
)
|
Total
Other
Income (Expense)
|
|
|
(52
|
)
|
|
(86
|
)
|
|
(121
|
)
|
|
(259
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
(benefit)
|
|
|
299
|
|
|
117
|
|
|
(65
|
)
|
|
351
|
|
Income
before
discontinued operations
|
|
|
440
|
|
|
175
|
|
|
(90
|
)
|
|
525
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
Income
(Loss)
|
|
$
|
440
|
|
$
|
175
|
|
$
|
(90
|
)
|
$
|
525
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Six Months of 2005 Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
2,169
|
|
$
|
2,746
|
|
$
|
-
|
|
$
|
4,915
|
|
Other
|
|
|
273
|
|
|
47
|
|
|
358
|
|
|
678
|
|
Internal
|
|
|
158
|
|
|
-
|
|
|
(158
|
)
|
|
-
|
|
Total
Revenues
|
|
|
2,600
|
|
|
2,793
|
|
|
200
|
|
|
5,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
1,828
|
|
|
-
|
|
|
1,828
|
|
Other
operating expenses
|
|
|
625
|
|
|
968
|
|
|
164
|
|
|
1,757
|
|
Provision
for
depreciation
|
|
|
261
|
|
|
17
|
|
|
14
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
|
617
|
|
|
-
|
|
|
-
|
|
|
617
|
|
Deferral
of
new regulatory assets
|
|
|
(160
|
)
|
|
(20
|
)
|
|
-
|
|
|
(180
|
)
|
General
taxes
|
|
|
274
|
|
|
67
|
|
|
12
|
|
|
353
|
|
Total
Expenses
|
|
|
1,617
|
|
|
2,860
|
|
|
190
|
|
|
4,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss)
|
|
|
983
|
|
|
(67
|
)
|
|
10
|
|
|
926
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
88
|
|
|
-
|
|
|
-
|
|
|
88
|
|
Interest
expense
|
|
|
(194
|
)
|
|
(16
|
)
|
|
(116
|
)
|
|
(326
|
)
|
Capitalized
interest
|
|
|
7
|
|
|
(3
|
)
|
|
-
|
|
|
4
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(10
|
)
|
|
-
|
|
|
-
|
|
|
(10
|
)
|
Total
Other
Income (Expense)
|
|
|
(109
|
)
|
|
(19
|
)
|
|
(116
|
)
|
|
(244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
(benefit)
|
|
|
350
|
|
|
(35
|
)
|
|
47
|
|
|
362
|
|
Income
before
discontinued operations
|
|
|
524
|
|
|
(51
|
)
|
|
(153
|
)
|
|
320
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
18
|
|
|
18
|
|
Net
Income
(Loss)
|
|
$
|
524
|
|
$
|
(51
|
)
|
$
|
(135
|
)
|
$
|
338
|
|
|
|
|
|
Power
|
|
|
|
|
|
Change
Between First Six Months of 2006
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
and
First Six Months of 2005
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Financial
Results -
Increase (Decrease)
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
(321
|
)
|
$
|
470
|
|
$
|
-
|
|
$
|
149
|
|
Other
|
|
|
7
|
|
|
34
|
|
|
(152
|
)
|
|
(111
|
)
|
Internal
|
|
|
(158
|
)
|
|
-
|
|
|
158
|
|
|
-
|
|
Total
Revenues
|
|
|
(472
|
)
|
|
504
|
|
|
6
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
-
|
|
|
162
|
|
|
-
|
|
|
162
|
|
Other
operating expenses
|
|
|
(43
|
)
|
|
(112
|
)
|
|
51
|
|
|
(104
|
)
|
Provision
for
depreciation
|
|
|
(77
|
)
|
|
79
|
|
|
(2
|
)
|
|
-
|
|
Amortization
of regulatory assets
|
|
|
(205
|
)
|
|
9
|
|
|
-
|
|
|
(196
|
)
|
Deferral
of
new regulatory assets
|
|
|
50
|
|
|
(96
|
)
|
|
-
|
|
|
(46
|
)
|
General
taxes
|
|
|
(5
|
)
|
|
17
|
|
|
1
|
|
|
13
|
|
Total
Expenses
|
|
|
(280
|
)
|
|
59
|
|
|
50
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(192
|
)
|
|
445
|
|
|
(44
|
)
|
|
209
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
49
|
|
|
17
|
|
|
(80
|
)
|
|
(14
|
)
|
Interest
expense
|
|
|
4
|
|
|
(93
|
)
|
|
72
|
|
|
(17
|
)
|
Capitalized
interest
|
|
|
1
|
|
|
9
|
|
|
-
|
|
|
10
|
|
Subsidiaries'
preferred stock dividends
|
|
|
3
|
|
|
-
|
|
|
3
|
|
|
6
|
|
Total
Other
Income (Expense)
|
|
|
57
|
|
|
(67
|
)
|
|
(5
|
)
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
(51
|
)
|
|
152
|
|
|
(112
|
)
|
|
(11
|
)
|
Income
before
discontinued operations
|
|
|
(84
|
)
|
|
226
|
|
|
63
|
|
|
205
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
(18
|
)
|
|
(18
|
)
|
Net
Income
|
|
$
|
(84
|
)
|
$
|
226
|
|
$
|
45
|
|
$
|
187
|
|
Regulated
Services - First Six Months of 2006 Compared to First Six Months of 2005
Net
income decreased
$84 million (16.0%) to $440 million in the first six months of 2006 compared
to
$524 million in the first six months of 2005, primarily due to decreased
operating revenues partially offset by lower operating expenses and
taxes.
Revenues
-
The
decrease in
total revenues resulted from the following sources:
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Distribution
services
|
|
$
|
1,848
|
|
$
|
2,169
|
|
$
|
(321
|
)
|
Transmission
services
|
|
|
181
|
|
|
197
|
|
|
(16
|
)
|
Internal
lease
revenues
|
|
|
-
|
|
|
158
|
|
|
(158
|
)
|
Other
|
|
|
99
|
|
|
76
|
|
|
23
|
|
Total
Revenues
|
|
$
|
2,128
|
|
$
|
2,600
|
|
$
|
(472
|
)
|
Decreases
in
distribution deliveries by customer class are summarized in the following
table:
Electric
Distribution Deliveries
|
|
|
|
Residential
|
|
|
(3.6
|
)%
|
Commercial
|
|
|
(1.6
|
)%
|
Industrial
|
|
|
(1.2
|
)%
|
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 was the primary reason
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 unseasonably milder weather during the first
six
months of 2006 as compared to the same period in 2005. The following table
summarizes major factors contributing to the $321 million decrease in
distribution service revenues in the first six months of 2006:
Sources
of Change in Distribution Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Changes
in
customer usage
|
|
$
|
(102
|
)
|
Ohio
shopping
incentives
|
|
|
100
|
|
Changes
in
prices:
|
|
|
|
|
Rate
mix and
other
|
|
|
(319
|
)
|
|
|
|
|
|
Net
Decrease
in Distribution Revenues
|
|
$
|
(321
|
)
|
The
decrease in
internal revenues reflected the effect of the generation asset transfers
discussed above. The 2005 generation assets lease revenue from affiliates ceased
as a result of the transfers.
Expenses-
The
decrease in
revenues discussed above was partially offset by the following decreases in
total expenses:
|
·
|
Other
operating expenses were $43 million lower in 2006 due, in part, to
the
following factors:
|
1) |
The
absence in
2006 of expenses for ancillary service refunds to third parties of
$13 million in 2005 due to the RCP, which provides that alternate
suppliers of ancillary services now bill customers directly for those
services;
|
2) |
The
absence in
2006 of receivables factoring discount expenses of approximately
$6 million incurred in 2005;
and
|
3) |
A
$33 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.
|
|
·
|
Lower
depreciation expense of $77 million resulted from the impact of the
generation asset transfers;
|
|
·
|
Reduced
amortization of regulatory assets of $205 million resulted principally
from the completion of Ohio generation transition cost recovery and
Penn's
transition plan in 2005; and
|
|
·
|
General
taxes
decreased by $5 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 the 2005 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 six months of 2006
is
partially offset by the absence in 2006 of the majority of nuclear
decommissioning trust income which is now included in the power supply
management services segment; and
|
|
·
|
Subsidiaries'
preferred stock dividends decreased by $3 million in 2006 due to
redemption activity in 2005.
|
Power
Supply Management Services - First Six Months of 2006 Compared to First Six
Months of 2005
Net
income for this
segment was $175 million in the first six months of 2006 compared to a net
loss
of $51 million in the same period last year. An improvement in the gross
generation margin was partially offset by higher depreciation, general taxes
and
interest expense resulting from the generation asset transfers.
Revenues
-
Electric
generation
sales revenues increased $423 million in the first six months of 2006
compared to the same period in 2005. This increase primarily resulted from
a
7.2% increase in retail KWH sales, mostly due to the return of customers as
a
result of third-party suppliers leaving the Ohio marketplace, and higher unit
prices resulting from the RSP and RCP that were effective in 2006. The higher
retail sales reduced energy available for sale to the wholesale market.
Increased transmission revenues reflected new revenues of approximately $54
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:
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Electric
Generation Sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
2,524
|
|
$
|
1,969
|
|
$
|
555
|
|
Wholesale
|
|
|
488
|
|
|
620
|
|
|
(132
|
)
|
Total
Electric
Generation Sales
|
|
|
3,012
|
|
|
2,589
|
|
|
423
|
|
Transmission
|
|
|
262
|
|
|
182
|
|
|
80
|
|
Other
|
|
|
23
|
|
|
22
|
|
|
1
|
|
Total
Revenues
|
|
$
|
3,297
|
|
$
|
2,793
|
|
$
|
504
|
|
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 7.2%
increase in customer usage
|
|
$
|
141
|
|
Change
in
prices
|
|
|
414
|
|
|
|
|
555
|
|
Wholesale:
|
|
|
|
|
Effect
of
11.9% decrease in KWH sales
|
|
|
(74
|
)
|
Change
in
prices
|
|
|
(58
|
)
|
|
|
|
(132
|
)
|
Net
Increase
in Electric Generation Sales
|
|
$
|
423
|
|
Expenses
-
Total
operating
expenses increased by $59 million.
The
increase was due to the following factors:
|
·
|
Higher
fuel
and purchased power costs of $162 million, including increased fuel
costs of $73 million - coal costs increased $81 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
$16 million. Purchased power costs increased $89 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
|
|
$
|
37
|
|
Change
due to
volume consumed
|
|
|
36
|
|
|
|
|
73
|
|
Purchased
Power:
|
|
|
|
|
Change
due to
increased unit costs
|
|
|
130
|
|
Change
due to
volume purchased
|
|
|
(31
|
)
|
Increase
in
NUG costs deferred
|
|
|
(10
|
)
|
|
|
|
89
|
|
|
|
|
|
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
$
|
162
|
|
|
·
|
Higher
transmission expenses of $42 million related to the transmission
revenues
discussed above;
|
|
·
|
Increased
depreciation expenses of $79 million, resulting principally from
the
generation asset transfers; and
|
|
·
|
Higher
general
taxes of $17 million due to additional property taxes resulting from
the
generation asset transfers.
|
Partially offsetting these higher costs were lower non-fuel operating expenses
of $112 million, which reflect the absence in 2006 of generating asset
lease rents of $158 million charged in 2005 due to the generation asset
transfers. Also absent in 2006 were: (1) the 2005 accrual of an $8.5 million
civil penalty payable to the DOJ and $10 million for obligations to fund
environmentally beneficial projects in connection with the Sammis Plant
settlement; and (2) a $3.5 million penalty related to the Davis-Besse
outage.
The
$96 million increase in the deferral of new regulatory assets represents
PJM/MISO costs incurred that are expected to be recovered from customers through
future rates. The deferrals also include the Ohio RCP fuel deferral of
$51 million.
Other
Income and
Expense -
|
·
|
Investment
income in the first six months of 2006 was $17 million higher primarily
due to nuclear decommissioning trust investments acquired through
the
generation asset transfers; and
|
|
|
|
|
·
|
Interest
expense increased by $93 million, primarily due to interest on the
associated company notes payable from the generation asset transfers.
This
increase was partially offset by an additional $9 million of
capitalized interest.
|
Other
-
First Six Months of 2006 Compared to First Six 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 $45 million increase to FirstEnergy’s net
income in the first six months of 2006 compared to the same period of 2005.
The
increase was primarily due to the absence of the write-off of income tax
benefits due to the 2005 change in Ohio tax legislation, the financing swap
gain
described in the Other - Second Quarter 2006 Compared to Second Quarter 2005
results analysis above and a $3 million increase in other investment income
in
the first half of 2006. These increases were partially offset by the FSG
impairment charge and gas commodity trading results reduction and the absence
of
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 for the six months ended June 30, 2005:
|
|
(In
millions)
|
|
Discontinued
Operations (Net of tax)
|
|
|
|
Gain
on
sale:
|
|
|
|
Natural
gas
business
|
|
$
|
5
|
|
Elliot-Lewis, Spectrum and Power Piping
|
|
|
12
|
|
Reclassification
of operating income
|
|
|
1
|
|
Total
|
|
$
|
18
|
|
CAPITAL
RESOURCES AND LIQUIDITY
During 2006 and thereafter, FirstEnergy expects to meet its contractual
obligations primarily with a combination of cash from operations and funds
from
the capital markets. Borrowing capacity under credit facilities is available
to
manage working capital requirements.
Changes
in Cash Position
FirstEnergy's
primary source of cash required for continuing operations as a holding company
is cash from the operations of its subsidiaries. FirstEnergy also has access
to
$2.0 billion of short-term financing under a revolving credit facility
which expires in 2010, subject to short-term debt limitations under current
regulatory approvals of $1.5 billion and to outstanding borrowings by
subsidiaries of FirstEnergy that are also parties to such facility. FirstEnergy
paid cash dividends to common shareholders of $148 million in each quarter
of
2006 totaling $296 million for the first six months of 2006. FirstEnergy
received $148 million of cash dividends from its subsidiaries in the first
quarter of 2006 and borrowed against the $2.0 billion revolving credit facility
for the second quarter dividend payment. In July, FirstEnergy received
$500 million from OE as a result of OE’s repurchase of common stock. There
are no material restrictions on the payment of cash dividends by FirstEnergy's
subsidiaries.
As of June 30, 2006, FirstEnergy had $583 million of cash and cash
equivalents compared with $64 million as of December 31, 2005.
Temporary cash investments of $544 million were used principally to redeem
$400 million of the outstanding $1 billion of FirstEnergy’s 5.5% notes
in July 2006, in advance of their November 15, 2006 maturity date. The remainder
was used in July 2006 to redeem $61 million of OE’s preferred stock and
reduce short-term borrowings. The major sources for 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
$551 million and $921 million in the first six months of 2006 and 2005,
respectively, summarized as follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings
*
|
|
$
|
771
|
|
$
|
827
|
|
Working
capital and other
|
|
|
(220
|
)
|
|
94
|
|
Net
cash
provided from operating activities
|
|
$
|
551
|
|
$
|
921
|
|
|
|
|
|
|
|
|
|
*
Cash
earnings are a Non-GAAP measure (see reconciliation
below).
|
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. FirstEnergy believes that cash earnings are a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
525
|
|
$
|
338
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
292
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
|
421
|
|
|
617
|
|
Deferral
of
new regulatory assets
|
|
|
(226
|
)
|
|
(180
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
30
|
|
|
38
|
|
Deferred
purchased power and other costs
|
|
|
(239
|
)
|
|
(210
|
)
|
Deferred
income taxes and investment tax credits
|
|
|
32
|
|
|
62
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(105
|
)
|
|
(101
|
)
|
Accrued
compensation and retirement benefits
|
|
|
33
|
|
|
11
|
|
Income
from
discontinued operations
|
|
|
-
|
|
|
(18
|
)
|
Other
non-cash
expenses
|
|
|
8
|
|
|
(22
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
771
|
|
$
|
827
|
|
Net
cash provided
from operating activities decreased by $370 million in the first six months
of 2006 compared to the first six months of 2005 primarily due to a
$314 million decrease from working capital and a $56 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
$144 million for payables primarily caused by higher fuel and purchased
power costs, and $77 million of cash collateral returned to suppliers.
These decreases were partially offset by an increase in cash provided from
the
settlement of receivables of $218 million, reflecting increased electric sales
revenues.
Cash
Flows From Financing Activities
In
the first six
months of 2006, cash provided from financing activities was $616 million
compared to cash used for financing activities of $468 million in the first
six
months of 2005. The following table summarizes security issuances and
redemptions.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Securities
Issued or Redeemed
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
New
issues
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
253
|
|
$
|
245
|
|
Secured
notes
|
|
|
200
|
|
|
-
|
|
Unsecured
notes
|
|
|
600
|
|
|
-
|
|
|
|
$
|
1,053
|
|
$
|
245
|
|
Redemptions
|
|
|
|
|
|
|
|
First
mortgage
bonds
|
|
$
|
1
|
|
$
|
178
|
|
Pollution
control notes
|
|
|
307
|
|
|
247
|
|
Secured
notes
|
|
|
179
|
|
|
49
|
|
Long-term
revolving credit
|
|
|
-
|
|
|
215
|
|
Preferred
stock
|
|
|
30
|
|
|
140
|
|
|
|
$
|
517
|
|
$
|
829
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
371
|
|
$
|
386
|
|
FirstEnergy
had
approximately $1.1 billion of short-term indebtedness as of June 30,
2006 compared to approximately $731 million as of December 31, 2005.
This increase was due primarily to higher capital expenditures and common
dividend payments compared to Net Cash from Operating Activities during the
first half of the year. Available bank borrowing capability as of June 30,
2006 included the following:
Borrowing
Capability
|
|
|
|
|
|
(In
millions)
|
|
Short-term
credit facilities(1)
|
|
$
|
2,120
|
|
Accounts
receivable financing facilities
|
|
|
550
|
|
Utilized
|
|
|
(1,096
|
)
|
LOCs
|
|
|
(123
|
)
|
Net
|
|
$
|
1,451
|
|
|
|
|
|
|
(1)A
$2 billion revolving credit facility that expires
in 2010 is available in various amounts to FirstEnergy and certain
of its
subsidiaries. A $100 million revolving credit facility that expires
in
December 2006 and a $20 million uncommitted line of credit facility
that
expires in September 2006 are both available to FirstEnergy
only.
|
As of June 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 $735 million and
$576 million, respectively, as of June 30, 2006. Under the provisions
of its senior note indenture, JCP&L may issue additional FMB only as
collateral for senior notes. As of June 30, 2006, JCP&L had the capability
to issue $610 million of additional senior notes upon the basis of FMB
collateral.
Based upon applicable earnings coverage tests in their respective charters,
OE,
Penn, TE and JCP&L could issue a total of $5 billion of preferred stock
(assuming no additional debt was issued) as of June 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 on July 7, 2006, the applicable
earnings coverage test is inoperative for OE. Accordingly, as of July 7, 2006,
Penn, TE and JCP&L could issue a total of $2.6 billion of preferred
stock (assuming no additional debt was issued). 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 June 30, 2006, approximately $1 billion of capacity remained unused
under an existing shelf registration statement, filed by FirstEnergy with the
SEC in 2003, to support future securities issuances. The shelf registration
provides the flexibility to issue and sell various types of securities,
including common stock, debt securities, and share purchase contracts and
related share purchase units. As of June 30, 2006, OE had approximately
$400 million of capacity remaining unused under its existing shelf
registration for unsecured debt securities.
FirstEnergy's
working capital and short-term borrowing needs are met principally with a
$2 billion five-year revolving credit facility (included in the table
above). Borrowings under the facility are available to each borrower separately
and mature on the earlier of 364 days from the date of borrowing or the June
16,
2010 commitment expiration date.
The
following table summarizes the borrowing sub-limits for each borrower under
the
facility, as well as the limitations on short-term indebtedness applicable
to
each borrower under current regulatory approvals and applicable statutory and/or
charter limitations:
|
|
Revolving
|
|
Regulatory
and
|
|
|
|
Credit
Facility
|
|
Other
Short-Term
|
|
Borrower
|
|
Sub-Limit
|
|
Debt
Limitations1
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
$
|
2,000
|
|
$
|
1,500
|
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
44
|
|
CEI
|
|
|
250
|
|
|
500
|
|
TE
|
|
|
250
|
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
412
|
|
Met-Ed
|
|
|
250
|
|
|
300
|
|
Penelec
|
|
|
250
|
|
|
300
|
|
FES
|
|
|
(2)
|
|
|
n/a
|
|
ATSI
|
|
|
(2)
|
|
|
26
|
|
|
(2)
|
Borrowing
sub-limits for FES and ATSI may be increased to up to $250 million
and $100 million, respectively, by delivering notice to the administrative
agent that either (i) such borrower has senior unsecured debt ratings
of
at least BBB- LC b 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 ($249 million unused as
of June 30, 2006) of accounts receivable financing facilities for OE, CEI,
TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet
short-term working capital requirements for FirstEnergy and its
subsidiaries.
Under the revolving credit facility, borrowers may request the issuance of
LOCs
expiring up to one year from the date of issuance. The stated amount of
outstanding LOCs will count against total commitments available under the
facility and against the applicable borrower’s borrowing sub-limit. Total unused
borrowing capability under existing credit facilities and accounts receivable
financing facilities was $1.5 billion as of June 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 June 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
|
|
40
|
%
|
Penn
|
|
34
|
%
|
CEI
|
|
49
|
%
|
TE
|
|
28
|
%
|
JCP&L
|
|
29
|
%
|
Met-Ed
|
|
38
|
%
|
Penelec
|
|
36
|
%
|
The revolving credit facility does not contain provisions that either restrict
the ability to borrow or accelerate repayment of outstanding advances as a
result of any change in credit ratings. Pricing is defined in “pricing grids”,
whereby the cost of funds borrowed under the facility is related to the credit
ratings of the company borrowing the funds.
FirstEnergy's
regulated companies also have the ability to borrow from each other and the
holding company to meet their short-term working capital requirements. A similar
but separate arrangement exists among FirstEnergy's unregulated companies.
FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money
pool
agreements must repay the principal amount of the loan, together with
accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from their respective pool and is based
on the average cost of funds available through the pool. The average interest
rate for borrowings in the first six months of 2006 was approximately 4.86%
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 July 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+
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
(1) Penn's only senior unsecured debt obligations are notes
underlying pollution control revenue refunding bonds issued by the Ohio Air
Quality Development Authority to which bonds this rating
applies.
On
January 20,
2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable
Rate Series B preferred stock at $25.00 per share, plus accrued dividends to
the
date of redemption.
On April 3, 2006, $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 the following Companies' pollution control notes (OE - $14.8
million at 5.45%, Penn - $6.95 million at 5.45%, TE - $34.85 million
at 3.18%, CEI - $47.5 million at 3.22%, $39.8 million at 3.20% and $2.8 million
at 3.15%) in April and May 2006. These refinancings were undertaken in
furtherance of FirstEnergy's intra-system generation asset transfers (see Note
14). The proceeds from NGC's and FGCO's refinancing issuances were used to
repay
a portion of their associated company notes payable to OE, Penn, CEI and TE,
who
then redeemed their respective debt.
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 8, 2006, the NJBPU approved JCP&L's request to issue securitization
bonds associated with BGS stranded cost deferrals. On August 4, 2006, JCP&L
Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing
on the issuance of $182 million of transition bonds with a weighted average
interest rate of 5.5%.
On June 20, 2006, FirstEnergy's Board of Directors authorized a share repurchase
program for up to 12 million shares of common stock. At management’s
discretion shares may be acquired 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
purchase any shares and the program may be terminated at any time. The
12 million shares represent 3.6% of the common stock currently
outstanding.
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. This offering represented an important
part
of FirstEnergy’s 2006 financing strategy to obtain additional financing
flexibility at the holding company level and to capitalize the 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 six
months ended June 30, 2006 and 2005 by segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2006
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(356
|
)
|
$
|
66
|
|
$
|
(9
|
)
|
$
|
(299
|
)
|
Power
supply
management services
|
|
|
(347
|
)
|
|
(24
|
)
|
|
1
|
|
|
(370
|
)
|
Other
|
|
|
(2
|
)
|
|
1
|
|
|
(5
|
)
|
|
(6
|
)
|
Reconciling
items
|
|
|
(20
|
)
|
|
37
|
|
|
10
|
|
|
27
|
|
Total
|
|
$
|
(725
|
)
|
$
|
80
|
|
$
|
(3
|
)
|
$
|
(648
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(299
|
)
|
$
|
9
|
|
$
|
(7
|
)
|
$
|
(297
|
)
|
Power
supply
management services
|
|
|
(147
|
)
|
|
14
|
|
|
(5
|
)
|
|
(138
|
)
|
Other
|
|
|
(5
|
)
|
|
4
|
|
|
(19
|
)
|
|
(20
|
)
|
Reconciling
items
|
|
|
(11
|
)
|
|
10
|
|
|
-
|
|
|
(1
|
)
|
Total
|
|
$
|
(462
|
)
|
$
|
37
|
|
$
|
(31
|
)
|
$
|
(456
|
)
|
Net cash used for investing activities in the first six months of 2006 increased
by $192 million compared to the first six months of 2005. The increase was
principally due to a $263 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 $44 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.
During
the last half of 2006, capital requirements for property additions and capital
leases are expected to be approximately $582 million. FirstEnergy and the
Companies have additional requirements of approximately $1.2 billion for
maturing long-term debt during the remainder of 2006. These cash requirements
are expected to be satisfied from a combination of internal cash, funds raised
in the long-term debt capital markets and short-term credit arrangements.
FirstEnergy's capital spending for the period 2006-2010 is expected to be
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
$745 million, of which approximately $164 million applies to 2006. During
the same period, FirstEnergy's nuclear fuel investments are expected to be
reduced by approximately $564 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 June 30, 2006, FirstEnergy's maximum exposure to potential future
payments under outstanding guarantees and other assurances totaled approximately
$3.5 billion, as summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
Exposure
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees of Subsidiaries:
|
|
|
|
Energy
and
Energy-Related Contracts(1)
|
|
$
|
814
|
|
Other(2)
|
|
|
1,081
|
|
|
|
|
1,895
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
146
|
|
LOC(3)(4)
|
|
|
1,471
|
|
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
$
|
3,512
|
|
|
(1)
|
Issued
for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
Issued
for
various terms.
|
|
(3)
|
Includes
$122
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
Perry by
OE.
|
FirstEnergy guarantees energy and energy-related payments of its subsidiaries
involved in energy commodity activities principally to facilitate normal
physical transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy to fulfill the obligations of
its
subsidiaries directly involved in these energy and energy-related transactions
or financings where the law might otherwise limit the counterparties' claims.
If
demands of a counterparty were to exceed the ability of a subsidiary to satisfy
existing obligations, FirstEnergy's guarantee enables the counterparty's legal
claim to be satisfied by FirstEnergy's other assets. The likelihood that such
parental guarantees will increase amounts otherwise paid by FirstEnergy to
meet
its obligations incurred in connection with ongoing energy and energy-related
contracts is remote.
While
these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or “material adverse event” the immediate posting of cash collateral
or provision of an LOC may be required of the subsidiary. As of June 30,
2006, FirstEnergy's maximum exposure under these collateral provisions was
$501
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 June 30,
2006) which is renewable and declines yearly based upon the senior outstanding
debt of TEBSA.
OFF-BALANCE
SHEET ARRANGEMENTS
FirstEnergy has obligations that are not included on its Consolidated Balance
Sheets related to the sale and leaseback arrangements involving Perry, 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 $1.2 billion
as of June 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 certain power purchase agreements with NUG entities
that were structured pursuant to the Public Utility Regulatory Policies Act
of
1978. These non-trading contracts are adjusted to fair value at the end of
each
quarter, with a corresponding regulatory asset recognized for above-market
costs. On April 1, 2006, FirstEnergy elected to apply the normal purchase and
normal sale exception to certain NUG power purchase agreements with 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 six months
ended June 30, 2006 is summarized in the following table:
|
Three
Months Ended
|
|
Six
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
June
30, 2006
|
|
June
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
|
$
|
(1,129
|
)
|
$
|
(5
|
)
|
$
|
(1,134
|
)
|
$
|
(1,170
|
)
|
$
|
(3
|
)
|
$
|
(1,173
|
)
|
New
contract
value when entered
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
(17
|
)
|
|
(3
|
)
|
|
(20
|
)
|
|
(30
|
)
|
|
(10
|
)
|
|
(40
|
)
|
Change
in
techniques/assumptions
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
78
|
|
|
4
|
|
|
82
|
|
|
132
|
|
|
9
|
|
|
141
|
|
Other
|
|
(13
|
)
|
|
-
|
|
|
(13
|
)
|
|
(13
|
)
|
|
-
|
|
|
(13
|
)
|
Outstanding
net liability at end of period(1)
|
|
(1,081
|
)
|
|
(4
|
)
|
|
(1,085
|
)
|
|
(1,081
|
)
|
|
(4
|
)
|
|
(1,085
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Liabilities at End of Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Rate
Swaps(2)
|
|
-
|
|
|
(25
|
)
|
|
(25
|
)
|
|
-
|
|
|
(25
|
)
|
|
(25
|
)
|
Net
Liabilities - Derivative Contracts
at
End
of Period
|
$
|
(1,081
|
)
|
$
|
(29
|
)
|
$
|
(1,110
|
)
|
$
|
(1,081
|
)
|
$
|
(29
|
)
|
$
|
(1,110
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
(1
|
)
|
$
|
(3
|
)
|
$
|
-
|
|
$
|
(3
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
$
|
-
|
|
$
|
1
|
|
$
|
1
|
|
$
|
-
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
Regulatory
assets (net)
|
$
|
(62
|
)
|
$
|
-
|
|
$
|
(62
|
)
|
$
|
(105
|
)
|
$
|
-
|
|
$
|
(105
|
)
|
(1) Includes
$1,078 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 June 30, 2006 as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Current-
|
|
|
|
|
|
|
|
Other
assets
|
|
$
|
1
|
|
$
|
1
|
|
$
|
2
|
|
Other
liabilities
|
|
|
(6
|
)
|
|
(4
|
)
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
|
47
|
|
|
29
|
|
|
76
|
|
Other
noncurrent liabilities
|
|
|
(1,123
|
)
|
|
(55
|
)
|
|
(1,178
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
liabilities
|
|
$
|
(1,081
|
)
|
$
|
(29
|
)
|
$
|
(1,110
|
)
|
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 June 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)
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(2
|
)
|
Other
external
sources(3)
|
|
|
(144
|
)
|
|
(251
|
)
|
|
(220
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(615
|
)
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(161
|
)
|
|
(138
|
)
|
|
(169
|
)
|
|
(468
|
)
|
Total(4)
|
|
$
|
(145
|
)
|
$
|
(252
|
)
|
$
|
(220
|
)
|
$
|
(161
|
)
|
$
|
(138
|
)
|
$
|
(169
|
)
|
$
|
(1,085
|
)
|
(1) For
the last two
quarters of 2006.
(2) Exchange
traded.
(3) Broker
quote
sheets.
|
(4)
|
Includes
$1,078 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 June 30, 2006. Based on derivative contracts held as of
June 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 six 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
maturity of each respective hedged security as increased interest expense.
As of
June 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 6.68%.
|
|
June
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
|
|
$ |
(4
|
)
|
|
100
|
|
$ |
2008
|
|
$
|
(3
|
)
|
|
|
|
50
|
|
|
2010
|
|
|
(2
|
)
|
|
50
|
|
|
2010
|
|
|
-
|
|
|
|
|
-
|
|
|
2011
|
|
|
-
|
|
|
50
|
|
|
2011
|
|
|
-
|
|
|
|
|
300
|
|
|
2013
|
|
|
(17
|
)
|
|
450
|
|
|
2013
|
|
|
(4
|
)
|
|
|
|
150
|
|
|
2015
|
|
|
(16
|
)
|
|
150
|
|
|
2015
|
|
|
(9
|
)
|
|
|
|
-
|
|
|
2016
|
|
|
-
|
|
|
150
|
|
|
2016
|
|
|
-
|
|
|
|
|
50
|
|
|
2025
|
|
|
(4
|
)
|
|
50
|
|
|
2025
|
|
|
(1
|
)
|
|
|
|
100
|
|
|
2031
|
|
|
(11
|
)
|
|
100
|
|
|
2031
|
|
|
(5
|
)
|
|
|
$
|
750
|
|
|
|
|
$
|
(54
|
)
|
$
|
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 six months of 2006, FirstEnergy revised the tenor and timing of its
financing plans, and in the second quarter 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 respective forward swaps. As of June 30, 2006,
FirstEnergy had outstanding forward swaps with an aggregate notional amount
of
$550 million and an aggregate fair value of $29 million.
|
|
June
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
|
|
$
|
1
|
|
$
|
25
|
|
|
2015
|
|
$
|
-
|
|
|
|
|
300
|
|
|
2016
|
|
|
14
|
|
|
600
|
|
|
2016
|
|
|
2
|
|
|
|
|
50
|
|
|
2017
|
|
|
3
|
|
|
25
|
|
|
2017
|
|
|
-
|
|
|
|
|
125
|
|
|
2018
|
|
|
8
|
|
|
275
|
|
|
2018
|
|
|
1
|
|
|
|
|
50
|
|
|
2020
|
|
|
3
|
|
|
50
|
|
|
2020
|
|
|
-
|
|
|
|
$
|
550
|
|
|
|
|
$
|
29
|
|
$
|
975
|
|
|
|
|
$
|
3
|
|
Equity
Price Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their market
value of approximately $1.1
billion as of June
30, 2006 and December 31, 2005. A hypothetical 10% decrease in prices
quoted by stock exchanges would result in a $111 million
reduction in fair value as of June 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 June 30, 2006, the largest
credit concentration with one party (currently rated investment grade)
represented 8.1% of FirstEnergy's total credit risk. Within FirstEnergy's
unregulated energy subsidiaries, 99% of credit exposures, net of collateral
and
reserves, were with investment-grade counterparties as of June 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 $237 million as of June 30, 2006. The following table
discloses the regulatory assets by company and by source:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
756
|
|
$
|
775
|
|
$
|
(19
|
)
|
CEI
|
|
|
859
|
|
|
862
|
|
|
(3
|
)
|
TE
|
|
|
267
|
|
|
287
|
|
|
(20
|
)
|
JCP&L
|
|
|
2,122
|
|
|
2,227
|
|
|
(105
|
)
|
Met-Ed
|
|
|
359
|
|
|
310
|
|
|
49
|
|
ATSI
|
|
|
33
|
|
|
25
|
|
|
8
|
|
Total
|
|
$
|
4,396
|
|
$
|
4,486
|
|
$
|
(90
|
)
|
|
*
|
Penn
had net
regulatory liabilities of approximately $59 million as of June 30,
2006 and December 31, 2005. Penelec had net regulatory liabilities of
approximately $135 million and $163 million as of June 30,
2006 and December 31, 2005, respectively. These net regulatory liabilities
are included in Other Noncurrent Liabilities on the Consolidated
Balance
Sheets.
|
Regulatory assets by source are as follows:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2006
|
|
2005
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
3,365
|
|
$
|
3,576
|
|
$
|
(211
|
)
|
Customer
shopping incentives
|
|
|
644
|
|
|
884
|
|
|
(240
|
)
|
Customer
receivables for future income taxes
|
|
|
219
|
|
|
217
|
|
|
2
|
|
Societal
benefits charge
|
|
|
19
|
|
|
29
|
|
|
(10
|
)
|
Loss
on
reacquired debt
|
|
|
40
|
|
|
41
|
|
|
(1
|
)
|
Employee
postretirement benefits costs
|
|
|
51
|
|
|
55
|
|
|
(4
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and
spent fuel
disposal costs
|
|
|
(124
|
)
|
|
(126
|
)
|
|
2
|
|
Asset
removal
costs
|
|
|
(163
|
)
|
|
(365
|
)
|
|
202
|
|
Property
losses and unrecovered plant costs
|
|
|
24
|
|
|
29
|
|
|
(5
|
)
|
MISO/PJM
transmission costs
|
|
|
135
|
|
|
91
|
|
|
44
|
|
Fuel
costs -
RCP
|
|
|
51
|
|
|
-
|
|
|
51
|
|
Distribution
costs - RCP
|
|
|
81
|
|
|
-
|
|
|
81
|
|
JCP&L
reliability costs
|
|
|
19
|
|
|
23
|
|
|
(4
|
)
|
Other
|
|
|
35
|
|
|
32
|
|
|
3
|
|
Total
|
|
$
|
4,396
|
|
$
|
4,486
|
|
$
|
(90
|
)
|
Reliability
Initiatives
FirstEnergy is proceeding with the implementation of the recommendations that
were issued from various entities, including governmental, industry and ad
hoc
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 review. On February 3,
2006, the FERC adopted a rule establishing certification requirements for the
ERO, as well as regional entities envisioned to assume monitoring responsibility
for the new reliability standards. The FERC issued an order on rehearing on
March 30, 2006, providing certain clarifications and essentially affirming
the rule.
The NERC has been preparing the implementation aspects of reorganizing its
structure to meet the FERC’s certification requirements for the ERO. The NERC
made a filing with the FERC on April 4, 2006 to obtain certification as the
ERO and to obtain FERC approval of delegation agreements with regional entities.
The new FERC rule referred to above, further provides for reorganizing regional
reliability organizations (regional entities) that would replace the current
regional councils and for rearranging the relationship with the ERO. The
“regional entity” may be delegated authority by the ERO, subject to FERC
approval, for enforcing reliability standards adopted by the ERO and approved
by
the FERC. 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 NERC as the ERO to implement the provisions of Section 215 of the
Federal Power Act. The FERC directed NERC to make a compliance filing within
ninety days addressing such issues as the regional delegation
agreements.
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, on the current NERC Version O reliability standards with
some additional 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 chairman has indicated that the FERC intends
to
act on the proposed reliability standards by issuing a NOPR in September of
this
year. Interested parties will be given the opportunity to comment on the NOPR.
NERC has requested an effective date of January 1, 2007 for the proposed
reliability standards.
The
ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network
reliability councils have completed the consolidation of these regions into
a
single new regional reliability organization known as ReliabilityFirst
Corporation. ReliabilityFirst began operations as a regional reliability
council
under NERC on January 1, 2006 and intends to file and obtain certification
consistent with the final rule as a “regional entity” under the ERO during 2006.
All of FirstEnergy’s facilities are located within the ReliabilityFirst
region.
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.
FirstEnergy
believes
that it is in compliance with all current NERC reliability standards. However,
it is expected that the FERC will adopt stricter reliability standards than
those contained in the current NERC standards. The financial impact of complying
with the new standards cannot be determined at this time. However, EPACT
requires that all prudent costs incurred to comply with the new reliability
standards be recovered in rates. If FirstEnergy is unable to meet the
reliability standards for the bulk power system in the future, it could have
a
material adverse effect on the Company’s and its subsidiaries’ financial
condition, results of operations and cash flows.
See
Note 11 to the consolidated financial statements for a more detailed
discussion of reliability initiatives.
Ohio
On
October 21, 2003
the Ohio Companies filed 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 September 28, 2005, the Supreme Court of Ohio heard oral arguments
on the appeals. 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 one matter back to the PUCO
for further consideration of the issue as to whether the RSP, as adopted by
the
PUCO, provided for sufficient means for customer participation in the
competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
for
Reconsideration with the Supreme Court of Ohio which was denied by the Court
on
June 21, 2006. 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.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP. 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
|
|
$
|
177
|
|
$
|
95
|
|
$
|
86
|
|
$
|
358
|
|
2007
|
|
|
180
|
|
|
113
|
|
|
90
|
|
|
383
|
|
2008
|
|
|
208
|
|
|
130
|
|
|
111
|
|
|
449
|
|
2009
|
|
|
-
|
|
|
211
|
|
|
-
|
|
|
211
|
|
2010
|
|
|
-
|
|
|
266
|
|
|
-
|
|
|
266
|
|
Total
Amortization
|
|
$
|
565
|
|
$
|
815
|
|
$
|
287
|
|
$
|
1,667
|
|
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 are due on August 4, 2006.
Appellants’ Reply Briefs will then be due on August 24, 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 May 1,
2006, the Ohio Companies filed a modification to the rider to determine revenues
($141 million) from July 2006 through June 2007.
The second application sought authority to defer costs associated with
transmission and ancillary service related costs incurred during the period
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
unable to predict when a decision may be issued.
See
Note 11 to the consolidated financial statements for further details and a
complete discussion of regulatory matters in Ohio.
Pennsylvania
As of June 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 $335 million and
$57 million, respectively. Penelec's $57 million is subject to the
pending resolution of taxable income issues associated with NUG trust fund
proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s
NUG purchase power stranded cost accounting methodology. If the PPUC orders
Met-Ed and Penelec to reverse the change in accounting methodology, this would
result in a pre-tax loss of $10.3 million for Met-Ed.
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 below. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Met-Ed and Penelec have deferred
approximately $46 million and $12 million, respectively, representing
transmission costs that were incurred from January 1, 2006 through June 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 below.
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.
The
wholesale power
sales agreement, as modified by the Tolling Agreement, requires Met-Ed and
Penelec to satisfy the portion of their PLR obligations currently supplied
by
FES from unaffiliated suppliers at prevailing prices, which are likely to be
higher than the current price charged by FES under the current agreement and,
as
a result, Met-Ed’s and Penelec’s purchased power costs could materially
increase. If Met-Ed and Penelec were to replace the entire FES supply at current
market power prices without corresponding regulatory authorization to increase
their generation prices to customers, each company would likely incur a
significant increase in operating expenses and experience a material
deterioration in credit quality metrics. Under such a scenario, each company's
credit profile would no longer be expected to support an investment grade rating
for its fixed income securities. There can be no assurance, however, that if
FES
ultimately determines to terminate, or significantly modify the agreement,
timely regulatory relief will be granted by the PPUC pursuant to the
April 10, 2006 comprehensive rate filing discussed below, or, to the extent
granted, adequate to mitigate such adverse consequences.
Met-Ed
and Penelec
made a comprehensive rate filing with the PPUC on April 10, 2006 that
addresses a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals is approved,
the
filing would increase annual revenues by $216 million and
$157 million, respectively. That filing includes, among other things, a
request to charge customers for an increasing amount of market priced power
procured through a 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 the 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 are scheduled for late August
2006 and a PPUC decision is expected early in the first quarter of
2007.
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. To the extent that an
affiliate of Penn supplies a portion of the PLR load included in the RFP,
authorization to make the affiliate sale must be obtained from the FERC.
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 to
obtain Penn's power supply requirements after 2006 through two separate
solicitations. An initial solicitation was held for Penn in May 2006 with all
tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
for the first solicitation. 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 only acquired for three of the five
tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
the
submissions for the second bid. A residual solicitation is scheduled to be
held
on August 15, 2006 for the two remaining Large Commercial Group tranches.
Acceptance of the winning bids is subject to approval by the PPUC.
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 its recovery of certain PLR costs via a
reconciliation mechanism and its 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 June 30, 2006, the accumulated deferred cost
balance totaled approximately $638 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 4, 2006, JCP&L Transition Funding II, a
wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182
million of transition bonds with a weighted average interest rate of
5.5%.
On
December 2,
2005, JCP&L filed a request for recovery of $165 million of actual
above-market NUG costs incurred from August 1, 2003 through
October 31, 2005 and forecasted above-market NUG costs for November and
December 2005. On February 23, 2006, JCP&L filed updated data reflecting
actual amounts through December 31, 2005 of $154 million of cost
incurred since July 31, 2003. On March 29, 2006, a pre-hearing conference
was held with the presiding ALJ. A schedule for the proceeding was established
including a discovery period and evidentiary hearings scheduled for September
2006.
An
NJBPU Decision
and Order approving a Phase II Stipulation of Settlement and resolving the
Motion for Reconsideration of the Phase I Order was issued on May 31, 2005.
The
Phase II Settlement includes a performance standard pilot program with potential
penalties of up to 0.25% of allowable equity return. The Order requires that
JCP&L file quarterly reliability reports (CAIDI and SAIFI information
related to the performance pilot program) through December 2006 and updates
to
reliability related project expenditures until all projects are completed.
The
last of the quarterly reliability reports was submitted on June 12, 2006. As
of
June 30, 2006, there were no performance penalties issued by the
NJBPU.
On
August 1,
2005, the NJBPU established a proceeding to determine whether additional
ratepayer protections are required at the state level in light of the 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. The NJBPU Staff issued a draft proposal on March 31, 2006
addressing various issues including access to books and records, ring-fencing,
cross subsidization, corporate governance and related matters. 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. JCP&L is unable to predict the outcome of this
proposal.
See
Note 11 to
the consolidated financial statements for further details and a complete
discussion of regulatory matters in New Jersey.
FERC
Matters
On
November 18,
2004, the FERC issued an order eliminating the 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 FERC has
ordered the Presiding Judge to issue an initial decision by August 11,
2006.
On November 1, 2004, ATSI filed with FERC a request to defer approximately
$54 million of costs to be incurred from 2004 through 2007 in connection
with ATSI’s 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 $33 million
deferred as of June 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 21, 2006, the FERC issued an order stating that
it
needs more time to consider the matter. In light of that order, there is no
time
period by which the FERC must act on the pending rehearing request. On July
14,
2006, the FERC accepted the ATSI’s June 13, 2006 compliance filing. The
estimated annual revenues to ATSI from the VMEP cost recovery is
$12 million.
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 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. The Companies, as
part of the Responsible Pricing Alliance, intend to submit a brief on exceptions
within thirty days of the initial decision. Following submission of reply
exceptions, the case is expected to 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. The PPUC approved Penn's plan with modifications
on April 20, 2006 to use an RFP process to obtain its power supply requirements
after 2006 through two separate solicitations. An initial solicitation was
held
for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006, the
PPUC approved the bid results for the first solicitation. 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
only
acquired for three of the five tranches for the Large Commercial Group. On
July
20, 2006, the PPUC approved the submission for the second bid. A residual
solicitation is scheduled to be held on August 15, 2006 for the two remaining
Large Commercial Group tranches. Acceptance of the winning bids is subject
to
approval by the PPUC.
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, aproved 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. The procedural schedule has been suspended
pending negotiations among the parties.
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
regulations.
Violations of such regulations can result in shutdown of the generating unit
involved and/or civil or criminal penalties of up to $32,500 for each day the
unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio
that allows for compliance based on a 30-day averaging period. FirstEnergy
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.
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
has been scheduled for August 8, 2006 to discuss the alleged violations with
the
EPA.
FirstEnergy
believes
it is complying with SO2
reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX
reductions required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX
reductions from
FirstEnergy's facilities. The EPA's NOX
Transport Rule
imposes uniform reductions of NOX
emissions (an
approximate 85% reduction in utility plant NOX
emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX
emissions are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX
budgets established
under State Implementation Plans through combustion controls and post-combustion
controls, including Selective Catalytic Reduction and Selective Non-Catalytic
Reduction systems, and/or using emission allowances.
National
Ambient
Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and 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 the Companies operate affected facilities.
Mercury
Emissions
In
December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as
the
hazardous air pollutant of greatest concern. 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 this approach is based on output,
new and non-emitting generating facilities, including renewables and nuclear,
would be entitled to their proportionate share of the allowances. Consequently,
FirstEnergy would be disadvantaged if these model rules were implemented because
FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation
is not recognized under the input-based allocation.
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 (the primary portion of which is expected to be spent in the
2008 to 2011 time period). On August 26, 2005, FGCO entered into an
agreement with Bechtel Power Corporation under which Bechtel will engineer,
procure, and construct air quality control systems for the reduction of sulfur
dioxide emissions. The settlement agreement also requires OE and Penn to spend
up to $25 million toward environmentally beneficial projects, which include
wind energy purchased power agreements over a 20-year term. OE and Penn agreed
to pay a civil penalty of $8.5 million. Results for the first quarter of
2005 included the penalties paid by OE and Penn of $7.8 million and
$0.7 million, respectively. OE and Penn also recognized liabilities in the
first quarter of 2005 of $9.2 million and $0.8 million, respectively,
for probable future cash contributions toward environmentally beneficial
projects.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and
2012. The United States signed the Kyoto Protocol in 1998 but it failed to
receive the two-thirds vote of the United States Senate required for
ratification. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity - the
ratio of emissions to economic output - by 18% through 2012. The EPACT
established a Committee on Climate Change Technology to coordinate federal
climate change activities and promote the development and deployment of GHG
reducing technologies.
FirstEnergy
cannot
currently estimate the financial impact of climate change policies, although
the
potential restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per
kilowatt-hour of electricity generated by the Companies is lower than many
regional competitors due to the Companies' diversified generation sources which
include low or non-CO2
emitting gas-fired
and nuclear generators.
Regulation
of
Hazardous Waste
The
Companies have
been named as PRPs at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of June
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 $70 million have been accrued through June 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 the 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 outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class action
complaints. 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. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
is currently expected that this case will be summarily dismissed, although
the
Motion is still pending. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of the
Ohio operating companies; dismissed FirstEnergy 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. These motions are pending. Additionally, on June 23, 2006, one of the
insurance carrier complainants filed an appeal with the Ohio Supreme Court
over
the PUCO’s denial of their motion for rehearing on the issue of the
admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
as
a respondent. Briefing is expected to be completed on this appeal by
mid-September. It is unknown when the Supreme Court will rule on the appeal.
No
estimate of potential liability is available for any of these cases.
In
addition to the
above proceedings, FirstEnergy was named in a complaint filed in Michigan State
Court by an individual who is not a customer of any FirstEnergy company.
FirstEnergy's motion to dismiss the matter was denied on June 2, 2006.
FirstEnergy has since filed an appeal, which is pending. A responsive pleading
to this matter has been filed. Also, the complaint has been amended to include
an additional party. No estimate of potential liability has been undertaken
in
this matter.
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 First Energy's earnings by $0.09 per common share in the fourth quarter
of 2005.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty
related to the degradation of the Davis-Besse reactor vessel head issue
discussed above. FirstEnergy accrued $2 million for a potential fine prior
to 2005 and accrued the remaining liability for the proposed fine during the
first quarter of 2005. On September 14, 2005, FENOC filed its response to
the NOV with the NRC. FENOC accepted full responsibility for the past failure
to
properly implement its boric acid corrosion control and corrective action
programs. The NRC NOV indicated that the violations do not represent current
licensee performance. FirstEnergy paid the penalty in the third quarter of
2005.
On January 23, 2006, FENOC supplemented its response to the NRC's NOV on
the Davis-Besse head degradation to reflect the deferred prosecution agreement
that FENOC had reached with the DOJ.
On
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take prompt
and corrective action. FENOC operates the Perry Nuclear Power Plant.
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the
NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Plant and stated that
the
CAL would remain open until substantial improvement was demonstrated. The CAL
was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's
2005 annual assessment letter dated March 2, 2006 and associated meetings
to discuss the performance of Perry on March 14, 2006, the NRC again stated
that the Perry Plant continued to operate in a manner that "preserved public
health and safety." However, the NRC also stated that increased levels of
regulatory oversight would continue until sustained improvement in the
performance of the facility was realized. If performance does not improve,
the
NRC has a range of options under the Reactor Oversight Process, from increased
oversight to possible impact to the plant’s operating authority. Although
FirstEnergy is unable to predict the impact of the ultimate disposition of
this
matter, it could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
As
of
December 16, 2005, NGC acquired ownership of the nuclear generation assets
transferred from OE, CEI, TE and Penn with the exception of leasehold interests
of OE and TE in certain of the nuclear plants that are subject to sale and
leaseback arrangements with non-affiliates.
Other
Legal
Matters
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy’s normal business operations pending against FirstEnergy
and its subsidiaries. The other material items not otherwise discussed above
are
described below.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have
become the subject of a formal order of investigation. The SEC's formal order
of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under 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.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16 million to the bargaining unit employees. On February 6, 2006, the
federal court granted a Union motion to dismiss JCP&L's appeal of the award
as premature. JCP&L will file its appeal again in federal district court
once the damages associated with this case are identified at an individual
employee level. JCP&L recognized a liability for the potential
$16 million award in 2005.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of a
newly-formed municipal electric utility. The complaint was filed on May 28,
2003, and OE timely filed its response on June 30, 2003. In a related
filing, the Ohio Companies filed for approval with the PUCO of a tariff that
would specifically allow the collection of transition charges from customers
of
municipal electric utilities formed after 1998. Both filings were consolidated
for hearing and decision described above. 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 60 days from the denial of rehearing to appeal the PUCO’s
decision.
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
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.
SUBSEQUENT
EVENTS
Pennsylvania
Law Change
On
July 12, 2006,
the Governor of Pennsylvania signed House Bill 859, which increases the net
operating loss deduction allowed for the corporate net income tax from
$2 million to $3 million, or the greater of 12.5% of taxable income.
As a result, FirstEnergy expects to recognize a net operating loss benefit
of
$2.2 million (net of federal tax benefit) in the third quarter of
2006.
New
Jersey
Law Change
On
July 8, 2006, the
Governor of New Jersey signed tax legislation that increased the current New
Jersey Corporate Business tax by an additional 4% surtax, which increases the
effective tax from 9% to 9.36%. This increase applies to JCP&L’s 2006
through 2008 tax years and is not expected to have a material impact on
FirstEnergy’s or JCP&L’s results of operations.
OHIO
EDISON COMPANY
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
573,092
|
|
$
|
716,612
|
|
$
|
1,159,295
|
|
$
|
1,442,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,821
|
|
|
12,006
|
|
|
5,772
|
|
|
23,922
|
|
Purchased
power
|
|
|
293,033
|
|
|
227,507
|
|
|
576,053
|
|
|
474,097
|
|
Nuclear
operating costs
|
|
|
43,506
|
|
|
92,607
|
|
|
84,590
|
|
|
188,260
|
|
Other
operating costs
|
|
|
91,604
|
|
|
95,589
|
|
|
182,414
|
|
|
178,768
|
|
Provision
for
depreciation
|
|
|
17,547
|
|
|
31,654
|
|
|
35,563
|
|
|
57,706
|
|
Amortization
of regulatory assets
|
|
|
43,444
|
|
|
109,670
|
|
|
97,305
|
|
|
221,441
|
|
Deferral
of
new regulatory assets
|
|
|
(42,083
|
)
|
|
(39,026
|
)
|
|
(78,323
|
)
|
|
(63,821
|
)
|
General
taxes
|
|
|
43,931
|
|
|
46,043
|
|
|
89,826
|
|
|
94,121
|
|
Total
expenses
|
|
|
493,803
|
|
|
576,050
|
|
|
993,200
|
|
|
1,174,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
79,289
|
|
|
140,562
|
|
|
166,095
|
|
|
268,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
32,818
|
|
|
22,482
|
|
|
65,860
|
|
|
43,089
|
|
Miscellaneous
expense
|
|
|
(1,001
|
)
|
|
(2,161
|
)
|
|
(804
|
)
|
|
(23,897
|
)
|
Interest
expense
|
|
|
(17,366
|
)
|
|
(21,402
|
)
|
|
(35,598
|
)
|
|
(39,605
|
)
|
Capitalized
interest
|
|
|
643
|
|
|
3,006
|
|
|
1,134
|
|
|
5,241
|
|
Subsidiary's
preferred stock dividend requirements
|
|
|
(155
|
)
|
|
(738
|
)
|
|
(311
|
)
|
|
(1,378
|
)
|
Total
other
income (expense)
|
|
|
14,939
|
|
|
1,187
|
|
|
30,281
|
|
|
(16,550
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
35,019
|
|
|
94,653
|
|
|
73,337
|
|
|
148,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
59,209
|
|
|
47,096
|
|
|
123,039
|
|
|
103,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS AND
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REDEMPTION
PREMIUM
|
|
|
3,587
|
|
|
658
|
|
|
4,246
|
|
|
1,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
55,622
|
|
$
|
46,438
|
|
$
|
118,793
|
|
$
|
102,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
59,209
|
|
$
|
47,096
|
|
$
|
123,039
|
|
$
|
103,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
(4,063
|
)
|
|
(12,960
|
)
|
|
1,672
|
|
|
(15,677
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(1,466
|
)
|
|
(4,546
|
)
|
|
603
|
|
|
(5,670
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
(2,597
|
)
|
|
(8,414
|
)
|
|
1,069
|
|
|
(10,007
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
56,612
|
|
$
|
38,682
|
|
$
|
124,108
|
|
$
|
93,846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
545,292
|
|
|
|
$
|
929
|
|
Receivables-
|
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,627,000 and $7,619,000,
respectively,
|
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
250,079
|
|
|
|
|
290,887
|
|
Associated
companies
|
|
|
165,501
|
|
|
|
|
187,072
|
|
Other
(less
accumulated provisions of $52,000 and $4,000,
respectively,
|
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
11,491
|
|
|
|
|
15,327
|
|
Notes
receivable from associated companies
|
|
|
506,337
|
|
|
|
|
536,629
|
|
Prepayments
and other
|
|
|
22,794
|
|
|
|
|
93,129
|
|
|
|
|
1,501,494
|
|
|
|
|
1,123,973
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,558,212
|
|
|
|
|
2,526,851
|
|
Less
-
Accumulated provision for depreciation
|
|
|
996,261
|
|
|
|
|
984,463
|
|
|
|
|
1,561,951
|
|
|
|
|
1,542,388
|
|
Construction
work in progress
|
|
|
63,277
|
|
|
|
|
58,785
|
|
|
|
|
1,625,228
|
|
|
|
|
1,601,173
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
1,676,228
|
|
|
|
|
1,758,776
|
|
Investment
in
lease obligation bonds
|
|
|
310,285
|
|
|
|
|
325,729
|
|
Nuclear
plant
decommissioning trusts
|
|
|
106,360
|
|
|
|
|
103,854
|
|
Other
|
|
|
40,968
|
|
|
|
|
44,210
|
|
|
|
|
2,133,841
|
|
|
|
|
2,232,569
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
756,481
|
|
|
|
|
774,983
|
|
Prepaid
pension costs
|
|
|
227,815
|
|
|
|
|
224,813
|
|
Property
taxes
|
|
|
52,897
|
|
|
|
|
52,875
|
|
Unamortized
sale and leaseback costs
|
|
|
52,637
|
|
|
|
|
55,139
|
|
Other
|
|
|
26,988
|
|
|
|
|
31,752
|
|
|
|
|
1,116,818
|
|
|
|
|
1,139,562
|
|
|
|
$
|
6,377,381
|
|
|
|
$
|
6,097,277
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
225,625
|
|
|
|
$
|
280,255
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
2,161
|
|
|
|
|
57,715
|
|
Other
|
|
|
22,431
|
|
|
|
|
143,585
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
123,912
|
|
|
|
|
172,511
|
|
Other
|
|
|
12,312
|
|
|
|
|
9,607
|
|
Accrued
taxes
|
|
|
173,248
|
|
|
|
|
163,870
|
|
Accrued
interest
|
|
|
7,150
|
|
|
|
|
8,333
|
|
Other
|
|
|
64,098
|
|
|
|
|
61,726
|
|
|
|
|
630,937
|
|
|
|
|
897,602
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares - 100 shares
outstanding
|
|
|
2,296,525
|
|
|
|
|
2,297,253
|
|
Accumulated
other comprehensive income
|
|
|
5,163
|
|
|
|
|
4,094
|
|
Retained
earnings
|
|
|
285,434
|
|
|
|
|
200,844
|
|
Total
common
stockholder's equity
|
|
|
2,587,122
|
|
|
|
|
2,502,191
|
|
Preferred
stock not subject to mandatory redemption
|
|
|
60,965
|
|
|
|
|
60,965
|
|
Preferred
stock of consolidated subsidiary not subject to mandatory
redemption
|
|
|
14,105
|
|
|
|
|
14,105
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,521,863
|
|
|
|
|
1,019,642
|
|
|
|
|
4,184,055
|
|
|
|
|
3,596,903
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
747,568
|
|
|
|
|
769,031
|
|
Accumulated
deferred investment tax credits
|
|
|
22,307
|
|
|
|
|
24,081
|
|
Asset
retirement obligation
|
|
|
85,578
|
|
|
|
|
82,527
|
|
Retirement
benefits
|
|
|
294,755
|
|
|
|
|
291,051
|
|
Deferred
revenues - electric service programs
|
|
|
104,855
|
|
|
|
|
121,693
|
|
Other
|
|
|
307,326
|
|
|
|
|
314,389
|
|
|
|
|
1,562,389
|
|
|
|
|
1,602,772
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,377,381
|
|
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
123,039
|
|
$
|
103,853
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
35,563
|
|
|
57,706
|
|
Amortization
of regulatory assets
|
|
|
97,305
|
|
|
221,441
|
|
Deferral
of
new regulatory assets
|
|
|
(78,323
|
)
|
|
(63,821
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
(11,337
|
)
|
|
18,663
|
|
Amortization
of lease costs
|
|
|
(4,334
|
)
|
|
(2,952
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(17,351
|
)
|
|
(5,142
|
)
|
Accrued
compensation and retirement benefits
|
|
|
930
|
|
|
3,504
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
66,215
|
|
|
77,745
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(18,149
|
)
|
Prepayments
and other current assets
|
|
|
70,335
|
|
|
(7,220
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(45,894
|
)
|
|
(85,227
|
)
|
Accrued
taxes
|
|
|
9,378
|
|
|
19,078
|
|
Accrued
interest
|
|
|
(1,183
|
)
|
|
(791
|
)
|
Electric
service prepayment programs
|
|
|
(16,838
|
)
|
|
132,151
|
|
Other
|
|
|
(8,772
|
)
|
|
12,876
|
|
Net
cash
provided from operating activities
|
|
|
218,733
|
|
|
463,715
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
599,778
|
|
|
146,450
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
47,442
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
(37,750
|
)
|
Long-term
debt
|
|
|
(146,893
|
)
|
|
(260,508
|
)
|
Short-term
borrowings, net
|
|
|
(176,708
|
)
|
|
-
|
|
Dividend
Payments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(35,000
|
)
|
|
(177,000
|
)
|
Preferred
stock
|
|
|
(1,317
|
)
|
|
(1,317
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
239,860
|
|
|
(282,683
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(49,659
|
)
|
|
(121,458
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
30,269
|
|
|
122,374
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(30,961
|
)
|
|
(138,144
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
112,840
|
|
|
(58,540
|
)
|
Other
|
|
|
23,281
|
|
|
14,789
|
|
Net
cash
provided from (used for) investing activities
|
|
|
85,770
|
|
|
(180,979
|
)
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
544,363
|
|
|
53
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
929
|
|
|
1,230
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
545,292
|
|
$
|
1,283
|
|
|
|
|
|
|
|
|
|
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 June 30, 2006, and the related consolidated statements
of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2006 and 2005 and the consolidated statement of cash
flows for the six-month period ended June 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
August
4,
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 will continue to provide
OE’s
PLR requirements under revised purchased power arrangements for the three-year
period beginning January 1, 2006 and Penn’s during 2006 (see Outlook
-
Regulatory
Matters).
The effects on the OE Companies' results of operations in the second quarter
and
first six months of 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
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
|
(a
|
)
|
$
|
(44
|
)
|
$
|
(89
|
)
|
Nuclear
generated KWH sales
|
|
(b
|
)
|
|
(67
|
)
|
|
(131
|
)
|
Total
-
Revenues Effect
|
|
|
|
|
(111
|
)
|
|
(220
|
)
|
Expenses:
|
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
|
(c
|
)
|
|
(9
|
)
|
|
(18
|
)
|
Nuclear
operating costs
|
|
(c
|
)
|
|
(43
|
)
|
|
(89
|
)
|
Provision
for
depreciation
|
|
(d
|
)
|
|
(17
|
)
|
|
(28
|
)
|
General
taxes
|
|
(e
|
)
|
|
(3
|
)
|
|
(6
|
)
|
Total
-
Expenses Effect
|
|
|
|
|
(72
|
)
|
|
(141
|
)
|
Operating
Income Effect
|
|
|
|
|
(39
|
)
|
|
(79
|
)
|
Other
Income:
|
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
|
(f
|
)
|
|
14
|
|
|
30
|
|
Nuclear
decommissioning trust earnings
|
|
(g
|
)
|
|
(4
|
)
|
|
(6
|
)
|
Capitalized
Interest
|
|
(h
|
)
|
|
(2
|
)
|
|
(4
|
)
|
Total
- Other
Income Effect
|
|
|
|
|
8.
|
|
|
20.
|
|
Income
taxes
|
|
(i
|
)
|
|
(13
|
)
|
|
(24
|
)
|
Net
Income
Effect
|
|
|
|
$
|
(18
|
)
|
$
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
(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 second quarter of 2006 increased to $56 million from
$46 million in the second quarter of 2005. In the first six months of 2006,
earnings on common stock increased to $119 million from $103 million in the
same
period of 2005. The increase in earnings in both periods of 2006 primarily
resulted from lower expenses and increased other income, partially offset
by
lower revenues principally from the asset transfer effects shown in the table
above. Earnings in both periods of 2005 were also reduced by a one-time income
tax charge of $36 million from the enactment of tax legislation in Ohio.
Earnings in the first six months of 2005 was additionally reduced by charges
relating to a $8.5 million civil penalty payable to the Department of Justice
and $10 million for environmental projects in connection with the Sammis
Plant
settlement (see Outlook — Environmental Matters).
Revenues
Revenues
decreased
by $144 million or 20.0% in the second 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
second quarter of 2006 decreased $33 million, primarily due to decreases
of
$70 million and $112 million in wholesale sales and distribution
revenues, respectively, partially offset by increases in retail generation
revenues of $125 million and reduced customer shopping incentives of
$21 million.
In
the first six
months of 2006 compared with the same period in 2005, revenues decreased
by $284
million or 19.7%, primarily from the generation asset transfer impact summarized
in the table above. Excluding the effects of the asset transfer, revenues
in the
first six months of 2006 decreased $64 million, primarily due to decreases
of
$130 million and $210 million in wholesale sales and distribution revenues,
respectively, partially offset by increases in retail generation revenues
of
$232 million and reduced customer shopping incentives of $38
million.
The
lower wholesale
revenues in both periods of 2006 reflect the termination of a non-affiliated
wholesale sales agreement and the cessation of the MSG sales arrangements
under
OE’s transition plan in December 2005. OE had been required to provide the MSG
to non-affiliated alternative suppliers.
Changes
in electric
generation KWH sales and revenues
in the
second quarter and first six months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
13.8
|
%
|
|
12.5
|
%
|
Wholesale
|
|
|
(84.2)
|
%
|
|
(82.8)
|
%
|
Net
Decrease in Generation Sales
|
|
|
(31.4)
|
%
|
|
(29.7)
|
%
|
Changes
in Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Retail
Generation:
|
|
|
|
|
|
|
|
Residential
|
|
$
|
41
|
|
$
|
84
|
|
Commercial
|
|
|
38
|
|
|
70
|
|
Industrial
|
|
|
46
|
|
|
78
|
|
Total
Retail
Generation
|
|
|
125
|
|
|
232
|
|
Wholesale*
|
|
|
(70
|
)
|
|
(130
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
55
|
|
$
|
102
|
|
|
|
|
|
|
|
|
|
*
Excludes
impact of generation asset transfers related to nuclear generated
KWH
sales.
|
|
Increased
retail generation
revenues for the second 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 - 10.4 percentage points;
commercial - 12.5 percentage points; and industrial - 11.2 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 six 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 - 9.5 percentage points;
commercial - 11.8 percentage points; and industrial - 10.2 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
second quarter and first six months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Distribution KWH Deliveries
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
(6.3)
|
%
|
|
(3.8)
|
%
|
Commercial
|
(2.2)
|
%
|
|
(1.6)
|
%
|
Industrial
|
2.7
|
%
|
|
0.5
|
%
|
Net
Decrease in Distribution Deliveries
|
(1.7)
|
%
|
|
(1.6)
|
%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Residential
|
|
$
|
(48
|
)
|
$
|
(88
|
)
|
Commercial
|
|
|
(34
|
)
|
|
(65
|
)
|
Industrial
|
|
|
(30
|
)
|
|
(57
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(112
|
)
|
$
|
(210
|
)
|
Lower
distribution
throughput revenues as shown in the table above in the second quarter and
first
six months of 2006 reflects lower composite prices and reduced KWH deliveries.
The lower unit prices in both periods were due to 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 distribution KWH deliveries to residential and commercial
customers reflected the impact of milder weather conditions in the second
quarter and first six 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 had provided incentives to customers to encourage switching
to alternative energy providers, which reduced OE’s revenues by $21 million in
the second quarter of 2005 and $38 million in the first six 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
decreased by $82 million in the second quarter of 2006 and $181 million in
the
first six months of 2006 from the same periods of 2005 principally due to
the
effects of the generation asset transfer shown in the table above. Excluding
the
asset transfer effects, the following table presents changes from the prior
year
by expense category.
Expenses
- Changes
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Purchased
power costs
|
|
$
|
66
|
|
$
|
102
|
|
Nuclear
operating costs
|
|
|
(6
|
)
|
|
(14
|
)
|
Other
operating costs
|
|
|
(4
|
)
|
|
4
|
|
Provision
for
depreciation
|
|
|
2
|
|
|
6
|
|
Amortization
of regulatory assets
|
|
|
(66
|
)
|
|
(124
|
)
|
Deferral
of
new regulatory assets
|
|
|
(3
|
)
|
|
(15
|
)
|
General
taxes
|
|
|
1
|
|
|
2
|
|
Net
decrease in expenses
|
|
$
|
(10
|
)
|
$
|
(39
|
)
|
|
|
|
|
|
|
|
|
Increased
purchased
power costs in the second quarter and first six 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 for OE’s nuclear leasehold interests were primarily due
to the absence in 2006 of the Beaver Valley Unit 2 refueling outage and 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 second quarter 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 customer in the fourth
quarter of 2005. The increase in other operating costs in the first six months
of 2006 was primarily due to increased transmission expenses related to MISO
Day
2 operations that began on April 1, 2005.
Excluding
the
effects of the generation asset transfers, higher depreciation expense in
the
second quarter and first six months of 2006 reflected capital additions
subsequent to the second 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 second
quarter and first six months of 2006 primarily resulted from the deferral
of
fuel ($14 million and $25 million, respectively) and distribution costs
($22 million and $39 million, respectively) under the RCP, partially offset
by lower MISO cost deferrals ($12 million and $11 million, respectively)
and the
decrease in shopping incentive deferrals ($21 million and $38 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.
Excluding
the
effects of the generation asset transfers, higher general taxes in both periods
reflects the phase-in of the Ohio commercial activity tax that became effective
July 1, 2005.
Other
Income
Other
income
increased $14 million in the second quarter of 2006 and $47 million in the
first
six months of 2006 as compared with the same periods of 2005, primarily due
to
the effects of the generation asset transfers. Excluding the effects of the
generation asset transfers, the $5 million increase in the second quarter
is
primarily due to lower interest expense, reflecting debt redemptions subsequent
to the second quarter of 2005.
Excluding
the
effects of the generation asset transfers, the $28 million increase in the
first
six months is primarily due to lower interest expense and 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).
Income
Taxes
Income
taxes
decreased $60 million in the second quarter of 2006 and $75 million in the
first
six months of 2006 compared with the same periods of 2005. Excluding the
effects
of the generation asset transfer, income taxes decreased $47 million in the
second quarter of 2006 and
$50 million in the
first six months of 2006.
As a result of new
Ohio tax legislation in 2005, OE wrote off $36 million in net deferred tax
benefits in the second quarter of 2005. The remainder of the net change in
both
the second quarter and the six-month period was mainly due to an increase
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.
Capital
Resources and Liquidity
OE’s
cash
requirements in 2006 for operating expenses, construction expenditures and
scheduled debt maturities are expected to be met with cash from operations,
short-term credit arrangements and funds from capital markets. OE repurchased
$500 million of common stock from FirstEnergy and redeemed $64 million of
preferred stock 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 $545 million
of cash and cash equivalents as of June 30, 2006 compared with $1 million
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 six months of 2006, compared with the
corresponding period in 2005, was as follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
Cash
earnings
(1)
|
|
$
|
129
|
|
$
|
329
|
|
Working
capital and other
|
|
|
90
|
|
|
135
|
|
Net
cash
provided from operating activities
|
|
$
|
219
|
|
$
|
464
|
|
|
|
|
|
|
|
|
|
(1) Cash
earnings are a
non-GAAP measure (see reconciliation below).
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. OE believes that cash earnings are a useful financial measure because
it
provides investors and management with an additional means of evaluating
its
cash-based operating performance. The following table reconciles cash earnings
with net income:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
123
|
|
$
|
104
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
36
|
|
|
58
|
|
Amortization
of regulatory assets
|
|
|
97
|
|
|
221
|
|
Deferral
of
new regulatory assets
|
|
|
(78
|
)
|
|
(64
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
(11
|
)
|
|
19
|
|
Amortization
of electric service obligation
|
|
|
(17
|
)
|
|
(4
|
)
|
Amortization
of lease costs
|
|
|
(4
|
)
|
|
(3
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(17
|
)
|
|
(5
|
)
|
Accrued
compensation and retirement benefits
|
|
|
--
|
|
|
3
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
129
|
|
$
|
329
|
|
|
|
|
|
|
|
|
|
Net
cash provided
from operating activities decreased $245 million in the first six months
of
2006, compared with the same period in 2005, due to a $45 million decrease
from
changes in working capital and a $200 million decrease in cash earnings as
described above under “Results from Operations.” The decrease in working capital
primarily reflects the absence in 2006 of $136 million in funds received
for the
Energy for Education program in 2005, partially offset by changes in prepayments
and other current assets of $78 million and accounts payable of
$39 million.
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities increased to $240 million in the first six months
of
2006 from $283 million used for financing activities in the first six
months of 2005. The increase primarily reflected more long-term debt financing,
and decreases of $151 million in redemptions of preferred stock and long-term
debt and $142 million in common stock dividend payments to FirstEnergy,
partially offset by higher repayments of short-term borrowings to associated
companies.
OE
had approximately
$1.1 billion of cash and temporary cash investments (which include
short-term notes receivable from associated companies) and $25 million of
short-term indebtedness as of June 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 SEC, continued by FERC rules adopted as a result of
EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit
of
$44 million as of June 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 June 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 June 30,
2006, the facility was drawn for $19 million.
As
of June 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 $735 million as of June 30, 2006. Based upon applicable earnings
coverage tests in their respective charters, OE and Penn could issue a total
of
$2.7 billion of preferred stock (assuming no additional debt was issued) as
of June 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 June 30, 2006,
OE had approximately $400 million of capacity remaining unused under its
existing shelf registration.
FirstEnergy,
OE,
Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have
entered into a syndicated $2 billion five-year revolving credit facility
with a syndicate of banks that expires in June 2010. Borrowings under the
facility are available to each Borrower separately and mature on the earlier
of
364 days from the date of borrowing or the commitment termination date, as
the
same may be extended. OE's borrowing limit under the facility is
$500 million and Penn’s is $50 million, subject in each case to
applicable regulatory approvals.
Under
the revolving
credit facility, borrowers may request the issuance of 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 $726 million as of June 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
June
30, 2006, debt to total capitalization as defined under the revolving credit
facility was 40% for OE and 34% for Penn.
The
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 six months of 2006 was
4.86%.
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 their associated company
notes payable to Penn and OE. With those repayments, OE redeemed
$74.8 million and Penn redeemed $6.95 million of pollution control
notes having variable interest rates.
Cash
Flows From
Investing Activities
Net
cash provided
from investing activities was $86 million in the first six months of 2006
compared to $181 million used for investing activities in the first six
months of 2005. The change resulted primarily from a $171 million increase
in
loan repayments from associated companies and a $72 million decrease in
property additions, which reflects the impact of the generation asset transfers.
During
the second
half of 2006, capital requirements for property additions and capital leases
are
expected to be approximately $46 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 $624
million,
of which
approximately $108
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 $640 million as of June 30, 2006.
Equity
Price Risk
Included
in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $70 million and $67 million
as of
June 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 June 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 to income as incurred. All regulatory assets are
expected to be recovered under the provisions of the OE Companies’ transition
plans and rate restructuring plans. OE‘s regulatory assets were
$756 million and $775 million as of June 30, 2006 and December
31, 2005, respectively. Penn had net regulatory liabilities of $59 million
as of June 30, 2006 and December 31, 2005, which are included in Other
Noncurrent Liabilities on the Consolidated Balance Sheets as of June 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 September 28, 2005, the Supreme Court of Ohio heard oral arguments
on the appeals. 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 one matter back to the PUCO
for further consideration of the issue as to whether the RSP, as adopted
by the
PUCO, provided for sufficient means for customer participation in the
competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
for
Reconsideration with the Supreme Court of Ohio which was denied by the Court
on
June 21, 2006. 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.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP. 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
|
|
$
|
177
|
2007
|
|
|
180
|
2008
|
|
|
208
|
Total
Amortization
|
|
$
|
565
|
|
|
|
|
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 are due on August 4, 2006.
Appellants’ Reply Briefs will then be due on August 24, 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. 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 $31 million. That amount included the recovery of a
portion of the 2005 deferred MISO expenses as described below. On May 1,
2006, OE filed a modification to the rider to determine revenues ($71 million)
from July 2006 through June 2007.
The second application sought authority to defer costs associated with
transmission and ancillary service related costs incurred during the period
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 unable to
predict when a decision may be issued.
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. To the
extent that an affiliate of Penn supplies a portion of the PLR load included
in
the RFP, authorization to make the affiliate sale must be obtained from the
FERC. 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
to
obtain Penn's power supply requirements after 2006 through two separate
solicitations. An initial solicitation was held for Penn in May 2006 with
all
tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
for the first solicitation. 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 only acquired for three of the
five
tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
the
submissions for the second bid. A residual solicitation is scheduled to be
held
on August 15, 2006 for the two remaining Large Commercial Group tranches.
Acceptance of the winning bids is subject to approval by the PPUC.
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 its recovery of certain
PLR costs via a reconciliation mechanism and its 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. The PPUC approved Penn's plan with modifications
on April 20, 2006 to use an RFP process to obtain its power supply requirements
after 2006 through two separate solicitations. An initial solicitation was
held
for Penn in May 2006 with all tranches fully subscribed. On June 2, 2006,
the
PPUC approved the bid results for the first solicitation. 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
only
acquired for three of the five tranches for the Large Commercial Group. On
July
20, 2006, the PPUC approved the submission for the second bid. A residual
solicitation is scheduled to be held on August 15, 2006 for the two remaining
Large Commercial Group tranches. Acceptance of the winning bids is subject
to
approval by the PPUC.
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. The procedural schedule has been suspended
pending negotiations among the parties.
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.
Those 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 the 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 outage. Two cases were
originally filed in Ohio State courts but were subsequently dismissed for
lack
of subject matter jurisdiction and further appeals were unsuccessful. In
these
cases the individual complainants—three in one case and four in the other—sought
to represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class
action
complaints. 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. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
is currently expected that this case will be summarily dismissed, although
the
Motion is still pending. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of
the
Ohio operating companies; dismissed FirstEnergy 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. These motions are pending. Additionally, on June 23, 2006, one of
the
insurance carrier complainants filed an appeal with the Ohio Supreme Court
over
the PUCO’s denial of their motion for rehearing on the issue of the
admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
as
a respondent. Briefing is expected to be completed on this appeal by
mid-September. It is unknown when the Supreme Court will rule on the appeal.
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 Perry (12.58%),
the transfer included the OE Companies’ prior owned interests in Beaver Valley
Unit 1 (100%), Beaver Valley Unit 2 (33.96%) and Perry
(22.66%).
On
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take
prompt
and corrective action. FENOC operates the Perry Nuclear Power Plant.
On April 4, 2005, the NRC held a public meeting to discuss FENOC’s
performance at the Perry Nuclear Power Plant as identified in the NRC's annual
assessment letter to FENOC. Similar public meetings are held with all nuclear
power plant licensees following issuance by the NRC of their annual assessments.
According to the NRC, overall the Perry Plant operated "in a manner that
preserved public health and safety" even though it remained under heightened
NRC
oversight. During the public meeting and in the annual assessment, the NRC
indicated that additional inspections will continue and that the plant must
improve performance to be removed from the Multiple/Repetitive Degraded
Cornerstone Column of the Action Matrix.
On September 28, 2005, the NRC sent a CAL to FENOC describing commitments
that FENOC had made to improve the performance at the Perry Plant and stated
that the CAL would remain open until substantial improvement was demonstrated.
The CAL was anticipated as part of the NRC's Reactor Oversight Process. In
the
NRC's 2005 annual assessment letter dated March 2, 2006 and associated
meetings to discuss the performance of Perry on March 14, 2006, the NRC
again stated that the Perry Plant continued to operate in a manner that
"preserved public health and safety." However, the NRC also stated that
increased levels of regulatory oversight would continue until sustained
improvement in the performance of the facility was realized. If performance
does
not improve, the NRC has a range of options under the Reactor Oversight Process,
from increased oversight to possible impact to the plant’s operating authority.
Although FirstEnergy is unable to predict the impact of the ultimate disposition
of this matter, it could have a material adverse effect on FirstEnergy's
or its
subsidiaries' financial condition, results of operations and cash
flows.
Other
Legal Matters-
On October 20, 2004, FirstEnergy was notified by the SEC that the
previously disclosed informal inquiry initiated by the SEC's Division of
Enforcement in September 2003 relating to the restatements in August 2003
of
previously reported results by FirstEnergy and the Ohio Companies, and the
Davis-Besse extended outage, have become the subject of a formal order of
investigation. The SEC's formal order of investigation also encompasses issues
raised during the SEC's examination of FirstEnergy and the Companies under
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.
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 described above. 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 60 days from the denial of rehearing to appeal the PUCO’s
decision.
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
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
June
30,
|
|
|
Six
Months
Ended
June
30,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
432,371
|
|
$
|
448,747
|
|
$
|
840,181
|
|
$
|
881,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
13,413
|
|
|
21,110
|
|
|
26,976
|
|
|
39,437
|
|
Purchased
power
|
|
|
157,942
|
|
|
138,842
|
|
|
301,711
|
|
|
281,726
|
|
Nuclear
operating costs
|
|
|
-
|
|
|
36,786
|
|
|
-
|
|
|
95,513
|
|
Other
operating costs
|
|
|
68,436
|
|
|
74,711
|
|
|
141,331
|
|
|
138,284
|
|
Provision
for
depreciation
|
|
|
11,050
|
|
|
33,387
|
|
|
28,251
|
|
|
64,502
|
|
Amortization
of regulatory assets
|
|
|
29,476
|
|
|
55,016
|
|
|
61,006
|
|
|
109,042
|
|
Deferral
of
new regulatory assets
|
|
|
(31,698
|
)
|
|
(40,701
|
)
|
|
(62,223
|
)
|
|
(65,989
|
)
|
General
taxes
|
|
|
31,510
|
|
|
36,605
|
|
|
66,580
|
|
|
75,492
|
|
Total
expenses
|
|
|
280,129
|
|
|
355,756
|
|
|
563,632
|
|
|
738,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
152,242
|
|
|
92,991
|
|
|
276,549
|
|
|
143,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
24,674
|
|
|
14,049
|
|
|
51,610
|
|
|
29,197
|
|
Miscellaneous
income (expense)
|
|
|
5,642
|
|
|
(2,292
|
)
|
|
5,396
|
|
|
(8,764
|
)
|
Interest
expense
|
|
|
(34,634
|
)
|
|
(30,152
|
)
|
|
(69,366
|
)
|
|
(64,618
|
)
|
Capitalized
interest
|
|
|
837
|
|
|
1,294
|
|
|
1,510
|
|
|
883
|
|
Total
other
income (expense)
|
|
|
(3,481
|
)
|
|
(17,101
|
)
|
|
(10,850
|
)
|
|
(43,302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
57,709
|
|
|
37,221
|
|
|
102,234
|
|
|
46,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
91,052
|
|
|
38,669
|
|
|
163,465
|
|
|
54,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
91,052
|
|
$
|
38,669
|
|
$
|
163,465
|
|
$
|
51,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
91,052
|
|
$
|
38,669
|
|
$
|
163,465
|
|
$
|
54,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
loss on available for sale securities
|
|
|
-
|
|
|
(1,349
|
)
|
|
-
|
|
|
(2,570
|
)
|
Income
tax
benefit related to other comprehensive income
|
|
|
-
|
|
|
419
|
|
|
-
|
|
|
923
|
|
Other
comprehensive loss, net of tax
|
|
|
-
|
|
|
(930
|
)
|
|
-
|
|
|
(1,647
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
91,052
|
|
$
|
37,739
|
|
$
|
163,465
|
|
$
|
52,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
217
|
|
$
|
207
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $5,836,000 and $5,180,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
273,324
|
|
|
268,427
|
|
Associated
companies
|
|
|
37,168
|
|
|
86,564
|
|
Other
|
|
|
14,703
|
|
|
16,466
|
|
Notes
receivable from associated companies
|
|
|
29,048
|
|
|
19,378
|
|
Prepayments
and other
|
|
|
1,504
|
|
|
1,903
|
|
|
|
|
355,964
|
|
|
392,945
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
2,063,137
|
|
|
2,030,935
|
|
Less
-
Accumulated provision for depreciation
|
|
|
800,356
|
|
|
788,967
|
|
|
|
|
1,262,781
|
|
|
1,241,968
|
|
Construction
work in progress
|
|
|
73,869
|
|
|
51,129
|
|
|
|
|
1,336,650
|
|
|
1,293,097
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
940,786
|
|
|
1,057,337
|
|
Investment
in
lessor notes
|
|
|
519,615
|
|
|
564,166
|
|
Other
|
|
|
13,710
|
|
|
12,840
|
|
|
|
|
1,474,111
|
|
|
1,634,343
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521
|
|
|
1,688,966
|
|
Regulatory
assets
|
|
|
858,618
|
|
|
862,193
|
|
Prepaid
pension costs
|
|
|
137,082
|
|
|
139,012
|
|
Property
taxes
|
|
|
63,500
|
|
|
63,500
|
|
Other
|
|
|
33,130
|
|
|
27,614
|
|
|
|
|
2,780,851
|
|
|
2,781,285
|
|
|
|
$
|
5,947,576
|
|
$
|
6,101,670
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
543
|
|
$
|
75,718
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
154,731
|
|
|
212,256
|
|
Other
|
|
|
149,000
|
|
|
140,000
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
65,148
|
|
|
74,993
|
|
Other
|
|
|
8,121
|
|
|
4,664
|
|
Accrued
taxes
|
|
|
119,555
|
|
|
121,487
|
|
Accrued
interest
|
|
|
18,810
|
|
|
18,886
|
|
Lease
market
valuation liability
|
|
|
60,200
|
|
|
60,200
|
|
Other
|
|
|
39,512
|
|
|
61,308
|
|
|
|
|
615,620
|
|
|
769,512
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
79,590,689
shares outstanding
|
|
|
1,355,926
|
|
|
1,354,924
|
|
Retained
earnings
|
|
|
687,615
|
|
|
587,150
|
|
Total
common
stockholder's equity
|
|
|
2,043,541
|
|
|
1,942,074
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,886,636
|
|
|
1,939,300
|
|
|
|
|
3,930,177
|
|
|
3,881,374
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
551,553
|
|
|
554,828
|
|
Accumulated
deferred investment tax credits
|
|
|
22,093
|
|
|
23,908
|
|
Lease
market
valuation liability
|
|
|
577,900
|
|
|
608,000
|
|
Retirement
benefits
|
|
|
83,604
|
|
|
83,414
|
|
Deferred
revenues - electric service programs
|
|
|
63,566
|
|
|
71,261
|
|
Other
|
|
|
103,063
|
|
|
109,373
|
|
|
|
|
1,401,779
|
|
|
1,450,784
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
5,947,576
|
|
$
|
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)
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
$
|
163,465
|
|
$
|
54,141
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
28,251
|
|
|
64,502
|
|
Amortization
of regulatory assets
|
|
61,006
|
|
|
109,042
|
|
Deferral
of
new regulatory assets
|
|
(62,223
|
)
|
|
(65,989
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
120
|
|
|
10,781
|
|
Deferred
rents
and lease market valuation liability
|
|
(55,043
|
)
|
|
(53,691
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
(4,745
|
)
|
|
4,450
|
|
Accrued
compensation and retirement benefits
|
|
1,584
|
|
|
(373
|
)
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
Receivables
|
|
46,262
|
|
|
(98,074
|
)
|
Materials
and
supplies
|
|
-
|
|
|
(28,791
|
)
|
Prepayments
and other current assets
|
|
399
|
|
|
188
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
Accounts
payable
|
|
(6,388
|
)
|
|
38,280
|
|
Accrued
taxes
|
|
(1,932
|
)
|
|
(6,779
|
)
|
Accrued
interest
|
|
(76
|
)
|
|
(320
|
)
|
Electric
service prepayment programs
|
|
(7,695
|
)
|
|
57,466
|
|
Other
|
|
(4,162
|
)
|
|
(7,871
|
)
|
Net
cash
provided from operating activities
|
|
158,823
|
|
|
76,962
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
Long-term
debt
|
|
-
|
|
|
53,284
|
|
Short-term
borrowings, net
|
|
-
|
|
|
58,874
|
|
Equity
contributions from parent
|
|
-
|
|
|
75,000
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
Preferred
stock
|
|
-
|
|
|
(101,900
|
)
|
Long-term
debt
|
|
(118,152
|
)
|
|
(56,930
|
)
|
Short-term
borrowings, net
|
|
(57,675
|
)
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
Common
stock
|
|
(63,000
|
)
|
|
(124,000
|
)
|
Preferred
stock
|
|
-
|
|
|
(2,260
|
)
|
Net
cash used
for financing activities
|
|
(238,827
|
)
|
|
(97,932
|
)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
Property
additions
|
|
(65,551
|
)
|
|
(60,244
|
)
|
Loan
repayments from associated companies, net
|
|
108,169
|
|
|
66,927
|
|
Investments
in
lessor notes
|
|
44,551
|
|
|
32,473
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
-
|
|
|
198,974
|
|
Investments
in
nuclear decommissioning trust funds
|
|
-
|
|
|
(213,486
|
)
|
Other
|
|
(7,155
|
)
|
|
(3,664
|
)
|
Net
cash
provided from investing activities
|
|
80,014
|
|
|
20,980
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
10
|
|
|
10
|
|
Cash
and cash
equivalents at beginning of period
|
|
207
|
|
|
197
|
|
Cash
and cash
equivalents at end of period
|
$
|
217
|
|
$
|
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 June 30, 2006, and the related consolidated
statements of income and comprehensive income for each of the three-month
and
six-month periods ended June 30, 2006 and 2005 and the consolidated statement
of
cash flows for the six-month period ended June 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
August
4,
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 their
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 will continue to provide CEI’s PLR requirements under
revised purchased power arrangements for the three-year period beginning
January 1, 2006 (see Regulatory Matters).
The
effects on CEI’s
results of operations in the second quarter and first six months of 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
|
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(14
|
) |
|
$
|
(29
|
) |
Nuclear
generated KWH sales
|
(b)
|
|
(57
|
) |
|
|
(110
|
) |
Total
-
Revenues Effect
|
|
|
(71
|
) |
|
|
(139
|
) |
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(8
|
) |
|
|
(14
|
) |
Nuclear
operating costs
|
(c)
|
|
(37
|
) |
|
|
(95
|
) |
Provision
for
depreciation
|
(d)
|
|
(13
|
) |
|
|
(32
|
) |
General
taxes
|
(e)
|
|
(4
|
) |
|
|
(8
|
) |
Total
-
Expenses Effect
|
|
|
(62
|
) |
|
|
(149
|
) |
Operating
Income Effect
|
|
|
(9
|
) |
|
|
10
|
|
Other
Income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
14
|
|
|
|
30
|
|
Nuclear
decommissioning trust earnings
|
(g)
|
|
(2
|
) |
|
|
(4
|
) |
Capitalized
interest
|
(h)
|
|
(1
|
) |
|
|
-
|
|
Total
- Other
Income Effect
|
|
|
11
|
|
|
|
26
|
|
Income
taxes
|
(i)
|
|
1
|
|
|
|
15
|
|
Net
Income
Effect
|
|
$
|
1
|
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
(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 second quarter of 2006 increased to $91 million from $39 million
in
the second quarter of 2005. In the first six months of 2006, earnings on
common
stock increased to $163 million from $51 million in the same period of 2005.
The
increase in earnings in both 2006 periods resulted primarily from lower expenses
and increased other income, partially offset by lower revenues. These changes
reflected the effects of the generation asset transfer shown in the table
above
and 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 $16 million or 3.6% in the second quarter of 2006 from the same period
in
2005. Excluding
the
effects of the generation asset transfers displayed above, revenues increased
$55 million due to a $105 million increase in retail generation sales revenues
and a $28 million reduction in customer shopping incentives, partially offset
by
a $62 million decrease in distribution revenues and a $19 million decrease
in
MSG wholesale sales. In the first six months of 2006 compared to the same
period
in 2005, revenues decreased by $42 million or 4.7%. Excluding the effects
of the
generation asset transfers discussed above, revenues increased $97 million
due
to a $193 million increase in retail generation sales revenues and a $47
million
reduction in customer shopping incentives, partially offset by a $106 million
decrease in distribution revenues and a $37 million decrease in MSG wholesale
sales.
Non-affiliated
wholesale sales revenues decreased by $19 million for the second quarter
of 2006
and $37 million for the first six months of 2006 compared with the same periods
in 2005 due to the cessation of the MSG sales arrangements under CEI’s
transition plan in December 2005. CEI had been required to provide the MSG
to
non-affiliated alternative suppliers.
Changes
in electric
generation KWH sales and revenues
in the
second quarter and first six months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
50.7
|
%
|
|
48.5
|
%
|
Wholesale
|
|
|
(74.0)
|
%
|
|
(71.4)
|
%
|
Net
Decrease in Generation Sales
|
|
|
(21.4)
|
%
|
|
(17.7)
|
%
|
Changes
in Generation Revenues
|
|
|
Three
Months
|
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
(In
millions)
|
|
Retail
Generation:
|
|
|
|
|
|
|
|
Residential
|
|
$
|
39
|
|
$
|
77
|
|
Commercial
|
|
|
38
|
|
|
70
|
|
Industrial
|
|
|
28
|
|
|
46
|
|
Total
Retail
Generation
|
|
|
105
|
|
|
193
|
|
Wholesale*
|
|
|
(19
|
)
|
|
(37
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
86
|
|
$
|
156
|
|
* Excludes
impact of
generation asset transfers related to nuclear generated KWH sales.
Increased
retail
generation revenue as shown in the table above for the second quarter 2006
compared with the same quarter of 2005 was due to increased KWH sales and
higher
unit prices. 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 - 61.0 percentage points, commercial - 43.5 percentage points
and industrial - 8.9 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 six months of 2006 compared with the same
period in 2005 were also due to increased KWH sales and the higher unit prices
under provisions of the RSP and RCP. The increase in generation KWH sales
reflected a similar decrease in customer shopping as discussed above. This
resulted in similar percentage decreases in the first half of 2006 in generation
services provided by alternative suppliers as a percentage of total sales
deliveries in CEI's service area (residential - 60.0 percentage points,
commercial - 41.1 percentage points and industrial - 7.6 percentage points).
Changes
in
distribution KWH deliveries and revenues
in the
second quarter and first six months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Distribution KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(5.6)
|
%
|
|
(3.8)
|
%
|
Commercial
|
|
|
(2.7)
|
%
|
|
(4.3)
|
%
|
Industrial
|
|
|
(1.5)
|
%
|
|
(2.6)
|
%
|
Net
Decrease in Distribution Deliveries
|
|
|
(2.8)
|
%
|
|
(3.3)
|
%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Residential
|
|
$
|
(16
|
)
|
$
|
(21
|
)
|
Commercial
|
|
|
(23
|
)
|
|
(45
|
)
|
Industrial
|
|
|
(23
|
)
|
|
(40
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(62
|
)
|
$
|
(106
|
)
|
Lower
distribution
revenues as shown in the table above in the second quarter and first six
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 reflected
the impact of milder weather conditions in the second quarter and first six
months of 2006, compared to the same periods of 2005.
Under
the Ohio
transition plan, CEI had 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 $28 million revenue increase for the second
quarter of 2006 and a $47 million increase for the first six months of 2006
compared to the same periods of 2005, as discussed above.
Expenses
Total
expenses
decreased by $76 million in the second quarter and $174 million in the first
six
months of 2006 from the same periods of 2005, principally due to the 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
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
costs
|
|
$
|
-
|
|
$
|
1
|
|
Purchased
power costs
|
|
|
19
|
|
|
20
|
|
Other
operating costs
|
|
|
(6
|
)
|
|
3
|
|
Provision
for
depreciation
|
|
|
(9
|
)
|
|
(4
|
)
|
Amortization
of regulatory assets
|
|
|
(26
|
)
|
|
(48
|
)
|
Deferral
of
new regulatory assets
|
|
|
9
|
|
|
4
|
|
General
taxes
|
|
|
(1
|
)
|
|
(1
|
)
|
Net
decrease in expenses
|
|
$
|
(14
|
)
|
$
|
(25
|
)
|
Higher
purchased
power
costs in the second quarter and in the first six months of 2006 compared
with
the same periods in 2005 primarily reflected increases in KWH purchased to
meet
higher retail generation sales requirements. These increases were partially
offset by the impact of lower unit prices associated with the new power supply
agreement with FES and purchased power lease credit amortizations of $8 million
and $16 million in the second quarter and the first six months of 2006,
respectively. The amortization is for the above-market lease liability related
to an existing Beaver Valley Unit 2 purchased power arrangement with TE.
The
lease credit amortization had been previously included in CEI's nuclear
operating costs and the related nuclear generation KWH purchased from TE
had
then been sold to FES. Subsequent to the generation asset transfer, CEI now
retains this purchased power from TE to meet a portion of its PLR obligation
and, consequently, the lease amortization is now included as part of CEI's
purchased power costs. Lower other operating costs in the second quarter
of 2006
compared with the same period 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. Higher other
operating costs in the first six months of 2006 compared with the same period
in
2005 reflect increased transmission expenses, primarily related to MISO Day
2
operations that began on April 1, 2005.
Excluding
the
effects of the generation asset transfers, the
decrease in
depreciation in the second quarter and first six months of 2006 compared
with
the same periods of 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 second quarter and first six months
of
2006 compared with the same periods in 2005 was primarily due to the termination
of the shopping incentive deferrals ($28 million and $47 million, respectively)
and lower deferred MISO costs ($6 million and $5 million, respectively),
partially offset by the deferrals of distribution costs ($14 million and
$29
million, respectively) and fuel costs ($11 million and $19 million,
respectively) under the RCP.
Other
Income
The
increase in
other income of $14 million in the second quarter and $32 million in the
first
six months of 2006 compared with the same periods last year was primarily
due to
interest income on associated company notes receivable from the generation
asset
transfers discussed above. Excluding the effects of the asset transfer, other
income increased for the second quarter and first six months of 2006 by $2
million and $7 million, respectively. The increase in both periods 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 in both periods due to the absence of financing cost reductions
recognized in 2005 related to refinancing activities.
Income
Taxes
Increased
income
taxes in the second quarter and in the first six months of 2006 compared
with
the same periods last year were primarily due to an increase 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 and the absence of a second quarter
2005
addition to income taxes of approximately $8 million, from the implementation
of
the Ohio tax legislation.
Preferred
Stock
Dividend Requirements
Preferred
stock
dividend requirements decreased by $3 million in the first six 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 2006, CEI expects to meet its contractual obligations with cash from
operations and short-term credit arrangements. Thereafter, CEI expects to
use a
combination of cash from operations and funds from the capital
markets.
Changes
in Cash
Position
As of June 30, 2006, CEI had $217,000 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 six months of 2006, compared with the
same
period last year, were as follows:
|
|
Six
Months Ended
June
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Cash
earnings
*
|
|
$
|
125
|
|
$
|
113
|
|
Working
capital and other
|
|
|
34
|
|
|
(36
|
)
|
Net
cash
provided from operating activities
|
|
$
|
159
|
|
$
|
77
|
|
*
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 are a useful financial measure because
it
provides investors and management with an additional means of evaluating
its
cash-based operating performance. The following table reconciles cash earnings
with net income:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
Income
(GAAP)
|
|
$
|
163
|
|
$
|
54
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
28
|
|
|
65
|
|
Amortization
of regulatory assets
|
|
|
61
|
|
|
109
|
|
Deferral
of
new regulatory assets
|
|
|
(62
|
)
|
|
(66
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
-
|
|
|
11
|
|
Amortization
of electric service obligation
|
|
|
(7
|
)
|
|
(10
|
)
|
Deferred
rents
and lease market valuation liability
|
|
|
(55
|
)
|
|
(54
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(5
|
)
|
|
5
|
|
Accrued
compensation and retirement benefits
|
|
|
2
|
|
|
(1
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
125
|
|
$
|
113
|
|
Net
cash provided
from operating activities increased by $82 million in the first six months
of
2006 from the same period last year as a result of a $12 million increase
in
cash earnings described above under "Results of Operations" and a $70 million
increase from working capital and other cash flows. The largest factors
contributing to the changes in working capital and other operating cash flows
for the first six 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, offset
in part by
changes in accounts payable and 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 $141 million in the first six months of
2006
from the same period last year. The increase in funds used for financing
activities primarily resulted from a $129 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 $61 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 $304 million of short-term
indebtedness as of June 30, 2006. CEI has obtained authorization from the
PUCO
to incur short-term debt of up to $500 million (including the bank facility
and utility money pool described below). As of June 30, 2006, CEI had the
capability to issue $247 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 $576 million as of June 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 June 30, 2006,
the
facility was drawn for $149 million.
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 six months of 2006 was
4.86%.
CEI, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as
Borrowers, have entered into a syndicated $2 billion five-year revolving
credit facility through a syndicate of banks that expires in June 2010.
Borrowings under the facility are available to each Borrower separately and
mature on the earlier of 364 days from the date of borrowing or the
commitment expiration date, as the same may be extended. 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.
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 June 30, 2006, CEI's debt to total capitalization as defined
under the revolving credit facility was 49%.
The facility
does not contain any provisions that either restrict CEI'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 CEI's credit
ratings.
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.
IIn
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 their associated company
notes
payable to CEI. CEI redeemed $117.8 million of pollution control notes
having variable interest rates.
Cash
Flows from
Investing Activities
Net
cash provided
from investing activities increased by $59 million in the first six 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.
CEI’s
capital
spending for the last half of 2006 is expected to be approximately $58 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 $620 million of which approximately $127
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 June 30,
2006, the present value of these operating lease commitments, net of trust
investments, total $98 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 June 30, 2006 and December
31, 2005, were $859 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 September 28, 2005, the Supreme Court of Ohio heard oral arguments
on the appeals. 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 one matter back to the PUCO
for further consideration of the issue as to whether the RSP, as adopted
by the
PUCO, provided for sufficient means for customer participation in the
competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
for
Reconsideration with the Supreme Court of Ohio which was denied by the Court
on
June 21, 2006. 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.
The
Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005 seeking
approval of the RCP. 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
|
|
$
|
95
|
|
2007
|
|
|
113
|
|
2008
|
|
|
130
|
|
2009
|
|
|
211
|
|
2010
|
|
|
266
|
|
Total
Amortization
|
|
$
|
815
|
|
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 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 are due on August 4, 2006.
Appellants’ Reply Briefs will then be due on August 24, 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 May 1, 2006, CEI filed a modification to the rider to
determine revenues ($51 million) from July 2006 through June 2007.
The
second
application sought authority to defer costs associated with transmission
and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO granted the
accounting authority for CEI 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 CEI 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 CEI’s case with a similar case
involving Dayton Power & Light Company. Oral arguments were heard on
May 10, 2006. CEI is unable to predict when a decision may be
issued.
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.
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. The procedural schedule has been suspended pending
negotiations among the parties.
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 June 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 $2 million as of June 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 the 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 outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases
the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class
action
complaints. 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. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
is currently expected that this case will be summarily dismissed, although
the
Motion is still pending. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of
the
Ohio operating companies; dismissed FirstEnergy 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. These motions are pending. Additionally, on June 23, 2006, one of
the
insurance carrier complainants filed an appeal with the Ohio Supreme Court
over
the PUCO’s denial of their motion for rehearing on the issue of the
admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
as
a respondent. Briefing is expected to be completed on this appeal by
mid-September. It is unknown when the Supreme Court will rule on the appeal.
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 has been provided. FirstEnergy has cooperated fully with
the
informal inquiry and continues 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 described above. 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 60 days
from the denial of rehearing to appeal the PUCO’s decision.
If it were ultimately determined that FirstEnergy or its subsidiaries have
legal
liability or are otherwise made subject to liability based on the above matters,
it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
See
Note 10 (C)
to the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
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
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
225,598
|
|
$
|
259,109
|
|
$
|
443,575
|
|
$
|
500,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
9,638
|
|
|
14,404
|
|
|
19,400
|
|
|
26,973
|
|
Purchased
power
|
|
|
80,659
|
|
|
72,300
|
|
|
156,079
|
|
|
152,456
|
|
Nuclear
operating costs
|
|
|
17,866
|
|
|
46,689
|
|
|
35,198
|
|
|
105,852
|
|
Other
operating costs
|
|
|
39,718
|
|
|
41,311
|
|
|
80,143
|
|
|
75,659
|
|
Provision
for
depreciation
|
|
|
8,240
|
|
|
15,209
|
|
|
16,337
|
|
|
29,889
|
|
Amortization
of regulatory assets
|
|
|
22,117
|
|
|
33,231
|
|
|
46,573
|
|
|
68,096
|
|
Deferral
of
new regulatory assets
|
|
|
(14,190
|
)
|
|
(12,670
|
)
|
|
(27,846
|
)
|
|
(22,094
|
)
|
General
taxes
|
|
|
12,253
|
|
|
13,620
|
|
|
25,184
|
|
|
27,801
|
|
Total
expenses
|
|
|
176,301
|
|
|
224,094
|
|
|
351,068
|
|
|
464,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
49,297
|
|
|
35,015
|
|
|
92,507
|
|
|
36,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
8,945
|
|
|
8,188
|
|
|
18,725
|
|
|
17,072
|
|
Miscellaneous
expense
|
|
|
(1,926
|
)
|
|
(3,100
|
)
|
|
(4,610
|
)
|
|
(6,402
|
)
|
Interest
expense
|
|
|
(4,364
|
)
|
|
(2,941
|
)
|
|
(8,674
|
)
|
|
(9,977
|
)
|
Capitalized
interest
|
|
|
344
|
|
|
188
|
|
|
558
|
|
|
(255
|
)
|
Total
other
income
|
|
|
2,999
|
|
|
2,335
|
|
|
5,999
|
|
|
438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
19,924
|
|
|
29,674
|
|
|
37,128
|
|
|
28,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
32,372
|
|
|
7,676
|
|
|
61,378
|
|
|
8,041
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
1,161
|
|
|
2,211
|
|
|
2,436
|
|
|
4,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
31,211
|
|
$
|
5,465
|
|
$
|
58,942
|
|
$
|
3,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
32,372
|
|
$
|
7,676
|
|
$
|
61,378
|
|
$
|
8,041
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
191
|
|
|
(501
|
)
|
|
(947
|
)
|
|
(2,184
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
69
|
|
|
(96
|
)
|
|
(342
|
)
|
|
(791
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
122
|
|
|
(405
|
)
|
|
(605
|
)
|
|
(1,393
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
32,494
|
|
$
|
7,271
|
|
$
|
60,773
|
|
$
|
6,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
23
|
|
$
|
15
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
|
|
|
782
|
|
|
2,209
|
|
Associated
companies
|
|
|
39,407
|
|
|
16,311
|
|
Other
|
|
|
2,998
|
|
|
6,410
|
|
Notes
receivable from associated companies
|
|
|
45,747
|
|
|
48,349
|
|
Prepayments
and other
|
|
|
5,135
|
|
|
1,059
|
|
|
|
|
94,092
|
|
|
74,353
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
852,572
|
|
|
824,677
|
|
Less
-
Accumulated provision for depreciation
|
|
|
380,234
|
|
|
372,845
|
|
|
|
|
472,338
|
|
|
451,832
|
|
Construction
work in progress
|
|
|
28,499
|
|
|
33,920
|
|
|
|
|
500,837
|
|
|
485,752
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
382,733
|
|
|
436,178
|
|
Investment
in
lessor notes
|
|
|
169,493
|
|
|
178,798
|
|
Nuclear
plant
decommissioning trusts
|
|
|
59,126
|
|
|
59,209
|
|
Other
|
|
|
1,843
|
|
|
1,781
|
|
|
|
|
613,195
|
|
|
675,966
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576
|
|
|
501,022
|
|
Regulatory
assets
|
|
|
267,032
|
|
|
287,095
|
|
Prepaid
pension costs
|
|
|
35,124
|
|
|
35,566
|
|
Property
taxes
|
|
|
18,047
|
|
|
18,047
|
|
Other
|
|
|
39,728
|
|
|
24,164
|
|
|
|
|
860,507
|
|
|
865,894
|
|
|
|
$
|
2,068,631
|
|
$
|
2,101,965
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
-
|
|
$
|
53,650
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
30,571
|
|
|
46,386
|
|
Other
|
|
|
4,256
|
|
|
2,672
|
|
Notes
payable
to associated companies
|
|
|
136,571
|
|
|
64,689
|
|
Accrued
taxes
|
|
|
53,092
|
|
|
49,344
|
|
Lease
market
valuation liability
|
|
|
24,600
|
|
|
24,600
|
|
Other
|
|
|
19,379
|
|
|
40,049
|
|
|
|
|
268,469
|
|
|
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
|
|
|
473,908
|
|
|
473,638
|
|
Accumulated
other comprehensive income
|
|
|
4,085
|
|
|
4,690
|
|
Retained
earnings
|
|
|
223,370
|
|
|
189,428
|
|
Total
common
stockholder's equity
|
|
|
897,033
|
|
|
863,426
|
|
Preferred
stock
|
|
|
66,000
|
|
|
96,000
|
|
Long-term
debt
|
|
|
237,691
|
|
|
237,753
|
|
|
|
|
1,200,724
|
|
|
1,197,179
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
209,389
|
|
|
221,149
|
|
Accumulated
deferred investment tax credits
|
|
|
11,419
|
|
|
11,824
|
|
Lease
market
valuation liability
|
|
|
231,100
|
|
|
243,400
|
|
Retirement
benefits
|
|
|
41,986
|
|
|
40,353
|
|
Asset
retirement obligation
|
|
|
25,675
|
|
|
24,836
|
|
Deferred
revenues - electric service programs
|
|
|
28,151
|
|
|
32,606
|
|
Other
|
|
|
51,718
|
|
|
49,228
|
|
|
|
|
599,438
|
|
|
623,396
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
2,068,631
|
|
$
|
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)
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
61,378
|
|
$
|
8,041
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
16,337
|
|
|
29,889
|
|
Amortization
of regulatory assets
|
|
|
46,573
|
|
|
68,096
|
|
Deferral
of
new regulatory assets
|
|
|
(27,846
|
)
|
|
(22,094
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
-
|
|
|
8,134
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(45,843
|
)
|
|
(44,466
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(13,322
|
)
|
|
8,193
|
|
Accrued
compensation and retirement benefits
|
|
|
1,268
|
|
|
1,500
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
(18,257
|
)
|
|
12,539
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(5,912
|
)
|
Prepayments
and other current assets
|
|
|
(4,076
|
)
|
|
408
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(14,231
|
)
|
|
(74,371
|
)
|
Accrued
taxes
|
|
|
3,748
|
|
|
10,509
|
|
Accrued
interest
|
|
|
(222
|
)
|
|
(196
|
)
|
Electric
service prepayment programs
|
|
|
(4,454
|
)
|
|
36,563
|
|
Other
|
|
|
3,326
|
|
|
(8,588
|
)
|
Net
cash
provided from operating activities
|
|
|
4,379
|
|
|
28,245
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
45,000
|
|
Short-term
borrowings, net
|
|
|
71,882
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
(30,000
|
)
|
|
-
|
|
Long-term
debt
|
|
|
(53,650
|
)
|
|
(46,933
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
(96,381
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(25,000
|
)
|
|
(10,000
|
)
|
Preferred
stock
|
|
|
(2,436
|
)
|
|
(4,422
|
)
|
Net
cash used
for financing activities
|
|
|
(39,204
|
)
|
|
(112,736
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(29,361
|
)
|
|
(32,168
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
2,611
|
|
|
(4,001
|
)
|
Collection
of
principal on long-term notes receivable
|
|
|
53,766
|
|
|
123,546
|
|
Investments
in
lessor notes
|
|
|
9,305
|
|
|
11,895
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
30,665
|
|
|
153,940
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(30,754
|
)
|
|
(168,211
|
)
|
Other
|
|
|
(1,399
|
)
|
|
(510
|
)
|
Net
cash
provided from investing activities
|
|
|
34,833
|
|
|
84,491
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
8
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
15
|
|
|
15
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
23
|
|
$
|
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 June 30, 2006, and the related consolidated statements
of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2006 and 2005 and the consolidated statement of cash
flows for the six-month period ended June 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
August
4,
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 will continue to provide TE’s PLR
requirements under revised purchased power arrangements for the three-year
period beginning January 1, 2006 (see Outlook - Regulatory
Matters).
The effects on TE’s results of operations in the second quarter and first six
months of 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
|
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(3
|
) |
|
$
|
(7
|
) |
Nuclear
generated KWH sales
|
(b)
|
|
(29
|
) |
|
|
(51
|
) |
Total
-
Revenues Effect
|
|
|
(32
|
) |
|
|
(58
|
) |
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(5
|
) |
|
|
(8
|
) |
Nuclear
operating costs
|
(c)
|
|
(22
|
) |
|
|
(62
|
) |
Provision
for
depreciation
|
(d)
|
|
(7
|
) |
|
|
(16
|
) |
General
taxes
|
(e)
|
|
(2
|
) |
|
|
(3
|
) |
Total
-
Expenses Effect
|
|
|
(36
|
) |
|
|
(89
|
) |
Operating
Income Effect
|
|
|
4
|
|
|
|
31
|
|
Other
Income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
4
|
|
|
|
8
|
|
Nuclear
decommissioning trust earnings
|
(g)
|
|
(3
|
) |
|
|
(4
|
) |
Capitalized
interest
|
(h)
|
|
(1
|
) |
|
|
-
|
|
Total
- Other
Income Effect
|
|
|
-
|
|
|
|
4
|
|
Income
taxes
|
(i)
|
|
1
|
|
|
|
14
|
|
Net
Income
Effect
|
|
$
|
3
|
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
(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 second quarter of 2006 increased to $31 million from
$5 million in the second quarter of 2005. This increase resulted primarily
from reduced 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. Earnings
on common
stock in the first six months of 2006 increased to $59 million from
$4 million in the first six months of 2005. This increase resulted
primarily from reduced expenses, increased other income and the absence of
the
additional income taxes discussed above, also partially offset by lower
revenues. The earnings increases for both periods included the effects of
the
generation asset transfer shown in the table above.
Revenues
Revenues decreased by $33 million or 12.9% in the second 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 decreased $1 million due to decreased
distribution revenues of $34 million, partially offset by a $23 million increase
in generation sales revenues, a $9 million reduction in customer shopping
incentives and a $1 million increase in other revenues.
In
the first six
months of 2006, revenues decreased by $57 million or 11.4% 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 $1 million due to a $44 million increase in
generation sales revenues, a $15 million reduction in customer shopping
incentives and a $1 million increase in other revenues, partially offset
by a
$59 million decrease in distribution revenues.
Changes
in electric
generation KWH sales and revenues
in the
second quarter and first six months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
16.1
|
%
|
|
12.8
|
%
|
Wholesale
|
|
|
(57.6
|
)%
|
|
(56.7
|
)%
|
Net
Decrease in Generation Sales
|
|
|
(24.5
|
)%
|
|
(23.8
|
)%
|
Changes
in Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Retail
Generation:
|
|
|
|
|
|
|
|
Residential
|
|
$
|
17
|
|
$
|
32
|
|
Commercial
|
|
|
13
|
|
|
22
|
|
Industrial
|
|
|
7
|
|
|
9
|
|
Total Retail Generation
|
|
|
37
|
|
|
63
|
|
Wholesale*
|
|
|
(14
|
)
|
|
(19
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
23
|
|
$
|
44
|
|
*
Excludes impact of
generation asset transfers related to nuclear generated KWH sales.
Retail
generation
revenues increased in all customer sectors as shown in the table above in
the
second quarter of 2006 compared to the corresponding quarter of 2005 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 - 52.5%,
commercial - 15.5% and industrial - 7.1%) 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 - 34.4
percentage
points,
commercial - 11.4
percentage points
and
industrial - 2
percentage
points.
In
the first six
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
- 44.1%, commercial - 13.6% and industrial - 3.8%). Similar to the second
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 - 29
percentage
points,
commercial - 10
percentage points
and
industrial - 1.7
percentage
points.
Lower
wholesale
revenues in the second quarter and first six months of 2006 reflected decreased
revenues from non-affiliates ($5 million and $8 million, respectively) and
decreased revenues from associated companies ($9 million and $11 million,
respectively). The non-affiliated wholesale revenue decreases in 2006 were
primarily due to the cessation of the MSG sales arrangements under TE’s
transition plan in December 2005. TE had been required to provide the MSG
to
non-affiliated alternative suppliers. The
lower wholesale
revenues from associated companies in 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
second quarter and first six months of 2006 from the corresponding periods
of
2005 are summarized in the following table.
Changes
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(6.6
|
)%
|
|
(3.8
|
)%
|
Commercial
|
|
|
(5.1
|
)%
|
|
(4.4
|
)%
|
Industrial
|
|
|
4.9
|
%
|
|
1.9
|
%
|
Net
Decrease in Distribution Deliveries
|
|
|
(0.5
|
)%
|
|
(1.2
|
)%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Residential
|
|
$
|
(14
|
)
|
$
|
(25
|
)
|
Commercial
|
|
|
(16
|
)
|
|
(29
|
)
|
Industrial
|
|
|
(4
|
)
|
|
(5
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(34
|
)
|
$
|
(59
|
)
|
The
distribution
revenue decreases as shown in the table above in the second quarter and first
six 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 reflected 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
distribution deliveries to residential and commercial customers in both periods
reflected the impact of milder weather in the second quarter and the first
six
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 second
quarter and first six months of 2006 by $9 million and $15 million,
respectively. The deferred shopping incentives (Extended RTC) are currently
being recovered under the RCP (see Outlook - Regulatory Matters).
Expenses
Total
expenses
decreased by $48 million and $114 million in the second quarter and the first
six 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
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
|
|
$
|
-
|
|
$
|
1
|
|
Purchased
power costs
|
|
|
8
|
|
|
4
|
|
Nuclear
operating costs
|
|
|
(6
|
)
|
|
(9
|
)
|
Other
operating costs
|
|
|
(1
|
)
|
|
4
|
|
Provision
for
depreciation
|
|
|
-
|
|
|
2
|
|
Amortization
of regulatory assets
|
|
|
(11
|
)
|
|
(21
|
)
|
Deferral
of
new regulatory assets
|
|
|
(2
|
)
|
|
(6
|
)
|
Net
decrease in expenses
|
|
$
|
(12
|
)
|
$
|
(25
|
)
|
|
|
|
|
|
|
|
|
Higher
purchased
power costs in the second quarter of 2006 compared to the second 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. Decreased nuclear operating costs in the
2006
quarter were due to lower costs associated with TE’s leasehold interest in
Beaver Valley Unit 2. The decrease reflected the absence in 2006 of expenses
in
the second quarter of 2005 related to Beaver Valley Unit 2’s 25-day nuclear
refueling outage in April 2005.
Higher
purchased
power costs in the first six months of 2006 compared to the same period of
2005
reflected an increase in KWH purchased to meet higher retail generation sales
requirements, partially offset by lower unit prices. The nuclear operating
costs
decrease in the first six months of 2006 was due to the reasons described
above
for the second quarter. Higher other operating costs reflect increased
transmission expenses, primarily related to MISO Day 2 operations that began
on
April 1, 2005.
Excluding
the
effects of the generation asset transfers, depreciation charges in the first
six
months of 2006 increased due to distribution plant additions.
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
second quarter and first six months of 2006 primarily resulted from the
deferrals of distribution costs ($7 million and $13 million in the second
quarter and the first six months of 2006, respectively) and incremental fuel
costs ($4 million and $7 million in the second quarter and the first six
months
of 2006, respectively) that began in 2006 under the RCP, partially offset
by the
impact of the termination of shopping incentive deferrals in 2006
($9 million and $16 million in the second quarter and the first six months
of 2006, respectively).
Other
Income
Other
income
increased $5 million in the first six months of 2006 compared to the same
period
of 2005, primarily due to the effects of the generation asset transfers.
Excluding the asset transfer effects, the $1 million increase reflected lower
net interest charges and the absence of a charge of $1.6 million for an NRC
fine
related to Davis-Besse Plant in the first quarter of 2005, partially offset
by
the absence of interest income on a note from FGCO, which had a balloon
repayment in May 2005.
Income
Taxes
Income
taxes
decreased $10 million in the second quarter of 2006 and increased by $8 million
in the first six months of 2006 compared to the same periods of 2005. Excluding
the effects of the generation asset transfer, income taxes decreased in the
second quarter and first six months of 2006 by $11 million and $6 million,
respectively. These decreases were 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 increases in taxable
income.
Preferred
Stock
Dividend Requirements
Lower
preferred
stock dividend requirements in the second quarter and first six months of
2006
compared to the corresponding 2005 periods were the result of $60 million
of
optional preferred stock redemptions subsequent to the end of the second
quarter
of 2005.
Capital
Resources and Liquidity
During
2006, TE
expects to meet its contractual obligations with a combination of cash from
operations and short-term credit arrangements. In connection with a plan
to
realign its capital structure, TE may issue up to $300 million of new
long-term debt in 2006 with proceeds expected to fund a return of equity
capital
to FirstEnergy.
Changes
in Cash
Position
As
of June 30, 2006,
TE had $23,000 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 six months of 2006, compared with the
first six months of 2005, were as follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings*
|
|
$
|
34
|
|
$
|
56
|
|
Working
capital and other
|
|
|
(30
|
)
|
|
(28
|
)
|
Net
cash
provided from operating activities
|
|
$
|
4
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
*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 are a useful financial measure because it provides investors and
management with an additional means of evaluating its cash-based operating
performance. The following table reconciles cash earnings with net
income:
|
|
Six
Months Ended
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
Income
(GAAP)
|
|
$
|
61
|
|
$
|
8
|
|
Non-Cash
Charges (Credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
16
|
|
|
30
|
|
Amortization
of regulatory assets
|
|
|
47
|
|
|
68
|
|
Deferral
of
new regulatory assets
|
|
|
(28
|
)
|
|
(22
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
-
|
|
|
8
|
|
Amortization
of electric service obligation
|
|
|
(4
|
)
|
|
(1
|
)
|
Deferred
rents
and lease market valuation liability
|
|
|
(46
|
)
|
|
(44
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(13
|
)
|
|
8
|
|
Accrued
compensation and retirement benefits
|
|
|
1
|
|
|
1
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
34
|
|
$
|
56
|
|
Net
cash provided
from operating activities decreased by $24 million in the first six months
of
2006 from the first six months of 2005 as a result of a $22 million decrease
in
cash earnings described above under “Results of Operations” and a
$2 million decrease from working capital and other changes. The decrease in
working capital and other primarily resulted from the absence in 2006 of
funds
received in 2005 for a prepaid electric service program and a reduction in
cash
received from the settlement of receivables, partially offset by lower cash
payments on accounts payable.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities decreased to $39 million in the first six months of
2006
from $113 million in the same period of 2005. The decrease resulted primarily
from a $168 million increase in net short-term borrowings, partially offset
by
an $82 million net increase in preferred stock and long-term debt redemptions
and a $15 million increase in common stock dividend payments to FirstEnergy
in
2006.
TE
had $46 million of cash and temporary investments (which included short-term
notes receivable from associated companies) and $137 million of short-term
indebtedness as of June 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 June 30, 2006, TE had the capability to
issue
$634 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 $1.1 billion of preferred stock (assuming
no additional debt) was issued as of June 30, 2006.
TE, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as
Borrowers, have entered into a syndicated $2 billion five-year revolving
credit facility with a syndicate of banks that expires in June 2010. Borrowings
under the facility are available to each Borrower separately and mature on
the
earlier of 364 days from the date of borrowing or the commitment expiration
date, as the same may be extended. 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
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 June 30, 2006, TE's debt to total capitalization, as
defined under the revolving credit facility, was 28%.
The 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 six months of 2006 was 4.86%.
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 their 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.
Cash
Flows From
Investing Activities
Net
cash provided from investing activities decreased by $50 million in the first
six months of 2006 from the same period of 2005 primarily due to a
decrease
in the
collection of principal on long-term notes receivable. This 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. This decrease in cash receipts was 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 half of 2006 is expected to be approximately
$29 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
$232 million, of which approximately $58 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 June 30, 2006, the present value of these operating lease
commitments, net of trust investments, totaled $498 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 June 30, 2006 and
December 31, 2005 were $267 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 September 28, 2005, the Supreme Court of Ohio heard oral arguments
on the appeals. 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 one matter back to the PUCO
for further consideration of the issue as to whether the RSP, as adopted
by the
PUCO, provided for sufficient means for customer participation in the
competitive marketplace. On May 12, 2006, the Ohio Companies filed a Motion
for
Reconsideration with the Supreme Court of Ohio which was denied by the Court
on
June 21, 2006. 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.
The Ohio Companies filed an application and stipulation with the PUCO on
September 9, 2005 seeking approval of the RCP. 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
|
|
$
|
86
|
|
2007
|
|
|
90
|
|
2008
|
|
|
111
|
|
Total
Amortization
|
|
$
|
287
|
|
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 their 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 are due on August 4, 2006.
Appellent’s Reply Briefs will then be due in August 24, 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 May 1, 2006, TE filed a modification to the rider to determine revenues
($19 million) from July 2006 through June 2007.
The
second application sought authority to defer costs associated with transmission
and ancillary service related costs incurred during the period from
October 1, 2003 through December 31, 2005. On May 18, 2005, the
PUCO granted the accounting authority for the Ohio Companies to defer
incremental transmission and ancillary service-related charges incurred as
a
participant in MISO, but only for those costs incurred during the period
December 30, 2004 through December 31, 2005. Permission to defer costs
incurred prior to December 30, 2004 was denied. The PUCO also authorized
the Ohio Companies to accrue carrying charges on the deferred balances. On
August 31, 2005, the OCC appealed the PUCO's decision. 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
unable to predict when a decision may be issued.
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.
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
upon the procedural schedule, approved in the case, FES expected an initial
decision to be issued inin 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. The procedural schedule has been suspended
pending negotiations among the parties.
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
June 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
June 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 the 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 outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of subject
matter jurisdiction and further appeals were unsuccessful. In these cases
the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class
action
complaints. 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. FirstEnergy filed a Motion to Dismiss on June 13, 2006. It
is currently expected that this case will be summarily dismissed, although
the
Motion is still pending. On
March 7,
2006, the PUCO issued a ruling applicable to all pending cases. Among its
various rulings, the PUCO consolidated all of the pending outage cases for
hearing; limited the litigation to service-related claims by customers of
the
Ohio operating companies; dismissed FirstEnergy 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. These motions are pending. Additionally, on June 23, 2006, one of
the
insurance carrier complainants filed an appeal with the Ohio Supreme Court
over
the PUCO’s denial of their motion for rehearing on the issue of the
admissibility of the Task Force Report and the dismissal of FirstEnergy Corp.
as
a respondent. Briefing is expected to be completed on this appeal by
mid-September. It is unknown when the Supreme Court will rule on the appeal.
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 described above. 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 60 days from the denial of rehearing to appeal the PUCO’s
decision.
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 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
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
|
|
Six
Months Ended
|
|
|
June
30,
|
|
June
30,
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
STATEMENTS
OF INCOME
|
(In
thousands)
|
|
REVENUES
|
$
|
80,650
|
|
$
|
134,282
|
|
$
|
163,369
|
|
$
|
268,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
-
|
|
|
5,526
|
|
|
-
|
|
|
11,146
|
|
Purchased
power
|
|
56,513
|
|
|
42,726
|
|
|
111,269
|
|
|
89,706
|
|
Nuclear
operating costs
|
|
-
|
|
|
19,765
|
|
|
-
|
|
|
39,713
|
|
Other
operating costs
|
|
14,124
|
|
|
16,743
|
|
|
28,328
|
|
|
29,511
|
|
Provision
for
depreciation
|
|
1,695
|
|
|
3,810
|
|
|
4,126
|
|
|
7,504
|
|
Amortization
of regulatory assets
|
|
-
|
|
|
9,833
|
|
|
3,411
|
|
|
19,715
|
|
General
taxes
|
|
5,670
|
|
|
6,444
|
|
|
11,504
|
|
|
12,916
|
|
Total
expenses
|
|
78,002
|
|
|
104,847
|
|
|
158,638
|
|
|
210,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
2,648
|
|
|
29,435
|
|
|
4,731
|
|
|
58,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
3,388
|
|
|
924
|
|
|
6,851
|
|
|
(223
|
)
|
Interest
expense
|
|
(1,407
|
)
|
|
(2,787
|
)
|
|
(5,362
|
)
|
|
(5,106
|
)
|
Capitalized
interest
|
|
48
|
|
|
1,476
|
|
|
82
|
|
|
2,843
|
|
Total
other
income (expense)
|
|
2,029
|
|
|
(387
|
)
|
|
1,571
|
|
|
(2,486
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
1,928
|
|
|
13,337
|
|
|
2,807
|
|
|
25,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
2,749
|
|
|
15,711
|
|
|
3,495
|
|
|
30,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
155
|
|
|
738
|
|
|
311
|
|
|
1,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
$
|
2,594
|
|
$
|
14,973
|
|
$
|
3,184
|
|
$
|
29,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
June
30,
|
|
December
31,
|
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
Cash
and cash
equivalents
|
$
|
38
|
|
$
|
24
|
|
Receivables
-
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $1,073,000 and $1,087,000,
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
38,303
|
|
|
44,555
|
|
Associated
companies
|
|
81,688
|
|
|
115,441
|
|
Other
|
|
1,332
|
|
|
2,889
|
|
Notes
receivable from associated companies
|
|
1,838
|
|
|
1,699
|
|
Prepayments
and other
|
|
17,728
|
|
|
86,995
|
|
|
|
140,927
|
|
|
251,603
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
In
service
|
|
365,959
|
|
|
359,069
|
|
Less
-
Accumulated provision for depreciation
|
|
131,181
|
|
|
129,118
|
|
|
|
234,778
|
|
|
229,951
|
|
Construction
work in progress-
|
|
5,457
|
|
|
3,775
|
|
|
|
240,235
|
|
|
233,726
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
276,052
|
|
|
283,248
|
|
Other
|
|
350
|
|
|
351
|
|
|
|
276,402
|
|
|
283,599
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
Prepaid
pension costs
|
|
43,056
|
|
|
42,243
|
|
Other
|
|
1,775
|
|
|
3,829
|
|
|
|
44,831
|
|
|
46,072
|
|
|
|
|
|
|
|
|
|
$
|
702,395
|
|
$
|
815,000
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Currently
payable long-term debt
|
$
|
15,474
|
|
$
|
69,524
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
Associated
companies
|
|
2,161
|
|
|
12,703
|
|
Other
|
|
19,000
|
|
|
-
|
|
Accounts
payable -
|
|
|
|
|
|
|
Associated
companies
|
|
20,420
|
|
|
73,444
|
|
Other
|
|
2,073
|
|
|
1,828
|
|
Accrued
taxes
|
|
23,029
|
|
|
28,632
|
|
Accrued
interest
|
|
1,070
|
|
|
1,877
|
|
Other
|
|
6,874
|
|
|
8,086
|
|
|
|
90,101
|
|
|
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
|
|
40,281
|
|
|
37,097
|
|
Total
common
stockholder's equity
|
|
300,117
|
|
|
296,933
|
|
Preferred
stock
|
|
14,105
|
|
|
14,105
|
|
Long-term
debt
and other long-term obligations
|
|
123,343
|
|
|
130,677
|
|
|
|
437,565
|
|
|
441,715
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
63,698
|
|
|
66,576
|
|
Retirement
benefits
|
|
46,845
|
|
|
45,967
|
|
Regulatory
liabilities
|
|
58,822
|
|
|
58,637
|
|
Other
|
|
5,364
|
|
|
6,011
|
|
|
|
174,729
|
|
|
177,191
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
$
|
702,395
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
June
30,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
3,495
|
|
$
|
30,713
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
4,126
|
|
|
7,504
|
|
Amortization
of regulatory assets
|
|
|
3,411
|
|
|
19,715
|
|
Nuclear
fuel
and other amortization
|
|
|
-
|
|
|
8,278
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(2,383
|
)
|
|
(4,955
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
41,562
|
|
|
10,838
|
|
Materials
and
supplies
|
|
|
-
|
|
|
(806
|
)
|
Prepayments
and other current assets
|
|
|
69,267
|
|
|
(8,260
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(52,779
|
)
|
|
(19,895
|
)
|
Accrued
taxes
|
|
|
(5,602
|
)
|
|
12,103
|
|
Accrued
interest
|
|
|
(807
|
)
|
|
116
|
|
Other
|
|
|
(3,290
|
)
|
|
463
|
|
Net
cash
provided from operating activities
|
|
|
57,000
|
|
|
55,814
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
8,458
|
|
|
33,745
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
(37,750
|
)
|
Long-term
debt
|
|
|
(61,899
|
)
|
|
(810
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
-
|
|
Dividend
Payments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
(8,000
|
)
|
Preferred
stock
|
|
|
(311
|
)
|
|
(1,378
|
)
|
Net
cash used
for financing activities
|
|
|
(53,752
|
)
|
|
(14,193
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(10,216
|
)
|
|
(41,093
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
-
|
|
|
36,995
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
-
|
|
|
(37,792
|
)
|
Loan
repayments from associated companies
|
|
|
7,057
|
|
|
173
|
|
Other
|
|
|
(75
|
)
|
|
82
|
|
Net
cash used
for investing activities
|
|
|
(3,234
|
)
|
|
(41,635
|
)
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
14
|
|
|
(14
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
24
|
|
|
38
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
38
|
|
$
|
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 June 30, 2006, and the related consolidated statement
of
income for each of the three-month and six-month periods ended June 30,
2006 and 2005 and the consolidated statement of cash flows for the six-month
period ended June 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
August
4,
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
In 2005, Penn and the Ohio Companies entered into certain agreements
implementing a series of intra-system generation asset transfers that were
completed in the fourth quarter of 2005. The asset transfers resulted in
the
respective undivided ownership interests of the Ohio Companies and Penn in
FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and
FGCO, respectively.
On October 24, 2005, Penn completed the intra-system transfer of non-nuclear
generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a
Master
Facility Lease with the Ohio Companies and Penn, leased, operated and maintained
the non-nuclear generation assets that it now owns. The asset transfers were
consummated pursuant to FGCO's purchase option under the Master Facility
Lease.
On December 16, 2005, Penn completed the intra-system transfer of its ownership
interests in the nuclear generation assets to NGC through an asset spin-off
in
the form of a dividend. FENOC continues to operate and maintain the nuclear
generation assets.
These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s
restructuring plans that were approved by the PUCO and the PPUC, respectively,
under applicable Ohio and Pennsylvania electric utility restructuring
legislation. Consistent with the restructuring plans, generation assets that
had
been owned by the Ohio Companies and Penn were required to be separated from
the
regulated delivery business of those companies through transfer to a separate
corporate entity. The transactions essentially completed the divestitures
contemplated by the restructuring plans by transferring the ownership interests
to NGC and FGCO without impacting the operation of the plants.
The transfers will affect Penn’s 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 second quarter and first six
months of 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
|
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
Non-nuclear
generating units rent
|
(a)
|
$
|
(5
|
) |
|
$
|
(10
|
) |
Nuclear
generated KWH sales
|
(b)
|
|
(38
|
) |
|
|
(76
|
) |
Total
-
Revenues Effect
|
|
|
(43
|
) |
|
|
(86
|
) |
Expenses:
|
|
|
|
|
|
|
|
|
Fuel
costs -
nuclear
|
(c)
|
|
(5
|
) |
|
|
(11
|
) |
Nuclear
operating costs
|
(c)
|
|
(20
|
) |
|
|
(40
|
) |
Provision
for
depreciation
|
(d)
|
|
(1
|
) |
|
|
(3
|
) |
General
taxes
|
(e)
|
|
(1
|
) |
|
|
(1
|
) |
Total
-
Expenses Effect
|
|
|
(27
|
) |
|
|
(54
|
) |
Operating
Income Effect
|
|
|
(16
|
) |
|
|
(32
|
) |
Other
Income:
|
|
|
|
|
|
|
|
|
Interest
income from notes receivable
|
(f)
|
|
2
|
|
|
|
5
|
) |
Capitalized
Interest
|
(g)
|
|
(1
|
) |
|
|
(3
|
) |
Total
- Other
Income Effect
|
|
|
1
|
|
|
|
2
|
|
Income
taxes
|
(h)
|
|
(6
|
) |
|
|
(12
|
) |
Net
Income
Effect
|
|
$
|
(9
|
) |
|
$
|
(18
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 second quarter of 2006 decreased to $2.6
million
from $15 million in the second quarter of 2005. During the first six months
of 2006 earnings on common stock decreased to $3.2 million from $29 million
in
the first six months of 2005. The lower earnings resulted principally from
the
generation asset transfer effects shown in the table above.
Revenues
Revenues decreased by $54 million, or 40%, and $105 million,
or 39%, in the second quarter of 2006 and the first six months of 2006,
respectively, as 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 asset transfer, revenues decreased by $11 million, or 12%
and $19
million, or 11%, in the second quarter and the first six months of 2006,
respectively. The decreases in the second quarter and the first half of 2006
resulted from lower distribution revenues ($9 million and $18 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 $12 million, respectively) resulting from
the
termination of a wholesale sales agreement with a non-affiliate in December
2005. These decreases were partially offset by an increase in retail generation
revenues of $5 million in the second quarter of 2006 and $11 million in the
first six 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 - total retail generation KWH sales remained substantially
unchanged.
Lower distribution KWH deliveries to residential and commercial
customers in the second quarter and first six months of 2006 reflect the
impact
of milder weather conditions compared to the same periods of 2005. Higher
KWH
deliveries to industrial customers in both periods of 2006 are largely due
to
increased demand from the steel sector.
Changes in distribution deliveries in the second quarter and the first six
months of 2006 from the same periods of 2005 are summarized in the following
table:
Changes
in Distribution Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
(7.8)
|
%
|
|
(4.9)
|
%
|
Commercial
|
|
|
(4.1)
|
%
|
|
(2.7)
|
%
|
Industrial
|
|
|
10.3
|
%
|
|
7.2
|
%
|
Total
Distribution Deliveries
|
|
|
-
|
%
|
|
(0.04)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
Total
expenses
decreased by $27 million in the second quarter and $52 million in the first
six
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 presents changes from the prior year by expense
category:
Expenses
- Changes
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
14
|
|
$
|
21
|
|
Other
operating costs
|
|
|
(3
|
) |
|
(1
|
) |
Provision
for
depreciation
|
|
|
(1
|
) |
|
-
|
|
Amortization
of regulatory assets
|
|
|
(10
|
) |
|
(16
|
) |
General
Taxes
|
|
|
-
|
|
|
(1
|
) |
Net
change in expenses
|
|
$
|
-
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increased
purchased
power costs in the second quarter and the first six 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 and a decrease in
the
use of outside contractors for tree trimming.
The
provision for
depreciation included an immaterial pretax adjustment of $0.7 million ($0.4
million net of tax) applicable to prior periods.
Amortization
of
regulatory assets was lower in the second quarter and the first six months
of
2006 as compared to the same periods of 2005 due to the completion of Penn's
rate restructuring plan and related transition cost amortization.
Other
Income
(Expense)
Investment
income
increased $2 million in the second quarter and $7 million the first
six months of 2006, compared with the same periods of 2005, primarily due
to the
impact of the generation asset transfer.
Net
Interest
Charges
Net
interest charges
were substantially unchanged in the second quarter and increased $3 million
in
the first six months as compared to the same periods of 2005 primarily due
to
the reduction of capitalized interest related to the generation asset
transfer.
Capital
Resources and Liquidity
Penn’s
cash
requirements in 2006 for expenses, construction expenditures and scheduled
debt
maturities are expected to be met with a combination of cash from operations
and
short-term credit arrangements. Available borrowing capacity under credit
facilities will be used to manage working capital requirements.
Changes
in Cash
Position
Penn
had $38,000 of
cash and cash equivalents as of June 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 six months of 2006, compared with
the
corresponding 2005 period, was as follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
|
(in
millions)
|
|
Cash
earnings
(*)
|
|
$
|
9
|
|
$
|
62
|
|
Working
capital and other
|
|
|
48
|
|
|
(6
|
)
|
Net
cash
provided from operating activities
|
|
$
|
57
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*)
Cash earnings
are a non-GAAP measure (see reconciliation
below).
|
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. Penn believes that cash earnings are a useful financial measure because
it
provides investors and management with an additional means of evaluating
its
cash-based operating performance. The following table reconciles cash earnings
with net income:
|
|
Six
Months Ended
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
3
|
|
$
|
31
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
4
|
|
|
8
|
|
Amortization
of regulatory assets
|
|
|
3
|
|
|
20
|
|
Nuclear
fuel
and other amortization
|
|
|
-
|
|
|
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(2
|
)
|
|
(5
|
) |
Other
non-cash
Items
|
|
|
1
|
|
|
-
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
9
|
|
$
|
62
|
|
The
$53 million
decrease in cash earnings for the first six months of 2006, as compared to
the
corresponding period of 2005, is described above under “Results of Operations”,
and resulted principally from the impact of the generation asset transfer.
The
$54 million change in working capital was primarily due to increases in
cash provided from the settlement of receivables of $31 million and a
$78 million change in prepayments and other current assets, principally as
a result of the asset transfer discussed above. These variances were partially
offset by increased cash outflows from the settlement of accounts payable
of
$33 million and an $18 million change in accrued taxes.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities totaled $54 million in the first six months of 2006,
compared with $14 million in the same period of 2005. The $40 million
increase resulted from $62 million of long-term debt redemptions in 2006
principally related to the generation asset transfer discussed above and
a $25
million decrease in short-term borrowings, partially offset by decreases
of $38
million in preferred stock redemptions and reductions of $8 million in common
stock dividend payments to OE as compared to the first six months of 2005.
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 as
of
June 30, 2006. Penn has authorization from the SEC, continued by FERC rules
adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt
up to
its charter limit of $44 million (including the utility money pool). Penn
had the capability to issue $66 million of additional FMB on the basis of
property additions and retired bonds as of June 30, 2006. Based upon
applicable earnings coverage tests, Penn could issue up to $290 million of
preferred stock (assuming no additional debt was issued) as of June 30,
2006.
Short-term
borrowings outstanding as of June 30, 2006, consisted of $19 million of
borrowings from affiliates. 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 at rates
based on bank commercial paper rates. The financing arrangements require
payment
of an annual facility fee of 0.125% on the entire finance limit. Penn Funding’s
receivables financing agreements expire June 28, 2007. As a separate legal
entity with separate creditors, it would have to satisfy its separate
obligations to creditors before any of its remaining assets could be made
available to Penn.
Penn
has the ability
to borrow under a syndicated $2 billion five-year revolving credit facility,
which expires in June 2010, along with FirstEnergy, OE, CEI, TE, JCP&L,
Met-Ed, Penelec, FES, and ATSI. Borrowings under the facility are available
to
each Borrower separately and will mature on the earlier of 364 days from
the
date of borrowing or the commitment termination date. Penn's borrowing limit
under the facility is $50 million.
Under
the revolving
credit facility, borrowers may request the issuance of LOC’s expiring up to one
year from the date of issuance. The stated amount of outstanding LOC’s 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 June 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
June
30, 2006, Penn's debt to total capitalization as defined under the revolving
credit facility was 34%.
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 six months
of
2006 was 4.86%.
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 six 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 used for
investing activities totaled $3 million in the first six months of 2006,
compared with $42 million in the same period of 2005. The $39 million
decrease in the 2006 period reflects a $31 million reduction in property
additions, 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 half
of 2006, capital requirements for property additions are expected to be
approximately $8 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 $90 million
of
which approximately $18 million applies to 2006. Penn had no other material
obligations as of June 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 $59 million as of June
30, 2006 and 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. To the
extent that an affiliate of Penn supplies a portion of the PLR load included
in
the RFP, authorization to make the affiliate sale must be obtained from the
FERC. 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
to
obtain Penn's power supply requirements after 2006 through two separate
solicitations. An initial solicitation was held for Penn in May 2006 with
all
tranches fully subscribed. On June 2, 2006, the PPUC approved the bid results
for the first solicitation. 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 only acquired for three of the
five
tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved
the
submissions for the second bid. A residual solicitation is scheduled to be
held
on August 15, 2006 for the two remaining Large Commercial Group tranches.
Acceptance of the winning bids is subject to approval by the PPUC.
On
November 1, 2005, FES filed a power sales agreement for approval with the
FERC that would permit Penn to obtain its PLR power requirements from FES
at a
fixed price equal to the retail generation price during 2006. As discussed
above, subsequent to the PPUC’s approval of Penn's plan for the RFP process to
obtain its post 2006 power supply requirements, the customer power supply
requirements for all of the residential and the small commercial sectors
and the
majority of the large commercial sector tranches have been fully subscribed
and
the bids approved by the PPUC. An additional solicitation for the remaining
two
large commercial sector tranches is scheduled for August 15, 2006.
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 its recovery of certain PLR costs via a
reconciliation mechanism and its 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.
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.
Those 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 the 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.
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
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. 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
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
Restated
|
|
|
|
Restated
|
|
|
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
611,484
|
|
$
|
595,291
|
|
$
|
1,187,276
|
|
$
|
1,124,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
343,045
|
|
|
321,393
|
|
|
658,755
|
|
|
598,525
|
|
Other
operating costs
|
|
|
72,105
|
|
|
80,239
|
|
|
155,133
|
|
|
181,306
|
|
Provision
for
depreciation
|
|
|
20,826
|
|
|
19,856
|
|
|
41,454
|
|
|
40,062
|
|
Amortization
of regulatory assets
|
|
|
65,526
|
|
|
70,250
|
|
|
132,271
|
|
|
138,624
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
(27,765
|
)
|
|
-
|
|
|
(27,765
|
)
|
General
taxes
|
|
|
14,272
|
|
|
14,824
|
|
|
30,504
|
|
|
30,264
|
|
Total
expenses
|
|
|
515,774
|
|
|
478,797
|
|
|
1,018,117
|
|
|
961,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
95,710
|
|
|
116,494
|
|
|
169,159
|
|
|
163,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
2,528
|
|
|
201
|
|
|
6,071
|
|
|
487
|
|
Interest
Expense
|
|
|
(20,367
|
)
|
|
(20,100
|
)
|
|
(40,983
|
)
|
|
(41,003
|
)
|
Capitalized
interest
|
|
|
1,037
|
|
|
437
|
|
|
1,929
|
|
|
840
|
|
Total
other
income (expense)
|
|
|
(16,802
|
)
|
|
(19,462
|
)
|
|
(32,983
|
)
|
|
(39,676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
38,632
|
|
|
42,729
|
|
|
62,190
|
|
|
55,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
40,276
|
|
|
54,303
|
|
|
73,986
|
|
|
67,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
125
|
|
|
125
|
|
|
250
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
40,151
|
|
$
|
54,178
|
|
$
|
73,736
|
|
$
|
67,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
40,276
|
|
$
|
54,303
|
|
$
|
73,986
|
|
$
|
67,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
38
|
|
|
36
|
|
|
107
|
|
|
105
|
|
Income
tax
expense related to other comprehensive income
|
|
|
15
|
|
|
15
|
|
|
43
|
|
|
43
|
|
Other
comprehensive income, net of tax
|
|
|
23
|
|
|
21
|
|
|
64
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
40,299
|
|
$
|
54,324
|
|
$
|
74,050
|
|
$
|
67,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to Jersey
Central Power & Light Company are an integral part
of these
statements.
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
95
|
|
$
|
102
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,078,000 and $3,830,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
282,352
|
|
|
258,077
|
|
Associated
companies
|
|
|
142
|
|
|
203
|
|
Other
(less
accumulated provisions of $206,000 and $204,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
41,317
|
|
|
41,456
|
|
Notes
receivable - associated companies
|
|
|
27,766
|
|
|
18,419
|
|
Materials
and
supplies, at average cost
|
|
|
2,012
|
|
|
2,104
|
|
Prepayments
(sales & use, corp. business, TEFA) taxes
|
|
|
110,787
|
|
|
10,137
|
|
Prepayments
and other
|
|
|
5,210
|
|
|
6,928
|
|
|
|
|
469,681
|
|
|
337,426
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
3,983,859
|
|
|
3,902,684
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,454,291
|
|
|
1,445,718
|
|
|
|
|
2,529,568
|
|
|
2,456,966
|
|
Construction
work in progress
|
|
|
77,325
|
|
|
98,720
|
|
|
|
|
2,606,893
|
|
|
2,555,686
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
fuel
disposal trust
|
|
|
165,132
|
|
|
164,203
|
|
Nuclear
plant
decommissioning trusts
|
|
|
149,000
|
|
|
145,975
|
|
Other
|
|
|
2,069
|
|
|
2,580
|
|
|
|
|
316,201
|
|
|
312,758
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
2,121,811
|
|
|
2,226,591
|
|
Goodwill
|
|
|
1,978,141
|
|
|
1,985,858
|
|
Prepaid
pension costs
|
|
|
150,760
|
|
|
148,054
|
|
Other
|
|
|
16,410
|
|
|
17,733
|
|
|
|
|
4,267,122
|
|
|
4,378,236
|
|
|
|
$
|
7,659,897
|
|
$
|
7,584,106
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
57,586
|
|
$
|
207,231
|
|
Notes
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
365,164
|
|
|
181,346
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
16,425
|
|
|
37,955
|
|
Other
|
|
|
194,619
|
|
|
149,501
|
|
Accrued
taxes
|
|
|
45,295
|
|
|
54,356
|
|
Accrued
interest
|
|
|
20,278
|
|
|
19,916
|
|
Cash
collateral from suppliers
|
|
|
32,434
|
|
|
141,225
|
|
Other
|
|
|
78,214
|
|
|
86,884
|
|
|
|
|
810,015
|
|
|
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
|
|
|
2,995,542
|
|
|
3,003,190
|
|
Accumulated
other comprehensive loss
|
|
|
(1,966
|
)
|
|
(2,030
|
)
|
Retained
earnings
|
|
|
104,626
|
|
|
55,890
|
|
Total
common
stockholder's equity
|
|
|
3,251,915
|
|
|
3,210,763
|
|
Preferred
stock
|
|
|
12,649
|
|
|
12,649
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,162,407
|
|
|
972,061
|
|
|
|
|
4,426,971
|
|
|
4,195,473
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
1,122,933
|
|
|
1,237,249
|
|
Accumulated
deferred income taxes
|
|
|
827,760
|
|
|
812,034
|
|
Nuclear
fuel
disposal costs
|
|
|
179,039
|
|
|
175,156
|
|
Asset
retirement obligation
|
|
|
81,949
|
|
|
79,527
|
|
Retirement
benefits
|
|
|
72,520
|
|
|
72,454
|
|
Other
|
|
|
138,710
|
|
|
133,799
|
|
|
|
|
2,422,911
|
|
|
2,510,219
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
7,659,897
|
|
$
|
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)
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
Restated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
73,986
|
|
$
|
67,752
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
41,454
|
|
|
40,062
|
|
Amortization
of regulatory assets
|
|
|
132,271
|
|
|
138,624
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
(27,765
|
)
|
Deferred
purchased power and other costs
|
|
|
(134,759
|
)
|
|
(126,265
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
10,942
|
|
|
16,426
|
|
Accrued
compensation and retirement benefits
|
|
|
(3,436
|
)
|
|
(8,029
|
)
|
Cash
collateral from (returned to) suppliers
|
|
|
(108,791
|
)
|
|
198
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
(24,074
|
)
|
|
14,271
|
|
Materials
and
supplies
|
|
|
91
|
|
|
177
|
|
Prepayments
and other current assets
|
|
|
(98,932
|
)
|
|
(66,525
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
23,589
|
|
|
32,087
|
|
Accrued
taxes
|
|
|
(9,062
|
)
|
|
58,139
|
|
Accrued
interest
|
|
|
362
|
|
|
580
|
|
Other
|
|
|
(1,642
|
)
|
|
16,856
|
|
Net
cash
provided from (used for) operating activities
|
|
|
(98,001
|
)
|
|
156,588
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
200,003
|
|
|
-
|
|
Short-term
borrowings, net
|
|
|
183,818
|
|
|
30,572
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(157,659
|
)
|
|
(63,327
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(25,000
|
)
|
|
(40,000
|
)
|
Preferred
stock
|
|
|
(250
|
)
|
|
(250
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
200,912
|
|
|
(73,005
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(91,101
|
)
|
|
(82,661
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(9,347
|
)
|
|
670
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
109,505
|
|
|
53,782
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(110,952
|
)
|
|
(55,229
|
)
|
Other
|
|
|
(1,023
|
)
|
|
105
|
|
Net
cash used
for investing activities
|
|
|
(102,918
|
)
|
|
(83,333
|
)
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(7
|
)
|
|
250
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
102
|
|
|
162
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
95
|
|
$
|
412
|
|
|
|
|
|
|
|
|
|
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 June 30, 2006, and the related consolidated
statements of income and comprehensive income for each of the three-month
and
six-month periods ended June 30, 2006 and 2005 and the consolidated statement
of
cash flows for the six-month period ended June 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
August
4,
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 six months ended June 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 second quarter of 2006 decreased to $40.2 million from
$54.2 million in 2005. The decrease was principally due to the absence of
the deferral of a new regulatory asset in 2005 and increased purchased
power
costs, partially offset by increased revenues and decreased other operating
costs. In the first six months of 2006, earnings on common stock increased
to
$73.7 million compared to $67.5 million for the same period in 2005. The
increase was primarily due to higher revenues and lower other operating
costs
partially offset by increased purchased power costs and the absence of
the
regulatory asset deferred in 2005.
Revenues
Revenues
increased
$16.2 million or 2.7% in the second quarter of 2006 and $62.9 million or
5.6%
for the first six months of 2006 compared with the same periods of 2005.
The
higher revenues in both periods were primarily due to retail generation
revenue
increases ($28.5 million and $66.3 million in the second quarter and the
first
six months of 2006, respectively), partially offset by wholesale revenue
decreases ($7.6 million in the second quarter and $5.8 million in the first
six
months of 2006). Distribution revenues declined $1.1 million in the second
quarter of 2006 but increased $4.2 million in the first six months of 2006
compared to the same periods of the prior year.
The
retail
generation revenue increases in both the second quarter and the first six
months
of 2006 as compared to the previous year were due to higher unit prices
resulting from the BGS auctions effective in May 2006 and May 2005, which
partially offset declines in retail generation KWH sales. Revenue from
residential customers increased $12.7 million and $27.6 million in the
second
quarter and the first six months of 2006, respectively, as compared to
the same
periods in 2005. Generation revenue from commercial customers also increased
for
the same periods by $15.3 million and $36.3 million, respectively. The
milder
weather in the second quarter and the first six months of 2006 as compared
to
the previous year (cooling degree days were 3.5% below the previous year
and
heating degree days were 18.6% below the previous year) resulted in lower
KWH
sales to residential customers in the second quarter and the first six
months of
2006. The milder weather also resulted in overall lower KWH sales to commercial
customers in the second quarter and first six months of 2006 - more than
offsetting the impact of commercial customers returning to JCP&L from
alternative suppliers. Revenues from industrial customers increased $0.3
million
and $2.1 million in the second quarter and first six months of 2006,
respectively, as compared to the previous year, as a result of higher unit
prices offsetting KWH sales decreases in the second quarter and the first
six
months of 2006. Wholesale sales revenues decreased $7.6 million in the
second quarter and $5.8 million for the first six months of 2006 as compared
to
2005 as lower unit prices offset KWH sales increases.
The
decrease in
distribution revenues of $1.1 million in the second quarter of 2006 compared
to
the same period of 2005 consists of two components, a $1.8 million increase
in
wires revenue and a $2.9 million reduction in MTC and SBC revenues. The
distribution revenue reduction was primarily due to lower KWH throughput
partially offset by higher composite unit prices resulting from a distribution
rate increase pursuant to the stipulated settlements approved by the NJBPU
on
May 25, 2005. While distribution KWH deliveries declined for the first six
months of 2006 as compared to the previous year, the impact of a full six
months
of 2006 of the distribution rate increase caused revenues to increase $4.2
million. Wires revenue increased $13.3 million while the MTC and SBC revenues
declined $9.1 million. Other revenues declined $3.6 million in the second
quarter and $1.8 million in the first six months of 2006 as compared to
the
comparable periods in 2005 due to reduced transmission
revenues.
Changes
in KWH sales
by customer class in the second quarter and the first six months of 2006
compared to the same periods of 2005 are summarized in the following
table:
|
|
Three
|
|
Six
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
(3.3)
|
%
|
|
(1.4)
|
%
|
Wholesale
|
|
|
2.2
|
%
|
|
1.1
|
%
|
Total
Electric Generation Sales
|
|
|
(2.1)
|
%
|
|
(0.9)
|
%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
(5.3)
|
%
|
|
(4.7)
|
%
|
Commercial
|
|
|
(0.3)
|
%
|
|
(0.7)
|
%
|
Industrial
|
|
|
(6.5)
|
%
|
|
(6.8)
|
%
|
Total
Distribution Deliveries
|
|
|
(3.2)
|
%
|
|
(3.3)
|
%
|
|
|
|
|
|
|
|
|
Expenses
Total
expenses and
taxes increased by $37.1 million in the second quarter and $57.0 million
in the
first six 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
|
|
Six
|
|
Expenses
- Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
21.7
|
|
$
|
60.2
|
|
Other
operating costs
|
|
|
(8.1
|
)
|
|
(26.2
|
)
|
Provision
for
depreciation
|
|
|
1.0
|
|
|
1.4
|
|
Amortization
of regulatory assets
|
|
|
(4.7
|
)
|
|
(6.4
|
)
|
Deferral
of
new regulatory assets
|
|
|
27.8
|
|
|
27.8
|
|
General
Taxes
|
|
|
(0.6
|
)
|
|
0.2
|
|
Net
increase in expenses
|
|
$
|
37.1
|
|
$
|
57.0
|
|
|
|
|
|
|
|
|
|
Purchased
power
costs increased $21.7 million in the second quarter of 2006 and $60.2 million
in
the first six months compared to the same periods of 2005. The increase
reflected higher unit prices resulting from the 2006 and 2005 BGS auctions.
The
change in the deferral of new regulatory assets of $27.8 million in both
periods
was due to the absence of a 2005 deferral of reliability expenses reflecting
a
May 2005 NJBPU rate decision. Other operating costs declined $8.1 million
in the
second quarter and $26.2 million for the first six months of 2006 due in
part to
the absence of costs related to the JCP&L labor strike in 2005. Amortization
of regulatory assets decreased $4.7 million in the second quarter and $6.4
million in the first six months of 2006 due to a reduction in the level
of MTC
revenue recovery.
Miscellaneous
income
increased $2.3 million in the second quarter of 2006 and $5.6 million in
the
first six months compared to the same periods in 2005. The increases in
both
periods is attributed to income received from customer requested service
projects.
Capital
Resources and Liquidity
JCP&L’s
cash
requirements in 2006 for expenses, construction expenditures and scheduled
debt
maturities are expected to be met with a combination of cash from operations
and
funds from the capital markets.
Changes
in Cash
Position
As
of June 30,
2006, JCP&L had $95,000 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 six months of 2006 compared with the
first six
months of 2005 were as follows:
|
|
Six
Months Ended
|
|
|
|
|
June
30,
|
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
|
|
(In
millions)
|
|
|
Cash
earnings
(1)
|
|
$
|
120
|
|
$
|
101
|
|
|
Working
capital and other
|
|
|
(218
|
)
|
|
56
|
|
|
Net
cash
provided from operating activities
|
|
$
|
(98
|
)
|
$
|
157
|
|
|
|
|
|
|
|
|
|
|
|
(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 are a useful
financial sure because it provides investors and management with an additional
means of evaluating its cash-based operating performance. The following
table
reconciles cash earnings with net income:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
74
|
|
$
|
68
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
41
|
|
|
40
|
|
Amortization
of regulatory assets
|
|
|
132
|
|
|
139
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
(28
|
)
|
Deferred
purchased power and other costs
|
|
|
(135
|
)
|
|
(126
|
)
|
Deferred
income taxes
|
|
|
11
|
|
|
16
|
|
Other
non-cash
items
|
|
|
(3
|
)
|
|
(8
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
120
|
|
$
|
101
|
|
|
|
|
|
|
|
|
|
The
$19 million
increase in cash earnings is described under “Results of Operations.” The
$274 million decrease from working capital changes primarily resulted from
a $109 million change in cash collateral from suppliers, changes in prepayments
of $32 million, accrued taxes of $67 million and receivables of $38
million. In the year 2005, JCP&L received cash collateral payments from its
suppliers of $135 million. During the first six months of 2006, JCP&L
returned $109 million back to its suppliers.
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities was $201 million in the first six months of 2006
as
compared to net cash used of $73 million in same period of 2005. The change
resulted from a $200 million issuance of long-term debt, a $153 million
increase
in short-term borrowings and a $15 million reduction in common stock
dividend payments to FirstEnergy, partially offset by $94 million of
additional debt redemptions in the first six months of 2006.
JCP&L had
$28 million of
cash and temporary investments (which includes short-term notes receivable
from
associated companies) and approximately $365 million of short-term
indebtedness as of June 30, 2006. JCP&L has authorization from the SEC,
continued by FERC rules adopted as a result of EPACT's repeal of PUHCA,
to incur
short-term debt up to its charter limit of $412 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
June 30, 2006, JCP&L had the capability to issue $610 million of
additional senior notes based upon FMB collateral. As of June 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 six months of 2006 was 4.86%.
JCP&L,
FirstEnergy, OE, Penn, CEI, TE, Penelec, Met-Ed, FES and ATSI, as Borrowers,
have entered into a syndicated $2 billion five-year revolving credit
facility which expires in June 2010. Borrowings under the facility are
available
to each Borrower separately and mature on the earlier of 364 days from
the date
of borrowing or the commitment termination date, as the same may be extended.
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
June 30, 2006, JCP&L's debt to total capitalization as defined under
the revolving credit facility was 29%.
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 June 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 4, 2006, JCP&L
Transition Funding II, a wholly owned subsidiary of JCP&L, secured pricing
on the issuance of $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 will use the proceeds it receives
from the issuer 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 $103 million in the first six months of 2006
compared to $83 million in the previous year. The $20 million change
primarily resulted from increases of $8 million in property additions for
distribution system reliability initiatives and $9 million of loans to
associated companies.
During
the last
half
of
2006, capital requirements for property additions and improvements are
expected
to be about $72 million. 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.
JCP&L’s
capital
spending for the period 2006-2010 is expected to be approximately
$912 million for property additions, of which approximately $162 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. Its Risk Policy Committee,
comprised of members of senior management, provides general management
oversight
to risk management activities throughout JCP&L. They are responsible for
promoting the effective design and implementation of sound risk management
programs. They also oversee compliance with corporate risk management policies
and established risk management practices.
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 power purchase
agreements with NUG entities that were structured pursuant to the Public
Utility
Regulatory Policy Act of 1978. These non-trading contracts are adjusted
to fair
value at the end of each quarter, with a corresponding regulatory asset
recognized for above-market costs. The changes in the fair value of commodity
derivative contracts related to energy production during the second quarter
and
first six months of 2006 are summarized in the following table:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
|
June
30, 2006
|
|
June
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
|
|
$
|
(1,173
|
)
|
$
|
-
|
|
$
|
(1,173
|
)
|
$
|
(1,223
|
)
|
$
|
-
|
|
$
|
(1,223
|
)
|
New
contract
value when entered
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
|
(15
|
)
|
|
-
|
|
|
(15
|
)
|
|
(30
|
)
|
|
-
|
|
|
(30
|
)
|
Change
in
techniques/assumptions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
|
76
|
|
|
-
|
|
|
76
|
|
|
141
|
|
|
-
|
|
|
141
|
|
Net
Liabilities - Derivative Contracts
at
End
of Period (1)
|
|
$
|
(1,112
|
)
|
$
|
-
|
|
$
|
(1,112
|
)
|
$
|
(1,112
|
)
|
$
|
-
|
|
$
|
(1,112
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
(1
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
assets (net)
|
|
$
|
(62
|
)
|
$
|
-
|
|
$
|
(62
|
)
|
$
|
(112
|
)
|
$
|
-
|
|
$
|
(112
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes
$1,112
million of non-hedge commodity derivative contracts (primarily with NUGs),
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 June 30,
2006
as follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
|
11
|
|
|
-
|
|
|
11
|
|
Other
noncurrent liabilities
|
|
|
(1,123
|
)
|
|
-
|
|
|
(1,123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
liabilities
|
|
$
|
(1,112
|
)
|
$
|
-
|
|
$
|
(1,112
|
)
|
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 June 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)
|
|
$
|
(147)
|
|
|
(257)
|
|
|
(226)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(630)
|
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(168)
|
|
|
(144)
|
|
|
(170)
|
|
|
(482)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
(147)
|
|
$
|
(257)
|
|
$
|
(226)
|
|
$
|
(168)
|
|
$
|
(144)
|
|
$
|
(170)
|
|
$
|
(1,112)
|
|
(1) For
the last two
quarters of 2006.
(2) Broker
quote
sheets.
(3) Includes
$1,112
million of non-hedge commodity derivative contracts (primarily with NUGs),
that
are offset by a regulatory asset and does not affect earnings.
JCP&L performs sensitivity analyses to estimate its exposure to the market
risk of its commodity positions. A hypothetical 10% adverse shift in quoted
market prices in the near term on 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 June 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 $86 million and $84 million as of June 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 June 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 $2.1 billion as of June 30, 2006 and $2.2 billion
as of 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 June 30, 2006, the accumulated
deferred cost balance totaled approximately $638 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 4, 2006, JCP&L Transition Funding II,
a wholly owned subsidiary of JCP&L, secured pricing on the issuance of $182
million of transition bonds with a weighted average interest rate of
5.5%.
On
December 2, 2005, JCP&L filed a request for recovery of
$165 million of actual above-market NUG costs incurred from August 1,
2003 through October 31, 2005 and forecasted above-market NUG costs for
November and December 2005. On February 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. A schedule for the proceeding
was
established, including a discovery period and evidentiary hearings scheduled
for
September 2006.
An NJBPU Decision and Order approving a Phase II Stipulation of Settlement
and
resolving the Motion for Reconsideration of the Phase I Order was issued
on May
31, 2005. The Phase II Settlement includes a performance standard pilot
program
with potential penalties of up to 0.25% of allowable equity return. The
Order
requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI
information related to the performance pilot program) through December
2006 and
updates to reliability related project expenditures until all projects
are
completed. The last of the quarterly reliability reports was submitted
on June
12, 2006. As of June 30, 2006, there were no performance penalties issued
by the NJBPU.
In a reaction to the higher closing prices of the 2006 BGS fixed rate auction,
the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate
the auction process and potential options for the future. On April 6, 2006,
initial comments were submitted. A public meeting was held on April 21,
2006 and
a legislative-type hearing was held on April 28, 2006. On June 21, 2006,
the NJBPU approved the continued use of a descending block auction for
the Fixed
Price Residential Class. A final decision as to the procurement method
for the
Commercial Industrial Energy Price Class is expected in October
2006.
In
accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on
June 7, 2004 supporting a continuation of the current level and duration of
the funding of TMI-2 decommissioning costs by its customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an
updated
total decommissioning cost estimate of $729 million (in 2003 dollars)
compared to the estimated $528 million (in 2003 dollars) from the prior
1995
decommissioning study. The DRA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. A schedule for further proceedings
has not yet been set.
On
August 1,
2005, the NJBPU established a proceeding to determine whether additional
ratepayer protections are required at the state level in light of the 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. The NJBPU Staff issued a draft proposal on March 31, 2006
addressing various issues including access to books and records, ring-fencing,
cross subsidization, corporate governance and related matters. 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. JCP&L is unable to predict the outcome of this
proceeding.
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 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 FERC has ordered the Presiding Judge to issue an initial
decision
by August 11, 2006.
On January 31, 2005, certain PJM transmission owners made three filings
with the FERC pursuant to a settlement agreement previously approved by
the
FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined
in two of the filings. In the first filing, the settling transmission owners
submitted a filing justifying continuation of their existing rate design
within
the PJM RTO. In the second filing, the settling transmission owners proposed
a
revised Schedule 12 to the PJM tariff designed to harmonize the rate
treatment of new and existing transmission facilities. Interventions and
protests were filed on February 22, 2005. In the third filing, Baltimore
Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate
for
transmission service provided within their respective zones. On May 31,
2005, the FERC issued an order on these cases. First, it set for hearing
the
existing rate design and indicated that it will issue a final order within
six
months. American Electric Power Company, Inc. filed
in
opposition proposing to create a "postage stamp" rate for high voltage
transmission facilities across PJM.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to 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. The
Companies, as part of the Responsible Pricing Alliance, intend to submit
a brief
on exceptions within thirty days of the initial decision. Following submission
of reply exceptions, the case is expected to 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 June 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
$54.7 million have been accrued through June 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 the result of adoption of mandatory reliability standards pursuant to
the
EPACT that could require additional material expenditures.
In addition to the above proceedings, FirstEnergy was named in a complaint
filed
in Michigan State Court by an individual who is not a customer of any
FirstEnergy company. FirstEnergy's motion to dismiss the matter was denied
on
June 2, 2006. FirstEnergy has since filed an appeal, which is pending. A
responsive pleading to this matter has been filed. Also, the complaint
has been
amended to include an additional party. No estimate of potential liability
has
been undertaken in this matter.
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 Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16 million to the bargaining unit employees. On February 6, 2006, the
federal court granted a Union motion to dismiss JCP&L's appeal of the award
as premature. JCP&L will file its appeal again in federal district court
once the damages associated with this case are identified at an individual
employee level. JCP&L recognized a liability for the potential
$16 million award in 2005.
The
other material items not otherwise discussed above are described in
Note 10(C) to the consolidated financial statements.
New
Accounting Standards and Interpretations
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. 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.
SUBSEQUENT
EVENTS
New
Jersey
Law Change
On
July 8, 2006, the
Governor of New Jersey signed tax legislation that increased the current
New
Jersey Corporate Business tax by an additional 4% surtax, which increases
the
effective tax from 9% to 9.36%. This increase applies to JCP&L’s 2006
through 2008 tax years and is not expected to have a material impact on
JCP&L’s results of operations.
METROPOLITAN
EDISON COMPANY
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
(Unaudited)
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
282,219
|
|
$
|
263,136
|
|
$
|
593,432
|
|
$
|
558,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
143,070
|
|
|
131,670
|
|
|
302,957
|
|
|
281,763
|
|
Other
operating costs
|
|
|
59,575
|
|
|
52,648
|
|
|
120,654
|
|
|
111,118
|
|
Provision
for
depreciation
|
|
|
10,288
|
|
|
11,377
|
|
|
21,193
|
|
|
22,898
|
|
Amortization
of regulatory assets
|
|
|
25,669
|
|
|
25,286
|
|
|
55,717
|
|
|
53,907
|
|
Deferral
of
new regulatory assets
|
|
|
(45,581
|
)
|
|
-
|
|
|
(45,581
|
)
|
|
-
|
|
General
taxes
|
|
|
18,595
|
|
|
17,023
|
|
|
39,216
|
|
|
36,295
|
|
Total
expenses
|
|
|
211,616
|
|
|
238,004
|
|
|
494,156
|
|
|
505,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
70,603
|
|
|
25,132
|
|
|
99,276
|
|
|
52,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
8,964
|
|
|
9,442
|
|
|
17,714
|
|
|
18,469
|
|
Miscellaneous
income
|
|
|
1,792
|
|
|
3,288
|
|
|
4,404
|
|
|
4,429
|
|
Interest
expense
|
|
|
(12,071
|
)
|
|
(11,398
|
)
|
|
(23,255
|
)
|
|
(22,621
|
)
|
Capitalized
interest
|
|
|
344
|
|
|
73
|
|
|
611
|
|
|
251
|
|
Total
other
income (expense)
|
|
|
(971
|
)
|
|
1,405
|
|
|
(526
|
)
|
|
528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
29,555
|
|
|
10,874
|
|
|
40,759
|
|
|
21,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
40,077
|
|
|
15,663
|
|
|
57,991
|
|
|
32,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
84
|
|
|
84
|
|
|
168
|
|
|
168
|
|
Income
tax
expense related to other comprehensive income
|
|
|
35
|
|
|
35
|
|
|
70
|
|
|
70
|
|
Other
comprehensive income, net of tax
|
|
|
49
|
|
|
49
|
|
|
98
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
40,126
|
|
$
|
15,712
|
|
$
|
58,089
|
|
$
|
32,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
134
|
|
$
|
120
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,069,000 and $4,352,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
128,349
|
|
|
129,854
|
|
Associated
companies
|
|
|
1,881
|
|
|
37,267
|
|
Other
|
|
|
7,489
|
|
|
8,780
|
|
Notes
receivable from associated companies
|
|
|
31,921
|
|
|
27,867
|
|
Prepaid
gross
receipts taxes
|
|
|
25,361
|
|
|
2,072
|
|
Prepayments
and other
|
|
|
7,115
|
|
|
5,840
|
|
|
|
|
202,250
|
|
|
211,800
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
1,885,164
|
|
|
1,856,425
|
|
Less
-
Accumulated provision for depreciation
|
|
|
723,799
|
|
|
721,566
|
|
|
|
|
1,161,365
|
|
|
1,134,859
|
|
Construction
work in progress
|
|
|
20,737
|
|
|
20,437
|
|
|
|
|
1,182,102
|
|
|
1,155,296
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
243,179
|
|
|
234,854
|
|
Other
|
|
|
1,367
|
|
|
1,453
|
|
|
|
|
244,546
|
|
|
236,307
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
860,485
|
|
|
864,438
|
|
Regulatory
assets
|
|
|
358,963
|
|
|
309,556
|
|
Prepaid
pension costs
|
|
|
92,472
|
|
|
89,005
|
|
Other
|
|
|
47,673
|
|
|
51,285
|
|
|
|
|
1,359,593
|
|
|
1,314,284
|
|
|
|
$
|
2,988,491
|
|
$
|
2,917,687
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
150,000
|
|
$
|
100,000
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
72,540
|
|
|
140,240
|
|
Other
|
|
|
66,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
18,134
|
|
|
37,220
|
|
Other
|
|
|
52,754
|
|
|
27,507
|
|
Accrued
taxes
|
|
|
5,866
|
|
|
17,911
|
|
Accrued
interest
|
|
|
9,735
|
|
|
9,438
|
|
Other
|
|
|
21,539
|
|
|
24,274
|
|
|
|
|
396,568
|
|
|
356,590
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
859,000
shares
outstanding
|
|
|
1,283,182
|
|
|
1,287,093
|
|
Accumulated
other comprehensive loss
|
|
|
(1,471
|
)
|
|
(1,569
|
)
|
Retained
earnings
|
|
|
88,566
|
|
|
30,575
|
|
Total
common
stockholder's equity
|
|
|
1,370,277
|
|
|
1,316,099
|
|
Long-term
debt
and other long-term obligations
|
|
|
541,948
|
|
|
591,888
|
|
|
|
|
1,912,225
|
|
|
1,907,987
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
369,737
|
|
|
344,929
|
|
Accumulated
deferred investment tax credits
|
|
|
9,643
|
|
|
10,043
|
|
Nuclear
fuel
disposal costs
|
|
|
40,444
|
|
|
39,567
|
|
Asset
retirement obligation
|
|
|
146,493
|
|
|
142,020
|
|
Retirement
benefits
|
|
|
57,118
|
|
|
57,809
|
|
Other
|
|
|
56,263
|
|
|
58,742
|
|
|
|
|
679,698
|
|
|
653,110
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
2,988,491
|
|
$
|
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.
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
Six
Months Ended
|
|
|
June
30,
|
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$
|
57,991
|
|
$
|
32,139
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
21,193
|
|
|
22,898
|
|
Amortization
of regulatory assets
|
|
|
55,717
|
|
|
53,907
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(50,570
|
)
|
|
(47,798
|
)
|
Deferral
of
new regulatory assets
|
|
|
(45,581
|
)
|
|
-
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
22,463
|
|
|
(1,898
|
)
|
Accrued
compensation and retirement benefits
|
|
|
(4,712
|
)
|
|
(4,519
|
)
|
Cash
collateral to suppliers
|
|
|
(2,250
|
)
|
|
-
|
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
38,182
|
|
|
110,210
|
|
Prepayments
and other current assets
|
|
|
(24,564
|
)
|
|
(21,205
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
6,161
|
|
|
(50,593
|
)
|
Accrued
taxes
|
|
|
(12,045
|
)
|
|
(5,184
|
)
|
Accrued
interest
|
|
|
297
|
|
|
(887
|
)
|
Other
|
|
|
(4,011
|
)
|
|
1,424
|
|
Net
cash
provided from operating activities
|
|
|
58,271
|
|
|
88,494
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
-
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
20,931
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
(37,830
|
)
|
Short-term
borrowings, net
|
|
|
(1,707
|
)
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
(34,000
|
)
|
Net
cash used
for financing activities
|
|
|
(1,707
|
)
|
|
(50,899
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(47,301
|
)
|
|
(34,395
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
116,704
|
|
|
55,081
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(121,446
|
)
|
|
(59,823
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(4,054
|
)
|
|
3,339
|
|
Other
|
|
|
(453
|
)
|
|
(1,797
|
)
|
Net
cash used
for investing activities
|
|
|
(56,550
|
)
|
|
(37,595
|
)
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
14
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
120
|
|
|
120
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
134
|
|
$
|
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 June 30, 2006, and the related consolidated statements
of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2006 and 2005 and the consolidated statement of
cash
flows for the six-month period ended June 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
August
4,
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
second quarter of 2006 increased to $40 million from $16 million in the
second
quarter of 2005. For the first six months of 2006, net income increased
to $58
million from $32 million in the same period of 2005. The increase in net
income
for both periods reflects higher revenues and the deferral of new regulatory
assets, partially offset by increased purchased power costs and other operating
costs as discussed below.
Revenues
Revenues
increased
by $19 million, or 7.3%, in the second quarter of 2006 and $35 million,
or 6.2%,
in the first six months of 2006, compared with the same periods of 2005.
Increases in both periods were primarily due to higher retail generation
electric revenues ($15 million for the second quarter and $27 million for
the
first six months) which reflected higher composite unit prices in all customer
classes. Higher KWH sales to commercial and industrial customers were partially
offset by lower KWH sales to residential customers. Industrial KWH sales
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 14.5 percentage points, in the second
quarter of 2006 and 14.2 percentage points in the first six months of 2006.
For
both periods, residential KWH sales decreased primarily due to the milder
weather in 2006 compared with 2005.
Revenues
from
distribution throughput increased by $1 million in the second quarter of
2006
compared with the same period of 2005. The increase was due to higher composite
unit prices and a 0.4% increase in total KWH deliveries. This relatively
flat
change in KWH deliveries reflected a 3.2% increase in deliveries to commercial
customers primarily due to a 1.7% increase in the number of commercial
customers, partially offset by milder weather in the second quarter of
2006 (a
21% decrease in heating degree days and an 8.0% decrease in cooling degree
days)
compared to the same period in 2005. The $1 million decrease in distribution
revenues in the first six months of 2006 was primarily due to a 1.1% decrease
in
KWH deliveries, reflecting the milder temperatures in 2006 compared to
the same
period in 2005.
For
both periods,
transmission revenues increased primarily due to higher transmission prices,
which also resulted in higher transmission expenses as discussed below.
In the
first six months of 2006, other revenues also increased due to a $2 million
increase in the first quarter of 2006, compared to the same period in 2005,
for
a payment received 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
is
credited to Met-Ed’s customers, resulting in no net earnings effect.
Changes
in KWH sales
by customer class in the second quarter and the first six months of 2006
compared with the same periods in 2005 are summarized in the following
table:
|
|
Three
|
|
Six
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
|
Residential
|
|
|
(1.0
|
)%
|
|
(1.9
|
)%
|
Commercial
|
|
|
4.2
|
%
|
|
2.1
|
%
|
Industrial
|
|
|
15.8
|
%
|
|
14.0
|
%
|
Total
Retail Electric Generation Sales
|
|
|
5.6
|
%
|
|
3.7
|
%
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
(1.2
|
)%
|
|
(2.1
|
)%
|
Commercial
|
|
|
3.2
|
%
|
|
1.2
|
%
|
Industrial
|
|
|
(0.9
|
)%
|
|
(2.3
|
)%
|
Total
Distribution Deliveries
|
|
|
0.4
|
%
|
|
(1.1
|
|
|
|
|
|
|
|
|
|
Expenses
Total expenses decreased by $27 million and $12 million in the second quarter
and the first six months of 2006, respectively, compared with the same
periods
of 2005. The following table presents changes from the prior year by expense
category:
|
|
Three
|
|
Six
|
|
Expenses
- Changes
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
11
|
|
$
|
21
|
|
Other
operating costs
|
|
|
7
|
|
|
10
|
|
Provision
for
depreciation
|
|
|
(1
|
)
|
|
(2
|
)
|
Amortization
of regulatory assets
|
|
|
-
|
|
|
2
|
|
Deferral
of
new regulatory assets
|
|
|
(46
|
)
|
|
(46
|
)
|
General
taxes
|
|
|
2
|
|
|
3
|
|
Net
decrease in expenses
|
|
$
|
(27
|
)
|
$
|
(12
|
)
|
Purchased
power
costs increased in the second quarter and first six months of 2006 by $11
million and $21 million, respectively, due to increased purchases to meet
higher
customer demand and higher composite unit prices. These increases were
partially
offset by increased NUG cost deferrals of $6 million in the second quarter
and
$4 million in the first six months of 2006. 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 of $46 million reflected the May 4, 2006 PPUC approval
of
Met-Ed’s request to defer certain 2006 transmission-related costs. Met-Ed
implemented the deferral accounting in the second quarter of 2006, which
included $24 million for costs incurred in the first quarter of 2006 (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 in 2006 for expenses, construction expenditures and scheduled
debt
maturities, are expected to be met with a combination of cash from operations,
issuance of long-term debt, and short-term credit arrangements.
Changes
in Cash
Position
As
of June 30, 2006,
Met-Ed had $134,000 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 six months of 2006 and 2005 were as
follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Cash
earnings
(1)
|
|
$
|
56
|
|
$
|
55
|
|
Working
capital and other
|
|
|
2
|
|
|
33
|
|
Net
cash
provided from operating activities
|
|
$
|
58
|
|
$
|
88
|
|
|
|
|
|
|
|
|
|
(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 are a useful financial measure
because
it provides investors and management with an additional means of evaluating
its
cash-based operating performance.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Net
income
(GAAP)
|
|
$
|
58
|
|
$
|
32
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
21
|
|
|
23
|
|
Amortization
of regulatory assets
|
|
|
56
|
|
|
54
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(51
|
)
|
|
(48
|
)
|
Deferral
of
new regulatory assets
|
|
|
(46
|
)
|
|
-
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
23
|
|
|
(2
|
)
|
Other
non-cash
charges
|
|
|
(5
|
)
|
|
(4
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
56
|
|
$
|
55
|
|
|
|
|
|
|
|
|
|
The
$1 million
increase in cash earnings is described above under “Results of Operations.” The
$31 million working capital change primarily resulted from a $72 million
decrease in cash provided from the settlement of receivables, a $7 million
decrease in accrued taxes, a $3 million decrease in prepayments, a $2 million
increase in cash collateral returned to suppliers, and a $4 million decrease
in
other accrued liabilities, partially offset by $57 million in decreased
outflows
for accounts payable.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities was $2 million in first six months of 2006 compared
to $51
million in the same period of 2005. The decrease primarily reflects a $38
million decrease in long-term debt redemptions and a $34 million decrease
in
common stock dividend payments to FirstEnergy in the first six months of
2006,
partially offset by a $23 million decrease in short-term
borrowings.
As
of June 30, 2006,
Met-Ed had approximately $32 million of cash and temporary investments
(which
included short-term notes receivable from associated companies) and $139
million
of short-term borrowings. Met-Ed has authorization from the SEC, continued
by
FERC rules adopted as a result of EPACT’s repeal of PUCHA, 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 June 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.
As of June 30, 2006 the facility was drawn for $66 million. In June 2006,
the
facility was renewed until June 28, 2007. The annual facility fee is 0.125%
on
the entire finance limit.
Under
the terms of
Met-Ed’s senior note indenture, FMBs may no longer be issued so long as the
senior notes are outstanding. As of June 30, 2006, Met-Ed had the capability
to
issue $633 million of additional senior notes based upon FMB collateral.
Met-Ed
had no restrictions on the issuance of preferred stock.
Met-Ed,
FirstEnergy,
OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as Borrowers, have entered
into a syndicated $2 billion five-year revolving credit facility with a
syndicate of banks that expires in June 2010. Borrowings under the facility
are
available to each Borrower separately and mature on the earlier of 364
days from
the date of borrowing or the commitment expiration date, as the same may
be
extended. 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 $264 million as of June 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
June 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 six months of 2006 was
4.86%.
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 June 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 first six
months of 2006, Met-Ed’s cash used for investing activities totaled $57 million,
compared with $38 million in the same period of 2005. The increase primarily
resulted from a $13 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 half
of 2006, capital requirements for property additions are expected to be
about
$29 million. Met-Ed has additional requirements of approximately
$100 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.
Met-Ed's
capital
spending for the period 2006 through 2010 is expected to be about
$360 million, of which approximately $76 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 and interest rate fluctuations. FirstEnergy’s Risk
Policy Committee, comprised of members of senior management, provides general
oversight to risk management activities throughout the company.
Commodity
Price
Risk
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 normal
purchase and normal sale exception under SFAS 133. Contracts that are not
exempt
from such treatment include purchase power agreements with NUG entities
that
were structured pursuant to the Public Utility Regulatory Policy Act of
1978.
These non-trading contracts are adjusted to fair value at the end of each
quarter, with a corresponding regulatory asset recognized for above-market
costs. On April 1, 2006, Met-Ed elected to apply the normal purchase and
normal
sale exception to certain NUG power purchase agreements with 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 second quarter
and
first six months of 2006 is summarized in the following table:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
|
June
30, 2006
|
|
June
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
|
|
$
|
24
|
|
$
|
-
|
|
$
|
24
|
|
$
|
27
|
|
$
|
-
|
|
$
|
27
|
|
New
contract
value when entered
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
4
|
|
|
-
|
|
|
4
|
|
Change
in
techniques/assumptions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
|
(2
|
)
|
|
-
|
|
|
(2
|
)
|
|
(9
|
)
|
|
-
|
|
|
(9
|
)
|
Other
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
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
|
)
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
(2
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OCI
(pre-tax)
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Regulatory
liability
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 June 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
June 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)
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
15
|
Prices
based
on models(3)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
4
|
|
|
4
|
|
|
-
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
4
|
|
$
|
4
|
|
$
|
-
|
|
$
|
23
|
(1) For
the last two
quarters 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 June 30, 2006.
Equity
Price
Risk
Included
in Met-Ed's
nuclear decommissioning trusts are marketable equity securities carried
at their
market value of approximately $146 million and $142 million as of June 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 June 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
June 30, 2006 and December 31, 2005 were $359 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 September 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.
As
of June 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 $335 million and
$57 million, respectively. Penelec's $57 million is subject to the
pending resolution of taxable income issues associated with NUG trust fund
proceeds. The PPUC is reviewing a January 2006 change in Met-Ed’s and Penelec’s
NUG purchase power stranded cost accounting methodology. If the PPUC orders
Met-Ed and Penelec to reverse the change in accounting methodology, this
would
result in a pre-tax loss of $10.3 million for Met-Ed.
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 FERC has ordered the Presiding Judge to issue an initial
decision
by August 11, 2006.
On January 31, 2005, certain PJM transmission owners made three filings
with the FERC pursuant to a settlement agreement previously approved by
the
FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined
in two of the filings. In the first filing, the settling transmission owners
submitted a filing justifying continuation of their existing rate design
within
the PJM RTO. In the second filing, the settling transmission owners proposed
a
revised Schedule 12 to the PJM tariff designed to harmonize the rate
treatment of new and existing transmission facilities. Interventions and
protests were filed on February 22, 2005. In the third filing, Baltimore
Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate
for
transmission service provided within their respective zones. On May 31,
2005, the FERC issued an order on these cases. First, it set for hearing
the
existing rate design and indicated that it will issue a final order within
six
months. American Electric Power Company, Inc. filed
in
opposition proposing to create a "postage stamp" rate for high voltage
transmission facilities across PJM.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to 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. The
Companies, as part of the Responsible Pricing Alliance, intend to submit
a brief
on exceptions within thirty days of the initial decision. Following submission
of reply exceptions, the case is expected to be reviewed by the FERC with
a
decision anticipated in the fourth quarter of 2006.
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 below. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Met-Ed has deferred approximately
$46 million, representing transmission costs that were incurred from
January 1, 2006 through June 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 deferral will be
determined in the comprehensive rate filing proceeding discussed further
below.
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 its 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.
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
was to replace the entire FES supply at current market power prices without
corresponding regulatory authorization to increase its generation prices
to
customers, Met-Ed 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,
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,
Met-Ed and Penelec. Hearings are scheduled for late August 2006 and a
PPUC decision is expected early in the first quarter of 2007.
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 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
June 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 the result of adoption of mandatory reliability standards pursuant to
the
EPACT that could require additional material expenditures.
In
addition to the
above proceedings, FirstEnergy was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
FirstEnergy's motion to dismiss the matter was denied on June 2, 2006.
FirstEnergy has since filed an appeal, which is pending. A responsive pleading
to this matter has been filed. Also, the complaint has been amended to
include
an additional party. No estimate of potential liability has been undertaken
in
this matter.
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
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. 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
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$
|
264,999
|
|
$
|
262,097
|
|
$
|
556,751
|
|
$
|
556,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
146,875
|
|
|
139,292
|
|
|
308,516
|
|
|
289,549
|
|
Other
operating costs
|
|
|
48,133
|
|
|
62,794
|
|
|
86,475
|
|
|
116,607
|
|
Provision
for
depreciation
|
|
|
11,798
|
|
|
12,479
|
|
|
24,441
|
|
|
24,985
|
|
Amortization
of regulatory assets
|
|
|
12,979
|
|
|
13,118
|
|
|
27,794
|
|
|
26,303
|
|
Deferral
of
new regulatory assets
|
|
|
(11,815
|
)
|
|
-
|
|
|
(11,815
|
)
|
|
-
|
|
General
taxes
|
|
|
17,458
|
|
|
16,134
|
|
|
36,847
|
|
|
34,340
|
|
Total
expenses
|
|
|
225,428
|
|
|
243,817
|
|
|
472,258
|
|
|
491,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
39,571
|
|
|
18,280
|
|
|
84,493
|
|
|
64,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
1,627
|
|
|
938
|
|
|
3,997
|
|
|
1,268
|
|
Interest
expense
|
|
|
(11,599
|
)
|
|
(10,091
|
)
|
|
(22,135
|
)
|
|
(19,738
|
)
|
Capitalized
interest
|
|
|
422
|
|
|
264
|
|
|
769
|
|
|
389
|
|
Total
other
income (expense)
|
|
|
(9,550
|
)
|
|
(8,889
|
)
|
|
(17,369
|
)
|
|
(18,081
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
14,564
|
|
|
3,554
|
|
|
28,518
|
|
|
18,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
15,457
|
|
|
5,837
|
|
|
38,606
|
|
|
27,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
16
|
|
|
16
|
|
|
32
|
|
|
32
|
|
Unrealized
loss on available for sale securities
|
|
|
(14
|
)
|
|
(18
|
)
|
|
(18
|
)
|
|
(21
|
)
|
Other
comprehensive income (loss)
|
|
|
2
|
|
|
(2
|
)
|
|
14
|
|
|
11
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
1
|
|
|
(6
|
)
|
|
7
|
|
|
-
|
|
Other
comprehensive income, net of tax
|
|
|
1
|
|
|
4
|
|
|
7
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
15,458
|
|
$
|
5,841
|
|
$
|
38,613
|
|
$
|
27,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
49
|
|
$
|
35
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,044,000 and $4,184,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
119,103
|
|
|
129,960
|
|
Associated
companies
|
|
|
2,173
|
|
|
18,626
|
|
Other
|
|
|
9,625
|
|
|
12,800
|
|
Notes
receivable from associated companies
|
|
|
21,090
|
|
|
17,624
|
|
Prepaid
gross
receipts taxes
|
|
|
22,626
|
|
|
-
|
|
Prepayments
and other
|
|
|
3,874
|
|
|
7,936
|
|
|
|
|
178,540
|
|
|
186,981
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
2,095,438
|
|
|
2,043,885
|
|
Less
-
Accumulated provision for depreciation
|
|
|
793,523
|
|
|
784,494
|
|
|
|
|
1,301,915
|
|
|
1,259,391
|
|
Construction
work in progress
|
|
|
27,761
|
|
|
30,888
|
|
|
|
|
1,329,676
|
|
|
1,290,279
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
115,252
|
|
|
113,368
|
|
Non-utility
generation trusts
|
|
|
97,866
|
|
|
96,761
|
|
Other
|
|
|
531
|
|
|
918
|
|
|
|
|
213,649
|
|
|
211,047
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
877,651
|
|
|
882,344
|
|
Prepaid
pension costs
|
|
|
92,307
|
|
|
89,637
|
|
Other
|
|
|
37,150
|
|
|
38,289
|
|
|
|
|
1,007,108
|
|
|
1,010,270
|
|
|
|
$
|
2,728,973
|
|
$
|
2,698,577
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
$
|
220,801
|
|
$
|
261,159
|
|
Other
|
|
|
67,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
16,256
|
|
|
33,770
|
|
Other
|
|
|
46,783
|
|
|
38,277
|
|
Accrued
taxes
|
|
|
17,148
|
|
|
27,905
|
|
Accrued
interest
|
|
|
9,094
|
|
|
8,905
|
|
Other
|
|
|
17,796
|
|
|
19,756
|
|
|
|
|
394,878
|
|
|
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
|
|
|
1,197,889
|
|
|
1,202,551
|
|
Accumulated
other comprehensive loss
|
|
|
(302
|
)
|
|
(309
|
)
|
Retained
earnings
|
|
|
64,429
|
|
|
25,823
|
|
Total
common
stockholder's equity
|
|
|
1,367,828
|
|
|
1,333,877
|
|
Long-term
debt
and other long-term obligations
|
|
|
476,904
|
|
|
476,504
|
|
|
|
|
1,844,732
|
|
|
1,810,381
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
135,494
|
|
|
162,937
|
|
Accumulated
deferred income taxes
|
|
|
119,912
|
|
|
106,871
|
|
Retirement
benefits
|
|
|
105,980
|
|
|
102,046
|
|
Asset
retirement obligation
|
|
|
74,574
|
|
|
72,295
|
|
Other
|
|
|
53,403
|
|
|
54,275
|
|
|
|
|
489,363
|
|
|
498,424
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
$
|
2,728,973
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
38,606
|
|
$
|
27,221
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
24,441
|
|
|
24,985
|
|
Amortization
of regulatory assets
|
|
|
27,794
|
|
|
26,303
|
|
Deferral
of
new regulatory assets
|
|
|
(11,815
|
)
|
|
-
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(54,092
|
)
|
|
(35,946
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
13,206
|
|
|
2,647
|
|
Accrued
retirement benefit obligations
|
|
|
1,264
|
|
|
1,905
|
|
Accrued
compensation, net
|
|
|
(371
|
)
|
|
(2,386
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
Receivables
|
|
|
30,485
|
|
|
79,602
|
|
Prepayments
and other current assets
|
|
|
(18,565
|
)
|
|
(22,107
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(9,008
|
)
|
|
(20,333
|
)
|
Accrued
taxes
|
|
|
(10,756
|
)
|
|
10,728
|
|
Accrued
interest
|
|
|
190
|
|
|
(34
|
)
|
Other
|
|
|
8,817
|
|
|
4,365
|
|
Net
cash
provided from operating activities
|
|
|
40,196
|
|
|
96,950
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
26,642
|
|
|
-
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
(3,521
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
(36,608
|
)
|
Dividend
Payments -
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
(30,000
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
26,642
|
|
|
(70,129
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(60,747
|
)
|
|
(33,683
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(3,466
|
)
|
|
7,011
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
51,536
|
|
|
24,127
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(51,536
|
)
|
|
(24,127
|
)
|
Other,
net
|
|
|
(2,611
|
)
|
|
(150
|
)
|
Net
cash used
for investing activities
|
|
|
(66,824
|
)
|
|
(26,822
|
)
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
14
|
|
|
(1
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
35
|
|
|
36
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
49
|
|
$
|
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 June 30, 2006, and the related consolidated statements
of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2006 and 2005 and the consolidated statement of
cash
flows for the six-month period ended June 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
August
4,
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
second quarter of 2006 increased to $15 million, compared to $6 million in
the second quarter of 2005. In the first six months of 2006, net income
increased to $39 million, compared to $27 million in the first six months
of
2005. The increase in net income for both periods resulted from lower other
operating costs, deferral of new regulatory assets, and higher revenues
which
were partially offset by higher purchased power costs, general taxes and
interest expense, as discussed below.
Revenues
Revenues
increased
by $3 million in the second quarter of 2006 and $1 million in the first
six
months of 2006, compared to the same periods of 2005. Increases in both
periods
were due primarily to higher retail generation revenues partially offset
by
lower transmission and distribution revenues.
Retail generation
revenues increased by $12 million in the second quarter of 2006 and $23
million
for the first six months of 2006 primarily due to higher KWH sales to industrial
customers and higher composite unit prices in all customer classes. Industrial
sales increased $8 million for the second quarter of 2006 and $15 million
for
the first six months of 2006 primarily due to the return of customers to
Penelec
from alternative suppliers. Generation service provided by alternative
suppliers
as a percent of total industrial sales in Penelec’s service area decreased by
12.1 percentage points and 13.2 percentage points in the second quarter
and the
first six months of 2006, respectively.
The
higher composite
unit prices also increased generation revenues from residential customers
by
$1 million and $3 million and from commercial customers by $3 million
and $5 million in the second quarter and first six months of 2006, respectively.
Distribution
revenues decreased by $1 million in the second quarter of 2006 and by $3
million in the first six months of 2006, compared with the same periods
of 2005.
The decreases were primarily due to 1.1% and 1.9% decreases in KWH deliveries
in
the second quarter and first six months of 2006, respectively. Reduced
KWH
deliveries reflected milder temperatures in both periods of 2006 compared
with
the same periods of 2005. Those reductions were partially offset by slightly
higher composite unit prices during the periods. Transmission revenues
decreased
by $8 million in the second quarter of 2006 and $20 million in the first
six
months of 2006 due to lower transmission load requirements and lower prices.
The
decreased loads for the first six months of 2006 (and related lower congestion
revenues) resulted from milder temperatures, as demonstrated by a 40.4%
decrease
in cooling degree days and a 14.4% decrease in heating degree days compared
to
the same period in 2005, which resulted in decreased transmission expenses
discussed further below. For
the first six
months of 2006, other revenues also increased 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 second quarter and first six months of 2006 compared
to
the respective periods in 2005 are summarized in the following
table:
|
|
Three
|
|
Six
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
|
Residential
|
|
|
(1.9
|
)%
|
|
(2.1
|
)%
|
Commercial
|
|
|
-
|
|
|
(0.7
|
)%
|
Industrial
|
|
|
14.8
|
%
|
|
14.9
|
%
|
Total
Retail Electric Generation Sales
|
|
|
3.8
|
%
|
|
3.3
|
%
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
(2.1
|
)%
|
|
(2.2
|
)%
|
Commercial
|
|
|
(1.0
|
)%
|
|
(1.7
|
)%
|
Industrial
|
|
|
(0.5
|
)%
|
|
(1.8
|
)%
|
Total
Distribution Deliveries
|
|
|
(1.1
|
)%
|
|
(1.9
|
)%
|
|
|
|
|
|
|
|
|
Expenses
Total
expenses
decreased by $19 million or 7.5% in the second quarter of 2006 and $20
million
or 4.0% in the first six months of 2006 compared with the same periods
in 2005.
The following table presents changes from the prior year by expense category:
|
|
Three
|
|
Six
|
Expenses
Changes
|
|
Months
|
|
Months
|
|
|
(In
millions)
|
Increase
(Decrease)
|
|
|
|
|
Purchased
power costs
|
|
$
|
8
|
|
$
|
19
|
Other
operating costs
|
|
|
(15)
|
|
|
(30)
|
Provision
for
depreciation
|
|
|
(1)
|
|
|
(1)
|
Amortization
of regulatory assets
|
|
|
-
|
|
|
1
|
Deferral
of
new regulatory assets
|
|
|
(12)
|
|
|
(12)
|
General
taxes
|
|
|
1
|
|
|
3
|
Net
decrease in expenses
|
|
$
|
(19)
|
|
$
|
(20)
|
|
|
|
|
|
|
|
Purchased
power
costs increased by $8 million or 5.4% in the second quarter and $19 million
or
6.6% in the first six months of 2006 compared to the same periods in 2005.
The
increases in both periods were primarily attributable to higher unit costs
from
non-affiliated suppliers and increased KWH purchased to meet retail generation
sales requirements. These increases were partially offset by increased
NUG
expense deferrals of $4 million in both the second quarter and in the first
six
months of 2006. Other operating costs decreased due to lower transmission
expenses resulting from lower congestion charges. Expenses were further
reduced
due to higher levels of construction activities in the second quarter of
2006
compared to a higher level of maintenance activities in the same period
of 2005
for energy delivery operations and reliability initiatives. The deferral
of new
regulatory assets of $12 million reflected the May 4, 2006 PPUC approval
of
Penelec’s request to defer certain 2006 transmission-related costs. Penelec
implemented the deferral accounting in the second quarter of 2006, which
included $4 million for costs incurred in the first quarter of 2006 (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 in 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 June 30,
2006, Penelec had $49,000 of cash and cash equivalents compared with $35,000
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 six months of 2006 and 2005 were as follows:
|
|
Six
Months Ended
|
|
|
June
30,
|
Operating
Cash Flows
|
|
2006
|
|
2005
|
|
|
(In
millions)
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
39
|
|
$
|
45
|
Working
capital and other
|
|
|
1
|
|
|
52
|
Net
cash
provided from operating activities
|
|
$
|
40
|
|
$
|
97
|
|
|
|
|
|
|
|
(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 are a useful financial measure
because
it provides investors and management with an additional means of evaluating
its
cash-based operating performance.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Reconciliation
of Cash Earnings
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
39
|
|
$
|
27
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
24
|
|
|
25
|
|
Amortization
of regulatory assets
|
|
|
28
|
|
|
26
|
|
Deferral
of
new regulatory assets
|
|
|
(12
|
)
|
|
-
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(54
|
|
|
(36
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
13
|
|
|
3
|
|
Other
non-cash
items
|
|
|
1
|
|
|
-
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
39
|
|
$
|
45
|
|
|
|
|
|
|
|
|
|
The
$6 million
decrease in cash earnings is described above under “Results of Operations.” The
$51 million decrease from working capital primarily resulted from a
decrease of $49 million in cash provided from the settlement of receivables
and
a $21 million decrease in accrued taxes, partially offset by decreased
outflows of $11 million for accounts payable and $4 million for
prepayments.
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities was $27 million in the first six months of 2006
compared to net cash used for financing activities of $70 million in the
first six months of 2005. The change reflects a $63 million increase in
short-term borrowings, a $30 million reduction in common stock dividend
payments to FirstEnergy and a $4 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
$288
million of short-term indebtedness as of June 30, 2006. Penelec has
authorization from the SEC, continued by FERC rules adopted as a result
of
EPACT's repeal of PUHCA, 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 June 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 June 30, 2006 the facility was drawn for $67 million.
In June 2006, the facility was renewed until July 28, 2007. 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 June 30, 2006, Penelec had
the ability to issue $50 million of additional senior notes based upon FMB
collateral. Penelec has no restrictions on the issuance of preferred
stock.
Penelec,
FirstEnergy, OE,
Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as Borrowers, have entered into
a syndicated $2 billion five-year revolving credit facility which expires
in June 2010. Borrowings under the facility are available to each Borrower
separately and mature on the earlier of 364 days from the date of borrowing
or
the commitment termination date, as the same may be extended. 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 $258 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%. As
of
June 30, 2006, Penelec’s debt to total capitalization as defined under the
revolving credit facility was 36%.
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
six months of 2006 was 4.86%.
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 six months of 2006, net cash used for investing activities
totaled
$67 million compared to $27 million in the first six months of 2005. The
increase primarily resulted from $27 million in increased property additions
and
a $10 million increase in loans to associated companies. Expenditures for
property additions primarily support Penelec’s energy delivery operations and
reliability initiatives.
During
the last half
of 2006, capital requirements for property additions are expected to be
approximately $46 million. Penelec’s capital spending for the period
2006-2010 is expected to be approximately $496 million, of which
approximately $110 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 and interest rate fluctuations.
FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
provides general oversight to risk management activities throughout the
Company.
Commodity
Price
Risk
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
purchase power agreements with NUG entities that were structured pursuant
to the
Public Utility Regulatory Policy Act of 1978. These
non-trading
contracts are adjusted to fair value at the end of each quarter, with a
corresponding regulatory asset recognized for above-market costs. On April
1,
2006, Penelec elected to apply the normal purchase and normal sale exception
to
certain NUG power purchase agreements with 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 second quarter and first six months of 2006 is summarized
in the following table:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
Increase
(Decrease) in the Fair Value
|
|
June
30, 2006
|
|
June
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
|
|
$
|
30
|
|
$
|
-
|
|
$
|
30
|
|
$
|
27
|
|
$
|
-
|
|
$
|
27
|
New
contract
value when entered
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Additions/change
in value of existing contracts
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
Change
in
techniques/assumptions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Settled
contracts
|
|
|
(4)
|
|
|
-
|
|
|
(4)
|
|
|
(3)
|
|
|
-
|
|
|
(3)
|
Other
|
|
|
(14)
|
|
|
-
|
|
|
(14)
|
|
|
(14)
|
|
|
-
|
|
|
(14)
|
Net
Assets - Derivative Contracts
at
End
of Period (1)
|
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
$
|
12
|
|
$
|
-
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
|
$
|
(4)
|
|
$
|
-
|
|
$
|
(4)
|
|
$
|
(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
increase in value of existing contracts, settled contracts and changes
in
techniques/assumptions.
Derivatives
are
included on the Consolidated Balance Sheet as of June 30, 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
June 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
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
8
|
Prices
based
on models(3)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
2
|
|
|
-
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(3)
|
|
$
|
3
|
|
$
|
3
|
|
$
|
2
|
|
$
|
2
|
|
$
|
2
|
|
$
|
-
|
|
$
|
12
|
(1) For
the last two
quarters 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
June 30, 2006. Penelec estimates that if energy commodity prices
experienced an adverse 10% change, net income for the next 12 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 $64 million and $62 million as of June 30,
2006 and December 31, 2005, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $6 million reduction
in fair
value as of June 30, 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 $135 million and
$163 million as of June 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.
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 FERC has ordered the Presiding Judge to issue an initial decision by
August 11, 2006.
On
January 31, 2005, certain PJM transmission owners made three filings with
the FERC pursuant to a settlement agreement previously approved by the
FERC.
JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two
of the filings. In the first filing, the settling transmission owners submitted
a filing justifying continuation of their existing rate design within the
PJM
RTO. In the second filing, the settling transmission owners proposed a
revised
Schedule 12 to the PJM tariff designed to harmonize the rate treatment of
new and existing transmission facilities. Interventions and protests were
filed
on February 22, 2005. In the third filing, Baltimore Gas and Electric
Company and Pepco Holdings, Inc. requested a formula rate for transmission
service provided within their respective zones. On May 31, 2005, the FERC
issued an order on these cases. First, it set for hearing the existing
rate
design and indicated that it will issue a final order within six months.
American Electric Power Company, Inc. filed
in
opposition proposing to create a "postage stamp" rate for high voltage
transmission facilities across PJM.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to 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. The
Companies, as part of the Responsible Pricing Alliance, intend to submit
a brief
on exceptions within thirty days of the initial decision. Following submission
of reply exceptions, the case is expected to be reviewed by the FERC with
a
decision anticipated in the fourth quarter of 2006.
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 below. On May 4, 2006, the PPUC approved
the modified request. Accordingly, Penelec deferred approximately
$12 million, representing transmission costs that were incurred from
January 1, 2006 through June 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
below.
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.
The
wholesale power
sales agreement, as modified by the Tolling Agreement, requires Met-Ed
and
Penelec to satisfy the portion of their PLR obligations currently supplied
by
FES from unaffiliated suppliers at prevailing prices, which are likely
to be
higher than the current price charged by FES under the current agreement
and, as
a result, Met-Ed’s and Penelec’s purchased power costs could materially
increase. If Met-Ed and Penelec were to replace the entire FES supply at
current
market power prices without corresponding regulatory authorization to increase
their generation prices to customers, each company would likely incur a
significant increase in operating expenses and experience a material
deterioration in credit quality metrics. Under such a scenario, each company's
credit profile would no longer be expected to support an investment grade
rating
for its fixed income securities. There can be no assurance, however, that
if FES
ultimately determines to terminate, or significantly modify the agreement,
timely regulatory relief will be granted by the PPUC pursuant to the
April 10, 2006 comprehensive rate filing discussed below, or, to the extent
granted, adequate to mitigate such adverse consequences.
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. 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,
Met-Ed and Penelec. Hearings are scheduled for late August 2006 and a
PPUC decision is expected early in the first quarter of 2007.
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
June 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 the result of adoption of mandatory reliability standards pursuant to
the
EPACT that could require additional material expenditures.
In
addition to the
above proceedings, FirstEnergy was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
FirstEnergy's motion to dismiss the matter was denied on June 2, 2006.
FirstEnergy has since filed an appeal, which is pending. A responsive pleading
to this matter has been filed. Also, the complaint has been amended to
include
an additional party. No estimate of potential liability has been undertaken
in
this matter.
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
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. 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.
SUBSEQUENT
EVENTS
Pennsylvania
Law Change
On
July 12, 2006,
the Governor of Pennsylvania signed House Bill 859, which increases the
net
operating loss deduction allowed for the corporate net income tax from
$2
million to $3 million, or the greater of 12.5% of taxable income. As a
result,
Penelec expects to recognize a net operating loss benefit of $2.2 million
(net
of federal tax benefit) in the third quarter of 2006.
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 June 30, 2006, there were no changes in the registrants' internal
control
over financial reporting that have materially affected, or are reasonably
likely
to materially affect, the registrants' internal control over financial
reporting.
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 June 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
|
|
|
|
April
1-30,
|
|
|
May
1-31,
|
|
|
June
1-30,
|
|
|
Second
|
|
|
|
2006
|
|
|
2006
|
|
|
2006
|
|
|
Quarter
|
Total
Number
of Shares Purchased (a)
|
|
|
132,910
|
|
|
481,150
|
|
|
470,009
|
|
|
1,084,069
|
Average
Price
Paid per Share
|
|
$
|
49.82
|
|
$
|
52.26
|
|
$
|
53.10
|
|
$
|
52.33
|
Total
Number
of Shares Purchased
|
|
|
|
|
|
|
|
|
|
|
|
|
As
Part of
Publicly Announced Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
or
Programs
(b)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
Maximum
Number
(or Approximate Dollar
|
|
|
|
|
|
|
|
|
|
|
|
|
Value)
of
Shares that May Yet Be
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Under the Plans or Programs
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
(b)
|
On
June 20, 2006, FirstEnergy Corp. announced that its Board of
Directors has authorized a share repurchase program for up to
12 million
shares of common stock. At management’s discretion, shares may be acquired
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 purchase any
shares and
the program may be terminated at any
time.
|
ITEM
4. SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a)
|
The
annual
meeting of FirstEnergy shareholders was held on May 16, 2006.
|
(b)
|
At
this
meeting, the following persons were elected to FirstEnergy's
Board of
Directors for one-year terms:
|
|
Number
of Votes
|
|
For
|
|
Withheld
|
|
|
|
|
Anthony
J.
Alexander
|
|
193,156,658
|
|
|
90,938,042
|
Dr.
Carol A.
Cartwright
|
|
164,744,513
|
|
|
119,350,187
|
William
T.
Cottle
|
|
183,961,100
|
|
|
100,133,600
|
Robert
B.
Heisler, Jr.
|
|
268,681,345
|
|
|
15,413,355
|
Russell
W.
Maier
|
|
186,309,666
|
|
|
97,785,034
|
George
M.
Smart
|
|
183,516,902
|
|
|
100,577,798
|
Wes
M.
Taylor
|
|
186,519,704
|
|
|
97,574,996
|
Jesse
T.
Williams, Sr.
|
|
185,540,843
|
|
|
98,553,857
|
The
term of office
for the following Directors continued after the shareholders meeting and
expires
in 2007: Paul T. Addison, Ernest J. Novak, Jr., Catherine A. Rein and Robert
C.
Savage. The following Directors retired from the Board effective May 16,
2006:
Robert N. Pokelwaldt, Paul J. Powers and Dr. Patricia K. Woolf.
(c) (i) At
this meeting, the
appointment of PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as auditor for the year 2006 was ratified:
Number
of Votes
|
For
|
|
Against
|
|
Abstentions
|
|
|
|
|
|
278,799,686
|
|
|
2,661,331
|
|
|
2,633,683
|
(ii) At
this meeting, a
shareholder proposal recommending that the Board of Directors adopt simple
majority shareholder voting and make it applicable to the greatest number
of
governance issues practicable was approved (approval required a favorable
vote
of a majority of the votes cast):
Number
of Votes
|
|
|
|
|
|
|
Broker
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
184,910,522
|
|
|
67,099,919
|
|
|
4,832,226
|
|
|
27,252,033
|
Based
on this
result, the Board of Directors will further review this proposal
and
consider
the
appropriate
steps to take in response.
(iii) At
this meeting, a
shareholder proposal urging the Board of Directors to seek shareholder
approval
of future severance agreements with senior executives that provide benefits
in
an amount exceeding 2.99 times the sum of the executives' base salary plus
bonus
was not approved (approval required a favorable vote of a majority of the
votes
cast):
Number
of Votes
|
|
|
|
|
|
|
Broker
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
123,673,866
|
|
|
128,388,870
|
|
|
4,780,131
|
|
|
27,251,833
|
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
FirstEnergy
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
OE
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
Penn
|
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
CEI
|
|
|
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
TE
|
|
|
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
JCP&L
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.3
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.2
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
Met-Ed
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
Penelec
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
Pursuant
to reporting requirements of respective financings, FirstEnergy, OE, JCP&L,
Met-Ed and Penelec are required to file fixed charge ratios as an exhibit
to
this Form 10-Q. CEI, TE and Penn do not have similar financing reporting
requirements and have not filed their respective fixed charge
ratios.
Pursuant
to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to
this Form 10-Q any instrument with respect to long-term debt if the
respective total amount of securities authorized thereunder does not exceed
10%
of their respective total assets of FirstEnergy and its subsidiaries on
a
consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or
Penelec but hereby agree to furnish to the Commission on request any such
documents.
SIGNATURE
Pursuant
to the
requirements of the Securities Exchange Act of 1934, each Registrant has
duly
caused this report to be signed on its behalf by the undersigned thereunto
duly
authorized.
August
7,
2006
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FIRSTENERGY
CORP.
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Registrant
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OHIO
EDISON COMPANY
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Registrant
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THE
CLEVELAND ELECTRIC
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ILLUMINATING
COMPANY
|
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Registrant
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THE
TOLEDO EDISON COMPANY
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|
Registrant
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PENNSYLVANIA
POWER COMPANY
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Registrant
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JERSEY
CENTRAL POWER & LIGHT COMPANY
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Registrant
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METROPOLITAN
EDISON COMPANY
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Registrant
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PENNSYLVANIA
ELECTRIC COMPANY
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Registrant
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/s/ Harvey
L.
Wagner
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Harvey L. Wagner
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Vice
President, Controller
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and
Chief
Accounting Officer
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