Unassociated Document
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D. C. 20549
FORM
10-Q
(Mark
One)
[X] QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the
quarterly period ended September 30, 2007
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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Address;
and Telephone Number
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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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333-145140-01
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FIRSTENERGY
SOLUTIONS CORP.
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31-1560186
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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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1-2578
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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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1-3141
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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 ( )
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FirstEnergy
Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland
Electric Illuminating Company and Pennsylvania Electric
Company
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Yes
( ) No (X)
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The
Toledo
Edison Company, Jersey Central Power & Light Company and Metropolitan
Edison Company
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Indicate
by check
mark whether any of the registrants 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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FirstEnergy
Solutions Corp., Ohio Edison 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 any of the registrants is a shell company (as defined in Rule
12b-2
of the Exchange 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
|
CLASS
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|
FirstEnergy
Corp., $.10 par value
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304,835,407
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FirstEnergy
Solutions Corp., no par value
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7
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Ohio
Edison
Company, no par value
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60
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The
Cleveland
Electric Illuminating Company, no par value
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67,930,743
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The
Toledo
Edison Company, $5 par value
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29,402,054
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Jersey
Central
Power & Light Company, $10 par value
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14,421,637
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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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4,427,577
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FirstEnergy
Corp. is
the sole holder of FirstEnergy Solutions Corp., 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.
This
combined Form
10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio
Edison 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.
FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and
are
therefore filing this Form 10-Q with the reduced disclosure format specified
in
General Instruction H(2) to Form 10-Q.
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 include declarations regarding management’s intents, beliefs
and current expectations. These statements typically contain, but are not
limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate”
and similar words. Forward-looking statements involve estimates, assumptions,
known and unknown risks, uncertainties and other factors that may cause actual
results, performance or achievements to be materially different from any future
results, performance or achievement expressed or implied by such forward-looking
statements. Actual results may differ materially due to the speed and nature
of
increased competition in the electric utility industry and legislative and
regulatory changes affecting how generation rates will be determined following
the expiration of existing rate plans in Ohio and Pennsylvania, 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’s regulated utilities to collect transition and other
charges or to recover increased transmission costs, maintenance costs being
higher than anticipated, other legislative and regulatory changes including
revised environmental requirements, 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 or other potential regulatory
initiatives, adverse regulatory or legal decisions and outcomes (including,
but
not limited to, the revocation of necessary licenses or operating permits and
oversight) by the NRC (including, but not limited to, the Demand for Information
issued to FENOC on May 14, 2007) as disclosed in the registrants’ SEC
filings, the timing and outcome of various proceedings before the PUCO
(including, but not limited to, the distribution rate cases and the generation
supply plan filing for the Ohio Companies and the successful resolution of
the
issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and
RCP,
including the deferral of fuel costs) and the PPUC (including the resolution
of
the Petitions for Review filed with the Commonwealth Court of Pennsylvania
with
respect to the transition rate plan for Met-Ed and Penelec), the continuing
availability of generating units and their the ability to operate at, or near
full capacity, the ability to comply with applicable state and federal
reliability standards, the inability to accomplish or realize anticipated
benefits from strategic goals (including employee workforce initiatives), the
ability to improve electric commodity margins and to experience growth in the
distribution business, the ability to access the public securities and other
capital markets and the cost of such capital, the outcome, cost and other
effects of present and potential legal and administrative proceedings and claims
related to the August 14, 2003 regional power outage, the risks
and other factors discussed from time to time in the registrants’ SEC filings,
and other similar factors. The foregoing review of factors should not be
construed as exhaustive. New factors emerge from time to time, and it is not
possible to predict all such factors, nor assess the impact of any such factor
on the registrants’ business or the extent to which any factor, or combination
of factors, may cause results to differ materially from those contained in
any
forward-looking statements. Also, 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 and each such rating should be evaluated independently of any other
rating. 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-iv
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Part
I. Financial
Information
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Items
1. and 2. - Financial
Statements and Management’s Discussion and Analysis of Financial Condition
and
Results of Operations.
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Notes
to
Consolidated Financial Statements
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1-34
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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35
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Consolidated
Statements of Comprehensive Income
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36
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Consolidated
Balance Sheets
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37
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Consolidated
Statements of Cash Flows
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38
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Report
of
Independent Registered Public Accounting Firm
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39
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Management's
Discussion and Analysis of Financial Condition and
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40-80
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Results
of Operations
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FirstEnergy
Solutions
Corp.
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Consolidated
Statements of Income and Comprehensive Income
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81
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Consolidated
Balance Sheets
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82
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Consolidated
Statements of Cash Flows
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83
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Report
of
Independent Registered Public Accounting Firm
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84
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Management's
Narrative Analysis of Results of Operations
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85-87
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Ohio
Edison
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
Narrative Analysis of Results of Operations
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92-93
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The
Cleveland Electric
Illuminating Company
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Consolidated
Statements of Income and Comprehensive Income
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94
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Consolidated
Balance Sheets
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95
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Consolidated
Statements of Cash Flows
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96
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Report
of
Independent Registered Public Accounting Firm
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97
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Management's
Narrative Analysis of Results of Operations
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98-99
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The
Toledo Edison
Company
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Consolidated
Statements of Income and Comprehensive Income
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100
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Consolidated
Balance Sheets
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101
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Consolidated
Statements of Cash Flows
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102
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Report
of
Independent Registered Public Accounting Firm
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103
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Management's
Narrative Analysis of Results of Operations
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104-105
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TABLE
OF
CONTENTS (Cont'd)
Jersey
Central Power & Light
Company
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Pages
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Consolidated
Statements of Income and Comprehensive Income
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106
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Consolidated
Balance Sheets
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107
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Consolidated
Statements of Cash Flows
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108
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Report
of
Independent Registered Public Accounting Firm
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109
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Management's
Narrative Analysis of Results of Operations
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110-111
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Metropolitan
Edison
Company
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Consolidated
Statements of Income and Comprehensive Income
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112
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Consolidated
Balance Sheets
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113
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Consolidated
Statements of Cash Flows
|
114
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Report
of
Independent Registered Public Accounting Firm
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115
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Management's
Narrative Analysis of Results of Operations
|
116-117
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Pennsylvania
Electric
Company
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Consolidated
Statements of Income and Comprehensive Income
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118
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Consolidated
Balance Sheets
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119
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Consolidated
Statements of Cash Flows
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120
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|
Report
of
Independent Registered Public Accounting Firm
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121
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Management's
Narrative Analysis of Results of Operations
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122-123
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Combined
Management’s Discussion
and Analysis of Registrant Subsidiaries
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124-137
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk.
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138
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Item
4. Controls
and Procedures.
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138
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Part
II. Other Information
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Item
1. Legal
Proceedings.
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139
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Item
1A. Risk
Factors.
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139
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Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds.
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139
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Item
6. Exhibits.
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140
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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
|
|
Companies
|
OE,
CEI, TE,
JCP&L, Met-Ed and Penelec
|
|
FENOC
|
FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
|
|
FES
|
FirstEnergy
Solutions Corp., provides energy-related products and
services
|
|
FESC
|
FirstEnergy
Service Company, provides legal, financial, and other corporate support
services
|
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FGCO
|
FirstEnergy
Generation Corp., owns and operates non-nuclear generating
facilities
|
|
FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
|
|
FSG
|
FirstEnergy
Facilities Services Group, LLC, former 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
Funding
|
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
|
|
OE
|
Ohio
Edison
Company, an Ohio electric utility operating subsidiary
|
|
Ohio
Companies
|
CEI,
OE and
TE
|
|
Penelec
|
Pennsylvania
Electric Company, a Pennsylvania electric utility operating
subsidiary
|
|
Penn
|
Pennsylvania
Power Company, a Pennsylvania electric utility operating subsidiary
of
OE
|
|
Pennsylvania
Companies
|
Met-Ed,
Penelec and Penn
|
|
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
|
|
APIC
|
Additional
Paid-In Capital
|
|
AOCL
|
Accumulated
Other Comprehensive Loss
|
|
ARO
|
Asset
Retirement Obligation
|
|
BGS
|
Basic
Generation Service
|
|
CAIR
|
Clean
Air
Interstate Rule
|
|
CAL
|
Confirmatory
Action Letter
|
|
CAMR
|
Clean
Air
Mercury Rule
|
|
CBP
|
Competitive
Bid Process
|
|
CO2
|
Carbon
Dioxide
|
|
DOJ
|
United
States
Department of Justice
|
DRA
|
Division
of
Ratepayer Advocate
|
ECAR
|
East
Central
Area Reliability Coordination Agreement
|
EIS
|
Energy
Independence Strategy
|
EITF
|
Emerging
Issues Task Force
|
EITF
06-11
|
EITF
Issue No.
06-11, “Accounting for Income Tax Benefits of Dividends or
Share-Based
Payment
Awards”
|
EMP
|
Energy
Master
Plan
|
EPA
|
Environmental
Protection Agency
|
EPACT
|
Energy
Policy
Act of 2005
|
ERO
|
Electric
Reliability Organization
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy
Regulatory Commission
|
FIN
|
FASB
Interpretation
|
FIN
39-1
|
FIN
39-1,
“Amendment of FASB Interpretation No. 39”
|
FIN
46R
|
FIN
46
(revised December 2003), "Consolidation of Variable Interest
Entities"
|
FIN
47
|
FIN
47,
"Accounting for Conditional Asset Retirement Obligations - an
interpretation of FASB
Statement
No. 143"
|
GLOSSARY
OF
TERMS,
Cont’d.
FIN
48
|
FIN
48,
“Accounting for Uncertainty in Income Taxes - an interpretation of
FASB
Statement
No.
109”
|
FMB
|
First
Mortgage
Bonds
|
GAAP
|
Accounting
Principles Generally Accepted in the United States
|
GHG
|
Greenhouse
Gases
|
IRS
|
Internal
Revenue Service
|
kV
|
Kilovolt
|
KWH
|
Kilowatt-hours
|
LOC
|
Letter
of
Credit
|
MEIUG
|
Met-Ed
Industrial Users Group
|
MISO
|
Midwest
Independent Transmission System Operator, Inc.
|
Moody’s
|
Moody’s
Investors Service
|
MOU
|
Memorandum
of
Understanding
|
MW
|
Megawatts
|
NAAQS
|
National
Ambient Air Quality Standards
|
NERC
|
North
American
Electric Reliability Corporation
|
NJBPU
|
New
Jersey
Board of Public Utilities
|
NOPR
|
Notice
of
Proposed Rulemaking
|
NOV
|
Notice
of
Violation
|
NOX
|
Nitrogen
Oxide
|
NRC
|
Nuclear
Regulatory Commission
|
NSR
|
New
Source
Review
|
NUG
|
Non-Utility
Generation
|
NUGC
|
Non-Utility
Generation Charge
|
OCA
|
Office
of
Consumer Advocate
|
OCC
|
Office
of the
Ohio Consumers’ Counsel
|
OVEC
|
Ohio
Valley
Electric Corporation
|
PICA
|
Penelec
Industrial Customer Alliance
|
PJM
|
PJM
Interconnection L. L. C.
|
PLR
|
Provider
of
Last Resort
|
PPUC
|
Pennsylvania
Public Utility Commission
|
PRP
|
Potentially
Responsible Party
|
PSA
|
Power
Supply
Agreement
|
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
|
|
RTO
|
Regional
Transmission Organization
|
|
RTOR
|
Regional
Through and Out Rates
|
|
S&P
|
Standard
&
Poor’s Ratings Service
|
|
SBC
|
Societal
Benefits Charge
|
|
SEC
|
U.S.
Securities and Exchange Commission
|
|
SECA
|
Seams
Elimination Cost Adjustment
|
|
SFAS
|
Statement
of
Financial Accounting Standards
|
|
SFAS
107
|
SFAS
No. 107,
“Disclosure about Fair Value of Financial Instruments”
|
|
SFAS
109
|
SFAS
No. 109,
“Accounting for Income Taxes”
|
|
SFAS
123(R)
|
SFAS
No.
123(R), "Share-Based Payment"
|
|
SFAS
133
|
SFAS
No. 133,
“Accounting for Derivative Instruments and Hedging
Activities”
|
|
SFAS
142
|
SFAS
No. 142,
“Goodwill and Other Intangible Assets”
|
|
SFAS
143
|
SFAS
No. 143,
“Accounting for Asset Retirement Obligations”
|
|
SFAS
157
|
SFAS
No. 157,
“Fair Value Measurements”
|
|
SFAS
159
|
SFAS
No. 159,
“The Fair Value Option for Financial Assets and Financial Liabilities
–
Including an
Amendment
of FASB Statement No. 115”
|
|
SIP
|
State
Implementation Plan(s) Under the Clean Air Act
|
|
SNCR
|
Selective
Non-Catalytic Reduction
|
|
SO2
|
Sulfur
Dioxide
|
|
SRM
|
Special
Reliability Master
|
|
TBC
|
Transition
Bond Charge
|
|
TMI-2
|
Three
Mile
Island Unit 2
|
|
VIE
|
Variable
Interest Entity
|
|
PART
I.
FINANCIAL INFORMATION
ITEMS
1. AND
2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
FIRSTENERGY
CORP. AND SUBSIDIARIES
FIRSTENERGY
SOLUTIONS CORP. AND SUBSIDIARIES
OHIO
EDISON
COMPANY AND SUBSIDIARIES
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE
TOLEDO
EDISON 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 subsidiaries: FENOC, FES and its subsidiaries FGCO and
NGC, and FESC.
FirstEnergy
and its
subsidiaries follow GAAP and comply with the regulations, orders, policies
and
practices prescribed by the SEC, FERC and, as applicable, the 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,
2006 for FirstEnergy and the Companies. The consolidated unaudited financial
statements of FirstEnergy, FES 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 2006 have been classified as discontinued operations on the
Consolidated Statements of Income (see Note 4). As discussed in
Note 14, interim period segment reporting in 2006 was reclassified to
conform with the current year business segment organizations and operations.
Certain prior year amounts have been reclassified to conform to the current
year
presentation. Unless otherwise indicated, defined terms used herein have the
meanings set forth in the accompanying Glossary of Terms.
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 8)
when it is determined to be the VIE's primary beneficiary. Investments in
non-consolidated affiliates over which FirstEnergy and its subsidiaries have
the
ability to exercise significant influence, but not control (20-50% owned
companies, joint ventures and partnerships) follow the equity method of
accounting. Under the equity method, the interest in the entity is reported
as
an investment in the Consolidated Balance Sheets and the percentage share of
the
entity’s earnings is reported in the Consolidated Statements of
Income.
The
consolidated
financial statements as of September 30, 2007 and for the three-month and
nine-month periods ended September 30, 2007 and 2006 have been reviewed by
PricewaterhouseCoopers LLP, an independent registered public accounting firm.
Their report (dated October 31, 2007) is included on page 39. The report of
PricewaterhouseCoopers LLP states that they did not audit and they do not
express an opinion on that unaudited financial information. Accordingly, the
degree of reliance on their report on such information should be restricted
in
light of the limited nature of the review procedures applied.
PricewaterhouseCoopers LLP is not subject to the liability provisions of Section
11 of the Securities Act of 1933 for their report on the unaudited financial
information because that report is not a “report” or a “part” of the
registration statement prepared or certified by PricewaterhouseCoopers LLP
within the meaning of Sections 7 and 11 of the Securities Exchange Act of
1934.
2. EARNINGS
PER SHARE
Basic
earnings per
share of common stock is computed using the weighted average of actual common
shares outstanding during the respective period as the denominator. The
denominator for diluted earnings per share of common stock 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 pool of stock-based compensation tax benefits is
calculated in accordance with SFAS 123(R). On August 10, 2006, FirstEnergy
repurchased 10.6 million shares, approximately 3.2%, of its outstanding
common stock through an accelerated share repurchase program. The initial
purchase price was $600 million, or $56.44 per share. A final purchase
price adjustment of $27 million was settled in cash on April 2, 2007.
On March 2, 2007, FirstEnergy repurchased approximately 14.4 million
shares, or 4.5%, of its outstanding common stock through an additional
accelerated share repurchase program at an initial price of $62.63 per share,
or
a total initial purchase price of approximately $900 million. The final purchase
price for this program will be adjusted to reflect the volume-weighted average
price of FirstEnergy’s common stock during the period of time that the bank will
acquire shares to cover its short position, which is expected to be by the
end
of 2007. The basic and diluted earnings per share calculations shown below
reflect the impact associated with these accelerated share repurchase programs.
FirstEnergy intends to settle, in cash or shares, any obligation on its part
to
pay the difference between the average of the daily volume-weighted average
price of the shares as calculated under the March 2007 program and the initial
price of the shares.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
Reconciliation
of Basic and Diluted Earnings per Share
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
413
|
|
$
|
452
|
|
$
|
1,041
|
|
$
|
983
|
|
Discontinued
operations
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
(4
|
)
|
Redemption
premium on subsidiary preferred stock
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(3
|
)
|
Net
earnings
available for common shareholders
|
|
$
|
413
|
|
$
|
454
|
|
$
|
1,041
|
|
$
|
976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares
of common stock outstanding – Basic
|
|
|
304
|
|
|
322
|
|
|
307
|
|
|
326
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
3
|
|
|
3
|
|
|
4
|
|
|
3
|
|
Average
shares
of common stock outstanding – Dilutive
|
|
|
307
|
|
|
325
|
|
|
311
|
|
|
329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from
continuing operations
|
|
$
|
1.36
|
|
$
|
1.40
|
|
$
|
3.39
|
|
$
|
3.00
|
|
Discontinued
operations
|
|
|
-
|
|
|
0.01
|
|
|
-
|
|
|
(0.01
|
)
|
Net
earnings
per basic share
|
|
$
|
1.36
|
|
$
|
1.41
|
|
$
|
3.39
|
|
$
|
2.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from
continuing operations
|
|
$
|
1.34
|
|
$
|
1.39
|
|
$
|
3.35
|
|
$
|
2.98
|
|
Discontinued
operations
|
|
|
-
|
|
|
0.01
|
|
|
-
|
|
|
(0.01
|
)
|
Net
earnings
per diluted share
|
|
$
|
1.34
|
|
$
|
1.40
|
|
$
|
3.35
|
|
$
|
2.97
|
|
3. GOODWILL
In
a business
combination, the excess of the purchase price over the estimated fair values
of
assets acquired and liabilities assumed is recognized as goodwill. Based on
the
guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment
at least annually and more frequently as indicators of impairment arise. In
accordance with the accounting standard, if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested
for
impairment. If impairment is indicated, FirstEnergy recognizes a loss –
calculated as the difference between the implied fair value of a reporting
unit's goodwill and the carrying value of the goodwill. FirstEnergy's 2007
annual review was completed in the third quarter of 2007 with no impairment
indicated.
FirstEnergy's
goodwill primarily relates to its energy delivery services segment. In the
third
quarter of 2007, FirstEnergy adjusted goodwill for the former GPU companies
due
to the realization of tax benefits that had been reserved in purchase
accounting. See Note 12 for a discussion of the tax implications related to
the
Bruce Mansfield Unit 1 sale and leaseback transaction. The following tables
reconcile changes to goodwill for the three months and nine months ended
September 30, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
Balance
as of
July 1, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
related to GPU acquisition
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
as of
September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
as of
January 1, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
related to GPU acquisition
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
as of
September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4. DIVESTITURES
AND DISCONTINUED OPERATIONS
In
2006, FirstEnergy
sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards
and
RPC) for an aggregate net after-tax gain of $2.2 million. Hattenbach,
Dunbar, Edwards, and RPC are included in discontinued operations for the third
quarter and nine months ended September 30, 2006; Roth Bros. did not meet the
criteria for that classification.
In
March 2006,
FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2
million. In June 2006, as part of the March agreement, FirstEnergy sold an
additional 1.67% interest. As a result of the March sale, FirstEnergy
deconsolidated MYR in the first quarter of 2006 and accounted for its remaining
38.33% interest under the equity method. In the fourth quarter of
2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of
$8.6 million.
The
income for the
period that MYR was accounted for as an equity method investment has not been
included in discontinued operations; however, results prior to the initial
sale
in March 2006, including the gain on the sale, are reported as discontinued
operations.
Revenues
associated
with discontinued operations were $36 million and $211 million in the third
quarter and first nine months of 2006, respectively. The following table
summarizes the net income (loss) included in "Discontinued Operations" on the
Consolidated Statements of Income for the three months and nine months ended
September 30, 2006:
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
FSG
subsidiaries
|
|
$
|
2
|
|
$
|
(6
|
)
|
MYR
|
|
|
-
|
|
|
2
|
|
Total
|
|
$
|
2
|
|
$
|
(4
|
)
|
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 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 for risk management activities
throughout FirstEnergy. They are responsible for promoting the effective design
and implementation of sound risk management programs. They also oversee
compliance with corporate risk management policies and established risk
management practices.
FirstEnergy
accounts
for derivative instruments on its Consolidated Balance Sheet at their fair
value
unless they meet the normal purchase and normal sales criterion. Derivatives
that meet that criterion are accounted for using traditional accrual accounting.
The changes in the fair value of derivative instruments that do not meet the
normal purchase and normal sales criterion are recorded as other expense, as
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 $52 million included in AOCL as of September 30, 2007, for
derivative hedging activity, as compared to $58 million as of
December 31, 2006, resulted from a net $10 million increase related to
current hedging activity and a $16 million decrease due to net hedge losses
reclassified to earnings during the nine months ended September 30, 2007. Based
on current estimates, approximately $14 million (after tax) of the net
deferred losses on derivative instruments in AOCL as of September 30, 2007
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 nine months of 2007,
FirstEnergy unwound swaps with a total notional value of $150 million, for
which it incurred $8 million in cash losses that will be recognized as
interest expense over the remaining maturity of each hedged security. As of
September 30, 2007, FirstEnergy had interest rate swaps with an aggregate
notional value of $600 million and a fair value of
$(14) million.
During
2006 and the
first nine months of 2007, 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 as outstanding
debt matures during 2007 and 2008. These derivatives are treated as cash flow
hedges, protecting against the risk of changes in future interest payments
resulting from changes in benchmark U.S. Treasury rates between the date of
hedge inception and the date of the debt issuance. During the first nine months
of 2007, FirstEnergy terminated swaps with a notional value of $1.6 billion
for which it paid $20 million, all of which were deemed effective.
FirstEnergy will recognize the $20 million loss over the life of the associated
future debt. As of September 30, 2007, FirstEnergy had forward swaps with an
aggregate notional amount of $400 million and a fair value of
$5 million.
6. 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.
The
ARO liability of
$1.2 billion as of September 30, 2007 is primarily related to the nuclear
decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear
generating facilities. FirstEnergy utilized an expected cash flow approach
to
measure the fair value of the nuclear decommissioning ARO.
FirstEnergy
maintains nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of September 30,
2007, the fair value of the decommissioning trust assets was approximately
$2.1 billion.
The
following tables
analyze changes to the ARO balances during the three months and nine months
ended September 30, 2007 and 2006, respectively.
Three
Months Ended
|
|
FirstEnergy
|
|
FES
|
|
OE
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
July
1, 2007
|
|
$
|
1,228
|
|
$
|
784
|
|
$
|
91
|
|
$
|
2
|
|
$
|
27
|
|
$
|
87
|
|
$
|
156
|
|
$
|
79
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
19
|
|
|
13
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
2
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2007
|
|
$
|
1,247
|
|
$
|
797
|
|
$
|
92
|
|
$
|
2
|
|
$
|
28
|
|
$
|
88
|
|
$
|
158
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
July
1, 2006
|
|
$
|
1,160
|
|
$
|
743
|
|
$
|
85
|
|
$
|
2
|
|
$
|
26
|
|
$
|
82
|
|
$
|
146
|
|
$
|
74
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
19
|
|
|
13
|
|
|
2
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
3
|
|
|
2
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2006
|
|
$
|
1,179
|
|
$
|
756
|
|
$
|
87
|
|
$
|
2
|
|
$
|
26
|
|
$
|
83
|
|
$
|
149
|
|
$
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended |
|
FirstEnergy
|
|
FES
|
|
OE
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec |
|
|
|
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2007
|
|
$
|
1,190
|
|
$
|
760
|
|
$
|
88
|
|
$
|
2
|
|
$
|
27
|
|
$
|
84
|
|
$
|
151
|
|
$
|
77
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
(2
|
)
|
|
(1
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
59
|
|
|
38
|
|
|
4
|
|
|
-
|
|
|
1
|
|
|
4
|
|
|
7
|
|
|
4
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2007
|
|
$
|
1,247
|
|
$
|
797
|
|
$
|
92
|
|
$
|
2
|
|
$
|
28
|
|
$
|
88
|
|
$
|
158
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2006
|
|
$
|
1,126
|
|
$
|
716
|
|
$
|
83
|
|
$
|
8
|
|
$
|
25
|
|
$
|
80
|
|
$
|
142
|
|
$
|
72
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
(6
|
)
|
|
-
|
|
|
-
|
|
|
(6
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
55
|
|
|
36
|
|
|
4
|
|
|
-
|
|
|
1
|
|
|
3
|
|
|
7
|
|
|
4
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
4
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2006
|
|
$
|
1,179
|
|
$
|
756
|
|
$
|
87
|
|
$
|
2
|
|
$
|
26
|
|
$
|
83
|
|
$
|
149
|
|
$
|
76
|
|
7. PENSION
AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy
provides
noncontributory defined benefit pension plans that cover substantially all
of
its and its subsidiaries’ employees. The trusteed plans provide defined benefits
based on years of service and compensation levels. FirstEnergy’s funding policy
is based on actuarial computations using the projected unit credit method.
FirstEnergy uses a December 31 measurement date for its pension and other
postretirement benefit plans. The fair value of the plan assets represents
the
actual market value as of December 31, 2006. On January 2, 2007,
FirstEnergy made a $300 million voluntary cash contribution to its
qualified pension plan. Projections indicate that additional cash contributions
are not expected to be required before 2016. FirstEnergy also provides a minimum
amount of noncontributory life insurance to retired employees in addition to
optional contributory insurance. Health care benefits, which include certain
employee contributions, deductibles and co-payments, are available upon
retirement to employees hired prior to January 1, 2005, their dependents
and, under certain circumstances, their survivors. FirstEnergy recognizes the
expected cost of providing pension benefits and other postretirement benefits
from the time employees are hired until they become eligible to receive those
benefits. During 2006, FirstEnergy amended the health care plan effective in
2008 to cap the monthly contribution for many of the retirees and their spouses
receiving subsidized health care coverage. In addition, FirstEnergy has
obligations to former or inactive employees after employment, but before
retirement, for disability-related benefits.
The
components of
FirstEnergy's net periodic pension and other postretirement benefit costs
(including amounts capitalized) for the three months and nine months ended
September 30, 2007 and 2006 consisted of the following:
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Pension
Benefits
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
21
|
|
$
|
21
|
|
$
|
63
|
|
$
|
63
|
|
Interest
cost
|
|
|
71
|
|
|
66
|
|
|
213
|
|
|
199
|
|
Expected
return on plan assets
|
|
|
(112
|
)
|
|
(99
|
)
|
|
(337
|
)
|
|
(297
|
)
|
Amortization
of prior service cost
|
|
|
2
|
|
|
2
|
|
|
7
|
|
|
7
|
|
Recognized
net
actuarial loss
|
|
|
10
|
|
|
15
|
|
|
31
|
|
|
44
|
|
Net
periodic
cost (credit)
|
|
$
|
(8
|
)
|
$
|
5
|
|
$
|
(23
|
)
|
$
|
16
|
|
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Other
Postretirement Benefits
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
5
|
|
$
|
9
|
|
$
|
16
|
|
$
|
26
|
|
Interest
cost
|
|
|
17
|
|
|
26
|
|
|
52
|
|
|
79
|
|
Expected
return on plan assets
|
|
|
(12
|
)
|
|
(12
|
)
|
|
(38
|
)
|
|
(35
|
)
|
Amortization
of prior service cost
|
|
|
(37
|
)
|
|
(19
|
)
|
|
(112
|
)
|
|
(57
|
)
|
Recognized
net
actuarial loss
|
|
|
11
|
|
|
14
|
|
|
34
|
|
|
42
|
|
Net
periodic
cost (credit)
|
|
$
|
(16
|
)
|
$
|
18
|
|
$
|
(48
|
)
|
$
|
55
|
|
Pension
and other
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. FirstEnergy’s subsidiaries capitalize employee
benefit costs related to construction projects. The net periodic pension and
other postretirement benefit costs (including amounts capitalized) recognized
by
FES and each of the Companies for the three months and nine months ended
September 30, 2007 and 2006 were as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Pension
Benefit Cost (Credit)
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
FES
|
|
$
|
5.2
|
|
$
|
9.9
|
|
$
|
15.7
|
|
$
|
29.9
|
|
OE
|
|
|
(4.0
|
)
|
|
(1.5
|
)
|
|
(11.9
|
)
|
|
(4.5
|
)
|
CEI
|
|
|
0.3
|
|
|
1.0
|
|
|
0.9
|
|
|
2.9
|
|
TE
|
|
|
-
|
|
|
0.2
|
|
|
(0.1
|
)
|
|
0.7
|
|
JCP&L
|
|
|
(2.1
|
)
|
|
(1.4
|
)
|
|
(6.4
|
)
|
|
(4.1
|
)
|
Met-Ed
|
|
|
(1.7
|
)
|
|
(1.7
|
)
|
|
(5.1
|
)
|
|
(5.2
|
)
|
Penelec
|
|
|
(2.6
|
)
|
|
(1.3
|
)
|
|
(7.7
|
)
|
|
(4.0
|
)
|
Other
FirstEnergy subsidiaries
|
|
|
(2.7
|
)
|
|
-
|
|
|
(8.1
|
)
|
|
-
|
|
|
|
$
|
(7.6
|
)
|
$
|
5.2
|
|
$
|
(22.7
|
)
|
$
|
15.7
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Other
Postretirement Benefit Cost (Credit)
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
FES
|
|
$
|
(2.4
|
)
|
$
|
3.4
|
|
$
|
(7.4
|
)
|
$
|
10.2
|
|
OE
|
|
|
(2.7
|
)
|
|
4.2
|
|
|
(8.0
|
)
|
|
12.6
|
|
CEI
|
|
|
1.0
|
|
|
2.8
|
|
|
2.9
|
|
|
8.3
|
|
TE
|
|
|
1.2
|
|
|
2.0
|
|
|
3.7
|
|
|
6.1
|
|
JCP&L
|
|
|
(4.0
|
)
|
|
0.6
|
|
|
(11.9
|
)
|
|
1.8
|
|
Met-Ed
|
|
|
(2.5
|
)
|
|
0.7
|
|
|
(7.7
|
)
|
|
2.2
|
|
Penelec
|
|
|
(3.2
|
)
|
|
1.8
|
|
|
(9.5
|
)
|
|
5.4
|
|
Other
FirstEnergy subsidiaries
|
|
|
(3.3
|
)
|
|
2.7
|
|
|
(9.8
|
)
|
|
7.9
|
|
|
|
$
|
(15.9
|
)
|
$
|
18.2
|
|
$
|
(47.7
|
)
|
$
|
54.5
|
|
8. 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.
Trusts
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 $827 million, $758 million and
$758 million, respectively, which represents the net amount of casualty
value payments upon the occurrence of specified casualty events that render
the
applicable plant worthless. Under the applicable sale and leaseback agreements,
OE, CEI and TE have net minimum discounted lease payments of $606 million,
$73 million and $429 million, respectively, that would not be payable
if the casualty value payments are made.
Effective
October 16, 2007, CEI and TE assigned their leasehold interests in the
Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations
arising under those leases. However, CEI and TE will remain primarily liable
on
the leases and related agreements as to the lessors and other parties to the
agreements. The assignment terminates automatically upon the termination of
the
underlying leases.
Power
Purchase
Agreements
In
accordance with
FIN 46R, FirstEnergy evaluated its power purchase agreements and determined
that
certain NUG entities may be VIEs to the extent they own a plant that sells
substantially all of its output to the Companies and the contract price for
power is correlated with the plant’s variable costs of production. FirstEnergy,
through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately
30 long-term power purchase agreements with NUG entities. The agreements were
entered into pursuant to the Public Utility Regulatory Policies Act of 1978.
FirstEnergy was not involved in the creation of, and has no equity or debt
invested in, these entities.
FirstEnergy
has
determined that for all but eight of these entities, neither JCP&L, Met-Ed
nor Penelec have variable interests in the entities or the entities are
governmental or not-for-profit organizations not within the scope of FIN 46R.
JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight
entities, which sell their output at variable prices that correlate to some
extent with the operating costs of the plants. As required by FIN 46R,
FirstEnergy periodically requests from these eight entities the information
necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or
Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the
requested information, which in most cases was deemed by the requested entity
to
be proprietary. As such, FirstEnergy applied the scope exception that exempts
enterprises unable to obtain the necessary information to evaluate entities
under FIN 46R.
Since
FirstEnergy
has no equity or debt interests in the NUG entities, its maximum exposure to
loss relates primarily to the above-market costs it incurs for power.
FirstEnergy expects any above-market costs it incurs to be recovered from
customers. As of September 30, 2007, the net above-market loss liability
projected for these eight NUG agreements was $158 million. Purchased power
costs from these entities during the three months and nine months ended
September 30, 2007 and 2006 are shown in the following table:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
JCP&L
|
|
$
|
30
|
|
$
|
29
|
|
$
|
71
|
|
$
|
63
|
|
Met-Ed
|
|
|
13
|
|
|
12
|
|
|
40
|
|
|
45
|
|
Penelec
|
|
|
7
|
|
|
8
|
|
|
22
|
|
|
22
|
|
Total
|
|
$
|
50
|
|
$
|
49
|
|
$
|
133
|
|
$
|
130
|
|
Transition
Bonds
The
consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned
limited liability companies of JCP&L. In June 2002, JCP&L Transition
Funding sold $320 million of transition bonds to securitize the recovery of
JCP&L's bondable stranded costs associated with the previously divested
Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition
Funding II sold $182 million of transition bonds to securitize the recovery
of
deferred costs associated with JCP&L’s supply of BGS.
JCP&L
did not
purchase and does not own any of the transition bonds, which are included as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As
of September 30, 2007, $404 million of the transition bonds were
outstanding. The transition bonds are the sole obligations of JCP&L
Transition Funding and JCP&L Transition Funding II and are collateralized by
each company’s equity and assets, which consists primarily of bondable
transition property.
Bondable
transition
property represents the irrevocable right under New Jersey law of a utility
company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on transition bonds and
other fees and expenses associated with their issuance. JCP&L sold its
bondable transition property to JCP&L Transition Funding and JCP&L
Transition Funding II and, as servicer, manages and administers the bondable
transition property, including the billing, collection and remittance of the
TBC, pursuant to separate servicing agreements with JCP&L Transition Funding
and JCP&L Transition Funding II. For the two series of transition bonds,
JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable
from TBC collections.
9. INCOME
TAXES
On
January 1, 2007,
FirstEnergy adopted FIN 48, which provides guidance for accounting for
uncertainty in income taxes recognized in a company’s financial statements in
accordance with SFAS 109. This interpretation prescribes a recognition threshold
and measurement attribute for financial statement recognition and measurement
of
tax positions taken or expected to be taken on a company’s tax return. FIN 48
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 is a two-step process.
The
first step is to determine if it is more likely than not that a tax position
will be sustained upon examination, based on the merits of the position, and
should therefore be recognized. The second step is to measure a tax position
that meets the more likely than not recognition threshold to determine the
amount of income tax benefit to recognize in the financial
statements.
As
of January 1,
2007, the total amount of FirstEnergy’s unrecognized tax benefits was
$268 million. FirstEnergy recorded a $2.7 million cumulative effect
adjustment to the January 1, 2007 balance of retained earnings to increase
reserves for uncertain tax positions. Of the total amount of unrecognized income
tax benefits, $92 million would favorably affect FirstEnergy’s effective
tax rate upon recognition. The majority of items that would not have affected
the effective tax rate would be purchase accounting adjustments to goodwill
upon
recognition. During the first nine months of 2007, there were no material
changes to FirstEnergy’s unrecognized tax benefits. As of September 30, 2007,
the entire liability for uncertain tax positions is included in other
non-current liabilities and changes to FirstEnergy’s tax contingencies that are
reasonably possible in the next twelve months are not material.
FIN
48 also requires
companies to recognize interest expense or income related to uncertain tax
positions. That amount is computed by applying the applicable statutory interest
rate to the difference between the tax position recognized in accordance with
FIN 48 and the amount previously taken or expected to be taken on the tax
return. FirstEnergy includes net interest and penalties in the provision for
income taxes, consistent with its policy prior to implementing FIN 48. As of
January 1, 2007, the net amount of interest accrued was $34 million. During
the first nine months of 2007, there were no material changes to the amount
of
interest accrued.
FirstEnergy
has tax
returns that are under review at the audit or appeals level by the IRS and
state
tax authorities. All state jurisdictions are open from 2001-2006. The IRS began
reviewing returns for the years 2001-2003 in July 2004 and several items are
under appeal. The federal audit for years 2004 and 2005 began in June 2006
and
is not expected to close before December 2007. The IRS began auditing the year
2006 in April 2006 under its Compliance Assurance Process experimental program,
which is not expected to close before December 2007. Management believes that
adequate reserves have been recognized and final settlement of these audits
is
not expected to have a material adverse effect on FirstEnergy’s financial
condition or results of operations.
On
July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated
capacity (see Note 12). This transaction generated tax capital gains of
approximately $752 million, all of which were offset by existing tax
capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss
carryforward valuation allowances in the third quarter of 2007, with a
corresponding reduction to goodwill (see Note 3).
10. COMMITMENTS,
GUARANTEES AND CONTINGENCIES
(A) GUARANTEES
AND OTHER ASSURANCES
As
part of normal
business activities, FirstEnergy enters into various agreements on behalf of
its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. As of
September 30, 2007, outstanding guarantees and other assurances aggregated
approximately $4.7 billion, consisting of parental guarantees - $1.2
billion, subsidiaries’ guarantees - $2.7 billion, surety bonds -
$0.1 billion and LOCs - $0.7 billion.
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved
in
energy commodity activities principally to facilitate normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of credit support
for
subsidiary financings or refinancings of costs related to the acquisition of
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 $0.6 billion
(included in the $1.2 billion discussed above) as of September 30,
2007 would increase amounts otherwise payable by FirstEnergy to meet its
obligations incurred in connection with financings and ongoing energy and
energy-related activities.
While
these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit
rating-downgrade or “material adverse event” the immediate posting of cash
collateral or provision of an LOC may be required of the subsidiary. As of
September 30, 2007, FirstEnergy's maximum exposure under these collateral
provisions was $442 million.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of
$75 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
|
|
|
|
Parent
Company
|
|
|
|
|
|
|
|
(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 ($27 million as of
September 30, 2007), which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA. The LOC was reduced to $19 million on
October 15, 2007.
On
July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1 (see Note 12). FES has unconditionally
and irrevocably guaranteed all of FGCO’s obligations under each of the
leases. The related lessor notes and pass through certificates are
not guaranteed by FES or FGCO, but the notes are secured by, among other things,
each lessor trust’s undivided interest in Unit 1, rights and interests under the
applicable lease and rights and interests under other related agreements,
including FES’ lease guaranty.
(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
FirstEnergy 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. FirstEnergy estimates capital expenditures for
environmental compliance of approximately $1.8 billion for 2007 through
2011.
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 become both
probable and reasonably estimable.
Clean
Air Act Compliance
FirstEnergy
is
required to meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500
for
each day the unit is in violation. The EPA has an interim enforcement policy
for
SO2 regulations
in Ohio that allows for compliance based on a 30-day averaging period.
FirstEnergy believes it is currently in compliance with this policy, but cannot
predict what action the EPA may take in the future with respect to the interim
enforcement policy.
The
EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006 alleging violations to various sections of the Clean Air Act.
FirstEnergy has disputed those alleged violations based on its Clean Air Act
permit, the Ohio SIP and other information provided at an August 2006 meeting
with the EPA. The EPA has several enforcement options (administrative compliance
order, administrative penalty order, and/or judicial, civil or criminal action)
and has indicated that such option may depend on the time needed to achieve
and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding the opacity limit applicable to
the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy
complies
with SO2
reduction requirements under the Clean Air Act Amendments of 1990 by burning
lower-sulfur fuel, generating more electricity from lower-emitting plants,
and/or using emission allowances. NOX reductions
required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX reductions
at
FirstEnergy's facilities. The EPA's NOX Transport
Rule
imposes uniform reductions of NOX emissions
(an
approximate 85% reduction in utility plant NOX emissions
from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX budgets
established
under SIPs through combustion controls and post-combustion controls, including
Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.
On
May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal Clean Air Act, alleging violations
of
air pollution laws at the Mansfield Plant, including opacity limitations. Prior
to the receipt of this notice, the Mansfield Plant was subject to a Consent
Order and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with
the
applicable laws will continue. On October 16, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. FirstEnergy is currently studying
PennFuture’s complaint.
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
allowed 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 generation facilities
will
be subject to caps on SO2 and NOX
emissions, whereas
its New Jersey fossil 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, allowing new and non-emitting generating
facilities (including renewables and nuclear) to be entitled to their
proportionate share of the allowances. Consequently, FirstEnergy will be
disadvantaged if these model rules were implemented as proposed because
FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation
is not recognized under the input-based allocation.
Pennsylvania
has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. Pennsylvania’s mercury
regulation would deprive FES of mercury emission allowances that were to be
allocated to the Mansfield Plant under the CAMR and that would otherwise be
available for achieving FirstEnergy system-wide compliance. It is anticipated
that compliance with these regulations, if approved by the EPA and implemented,
would not require the addition of mercury controls at the Mansfield Plant,
FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at
all.
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,
and is now owned by FGCO. 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 the New Source Review, or NSR, 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 Sammis NSR litigation. This settlement agreement, which is in
the
form of a consent decree, was approved by the court on July 11, 2005, and
requires reductions of NOX and SO2
emissions at the
Sammis, Burger, Eastlake and Mansfield 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 Sammis NSR
Litigation consent decree. Capital expenditures necessary to complete
requirements of the Sammis NSR Litigation settlement agreement are currently
estimated to be $1.7 billion for 2007 through 2011 ($400 million of
which is expected to be spent during 2007, with the largest portion of the
remaining $1.3 billion expected to be spent in 2008 and 2009).
The
Sammis NSR
Litigation consent decree also requires FirstEnergy to spend up to
$25 million toward environmentally beneficial projects, $14 million of
which is satisfied by entering into 93 MW (or 23 MW if federal tax credits
are
not applicable) of wind energy purchased power agreements with a 20-year term.
An initial 16 MW of the 93 MW consent decree obligation was satisfied
during 2006.
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. At the international
level, efforts have begun to develop climate change agreements for post-2012
GHG
reductions. 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.
At
the federal
level, members of Congress have introduced several bills seeking to reduce
emissions of GHG in the United States. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states led by California, have coordinated
efforts to develop regional strategies to control emissions of certain GHGs.
On
April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2 emissions
from automobiles as “air pollutants” under the Clean Air Act. Although this
decision did not address CO2 emissions
from
electric generating plants, the EPA has similar authority under the Clean Air
Act to regulate “air pollutants” from those and other facilities. Also on
April 2, 2007, the United States Supreme Court ruled that changes in annual
emissions (in tons/year) rather than changes in hourly emissions rate (in
kilograms/hour) must be used to determine whether an emissions increase triggers
NSR. Subsequently, the EPA proposed to change the NSR regulations, on
May 8, 2007, to utilize changes in the hourly emission rate (in
kilograms/hour) to determine whether an emissions increase triggers
NSR.
FirstEnergy
cannot
currently estimate the financial impact of climate change policies, although
potential legislative or regulatory programs restricting 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 life is drawn into a facility's cooling
water system. On January 26, 2007, the federal Court of Appeals for the Second
Circuit remanded portions of the rulemaking dealing with impingement mortality
and entrainment back to EPA for further rulemaking and eliminated the
restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended
this rule, noting that until further rulemaking occurs, permitting authorities
should continue the existing practice of applying their best professional
judgment (BPJ) to minimize impacts on fish and shellfish from cooling water
intake structures. FirstEnergy is evaluating various control options and their
costs and effectiveness. Depending on the outcome of such studies, the EPA’s
further rulemaking and any action taken by the states exercising BPJ, 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.
Under
NRC
regulations, FirstEnergy must ensure that adequate funds will be available
to
decommission its nuclear facilities. As of September 30, 2007,
FirstEnergy had approximately $1.5 billion invested in external trusts to
be used for the decommissioning and environmental remediation of Davis-Besse,
Beaver Valley and Perry. As part of the application to the NRC to
transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy
agreed to contribute another $80 million to these trusts by 2010. Consistent
with NRC guidance, utilizing a “real” rate of return on these funds of
approximately 2% over inflation, these trusts are expected to exceed the minimum
decommissioning funding requirements set by the NRC. Conservatively, these
estimates do not include any rate of return that the trusts may earn over the
20-year plant useful life extensions that FirstEnergy plans to seek for these
facilities.
The
Companies have
been named as PRPs at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of September
30, 2007, 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 $89 million (JCP&L - $60 million, TE
- $3 million, CEI - $1 million, and FirstEnergy Corp. -
$25 million) have been accrued through September 30,
2007.
(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
in
July 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, NJ, based on a
common incident involving the failure of the bushings of two large transformers
in the Red Bank substation resulting in planned and unplanned outages in the
area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify
the class based on a very limited number of class members who incurred damages
and also filed a motion for summary judgment on the remaining plaintiffs’ claims
for negligence, breach of contract and punitive damages. In July 2006, the
New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division which, in March 2007, reversed the decertification of the Red Bank
class and remanded this matter back to the Trial Court to allow plaintiffs
sufficient time to establish a damage model or individual proof of
damages. JCP&L filed a petition for allowance of an appeal of the
Appellate Division ruling to the New Jersey Supreme Court which was denied
in
May 2007. Proceedings are continuing in the Superior
Court. FirstEnergy is defending this class action but is unable
to predict the outcome of this matter. No liability has been accrued
as of September 30, 2007.
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
that could require additional material expenditures.
FirstEnergy
companies also are defending four separate complaint cases before the PUCO
relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various
FirstEnergy companies (and, in one case, from PJM, MISO and American Electric
Power Company, Inc. (AEP), as well) for claims paid to insureds for damages
allegedly arising as a result of the loss of power on August 14, 2003. A
fifth case in which a carrier sought reimbursement for claims paid to insureds
was voluntarily dismissed by the claimant in April 2007. A sixth case involving
the claim of a non-customer seeking reimbursement for losses incurred when
its
store was burglarized on August 14, 2003 was dismissed. The four cases
remaining were consolidated for hearing by the PUCO in an order dated
March 7, 2006. In that order the PUCO also limited the
litigation to service-related claims by customers of the Ohio operating
companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada
Power System Outage Task Force Report was not admissible into evidence. In
response to a motion for rehearing filed by one of the claimants, the PUCO
ruled
on April 26, 2006 that the insurance company claimants, as insurers, may
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 amended complaints and the named FirstEnergy companies have
answered and also have filed a motion to dismiss each action. On September
27,
2006, the PUCO dismissed certain parties and claims and otherwise ordered the
complaints to go forward to hearing. The cases have been set for hearing on
January 8, 2008.
FirstEnergy
is 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 FirstEnergy is 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
May 14, 2007, the
Office of Enforcement of the NRC issued a Demand for Information to FENOC
following FENOC’s reply to an April 2, 2007 NRC request for information about
two reports prepared by expert witnesses for an insurance arbitration related
to
Davis-Besse. The NRC indicated that this information was needed for the NRC
“to
determine whether an Order or other action should be taken pursuant to 10 CFR
2.202, to provide reasonable assurance that FENOC will continue to operate
its
licensed facilities in accordance with the terms of its licenses and the
Commission’s regulations.” FENOC was directed to submit the information to the
NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand
for Information reaffirming that it accepts full responsibility for the mistakes
and omissions leading up to the damage to the reactor vessel head and that
it
remains committed to operating Davis-Besse and FirstEnergy’s other nuclear
plants safely and responsibly. The NRC held a public meeting on June 27, 2007
with FENOC to discuss FENOC’s response to the Demand for Information. In
follow-up discussions, FENOC was requested to provide supplemental information
to clarify certain aspects of the Demand for Information response and provide
additional details regarding plans to implement the commitments made therein.
FENOC submitted this supplemental response to the NRC on July 16, 2007. On
August 15, 2007, the NRC issued a confirmatory order imposing these
commitments. FENOC must inform the NRC’s Office of Enforcement after it
completes the key commitments embodied in the NRC’s order. FENOC’s compliance
with these commitments is subject to future NRC review.
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
August 22, 2005,
a class action complaint was filed against OE in Jefferson County,
Ohio Common Pleas Court, seeking compensatory and punitive damages to be
determined at trial based on claims of negligence and eight other tort counts
alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs
are also seeking injunctive relief to eliminate harmful emissions and repair
property damage and the institution of a medical monitoring program for class
members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify
this case as a class action and, accordingly, did not appoint the plaintiffs
as
class representatives or their counsel as class counsel. On July 30, 2007,
plaintiffs’ counsel voluntarily withdrew their request for reconsideration of
the April 5, 2007 Court order denying class certification and the Court
heard oral argument on the plaintiffs’ motion to amend their complaint which OE
has opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend
their complaint. The plaintiffs have appealed the Court’s denial of the motion
for certification as a class action and motion to amend their
complaint.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. The arbitration
panel provided additional rulings regarding damages during a September 2007
hearing and it is anticipated that he will issue a final order in late 2007.
JCP&L intends to re-file an appeal again in federal district court once the
damages associated with this case are identified at an individual employee
level. JCP&L recognized a liability for the potential $16 million award
in 2005.
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
(A)
RELIABILITY
INITIATIVES
In
late 2003 and
early 2004, a series of letters, reports and recommendations were issued from
various entities, including governmental, industry and ad hoc reliability
entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force)
regarding enhancements to regional reliability. In 2004, FirstEnergy completed
implementation of all actions and initiatives related to enhancing area
reliability, improving voltage and reactive management, operator readiness
and
training and emergency response preparedness recommended for completion in
2004.
On July 14, 2004, NERC independently verified that FirstEnergy had
implemented the various initiatives to be completed by June 30 or summer
2004, with minor exceptions noted by FirstEnergy, which exceptions are now
essentially complete. FirstEnergy is proceeding with the implementation of
the
recommendations that were to be completed subsequent to 2004 and will continue
to periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new equipment or material upgrades to
existing equipment. The FERC or other applicable government agencies and
reliability entities may, however, take a different view as to recommended
enhancements or may recommend additional enhancements in the future, which
could
require additional, material expenditures.
As
a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU
adopted an MOU that set out specific tasks related to service reliability to
be
performed by JCP&L and a timetable for completion and endorsed JCP&L’s
ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a
stipulation that incorporates the final report of an SRM who made
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The stipulation also incorporates the Executive Summary and
Recommendation portions of the final report of a focused audit of JCP&L’s
Planning and Operations and Maintenance programs and practices. 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. 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 served,
among other things, partly to amend the Federal Power Act by adding a new
Section 215, which requires that a new ERO establish and enforce reliability
standards for the bulk-power system, subject to review by the FERC.
Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance
Monitoring and Enforcement Program and approved a set of reliability standards,
which became mandatory and enforceable on June 18, 2007 with penalties and
sanctions for noncompliance. The FERC also approved a delegation agreement
between NERC and ReliabilityFirst Corporation, one of eight Regional
Entities that carry out enforcement for NERC. All of FirstEnergy’s
facilities are located within the ReliabilityFirst region.
To
date, FERC has
approved 83 of the 107 reliability standards proposed by NERC. Nevertheless,
the
FERC has directed NERC to submit improvements to 56 of the 83 approved standards
and has endorsed NERC's process for developing reliability standards and its
associated work plan. On May 4, 2007, NERC submitted 24 proposed Violation
Risk
Factors that would operate as a system of weighting the risk to the power grid
associated with a particular reliability standard violation. The FERC issued
an
order approving 22 of those factors on June 26, 2007. Further, NERC adopted
eight cyber security standards and filed them with the FERC for approval. On
December 11, 2006, the FERC Staff provided its preliminary assessment of
the cyber security standards and cited various deficiencies in the proposed
standards. Numerous parties, including FirstEnergy, provided comments on the
preliminary assessment. The standards remain pending before the FERC.
Separately, on July 20, 2007, the FERC issued a NOPR proposing to adopt eight
related Critical Infrastructure Protection Reliability Standards. On October
5,
2007, numerous parties, including FirstEnergy, provided comments on the proposed
Critical Infrastructure Protection standards. These standards, and FirstEnergy’s
comments thereon, are pending before FERC.
FirstEnergy
believes
it is in compliance with all current NERC reliability standards. However, based
upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule
on
Mandatory Reliability Standards, it appears that the FERC may eventually adopt
stricter standards than those just approved. The financial impact of complying
with the new standards cannot be determined at this time. However, the EPACT
required that all prudent costs incurred to comply with the new reliability
standards be recovered in rates. If FirstEnergy is unable to meet the
reliability standards for its bulk power system in the future, it could have
a
material adverse effect on FirstEnergy’s and its subsidiaries’ financial
condition, results of operations and cash flows.
On
April 18-20,
2007, ReliabilityFirst performed a routine compliance audit of
FirstEnergy's bulk-power system within the Midwest ISO region and found
FirstEnergy to be in full compliance with all audited reliability
standards. Similarly, ReliabilityFirst has scheduled a
compliance audit of FirstEnergy's bulk-power system within the PJM region in
2008. FirstEnergy does not expect any material adverse impact to its financial
condition as a result of these audits.
(B)
OHIO
On
September 9,
2005, the Ohio Companies filed their RCP with the PUCO. The filing included
a
stipulation and supplemental stipulation with several parties agreeing to the
provisions set forth in the plan. On January 4, 2006, the PUCO issued an
order which approved the stipulation on the RCP after clarifying certain
provisions. Several parties subsequently filed appeals to the Supreme Court
of
Ohio in connection with certain portions of the RCP approved by the PUCO. In
its
order, the PUCO authorized the Ohio Companies to recover certain increased
fuel
costs through a fuel rider and to defer certain other increased fuel costs,
all
such costs to be incurred from January 1, 2006 through December 31, 2008,
including interest on the deferred balances. The order also provided for
recovery of the deferred costs over a 25-year period through distribution rates,
which was expected to begin on January 1, 2009 for OE and TE, and
approximately May 2009 for CEI. Through September 30, 2007, the
deferred fuel costs, including interest, were $89 million, $61 million and
$26
million for OE, CEI and TE, respectively.
On
August 29, 2007,
the Supreme Court of Ohio concluded that the PUCO violated certain provisions
of
the Ohio Revised Code by permitting the Ohio Companies “to collect deferred
increased fuel costs through future distribution rate cases, or to alternatively
use excess fuel-cost recovery to reduce deferred distribution-related expenses”
because fuel costs are a component of generation service, not distribution
service, and because the Court concluded the PUCO did not address whether the
deferral of fuel costs was anticompetitive. The Court remanded the
matter to the PUCO for further consideration consistent with the Court’s Opinion
on this issue and affirmed the PUCO’s Order in all other respects. On
September 7, 2007, the Ohio Companies filed a Motion for Reconsideration
with the Court. On September 10, 2007 the Ohio Companies filed an
Application with the PUCO that requests the implementation of two
generation-related fuel cost riders to collect the increased fuel costs that
were previously authorized to be deferred. The Ohio Companies requested the
riders become effective in October 2007 and end in December 2008, subject to
reconciliation which is expected to continue through the first quarter of 2009.
This matter is currently pending before the PUCO. Although unable to predict
the
ultimate outcome of this matter, the Ohio Companies intend to continue deferring
the fuel costs pursuant to the RCP, pending the Court’s disposition of the
Motion for Reconsideration and the PUCO’s action with respect to the Ohio
Companies’ Application.
On
August 31, 2005,
the PUCO approved a rider recovery mechanism through which the Ohio Companies
may recover all MISO transmission and ancillary service related costs incurred
during each year ending June 30. Pursuant to the PUCO’s order, the Ohio
Companies, on May 1, 2007, filed revised riders, which became effective on
July
1, 2007. The revised riders represent an increase over the amounts
collected through the 2006 riders of approximately $64 million
annually. If it is subsequently determined by the PUCO that
adjustments to the rider as filed are necessary, such adjustments, with carrying
costs, will be incorporated into the 2008 transmission rider
filing.
On
May 8, 2007, the
Ohio Companies filed with the PUCO a notice of intent to file for an increase
in
electric distribution rates. The Ohio Companies filed the application and rate
request with the PUCO on June 7, 2007. The requested increase is expected to
be
more than offset by the elimination or reduction of transition charges at the
time the rates go into effect and would result in lowering the overall
non-generation portion of the bill for most Ohio customers. The
distribution rate increases reflect capital expenditures since the Ohio
Companies’ last distribution rate proceedings, increases in operating and
maintenance expenses and recovery of regulatory assets created by deferrals
that
were approved in prior cases. On August 6, 2007, the Ohio Companies updated
their filing supporting a distribution rate increase of $332 million to the
PUCO to establish the test period data that will be used as the basis for
setting rates in that proceeding. The PUCO Staff is expected to issue its report
in the case in the fourth quarter of 2007 with evidentiary hearings to follow
in
early 2008. The PUCO order is expected to be issued in the second quarter of
2008. The new rates would become effective January 1, 2009 for OE and TE, and
approximately May 2009 for CEI.
On
July 10, 2007,
the Ohio Companies filed an application with the PUCO requesting approval of
a
comprehensive supply plan for providing generation service to customers who
do
not purchase electricity from an alternative supplier, beginning January 1,
2009. The proposed competitive bidding process would average the results of
multiple bidding sessions conducted at different times during the year. The
final price per kilowatt-hour would reflect an average of the prices resulting
from all bids. In their filing, the Ohio Companies offered two alternatives
for
structuring the bids, either by customer class or a “slice-of-system” approach.
The proposal provides the PUCO with an option to phase in generation price
increases for residential tariff groups who would experience a change in their
average total price of 15 percent or more. The PUCO held a technical conference
on August 16, 2007 regarding the filing. Comments by intervenors in the case
were filed on September 5, 2007. The PUCO Staff filed comments on
September 21, 2007. Parties filed reply comments on October 12,
2007. The Ohio Companies requested that the PUCO issue an order by November
1, 2007, to provide sufficient time to conduct the bidding process.
On
September 25,
2007, the Ohio Governor’s proposed energy plan was officially introduced into
the Ohio Senate. The bill proposes to revise state energy policy to address
electric generation pricing after 2008, establish advanced energy portfolio
standards and energy efficiency standards, and create GHG emissions reporting
and carbon control planning requirements. The bill also proposes to move to
a
“hybrid” system for determining rates for PLR service in which electric
utilities would provide regulated generation service unless they satisfy a
statutory burden to demonstrate the existence of a competitive market for retail
electricity. The Senate Energy & Public Utilities Committee has been
conducting hearings on the bill and receiving testimony from interested parties,
including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer
groups, utility executives and others. Several proposed amendments to the bill
have been submitted, including those from Ohio’s investor-owned electric
utilities. A substitute version of the bill, which incorporated certain of
the
proposed amendments, was introduced into the Senate Energy & Public
Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, such
legislation may have on its operations or those of the Ohio
Companies.
(C)
PENNSYLVANIA
Met-Ed
and Penelec
have been purchasing a portion of their PLR requirements from FES through a
partial requirements wholesale power sales agreement and various amendments.
Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's
exposure to high wholesale power prices by providing power at a fixed price
for
their uncommitted PLR capacity and energy requirements during the term of these
agreements with FES.
On
September 26, 2006, Met-Ed and Penelec successfully conducted a competitive
RFP for a portion of their PLR obligation for the period December 1, 2006
through December 31, 2008. FES was one of the successful bidders in that
RFP process and on September 26, 2006 entered into a supplier master agreement
to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market
prices that were substantially higher than the fixed price in the partial
requirements agreements.
Based
on the outcome
of the 2006 comprehensive transition rate filing, as described below, Met-Ed,
Penelec and FES agreed to restate the partial requirements power sales agreement
effective January 1, 2007. The restated agreement incorporates the same fixed
price for residual capacity and energy supplied by FES as in the prior
arrangements between the parties, and automatically extends for successive
one
year terms unless any party gives 60 days’ notice prior to the end of the year.
The restated agreement also allows Met-Ed and Penelec to sell the output of
NUG
energy to the market and requires FES to provide energy at fixed prices to
replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec
to
satisfy their PLR obligations. The parties also have separately terminated
the
supplier master agreements in connection with the restatement of the partial
requirements agreement. Accordingly, the energy that would have been supplied
under the supplier master agreement will now be provided under the restated
partial requirements agreement. The fixed price under the restated agreement
is
expected to remain below wholesale market prices during the term of the
agreement.
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.
Based on the PPUC’s January 11, 2007 order described below, if FES ultimately
determines to terminate, reduce, or significantly modify the agreement prior
to
the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely
regulatory relief is not likely to be granted by the PPUC.
Met-Ed
and Penelec
made a comprehensive transition rate filing with the PPUC on April 10, 2006
to address a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals had been
approved, annual revenues would have increased by $216 million and
$157 million, respectively. That filing included, 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 then existing
FES agreement was to be phased out. Met-Ed and Penelec also requested approval
of a January 12, 2005 petition for the deferral of transmission-related
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.
Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG
stranded costs were also included in the filing. On May 4, 2006, the PPUC
consolidated the remand of the FirstEnergy and GPU merger proceeding, related
to
the quantification and allocation of merger savings, with the comprehensive
transition rate filing case.
The
PPUC entered its
Opinion and Order in the comprehensive rate filing proceeding on January 11,
2007. The order approved the recovery of transmission costs, including the
transmission-related deferral for January 1, 2006 through January 10, 2007,
when
new transmission rates were effective, and determined that no merger savings
from prior years should be considered in determining customers’ rates. The
request for increases in generation supply rates was denied as were the
requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs.
The order decreased Met-Ed’s and Penelec’s distribution rates by
$80 million and $19 million, respectively. These decreases were offset
by the increases allowed for the recovery of transmission expenses and the
transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton
decommissioning costs was granted and, in January 2007, Met-Ed and Penelec
recognized income of $15 million and $12 million, respectively, to
establish regulatory assets for those previously expensed decommissioning costs.
Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for
Penelec ($50 million). Met-Ed and Penelec filed a Petition for
Reconsideration on January 26, 2007 on the issues of consolidated tax savings
and rate of return on equity. Other parties filed Petitions for Reconsideration
on transmission (including congestion), transmission deferrals and rate design
issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s,
Penelec’s and the other parties’ petitions for procedural purposes. Due to that
ruling, the period for appeals to the Commonwealth Court of Pennsylvania was
tolled until 30 days after the PPUC entered a subsequent order ruling on the
substantive issues raised in the petitions. On March 1, 2007, the PPUC issued
three orders: (1) a tentative order regarding the reconsideration by the PPUC
of
its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed,
Penelec and the OCA and denying in part and accepting in part the MEIUG’s and
PICA’s Petition for Reconsideration; and (3) an order approving the compliance
filing. Comments to the PPUC for reconsideration of its order were filed on
March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007,
making minor changes to rate design as agreed upon by Met-Ed, Penelec and
certain other parties.
On
March 30, 2007,
MEIUG and PICA filed a Petition for Review with the Commonwealth Court of
Pennsylvania asking the court to review the PPUC’s determination on transmission
(including congestion) and the transmission deferral. Met-Ed and Penelec filed
a
Petition for Review on April 13, 2007 on the issues of consolidated tax savings
and the requested generation rate increase. The OCA filed its
Petition for Review on April 13, 2007, on the issues of transmission
(including congestion) and recovery of universal service costs from only the
residential rate class. On June 19, 2007, initial briefs were filed and
responsive briefs were filed through September 21, 2007. Reply briefs
were filed on October 5, 2007. Oral arguments are expected to take place in
late
2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of
congestion, it could have a material adverse effect on the financial condition
and results of operations of Met-Ed, Penelec and FirstEnergy.
As
of September 30,
2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the
2006 comprehensive transition rate case, the 1998 Restructuring Settlement
(including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement
Stipulation were $496 million and $58 million, respectively. During the
PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in
2006, it noted a modification to the NUG purchased power stranded cost
accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC
Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG
cost
balances as if the stranded cost accounting methodology modification had not
been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax
charge of approximately $10.3 million in the third quarter of 2006,
representing incremental costs deferred under the revised methodology in 2005.
Met-Ed and Penelec continue to believe that the stranded cost accounting
methodology modification is appropriate and on August 24, 2006 filed a petition
with the PPUC pursuant to its order for authorization to reflect the stranded
cost accounting methodology modification effective January 1, 1999. Hearings
on
this petition were held in February 2007 and briefing was completed on March
28,
2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's
and Penelec’s request to modify their NUG stranded cost accounting methodology.
The companies filed exceptions to the initial decision on May 23, 2007 and
replies to those exceptions were filed on June 4, 2007. It is not known when
the
PPUC may issue a final decision in this matter.
On
May 2, 2007, Penn
filed a plan with the PPUC for the procurement of PLR supply from June 2008
through May 2011. The filing proposes multiple, competitive RFPs with staggered
delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the
residential and commercial classes. The proposal phases out existing promotional
rates and eliminates the declining block and the demand components on generation
rates for residential and commercial customers. The industrial class PLR service
will be provided through an hourly-priced service provided by Penn. Quarterly
reconciliation of the differences between the costs of supply and revenues
from
customers is also proposed. On
September 28, 2007, Penn filed a Joint Petition for Settlement resolving all
but
one issue in the case. Briefs were also filed on September 28, 2007
on the unresolved issue of incremental uncollectible accounts
expense. The settlement is either supported, or not opposed, by all
parties. The PPUC is expected to act on the settlement and the unresolved issue
in late November or early December 2007 for the initial RFP to take place in
January 2008.
On
February 1, 2007,
the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces
of
proposed legislation that, according to the Governor, is designed to reduce
energy costs, promote energy independence and stimulate the economy. Elements
of
the EIS include the installation of smart meters, funding for solar panels
on
residences and small businesses, conservation programs to meet demand growth,
a
requirement that electric distribution companies acquire power that results
in
the “lowest reasonable rate on a long-term basis,” the utilization of
micro-grids and an optional three year phase-in of rate increases. On July
17,
2007 the Governor signed into law two pieces of energy legislation. The first
amended the Alternative Energy Portfolio Standards Act of 2004 to, among other
things, increase the percentage of solar energy that must be supplied at the
conclusion of an electric distribution company’s transition period. The second
law allows electric distribution companies, at their sole discretion, to enter
into long term contracts with large customers and to build or acquire interests
in electric generation facilities specifically to supply long-term contracts
with such customers. A special legislative session on energy was convened in
mid-September 2007 to consider other aspects of the EIS. The final form of
any
legislation arising from the special legislative session is uncertain.
Consequently, FirstEnergy is unable to predict what impact, if any, such
legislation may have on its operations.
(D)
NEW JERSEY
JCP&L
is
permitted to defer for future collection from customers the amounts by which
its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of September 30, 2007, the accumulated deferred
cost balance totaled approximately $330 million.
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 NJBPU
proceedings has not yet been set.
On
August 1,
2005, the NJBPU established a proceeding to determine whether additional
ratepayer protections are required at the state level in light of the repeal
of
PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October
2,
2006 that 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.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an
additional draft proposal on March 31, 2006 addressing various issues
including access to books and records, ring-fencing, cross subsidization,
corporate governance and related matters. With the approval of the NJBPU Staff,
the affected utilities jointly submitted an alternative proposal on June 1,
2006. Comments on the alternative proposal were submitted on June 15, 2006.
On November 3, 2006, the Staff circulated a revised draft proposal to
interested stakeholders. Another revised draft was circulated by the NJBPU
Staff
on February 8, 2007.
New
Jersey statutes
require that the state periodically undertake a planning process, known as
the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement
of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President
and
includes representatives of several State departments. In October 2006, the
current EMP process was initiated with the issuance of a proposed set of
objectives which, as to electricity, included the following:
·
Reduce
the total projected electricity demand by 20% by 2020;
·
|
Meet
22.5% of
New Jersey’s electricity needs with renewable energy resources by that
date;
|
·
Reduce
air pollution related to energy use;
·
Encourage
and
maintain economic growth and development;
·
|
Achieve
a 20%
reduction in both Customer Average Interruption Duration Index and
System
Average Interruption Frequency Index by
2020;
|
·
|
Maintain
unit
prices for electricity to no more than +5% of the regional average
price
(region includes New York, New Jersey, Pennsylvania, Delaware, Maryland
and the District of Columbia); and
|
·
Eliminate
transmission congestion by 2020.
Comments
on the
objectives and participation in the development of the EMP have been solicited
and a number of working groups have been formed to obtain input from a broad
range of interested stakeholders including utilities, environmental groups,
customer groups, and major customers. EMP working groups addressing (1) energy
efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing
issues have completed their assigned tasks of data gathering and analysis and
have provided reports to the EMP Committee. Public stakeholder meetings were
held in the fall of 2006 and in early 2007, and further public meetings are
expected later in 2007. A final draft of the EMP is expected to be presented
to
the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome
of this process nor determine the impact, if any, such legislation may have
on
its operations or those of JCP&L.
On
February 13,
2007, the NJBPU Staff informally issued a draft proposal relating to changes
to
the regulations addressing electric distribution service reliability and quality
standards. Meetings between the NJBPU Staff and interested
stakeholders to discuss the proposal were held and additional, revised informal
proposals were subsequently circulated by the Staff. On September 4,
2007, proposed regulations were published in the New Jersey Register, which
proposal will be subsequently considered by the NJBPU following comments which
were due on September 26, 2007. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, such
regulations may have on its operations or those of JCP&L.
(E)
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 participated in the
FERC hearings held in May 2006 concerning the calculation and imposition of
the
SECA charges. The presiding judge issued an initial decision on August 10,
2006,
rejecting the compliance filings made by the RTOs and transmission owners,
ruling on various issues and directing new compliance filings. This decision
is
subject to review and approval by the FERC. Briefs addressing the initial
decision were filed on September 11, 2006 and October 20, 2006. A final order
could be issued by the FERC in the fourth quarter of 2007.
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 & Electric Company (BG&E) and
Pepco Holdings, Inc. requested a formula rate for transmission service provided
within their respective zones. Hearings were held and numerous parties appeared
and litigated various issues; including AEP, which filed in opposition proposing
to create a "postage stamp" rate for high voltage transmission facilities across
PJM. At the conclusion of the hearings, the ALJ issued an initial decision
adopting the FERC 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. Numerous parties, including
FirstEnergy, submitted briefs opposing the ALJ’s decision and
recommendations. On April 19, 2007, the FERC issued an order
rejecting the ALJ’s findings and recommendations in nearly every respect. The
FERC found that the PJM transmission owners’ existing “license plate” rate
design was just and reasonable and ordered that the current license plate rates
for existing transmission facilities be retained. On the issue of rates for
new
transmission facilities, the FERC directed that costs for new transmission
facilities that are rated at 500 kV or higher are to be socialized throughout
the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to
be
allocated on a “beneficiary pays” basis. Nevertheless, the FERC found
that PJM’s current beneficiary-pays cost allocation methodology is not
sufficiently detailed and, in a related order that also was issued on April
19,
2007, directed that hearings be held for the purpose of establishing a just
and
reasonable cost allocation methodology for inclusion in PJM’s
tariff.
On
May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007
Order. Subsequently, FirstEnergy and other parties filed pleadings
opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if
sustained on rehearing and appeal, will prevent the allocation of the cost
of
existing transmission facilities of other utilities to JCP&L, Met-Ed and
Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce future
transmission costs shifting to the JCP&L, Met-Ed and Penelec
zones.
New
FERC Transmission Rate
Design Filings
On
August 1, 2007, a
number of filings were made with the FERC by transmission owning utilities
in
the MISO and PJM footprint that could affect the transmission rates paid by
FirstEnergy’s operating companies and FES.
FirstEnergy
joined
in a filing made by the MISO transmission owners that would maintain the
existing “license plate” rates for transmission service within MISO provided
over existing transmission facilities. FirstEnergy also joined in a
filing made by both the MISO and PJM transmission owners proposing to continue
the elimination of transmission rates associated with service over existing
transmission facilities between MISO and PJM. If adopted by the FERC,
these filings would not affect the rates charged to load-serving FirstEnergy
affiliates for transmission service over existing transmission
facilities. In a related filing, MISO and MISO transmission owners
requested that the current MISO pricing for new transmission facilities that
spreads 20% of the cost of new 345 kV and higher transmission facilities across
the entire MISO footprint be maintained (known as the RECB Process). Each of
these filings was supported by the majority of transmission owners in either
MISO or PJM, as applicable.
The
Midwest
Stand-Alone Transmission Companies made a filing under Section 205 of the
Federal Power Act requesting that 100% of the cost of new qualifying 345 kV
and
higher transmission facilities be spread throughout the entire MISO
footprint. Further, Indianapolis Power and Light Company separately
moved the FERC to reopen the record to address the cost allocation for the
RECB
Process. If either proposal is adopted by the FERC, it could shift a
greater portion of the cost of new 345 kV and higher transmission facilities
to
the FirstEnergy footprint in MISO, and increase the transmission rates paid
by
load-serving FirstEnergy affiliates in MISO.
On
September 17,
2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power
Act
seeking to have the entire transmission rate design and cost allocation methods
used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory,
and to have FERC fix a uniform regional transmission rate design and cost
allocation method for the entire MISO and PJM “SuperRegion” that regionalizes
the cost of new and existing transmission facilities operated at voltages of
345
kV and above. Lower voltage facilities would continue to be recovered
in the host utility transmission rate zone through a license plate
rate. AEP requests a refund effective October 1, 2007, or
alternatively, February 1, 2008. The effect of this proposal, if
adopted by FERC, would be to shift significant costs to the FirstEnergy zones
in
MISO and PJM. FirstEnergy believes that most of these costs would
ultimately be recoverable in retail rates. On October 12, 2007, BG&E
filed a motion to dismiss AEP’s complaint. On October 16, 2007, the
Organization of MISO States filed comments urging the FERC to dismiss AEP’s
complaint. Interventions and protests to AEP’s complaint and answers to
BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and
other transmission owners filed protests to AEP’s complaint and support for
BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint
with the cases above, and FirstEnergy expects it to be resolved on the same
timeline as those cases.
Any
increase in
rates charged for transmission service to FirstEnergy affiliates is dependent
upon the outcome of these proceedings at FERC. All or some of these
proceedings may be consolidated by the FERC and set for hearing. The
outcome of these cases cannot be predicted. Any material adverse
impact on FirstEnergy would depend upon the ability of the load-serving
FirstEnergy affiliates to recover increased transmission costs in their retail
rates. FirstEnergy believes that current retail rate mechanisms in
place for PLR service for the Ohio Companies and for Met-Ed and Penelec would
permit them to pass through increased transmission charges in their retail
rates. Increased transmission charges in the JCP&L and Penn
transmission zones would be the responsibility of competitive electric retail
suppliers, including FES.
MISO
Ancillary Services
Market and Balancing Area Consolidation Filing
MISO
made a filing
on September 14, 2007 to establish Ancillary Services markets for regulation,
spinning and supplemental reserves to consolidate the existing 24 balancing
areas within the MISO footprint, and to establish MISO as the NERC registered
balancing authority for the region. An effective date of June 1, 2008
was requested in the filing.
MISO’s
previous
filing to establish an Ancillary Services market was rejected without prejudice
by FERC on June 22, 2007, subject to MISO making certain modifications in its
filing. FirstEnergy believes that MISO’s September 14 filing generally
addresses the FERC’s directives. FirstEnergy supports the proposal to
establish markets for Ancillary Services and consolidate existing balancing
areas, but filed objections on specific aspects of the MISO
proposal. Interventions and protests to MISO’s filing were made with
FERC on October 15, 2007.
Order
No. 890 on Open Access
Transmission Tariffs
On
February 16,
2007, the FERC issued a final rule (Order No. 890) that revises its decade-old
open access transmission regulations and policies. The FERC explained
that the final rule is intended to strengthen non-discriminatory access to
the
transmission grid, facilitate FERC enforcement, and provide for a more open
and
coordinated transmission planning process. The final rule became
effective on May 14, 2007. MISO, PJM and ATSI will be filing revised
tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff
filings to the FERC on October 11, 2007. As a market participant in both MISO
and PJM, FirstEnergy will conform its business practices to each respective
revised tariff.
12. LEASES
On
July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated
capacity. The purchase price of approximately $1.329 billion (net after-tax
proceeds of approximately $1.2 billion) for the undivided interest was funded
through a combination of equity investments by affiliates of AIG Financial
Products Corp. and Union Bank of California, N.A. in six lessor trusts and
proceeds from the sale of $1.135 billion aggregate principal amount of 6.85%
pass through certificates due 2034. A like principal amount of
secured notes maturing June 1, 2034 were issued by the lessor trusts to the
pass
through trust that issued and sold the certificates. The lessor
trusts leased the undivided interest back to FGCO for a term of approximately
33
years under substantially identical leases. FES has unconditionally and
irrevocably guaranteed all of FGCO’s obligations under each of the leases. FES’
registration obligations under the registration rights agreement applicable
to
the $1.135 billion principal amount of pass through certificates issued in
connection with the transaction were satisfied in September 2007, at which
time
the transaction was classified as an operating lease under GAAP for FES and
FirstEnergy. This transaction generated tax capital gains of approximately
$752 million, all of which were offset by existing tax capital loss
carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward
valuation allowances in the third quarter of 2007, with a corresponding
reduction to goodwill (see Note 3).
The
future minimum
lease payments associated with the recently completed Bruce Mansfield Unit
1
sale and leaseback transaction as of September 30, 2007 are as follows (in
millions):
2007
|
$
|
44
|
2008
|
|
89
|
2009
|
|
89
|
2010
|
|
89
|
2011
|
|
89
|
Years
thereafter
|
|
2,286
|
Total
minimum
lease payments
|
$
|
2,686
|
13. NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
SFAS
157 – “Fair Value
Measurements”
In
September 2006,
the FASB issued SFAS 157 that establishes how companies should measure fair
value when they are required to use a fair value measure for recognition or
disclosure purposes under GAAP. This Statement addresses the need for increased
consistency and comparability in fair value measurements and for expanded
disclosures about fair value measurements. The key changes to current practice
are: (1) the definition of fair value which focuses on an exit price rather
than
entry price; (2) the methods used to measure fair value such as emphasis that
fair value is a market-based measurement, not an entity-specific measurement,
as
well as the inclusion of an adjustment for risk, restrictions and credit
standing; and (3) the expanded disclosures about fair value measurements. This
Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
FirstEnergy is currently evaluating the impact of this Statement on its
financial statements.
|
|
SFAS
159 –
“The Fair Value Option for Financial Assets and Financial Liabilities
–
Including an amendment of
FASB
Statement No. 115”
|
In
February 2007,
the FASB issued SFAS 159, which provides companies with an option to report
selected financial assets and liabilities at fair value. This Statement requires
companies to provide additional information that will help investors and other
users of financial statements to more easily understand the effect of the
company’s choice to use fair value on its earnings. The Standard also
requires companies to display the fair value of those assets and liabilities
for
which the company has chosen to use fair value on the face of the balance
sheet. This guidance does not eliminate disclosure requirements
included in other accounting standards, including requirements for disclosures
about fair value measurements included in SFAS 157 and SFAS
107. This Statement is effective for financial statements issued for
fiscal years beginning after November 15, 2007, and interim periods within
those years. FirstEnergy is currently evaluating the impact of this Statement
on
its financial statements.
EITF
06-11 – “Accounting for Income Tax
Benefits of Dividends or Share-based Payment Awards”
In
June 2007, the
FASB released EITF 06-11, which provides guidance on the appropriate accounting
for income tax benefits related to dividends earned on nonvested share units
that are charged to retained earnings under SFAS 123(R). The
consensus requires that an entity recognize the realized tax benefit associated
with the dividends on nonvested shares as an increase to APIC. This amount
should be included in the APIC pool, which is to be used when an entity’s
estimate of forfeitures increases or actual forfeitures exceed its estimates,
at
which time the tax benefits in the APIC pool would be reclassified to the income
statement. The consensus is effective for income tax benefits of
dividends declared during fiscal years beginning after December 15,
2007. EITF 06-11 is not expected to have a material effect on
FirstEnergy’s financial statements.
FSP
FIN 39-1 – “Amendment of FASB
Interpretation No. 39”
In
April 2007, the
FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to
offset fair value amounts recognized for the right to reclaim cash collateral
(a
receivable) or the obligation to return cash collateral (a payable) against
fair
value amounts recognized for derivative instruments that have been offset under
the same master netting arrangement as the derivative
instruments. This FSP is effective for fiscal years beginning after
November 15, 2007, with early application permitted. The effects of applying
the
guidance in this FSP should be recognized as a retrospective change in
accounting principle for all financial statements presented. FirstEnergy is
currently evaluating the impact of this FSP on its financial statements but
it
is not expected to have a material impact.
14. SEGMENT
INFORMATION
Effective
January 1, 2007, FirstEnergy has three reportable operating segments:
energy delivery services, competitive energy services and Ohio transitional
generation services. None of the aggregate “Other” segments individually meet
the criteria to be considered a reportable segment. The energy delivery services
segment consists of regulated transmission and distribution operations,
including transition cost recovery, and PLR generation service for FirstEnergy’s
Pennsylvania and New Jersey electric utility subsidiaries. The competitive
energy services segment primarily consists of unregulated generation and
commodity operations, including competitive electric sales, and generation
sales
to affiliated electric utilities. The Ohio transitional generation services
segment represents PLR generation service by FirstEnergy’s Ohio electric utility
subsidiaries. “Other” primarily consists of telecommunications services and
other non-core assets. The assets and revenues for the other business operations
are below the quantifiable threshold for operating segments for separate
disclosure as “reportable operating segments.”
The
energy delivery
services segment designs, constructs, operates and maintains FirstEnergy's
regulated transmission and distribution systems and is responsible for the
regulated generation commodity operations of FirstEnergy’s Pennsylvania and New
Jersey electric utility subsidiaries. Its revenues are primarily derived from
the delivery of electricity, cost recovery of regulatory assets and PLR electric
generation sales to non-shopping customers in its Pennsylvania and New Jersey
franchise areas. Its results reflect the commodity costs of securing electric
generation from FES under partial requirements purchased power agreements and
non-affiliated power suppliers as well as the net PJM transmission expenses
related to the delivery of that generation load.
The
competitive
energy services segment supplies electric power to its electric utility
affiliates and competitive electric sales to customers primarily in Ohio,
Pennsylvania, Maryland and Michigan. The segment owns or leases and operates
FirstEnergy’s generating facilities and purchases electricity to meet its sales
obligations. The segment's net income is primarily derived from the affiliated
company power sales and the non-affiliated electric generation sales revenues
less the related costs of electricity generation, including purchased power
and
net transmission (including congestion) and ancillary costs charged by PJM
and
MISO to deliver electricity to the segment’s customers. The segment’s internal
revenues represent the affiliated company power sales.
The
Ohio
transitional generation services segment represents the regulated generation
operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are
primarily derived from electric generation sales to non-shopping customers
under
the PLR obligations of the Ohio Companies. Its results reflect the purchase
of
electric generation from the competitive energy services segment through full
requirements PSA arrangements, the deferral and amortization of certain fuel
costs authorized for recovery by the energy delivery services segment and the
net MISO transmission revenues and expenses related to the delivery of its
generation load. This segment’s total assets consist of accounts receivable for
generation revenues from retail customers.
Segment
reporting in
2006 has been revised to conform to the current year business segment
organization and operations. Changes in the current year operations reporting
and revised 2006 segment reporting primarily reflect the transfer from FES
to
the regulated utilities of the responsibility for obtaining PLR generation
for
the utilities’ non-shopping customers. This reflects FirstEnergy’s alignment of
its business units to accommodate its retail strategy and participation in
competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey.
The
differentiation of the regulated generation commodity operations between the
two
regulated business segments recognizes that generation sourcing for the Ohio
Companies is currently in a transitional state through 2008 as compared to
the
segregated commodity sourcing of their Pennsylvania and New Jersey utility
affiliates. The results of the energy delivery services and the Ohio
transitional generation services segments now include their electric generation
revenues and the corresponding generation commodity costs under affiliated
and
non-affiliated purchased power arrangements and related net retail PJM/MISO
transmission expenses associated with serving electricity load in their
respective franchise areas.
FSG
completed the
sale of its five remaining subsidiaries in 2006. Its assets and results for
2006
are combined in the “Other” segments in this report, as the remaining business
does not meet the criteria of a reportable segment. Interest expense on holding
company debt and corporate support services revenues and expenses are included
in "Reconciling Adjustments."
Segment
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
|
|
|
Reconciling
|
|
|
|
|
Three
Months Ended
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Other
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
September
30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
2,520
|
|
|
$ |
370
|
|
|
$ |
723
|
|
|
$ |
9
|
|
|
$ |
19
|
|
|
$ |
3,641
|
|
Internal
revenues
|
|
|
-
|
|
|
|
806
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(806 |
) |
|
|
-
|
|
Total
revenues
|
|
|
2,520
|
|
|
|
1,176
|
|
|
|
723
|
|
|
|
9
|
|
|
|
(787 |
) |
|
|
3,641
|
|
Depreciation
and amortization
|
|
|
299
|
|
|
|
51
|
|
|
|
(16 |
) |
|
|
1
|
|
|
|
8
|
|
|
|
343
|
|
Investment
income
|
|
|
58
|
|
|
|
5
|
|
|
|
-
|
|
|
|
1
|
|
|
|
(34 |
) |
|
|
30
|
|
Net
interest
charges
|
|
|
117
|
|
|
|
39
|
|
|
|
-
|
|
|
|
1
|
|
|
|
37
|
|
|
|
194
|
|
Income
taxes
|
|
|
175
|
|
|
|
99
|
|
|
|
11
|
|
|
|
(2 |
) |
|
|
(10 |
) |
|
|
273
|
|
Net
income
|
|
|
269
|
|
|
|
148
|
|
|
|
16
|
|
|
|
6
|
|
|
|
(26 |
) |
|
|
413
|
|
Total
assets
|
|
|
23,308
|
|
|
|
7,182
|
|
|
|
268
|
|
|
|
232
|
|
|
|
663
|
|
|
|
31,653
|
|
Total
goodwill
|
|
|
5,585
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,609
|
|
Property
additions
|
|
|
209
|
|
|
|
199
|
|
|
|
-
|
|
|
|
1
|
|
|
|
21
|
|
|
|
430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
2,306
|
|
|
$ |
353
|
|
|
$ |
690
|
|
|
$ |
24
|
|
|
$ |
(9 |
) |
|
$ |
3,364
|
|
Internal
revenues
|
|
|
-
|
|
|
|
762
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(762 |
) |
|
|
-
|
|
Total
revenues
|
|
|
2,306
|
|
|
|
1,115
|
|
|
|
690
|
|
|
|
24
|
|
|
|
(771 |
) |
|
|
3,364
|
|
Depreciation
and amortization
|
|
|
227
|
|
|
|
49
|
|
|
|
(40 |
) |
|
|
1
|
|
|
|
6
|
|
|
|
243
|
|
Investment
income
|
|
|
80
|
|
|
|
18
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(52 |
) |
|
|
46
|
|
Net
interest
charges
|
|
|
107
|
|
|
|
49
|
|
|
|
-
|
|
|
|
2
|
|
|
|
22
|
|
|
|
180
|
|
Income
taxes
|
|
|
187
|
|
|
|
112
|
|
|
|
18
|
|
|
|
(14 |
) |
|
|
(30 |
) |
|
|
273
|
|
Income
from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
continuing
operations
|
|
|
280
|
|
|
|
169
|
|
|
|
27
|
|
|
|
25
|
|
|
|
(49 |
) |
|
|
452
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
Net
income
|
|
|
280
|
|
|
|
169
|
|
|
|
27
|
|
|
|
27
|
|
|
|
(49 |
) |
|
|
454
|
|
Total
assets
|
|
|
23,940
|
|
|
|
6,822
|
|
|
|
240
|
|
|
|
321
|
|
|
|
839
|
|
|
|
32,162
|
|
Total
goodwill
|
|
|
5,911
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,935
|
|
Property
additions
|
|
|
119
|
|
|
|
126
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
6,655
|
|
|
$ |
1,089
|
|
|
$ |
1,968
|
|
|
$ |
29
|
|
|
$ |
(18 |
) |
|
$ |
9,723
|
|
Internal
revenues
|
|
|
-
|
|
|
|
2,210
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,210 |
) |
|
|
-
|
|
Total
revenues
|
|
|
6,655
|
|
|
|
3,299
|
|
|
|
1,968
|
|
|
|
29
|
|
|
|
(2,228 |
) |
|
|
9,723
|
|
Depreciation
and amortization
|
|
|
767
|
|
|
|
153
|
|
|
|
(80 |
) |
|
|
3
|
|
|
|
20
|
|
|
|
863
|
|
Investment
income
|
|
|
190
|
|
|
|
13
|
|
|
|
1
|
|
|
|
1
|
|
|
|
(112 |
) |
|
|
93
|
|
Net
interest
charges
|
|
|
340
|
|
|
|
131
|
|
|
|
1
|
|
|
|
3
|
|
|
|
97
|
|
|
|
572
|
|
Income
taxes
|
|
|
464
|
|
|
|
259
|
|
|
|
46
|
|
|
|
-
|
|
|
|
(74 |
) |
|
|
695
|
|
Net
income
|
|
|
695
|
|
|
|
388
|
|
|
|
69
|
|
|
|
13
|
|
|
|
(124 |
) |
|
|
1,041
|
|
Total
assets
|
|
|
23,308
|
|
|
|
7,182
|
|
|
|
268
|
|
|
|
232
|
|
|
|
663
|
|
|
|
31,653
|
|
Total
goodwill
|
|
|
5,585
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,609
|
|
Property
additions
|
|
|
609
|
|
|
|
462
|
|
|
|
-
|
|
|
|
4
|
|
|
|
52
|
|
|
|
1,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
5,876
|
|
|
$ |
1,077
|
|
|
$ |
1,808
|
|
|
$ |
92
|
|
|
$ |
(32 |
) |
|
$ |
8,821
|
|
Internal
revenues
|
|
|
14
|
|
|
|
1,997
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,011 |
) |
|
|
-
|
|
Total
revenues
|
|
|
5,890
|
|
|
|
3,074
|
|
|
|
1,808
|
|
|
|
92
|
|
|
|
(2,043 |
) |
|
|
8,821
|
|
Depreciation
and amortization
|
|
|
657
|
|
|
|
143
|
|
|
|
(89 |
) |
|
|
3
|
|
|
|
17
|
|
|
|
731
|
|
Investment
income
|
|
|
244
|
|
|
|
35
|
|
|
|
-
|
|
|
|
1
|
|
|
|
(160 |
) |
|
|
120
|
|
Net
interest
charges
|
|
|
308
|
|
|
|
139
|
|
|
|
1
|
|
|
|
5
|
|
|
|
60
|
|
|
|
513
|
|
Income
taxes
|
|
|
468
|
|
|
|
201
|
|
|
|
58
|
|
|
|
(17 |
) |
|
|
(85 |
) |
|
|
625
|
|
Income
from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
continuing
operations
|
|
|
702
|
|
|
|
302
|
|
|
|
88
|
|
|
|
30
|
|
|
|
(139 |
) |
|
|
983
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4 |
) |
|
|
-
|
|
|
|
(4 |
) |
Net
income
|
|
|
702
|
|
|
|
302
|
|
|
|
88
|
|
|
|
26
|
|
|
|
(139 |
) |
|
|
979
|
|
Total
assets
|
|
|
23,940
|
|
|
|
6,822
|
|
|
|
240
|
|
|
|
321
|
|
|
|
839
|
|
|
|
32,162
|
|
Total
goodwill
|
|
|
5,911
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,935
|
|
Property
additions
|
|
|
489
|
|
|
|
473
|
|
|
|
-
|
|
|
|
-
|
|
|
|
28
|
|
|
|
990
|
|
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 and elimination of intersegment transactions.
15. SUPPLEMENTAL
GUARANTOR INFORMATION
As
discussed in Note
12, on July 13, 2007, FGCO completed a sale and leaseback transaction for its
93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally
and irrevocably guaranteed all of FGCO’s obligations under each of the
leases. The related lessor notes and pass through certificates are
not guaranteed by FES or FGCO, but the notes are secured by, among other things,
each lessor trust’s undivided interest in Unit 1, rights and interests under the
applicable lease and rights and interests under other related agreements,
including FES’ lease guaranty.
The
consolidating
statements of income for the three months and nine months ended September 30,
2007 and 2006, consolidating balance sheets as of September 30, 2007 and
December 31, 2006 and condensed consolidating statements of cash flows for
the
nine months ended September 30, 2007 and 2006 for FES (parent), FGCO and NGC
(non-guarantor) are presented below. Investments in wholly owned subsidiaries
are accounted for by FES using the equity method. Results of operations for
FGCO
and NGC are, therefore, reflected in FES’ investment accounts and earnings. The
principal elimination entries eliminate investments in subsidiaries and
intercompany balances and transactions and reflect the consolidating entries
associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback
transaction.
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATING
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended September 30, 2007
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
1,180,449
|
|
|
$ |
496,204
|
|
|
$ |
280,072
|
|
|
$ |
(785,817 |
) |
|
$ |
1,170,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
10,944
|
|
|
|
261,759
|
|
|
|
29,083
|
|
|
|
-
|
|
|
|
301,786
|
|
Purchased
power from non-affiliates
|
|
|
228,755
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
228,755
|
|
Purchased
power from affiliates
|
|
|
774,873
|
|
|
|
57,927
|
|
|
|
15,525
|
|
|
|
(785,817 |
) |
|
|
62,508
|
|
Other
operating expenses
|
|
|
41,828
|
|
|
|
75,985
|
|
|
|
117,220
|
|
|
|
-
|
|
|
|
235,033
|
|
Provision
for
depreciation
|
|
|
650
|
|
|
|
24,669
|
|
|
|
23,181
|
|
|
|
-
|
|
|
|
48,500
|
|
General
taxes
|
|
|
5,406
|
|
|
|
11,788
|
|
|
|
5,048
|
|
|
|
-
|
|
|
|
22,242
|
|
Total
expenses
|
|
|
1,062,456
|
|
|
|
432,128
|
|
|
|
190,057
|
|
|
|
(785,817 |
) |
|
|
898,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
117,993
|
|
|
|
64,076
|
|
|
|
90,015
|
|
|
|
-
|
|
|
|
272,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
income
from equity investees
|
|
|
82,870
|
|
|
|
2,375
|
|
|
|
3,935
|
|
|
|
(76,525 |
) |
|
|
12,655
|
|
Interest
expense to affiliates
|
|
|
(676 |
) |
|
|
(4,769 |
) |
|
|
(4,196 |
) |
|
|
-
|
|
|
|
(9,641 |
) |
Interest
expense - other
|
|
|
(808 |
) |
|
|
(21,274 |
) |
|
|
(9,712 |
) |
|
|
-
|
|
|
|
(31,794 |
) |
Capitalized
interest
|
|
|
9
|
|
|
|
3,889
|
|
|
|
1,233
|
|
|
|
-
|
|
|
|
5,131
|
|
Total
other
income (expense)
|
|
|
81,395
|
|
|
|
(19,779 |
) |
|
|
(8,740 |
) |
|
|
(76,525 |
) |
|
|
(23,649 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
199,388
|
|
|
|
44,297
|
|
|
|
81,275
|
|
|
|
(76,525 |
) |
|
|
248,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
44,624
|
|
|
|
19,850
|
|
|
|
29,197
|
|
|
|
-
|
|
|
|
93,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
154,764
|
|
|
$ |
24,447
|
|
|
$ |
52,078
|
|
|
$ |
(76,525 |
) |
|
$ |
154,764
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATING
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended September 30, 2006
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
1,120,844
|
|
|
$ |
466,628
|
|
|
$ |
246,039
|
|
|
$ |
(723,931 |
) |
|
$ |
1,109,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
12,632
|
|
|
|
273,398
|
|
|
|
29,491
|
|
|
|
-
|
|
|
|
315,521
|
|
Purchased
power from non-affiliates
|
|
|
173,620
|
|
|
|
- |
|
|
|
-
|
|
|
|
-
|
|
|
|
173,620
|
|
Purchased
power from affiliates
|
|
|
711,298
|
|
|
|
52,062
|
|
|
|
16,218
|
|
|
|
(723,931 |
) |
|
|
55,647
|
|
Other
operating expenses
|
|
|
42,115
|
|
|
|
48,728
|
|
|
|
107,873
|
|
|
|
-
|
|
|
|
198,716
|
|
Provision
for
depreciation
|
|
|
456
|
|
|
|
24,656
|
|
|
|
21,782
|
|
|
|
-
|
|
|
|
46,894
|
|
General
taxes
|
|
|
3,223
|
|
|
|
8,931
|
|
|
|
5,455
|
|
|
|
-
|
|
|
|
17,609
|
|
Total
expenses
|
|
|
943,344
|
|
|
|
407,775
|
|
|
|
180,819
|
|
|
|
(723,931 |
) |
|
|
808,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
177,500
|
|
|
|
58,853
|
|
|
|
65,220
|
|
|
|
-
|
|
|
|
301,573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
income
from equity investees
|
|
|
69,102
|
|
|
|
1,694
|
|
|
|
18,089
|
|
|
|
(61,223 |
) |
|
|
27,662
|
|
Interest
expense to affiliates
|
|
|
-
|
|
|
|
(29,988 |
) |
|
|
(11,428 |
) |
|
|
-
|
|
|
|
(41,416 |
) |
Interest
expense - other
|
|
|
(207 |
) |
|
|
(2,749 |
) |
|
|
(4,958 |
) |
|
|
-
|
|
|
|
(7,914 |
) |
Capitalized
interest
|
|
|
5
|
|
|
|
1,217
|
|
|
|
1,167
|
|
|
|
-
|
|
|
|
2,389
|
|
Total
other
income (expense)
|
|
|
68,900
|
|
|
|
(29,826 |
) |
|
|
2,870
|
|
|
|
(61,223 |
) |
|
|
(19,279 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
246,400
|
|
|
|
29,027
|
|
|
|
68,090
|
|
|
|
(61,223 |
) |
|
|
282,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
70,281
|
|
|
|
10,134
|
|
|
|
25,760
|
|
|
|
-
|
|
|
|
106,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
176,119
|
|
|
$ |
18,893
|
|
|
$ |
42,330
|
|
|
$ |
(61,223 |
) |
|
$ |
176,119
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATING
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30, 2007
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
3,274,694
|
|
|
$ |
1,501,112
|
|
|
$ |
793,255
|
|
|
$ |
(2,311,129 |
) |
|
$ |
3,257,932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
20,824
|
|
|
|
698,643
|
|
|
|
84,734
|
|
|
|
-
|
|
|
|
804,201
|
|
Purchased
power from non-affiliates
|
|
|
577,831
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
577,831
|
|
Purchased
power from affiliates
|
|
|
2,290,305
|
|
|
|
176,654
|
|
|
|
53,746
|
|
|
|
(2,311,129 |
) |
|
|
209,576
|
|
Other
operating expenses
|
|
|
123,596
|
|
|
|
240,774
|
|
|
|
367,404
|
|
|
|
-
|
|
|
|
731,774
|
|
Provision
for
depreciation
|
|
|
1,572
|
|
|
|
74,844
|
|
|
|
68,614
|
|
|
|
-
|
|
|
|
145,030
|
|
General
taxes
|
|
|
15,942
|
|
|
|
31,406
|
|
|
|
17,522
|
|
|
|
-
|
|
|
|
64,870
|
|
Total
expenses
|
|
|
3,030,070
|
|
|
|
1,222,321
|
|
|
|
592,020
|
|
|
|
(2,311,129 |
) |
|
|
2,533,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
244,624
|
|
|
|
278,791
|
|
|
|
201,235
|
|
|
|
-
|
|
|
|
724,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
income
from equity investees
|
|
|
271,599
|
|
|
|
2,669
|
|
|
|
13,350
|
|
|
|
(239,862 |
) |
|
|
47,756
|
|
Interest
expense to affiliates
|
|
|
(676 |
) |
|
|
(47,090 |
) |
|
|
(14,138 |
) |
|
|
-
|
|
|
|
(61,904 |
) |
Interest
expense - other
|
|
|
(7,966 |
) |
|
|
(34,150 |
) |
|
|
(28,729 |
) |
|
|
-
|
|
|
|
(70,845 |
) |
Capitalized
interest
|
|
|
20
|
|
|
|
9,044
|
|
|
|
3,699
|
|
|
|
-
|
|
|
|
12,763
|
|
Total
other
income (expense)
|
|
|
262,977
|
|
|
|
(69,527 |
) |
|
|
(25,818 |
) |
|
|
(239,862 |
) |
|
|
(72,230 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
507,601
|
|
|
|
209,264
|
|
|
|
175,417
|
|
|
|
(239,862 |
) |
|
|
652,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
98,917
|
|
|
|
82,031
|
|
|
|
62,788
|
|
|
|
-
|
|
|
|
243,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
408,684
|
|
|
$ |
127,233
|
|
|
$ |
112,629
|
|
|
$ |
(239,862 |
) |
|
$ |
408,684
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATING
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30, 2006
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
3,071,970
|
|
|
$ |
1,336,076
|
|
|
$ |
797,967
|
|
|
$ |
(2,145,891 |
) |
|
$ |
3,060,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
16,650
|
|
|
|
752,229
|
|
|
|
76,034
|
|
|
|
-
|
|
|
|
844,913
|
|
Purchased
power from non-affiliates
|
|
|
477,249
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
477,249
|
|
Purchased
power from affiliates
|
|
|
2,143,509
|
|
|
|
141,974
|
|
|
|
49,106
|
|
|
|
(2,145,891 |
) |
|
|
188,698
|
|
Other
operating expenses
|
|
|
149,042
|
|
|
|
204,282
|
|
|
|
421,443
|
|
|
|
-
|
|
|
|
774,767
|
|
Provision
for
depreciation
|
|
|
1,314
|
|
|
|
72,778
|
|
|
|
61,322
|
|
|
|
-
|
|
|
|
135,414
|
|
General
taxes
|
|
|
9,268
|
|
|
|
29,536
|
|
|
|
16,746
|
|
|
|
-
|
|
|
|
55,550
|
|
Total
expenses
|
|
|
2,797,032
|
|
|
|
1,200,799
|
|
|
|
624,651
|
|
|
|
(2,145,891 |
) |
|
|
2,476,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
274,938
|
|
|
|
135,277
|
|
|
|
173,316
|
|
|
|
-
|
|
|
|
583,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
income
from equity investees
|
|
|
146,375
|
|
|
|
(3,052 |
) |
|
|
35,518
|
|
|
|
(133,998 |
) |
|
|
44,843
|
|
Interest
expense to affiliates
|
|
|
(241 |
) |
|
|
(87,318 |
) |
|
|
(35,105 |
) |
|
|
-
|
|
|
|
(122,664 |
) |
Interest
expense - other
|
|
|
(564 |
) |
|
|
(5,650 |
) |
|
|
(11,666 |
) |
|
|
-
|
|
|
|
(17,880 |
) |
Capitalized
interest
|
|
|
(3 |
) |
|
|
3,290
|
|
|
|
5,411
|
|
|
|
-
|
|
|
|
8,698
|
|
Total
other
income (expense)
|
|
|
145,567
|
|
|
|
(92,730 |
) |
|
|
(5,842 |
) |
|
|
(133,998 |
) |
|
|
(87,003 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
420,505
|
|
|
|
42,547
|
|
|
|
167,474
|
|
|
|
(133,998 |
) |
|
|
496,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
108,549
|
|
|
|
13,296
|
|
|
|
62,727
|
|
|
|
-
|
|
|
|
184,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
311,956
|
|
|
$ |
29,251
|
|
|
$ |
104,747
|
|
|
$ |
(133,998 |
) |
|
$ |
311,956
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATING
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of
September 30, 2007
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
2
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
2
|
|
Receivables-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
144,443
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
144,443
|
|
Associated
companies
|
|
|
282,118
|
|
|
|
169,108
|
|
|
|
113,936
|
|
|
|
(279,700 |
) |
|
|
285,462
|
|
Other
|
|
|
4,862
|
|
|
|
554
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,416
|
|
Notes
receivable from associated companies
|
|
|
-
|
|
|
|
242,612
|
|
|
|
-
|
|
|
|
-
|
|
|
|
242,612
|
|
Materials
and
supplies, at average cost
|
|
|
195
|
|
|
|
224,149
|
|
|
|
216,722
|
|
|
|
-
|
|
|
|
441,066
|
|
Prepayments
and other
|
|
|
67,892
|
|
|
|
13,693
|
|
|
|
2,240
|
|
|
|
-
|
|
|
|
83,825
|
|
|
|
|
499,512
|
|
|
|
650,116
|
|
|
|
332,898
|
|
|
|
(279,700 |
) |
|
|
1,202,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
25,171
|
|
|
|
5,023,255
|
|
|
|
3,530,969
|
|
|
|
(395,817 |
) |
|
|
8,183,578
|
|
Less
-
Accumulated provision for depreciation
|
|
|
6,807
|
|
|
|
2,539,192
|
|
|
|
1,476,051
|
|
|
|
(169,154 |
) |
|
|
3,852,896
|
|
|
|
|
18,364
|
|
|
|
2,484,063
|
|
|
|
2,054,918
|
|
|
|
(226,663 |
) |
|
|
4,330,682
|
|
Construction
work in progress
|
|
|
1,034
|
|
|
|
414,243
|
|
|
|
181,602
|
|
|
|
-
|
|
|
|
596,879
|
|
|
|
|
19,398
|
|
|
|
2,898,306
|
|
|
|
2,236,520
|
|
|
|
(226,663 |
) |
|
|
4,927,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
1,342,083
|
|
|
|
-
|
|
|
|
1,342,083
|
|
Long-term
notes receivable from associated companies
|
|
|
-
|
|
|
|
-
|
|
|
|
62,900
|
|
|
|
-
|
|
|
|
62,900
|
|
Investment
in
associated companies
|
|
|
2,462,960
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,462,960 |
) |
|
|
-
|
|
Other
|
|
|
5,315
|
|
|
|
34,447
|
|
|
|
202
|
|
|
|
-
|
|
|
|
39,964
|
|
|
|
|
2,468,275
|
|
|
|
34,447
|
|
|
|
1,405,185
|
|
|
|
(2,462,960 |
) |
|
|
1,444,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
28,756
|
|
|
|
403,890
|
|
|
|
-
|
|
|
|
(192,464 |
) |
|
|
240,182
|
|
Goodwill
|
|
|
24,248
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
24,248
|
|
Property
taxes
|
|
|
-
|
|
|
|
20,946
|
|
|
|
23,165
|
|
|
|
-
|
|
|
|
44,111
|
|
Pension
assets
|
|
|
1,154
|
|
|
|
8,295
|
|
|
|
-
|
|
|
|
-
|
|
|
|
9,449
|
|
Other
|
|
|
33,049
|
|
|
|
32,477
|
|
|
|
5,112
|
|
|
|
-
|
|
|
|
70,638
|
|
|
|
|
87,207
|
|
|
|
465,608
|
|
|
|
28,277
|
|
|
|
(192,464 |
) |
|
|
388,628
|
|
|
|
$ |
3,074,392
|
|
|
$ |
4,048,477
|
|
|
$ |
4,002,880
|
|
|
$ |
(3,161,787 |
) |
|
$ |
7,963,962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
-
|
|
|
$ |
624,517
|
|
|
$ |
861,265
|
|
|
$ |
(16,061 |
) |
|
$ |
1,469,721
|
|
Notes
payable-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
223,942
|
|
|
|
-
|
|
|
|
13,128
|
|
|
|
-
|
|
|
|
237,070
|
|
Other
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
279,976
|
|
|
|
158,500
|
|
|
|
273,919
|
|
|
|
(279,700 |
) |
|
|
432,695
|
|
Other
|
|
|
65,782
|
|
|
|
112,038
|
|
|
|
-
|
|
|
|
-
|
|
|
|
177,820
|
|
Accrued
taxes
|
|
|
44,995
|
|
|
|
461,635
|
|
|
|
30,430
|
|
|
|
-
|
|
|
|
537,060
|
|
Other
|
|
|
60,252
|
|
|
|
59,770
|
|
|
|
9,731
|
|
|
|
33,486
|
|
|
|
163,239
|
|
|
|
|
674,947
|
|
|
|
1,416,460
|
|
|
|
1,188,473
|
|
|
|
(262,275 |
) |
|
|
3,017,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
2,369,019
|
|
|
|
905,100
|
|
|
|
1,557,860
|
|
|
|
(2,462,960 |
) |
|
|
2,369,019
|
|
Long-term
debt
|
|
|
-
|
|
|
|
1,575,653
|
|
|
|
242,400
|
|
|
|
(1,312,857 |
) |
|
|
505,196
|
|
|
|
|
2,369,019
|
|
|
|
2,480,753
|
|
|
|
1,800,260
|
|
|
|
(3,775,817 |
) |
|
|
2,874,215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
gain
on sale and leaseback transaction
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,068,769
|
|
|
|
1,068,769
|
|
Accumulated
deferred income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
192,464
|
|
|
|
(192,464 |
) |
|
|
-
|
|
Accumulated
deferred investment tax credits
|
|
|
-
|
|
|
|
36,764
|
|
|
|
25,511
|
|
|
|
-
|
|
|
|
62,275
|
|
Asset
retirement obligations
|
|
|
-
|
|
|
|
24,350
|
|
|
|
773,007
|
|
|
|
-
|
|
|
|
797,357
|
|
Retirement
benefits
|
|
|
7,843
|
|
|
|
45,662
|
|
|
|
-
|
|
|
|
-
|
|
|
|
53,505
|
|
Property
taxes
|
|
|
-
|
|
|
|
21,268
|
|
|
|
23,165
|
|
|
|
-
|
|
|
|
44,433
|
|
Other
|
|
|
22,583
|
|
|
|
23,220
|
|
|
|
-
|
|
|
|
-
|
|
|
|
45,803
|
|
|
|
|
30,426
|
|
|
|
151,264
|
|
|
|
1,014,147
|
|
|
|
876,305
|
|
|
|
2,072,142
|
|
|
|
$ |
3,074,392
|
|
|
$ |
4,048,477
|
|
|
$ |
4,002,880
|
|
|
$ |
(3,161,787 |
) |
|
$ |
7,963,962
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATING
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of
December 31, 2006
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
2
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
2
|
|
Receivables-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
129,843
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
129,843
|
|
Associated
companies
|
|
|
201,281
|
|
|
|
160,965
|
|
|
|
69,751
|
|
|
|
(196,465 |
) |
|
|
235,532
|
|
Other
|
|
|
2,383
|
|
|
|
1,702
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,085
|
|
Notes
receivable from associated companies
|
|
|
460,023
|
|
|
|
-
|
|
|
|
292,896
|
|
|
|
-
|
|
|
|
752,919
|
|
Materials
and
supplies, at average cost
|
|
|
195
|
|
|
|
238,936
|
|
|
|
221,108
|
|
|
|
-
|
|
|
|
460,239
|
|
Prepayments
and other
|
|
|
45,314
|
|
|
|
10,389
|
|
|
|
1,843
|
|
|
|
-
|
|
|
|
57,546
|
|
|
|
|
839,041
|
|
|
|
411,992
|
|
|
|
585,598
|
|
|
|
(196,465 |
) |
|
|
1,640,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
16,261
|
|
|
|
4,960,453
|
|
|
|
3,378,630
|
|
|
|
-
|
|
|
|
8,355,344
|
|
Less
-
Accumulated provision for depreciation
|
|
|
5,738
|
|
|
|
2,477,004
|
|
|
|
1,335,526
|
|
|
|
-
|
|
|
|
3,818,268
|
|
|
|
|
10,523
|
|
|
|
2,483,449
|
|
|
|
2,043,104
|
|
|
|
-
|
|
|
|
4,537,076
|
|
Construction
work in progress
|
|
|
345
|
|
|
|
170,063
|
|
|
|
169,478
|
|
|
|
-
|
|
|
|
339,886
|
|
|
|
|
10,868
|
|
|
|
2,653,512
|
|
|
|
2,212,582
|
|
|
|
-
|
|
|
|
4,876,962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
1,238,272
|
|
|
|
-
|
|
|
|
1,238,272
|
|
Long-term
notes receivable from associated companies
|
|
|
-
|
|
|
|
-
|
|
|
|
62,900
|
|
|
|
-
|
|
|
|
62,900
|
|
Investment
in
associated companies
|
|
|
1,471,184
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,471,184 |
) |
|
|
-
|
|
Other
|
|
|
6,474
|
|
|
|
65,833
|
|
|
|
202
|
|
|
|
-
|
|
|
|
72,509
|
|
|
|
|
1,477,658
|
|
|
|
65,833
|
|
|
|
1,301,374
|
|
|
|
(1,471,184 |
) |
|
|
1,373,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
24,248
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
24,248
|
|
Property
taxes
|
|
|
-
|
|
|
|
20,946
|
|
|
|
23,165
|
|
|
|
-
|
|
|
|
44,111
|
|
Accumulated
deferred income taxes
|
|
|
32,939
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(32,939 |
) |
|
|
-
|
|
Other
|
|
|
23,544
|
|
|
|
11,542
|
|
|
|
4,753
|
|
|
|
-
|
|
|
|
39,839
|
|
|
|
|
80,731
|
|
|
|
32,488
|
|
|
|
27,918
|
|
|
|
(32,939 |
) |
|
|
108,198
|
|
|
|
$ |
2,408,298
|
|
|
$ |
3,163,825
|
|
|
$ |
4,127,472
|
|
|
$ |
(1,700,588 |
) |
|
$ |
7,999,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
-
|
|
|
$ |
608,395
|
|
|
$ |
861,265
|
|
|
$ |
-
|
|
|
$ |
1,469,660
|
|
Notes
payable
to associated companies
|
|
|
-
|
|
|
|
1,022,197
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,022,197
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
375,328
|
|
|
|
11,964
|
|
|
|
365,222
|
|
|
|
(196,465 |
) |
|
|
556,049
|
|
Other
|
|
|
32,864
|
|
|
|
103,767
|
|
|
|
-
|
|
|
|
-
|
|
|
|
136,631
|
|
Accrued
taxes
|
|
|
54,537
|
|
|
|
32,028
|
|
|
|
26,666
|
|
|
|
-
|
|
|
|
113,231
|
|
Other
|
|
|
49,906
|
|
|
|
41,401
|
|
|
|
9,634
|
|
|
|
-
|
|
|
|
100,941
|
|
|
|
|
512,635
|
|
|
|
1,819,752
|
|
|
|
1,262,787
|
|
|
|
(196,465 |
) |
|
|
3,398,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
1,859,363
|
|
|
|
78,542
|
|
|
|
1,392,642
|
|
|
|
(1,471,184 |
) |
|
|
1,859,363
|
|
Long-term
debt
|
|
|
-
|
|
|
|
1,057,252
|
|
|
|
556,970
|
|
|
|
-
|
|
|
|
1,614,222
|
|
|
|
|
1,859,363
|
|
|
|
1,135,794
|
|
|
|
1,949,612
|
|
|
|
(1,471,184 |
) |
|
|
3,473,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
-
|
|
|
|
25,293
|
|
|
|
129,095
|
|
|
|
(32,939 |
) |
|
|
121,449
|
|
Accumulated
deferred investment tax credits
|
|
|
-
|
|
|
|
38,894
|
|
|
|
26,857
|
|
|
|
-
|
|
|
|
65,751
|
|
Asset
retirement obligations
|
|
|
-
|
|
|
|
24,272
|
|
|
|
735,956
|
|
|
|
-
|
|
|
|
760,228
|
|
Retirement
benefits
|
|
|
10,255
|
|
|
|
92,772
|
|
|
|
-
|
|
|
|
-
|
|
|
|
103,027
|
|
Property
taxes
|
|
|
-
|
|
|
|
21,268
|
|
|
|
23,165
|
|
|
|
-
|
|
|
|
44,433
|
|
Other
|
|
|
26,045
|
|
|
|
5,780
|
|
|
|
-
|
|
|
|
-
|
|
|
|
31,825
|
|
|
|
|
36,300
|
|
|
|
208,279
|
|
|
|
915,073
|
|
|
|
(32,939 |
) |
|
|
1,126,713
|
|
|
|
$ |
2,408,298
|
|
|
$ |
3,163,825
|
|
|
$ |
4,127,472
|
|
|
$ |
(1,700,588 |
) |
|
$ |
7,999,007
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30, 2007
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CASH PROVIDED FROM (USED FOR)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
$ |
(17,080 |
) |
|
$ |
350,927
|
|
|
$ |
146,468
|
|
|
$ |
-
|
|
|
$ |
480,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
|
1,328,919
|
|
|
|
-
|
|
|
|
(1,328,919 |
) |
|
|
-
|
|
Equity
contribution from parent
|
|
|
710,468
|
|
|
|
700,000
|
|
|
|
1,325
|
|
|
|
(701,325 |
) |
|
|
710,468
|
|
Short-term
borrowings, net
|
|
|
223,942
|
|
|
|
-
|
|
|
|
13,128
|
|
|
|
(237,070 |
) |
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
|
(795,019 |
) |
|
|
(315,155 |
) |
|
|
-
|
|
|
|
(1,110,174 |
) |
Short-term
borrowings, net
|
|
|
-
|
|
|
|
(1,022,197 |
) |
|
|
-
|
|
|
|
237,070
|
|
|
|
(785,127 |
) |
Common
stock
|
|
|
(600,000 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(600,000 |
) |
Common
stock
dividend payments
|
|
|
(67,000 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(67,000 |
) |
Net
cash
provided from (used for) financing activities
|
|
|
267,410
|
|
|
|
211,703
|
|
|
|
(300,702 |
) |
|
|
(2,030,244 |
) |
|
|
(1,851,833 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(10,119 |
) |
|
|
(332,499 |
) |
|
|
(140,289 |
) |
|
|
-
|
|
|
|
(482,907 |
) |
Proceeds
from
asset sales
|
|
|
-
|
|
|
|
12,990
|
|
|
|
-
|
|
|
|
-
|
|
|
|
12,990
|
|
Proceeds
from
sale and leaseback transaction
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,328,919
|
|
|
|
1,328,919
|
|
Sales
of
investment securities held in trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
521,535
|
|
|
|
-
|
|
|
|
521,535
|
|
Purchases
of
investment securities held in trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
(521,535 |
) |
|
|
-
|
|
|
|
(521,535 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
460,023
|
|
|
|
(242,612 |
) |
|
|
292,896
|
|
|
|
-
|
|
|
|
510,307
|
|
Investment
in
subsidiary
|
|
|
(701,325 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
701,325
|
|
|
|
-
|
|
Other
|
|
|
1,091
|
|
|
|
(509 |
) |
|
|
1,627
|
|
|
|
- |
|
|
|
2,209
|
|
Net
cash
provided from (used for) investing activities
|
|
|
(250,330 |
) |
|
|
(562,630 |
) |
|
|
154,234
|
|
|
|
2,030,244
|
|
|
|
1,371,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
2
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
2
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Nine Months Ended September 30, 2006
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CASH PROVIDED FROM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
$ |
145,390
|
|
|
$ |
72,860
|
|
|
$ |
239,855
|
|
|
$ |
-
|
|
|
$ |
458,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
|
146,704
|
|
|
|
105,241
|
|
|
|
-
|
|
|
|
251,945
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
|
66,817
|
|
|
|
- |
|
|
|
-
|
|
|
|
66,817
|
|
Redemptions
and Reyapments- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
(146,740 |
) |
|
|
(106,500 |
) |
|
|
- |
|
|
|
(253,240 |
) |
Net
cash
provided from financing activities
|
|
|
-
|
|
|
|
66,781
|
|
|
|
(1,259
|
) |
|
|
-
|
|
|
|
65,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(699 |
) |
|
|
(131,853 |
) |
|
|
(294,746 |
) |
|
|
-
|
|
|
|
(427,298 |
) |
Proceeds
from
asset sales
|
|
|
-
|
|
|
|
20,437
|
|
|
|
-
|
|
|
|
-
|
|
|
|
20,437
|
|
Sales
of
investment securities held in trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
886,863
|
|
|
|
-
|
|
|
|
886,863
|
|
Purchases
of
investment securities held in trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
(886,863 |
) |
|
|
-
|
|
|
|
(886,863 |
) |
Loans
to
associated companies
|
|
|
(145,734 |
) |
|
|
- |
|
|
|
57,442 |
|
|
|
-
|
|
|
|
(88,292 |
) |
Other
|
|
|
1,043
|
|
|
|
(28,225 |
) |
|
|
(1,292 |
) |
|
|
-
|
|
|
|
(28,474 |
) |
Net
cash used
for investing activities
|
|
|
(145,390 |
) |
|
|
(139,641 |
) |
|
|
(238,596 |
) |
|
|
-
|
|
|
|
(523,627 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
2
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
2
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
utilities
|
|
$ |
3,260
|
|
|
$ |
2,996
|
|
|
$ |
8,685
|
|
|
$ |
7,677
|
|
Unregulated
businesses
|
|
|
381
|
|
|
|
368
|
|
|
|
1,038
|
|
|
|
1,144
|
|
Total
revenues
*
|
|
|
3,641
|
|
|
|
3,364
|
|
|
|
9,723
|
|
|
|
8,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
1,495
|
|
|
|
1,317
|
|
|
|
3,801
|
|
|
|
3,306
|
|
Other
operating expenses
|
|
|
756
|
|
|
|
758
|
|
|
|
2,255
|
|
|
|
2,230
|
|
Provision
for
depreciation
|
|
|
162
|
|
|
|
153
|
|
|
|
477
|
|
|
|
445
|
|
Amortization
of regulatory assets
|
|
|
288
|
|
|
|
243
|
|
|
|
785
|
|
|
|
665
|
|
Deferral
of
new regulatory assets
|
|
|
(107 |
) |
|
|
(153 |
) |
|
|
(399 |
) |
|
|
(379 |
) |
General
taxes
|
|
|
197
|
|
|
|
187
|
|
|
|
589
|
|
|
|
553
|
|
Total
expenses
|
|
|
2,791
|
|
|
|
2,505
|
|
|
|
7,508
|
|
|
|
6,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
850
|
|
|
|
859
|
|
|
|
2,215
|
|
|
|
2,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
30
|
|
|
|
46
|
|
|
|
93
|
|
|
|
120
|
|
Interest
expense
|
|
|
(203 |
) |
|
|
(185 |
) |
|
|
(593 |
) |
|
|
(528 |
) |
Capitalized
interest
|
|
|
9
|
|
|
|
7
|
|
|
|
21
|
|
|
|
21
|
|
Subsidiaries’
preferred stock dividends
|
|
|
-
|
|
|
|
(2 |
) |
|
|
-
|
|
|
|
(6 |
) |
Total
other
expense
|
|
|
(164 |
) |
|
|
(134 |
) |
|
|
(479 |
) |
|
|
(393 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
|
|
|
686
|
|
|
|
725
|
|
|
|
1,736
|
|
|
|
1,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
273
|
|
|
|
273
|
|
|
|
695
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
FROM CONTINUING OPERATIONS
|
|
|
413
|
|
|
|
452
|
|
|
|
1,041
|
|
|
|
983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income tax benefits of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1
million and
$2 million in the three months and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
nine
months
ended September 30, 2006, respectively) (Note 4)
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
413
|
|
|
$ |
454
|
|
|
$ |
1,041
|
|
|
$ |
979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$ |
1.36
|
|
|
$ |
1.40
|
|
|
$ |
3.39
|
|
|
$ |
3.00
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
0.01
|
|
|
|
-
|
|
|
|
(0.01 |
) |
Net
earnings
per basic share
|
|
$ |
1.36
|
|
|
$ |
1.41
|
|
|
$ |
3.39
|
|
|
$ |
2.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
304
|
|
|
|
322
|
|
|
|
307
|
|
|
|
326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$ |
1.34
|
|
|
$ |
1.39
|
|
|
$ |
3.35
|
|
|
$ |
2.98
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
0.01
|
|
|
|
-
|
|
|
|
(0.01 |
) |
Net
earnings
per diluted share
|
|
$ |
1.34
|
|
|
$ |
1.40
|
|
|
$ |
3.35
|
|
|
$ |
2.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
307
|
|
|
|
325
|
|
|
|
311
|
|
|
|
329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$ |
1.00
|
|
|
$ |
0.45
|
|
|
$ |
1.50
|
|
|
$ |
1.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Includes
excise tax collections of $108 million in the third quarter of
both 2007
and 2006, and $308 million and $297 million in the nine
|
months ended September 2007 and 2006, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Corp. are an integral part of these
statements.
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
413
|
|
|
$ |
454
|
|
|
$ |
1,041
|
|
|
$ |
979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(12 |
) |
|
|
-
|
|
|
|
(34 |
) |
|
|
-
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
(10 |
) |
|
|
(28 |
) |
|
|
10
|
|
|
|
45
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
26
|
|
|
|
26
|
|
|
|
89
|
|
|
|
39
|
|
Other
comprehensive income (loss)
|
|
|
4
|
|
|
|
(2 |
) |
|
|
65
|
|
|
|
84
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
-
|
|
|
|
(1 |
) |
|
|
19
|
|
|
|
30
|
|
Other
comprehensive income (loss), net of tax
|
|
|
4
|
|
|
|
(1 |
) |
|
|
46
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
$ |
417
|
|
|
$ |
453
|
|
|
$ |
1,087
|
|
|
$ |
1,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Corp. are an integral part of
|
|
|
|
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
30
|
|
|
$ |
90
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $38 million and
|
|
|
|
|
|
|
|
|
$43
million,
respectively, for uncollectible accounts)
|
|
|
1,432
|
|
|
|
1,135
|
|
Other
(less
accumulated provisions of $22 million and
|
|
|
|
|
|
|
|
|
$24
million,
respectively, for uncollectible accounts)
|
|
|
194
|
|
|
|
132
|
|
Materials
and
supplies, at average cost
|
|
|
543
|
|
|
|
577
|
|
Prepayments
and other
|
|
|
207
|
|
|
|
149
|
|
|
|
|
2,406
|
|
|
|
2,083
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
24,353
|
|
|
|
24,105
|
|
Less
-
Accumulated provision for depreciation
|
|
|
10,248
|
|
|
|
10,055
|
|
|
|
|
14,105
|
|
|
|
14,050
|
|
Construction
work in progress
|
|
|
933
|
|
|
|
617
|
|
|
|
|
15,038
|
|
|
|
14,667
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
2,140
|
|
|
|
1,977
|
|
Investments
in
lease obligation bonds
|
|
|
738
|
|
|
|
811
|
|
Other
|
|
|
787
|
|
|
|
746
|
|
|
|
|
3,665
|
|
|
|
3,534
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
5,609
|
|
|
|
5,898
|
|
Regulatory
assets
|
|
|
4,047
|
|
|
|
4,441
|
|
Pension
assets
|
|
|
318
|
|
|
|
-
|
|
Other
|
|
|
570
|
|
|
|
573
|
|
|
|
|
10,544
|
|
|
|
10,912
|
|
|
|
$ |
31,653
|
|
|
$ |
31,196
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
2,265
|
|
|
$ |
1,867
|
|
Short-term
borrowings
|
|
|
573
|
|
|
|
1,108
|
|
Accounts
payable
|
|
|
760
|
|
|
|
726
|
|
Accrued
taxes
|
|
|
671
|
|
|
|
598
|
|
Accrued
interest
|
|
|
215
|
|
|
|
111
|
|
Other
|
|
|
894
|
|
|
|
845
|
|
|
|
|
5,378
|
|
|
|
5,255
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholders’ equity-
|
|
|
|
|
|
|
|
|
Common
stock,
$.10 par value, authorized 375,000,000 shares-
|
|
|
|
|
|
|
|
|
304,835,407
and 319,205,517 shares outstanding, respectively
|
|
|
30
|
|
|
|
32
|
|
Other
paid-in
capital
|
|
|
5,564
|
|
|
|
6,466
|
|
Accumulated
other comprehensive loss
|
|
|
(213 |
) |
|
|
(259 |
) |
Retained
earnings
|
|
|
3,387
|
|
|
|
2,806
|
|
Unallocated
employee stock ownership plan common stock-
|
|
|
|
|
|
|
|
|
521,818
shares
|
|
|
-
|
|
|
|
(10 |
) |
Total
common
stockholders' equity
|
|
|
8,768
|
|
|
|
9,035
|
|
Long-term
debt
and other long-term obligations
|
|
|
8,617
|
|
|
|
8,535
|
|
|
|
|
17,385
|
|
|
|
17,570
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
2,317
|
|
|
|
2,740
|
|
Asset
retirement obligations
|
|
|
1,247
|
|
|
|
1,190
|
|
Deferred
gain
on sale and leaseback transaction
|
|
|
1,069
|
|
|
|
-
|
|
Power
purchase
contract loss liability
|
|
|
872
|
|
|
|
1,182
|
|
Retirement
benefits
|
|
|
918
|
|
|
|
944
|
|
Lease
market
valuation liability
|
|
|
684
|
|
|
|
767
|
|
Other
|
|
|
1,783
|
|
|
|
1,548
|
|
|
|
|
8,890
|
|
|
|
8,371
|
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
31,653
|
|
|
$ |
31,196
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of these
|
|
balance
sheets.
|
|
|
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
1,041
|
|
|
$ |
979
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
477
|
|
|
|
445
|
|
Amortization
of regulatory assets
|
|
|
785
|
|
|
|
665
|
|
Deferral
of
new regulatory assets
|
|
|
(399 |
) |
|
|
(379 |
) |
Nuclear
fuel
and lease amortization
|
|
|
75
|
|
|
|
67
|
|
Deferred
purchased power and other costs
|
|
|
(265 |
) |
|
|
(323 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(158 |
) |
|
|
36
|
|
Investment
impairment
|
|
|
16
|
|
|
|
13
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(41 |
) |
|
|
(54 |
) |
Accrued
compensation and retirement benefits
|
|
|
(50 |
) |
|
|
78
|
|
Commodity
derivative transactions, net
|
|
|
5
|
|
|
|
28
|
|
Gain
on asset
sales
|
|
|
(35 |
) |
|
|
(38 |
) |
Income
from
discontinued operations
|
|
|
-
|
|
|
|
4
|
|
Cash
collateral
|
|
|
(50 |
) |
|
|
(98 |
) |
Pension
trust
contribution
|
|
|
(300 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(329 |
) |
|
|
(7 |
) |
Materials
and
supplies
|
|
|
62
|
|
|
|
(30 |
) |
Prepayments
and other current assets
|
|
|
(39 |
) |
|
|
(49 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(15 |
) |
|
|
(93 |
) |
Accrued
taxes
|
|
|
355
|
|
|
|
(32 |
) |
Accrued
interest
|
|
|
104
|
|
|
|
104
|
|
Electric
service prepayment programs
|
|
|
(52 |
) |
|
|
(45 |
) |
Other
|
|
|
(36 |
) |
|
|
(28 |
) |
Net
cash
provided from operating activities
|
|
|
1,151
|
|
|
|
1,243
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,100
|
|
|
|
1,235
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
|
482
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(918 |
) |
|
|
(600 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(107 |
) |
Long-term
debt
|
|
|
(647 |
) |
|
|
(993 |
) |
Short-term
borrowings, net
|
|
|
(535 |
) |
|
|
-
|
|
Net
controlled
disbursement activity
|
|
|
6
|
|
|
|
(22 |
) |
Stock-based
compensation tax benefit
|
|
|
16
|
|
|
|
-
|
|
Common
stock
dividend payments
|
|
|
(464 |
) |
|
|
(439 |
) |
Net
cash used
for financing activities
|
|
|
(1,442 |
) |
|
|
(444 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(1,127 |
) |
|
|
(990 |
) |
Proceeds
from
asset sales
|
|
|
37
|
|
|
|
83
|
|
Proceeds
from
sale and leaseback transaction
|
|
|
1,329
|
|
|
|
-
|
|
Sales
of
investment securities held in trusts
|
|
|
1,010
|
|
|
|
1,370
|
|
Purchases
of
investment securities held in trusts
|
|
|
(1,067 |
) |
|
|
(1,381 |
) |
Cash
investments
|
|
|
48
|
|
|
|
109
|
|
Other
|
|
|
1
|
|
|
|
(13 |
) |
Net
cash
provided from (used for) investing activities
|
|
|
231
|
|
|
|
(822 |
) |
|
|
|
|
|
|
|
|
|
Net
decrease
in cash and cash equivalents
|
|
|
(60 |
) |
|
|
(23 |
) |
Cash
and cash
equivalents at beginning of period
|
|
|
90
|
|
|
|
64
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
30
|
|
|
$ |
41
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2007 and 2006 and the consolidated statement of
cash
flows for the nine-month periods ended September 30, 2007 and
2006. 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
(United States), the objective of which is the expression of an opinion
regarding the financial statements taken as a whole. Accordingly, we
do not express such an opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, and the related consolidated statements of income, capitalization,
common stockholders’ equity, preferred stock, and of cash flows 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006 and conditional
asset retirement obligations as of December 31, 2005, as discussed in Note
3,
Note 2(K) and Note 12 to the consolidated financial statements) dated
February 27, 2007, except as to Note 2(H) and Note 16, which are as of September
14, 2007, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31, 2006,
is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE
SUMMARY
Net
income in the
third quarter of 2007 was $413 million, or basic earnings of $1.36 per share
of
common stock ($1.34 diluted), compared with net income of $454 million, or
basic
earnings of $1.41 per share of common stock ($1.40 diluted) in the third quarter
of 2006. Net income in the first nine months of 2007 was $1.04 billion, or
basic
earnings of $3.39 per share of common stock ($3.35 diluted), compared with
net
income of $979 million, or basic earnings of $2.99 per share of common stock
($2.97 diluted) in the first nine months of 2006. The decrease in FirstEnergy’s
third quarter earnings was driven primarily by higher fuel and purchased power
costs and increased depreciation and amortization, partially offset by higher
electric sales revenues.
Change
in Basic Earnings Per Share
From
Prior Year Periods
|
|
Three
Months
Ended
September
30,
|
|
Nine
Months
Ended
September
30,
|
|
|
|
|
|
|
|
|
|
Basic
Earnings
Per Share – 2006
|
|
$
|
1.41
|
|
$
|
2.99
|
|
Revenues
|
|
|
0.55
|
|
|
1.76
|
|
Fuel
and
purchased power
|
|
|
(0.37
|
)
|
|
(0.99
|
)
|
Depreciation
and amortization
|
|
|
(0.11
|
)
|
|
(0.29
|
)
|
Deferral
of
new regulatory assets
|
|
|
(0.09
|
)
|
|
(0.01
|
)
|
Other
expenses
|
|
|
(0.16
|
)
|
|
(0.36
|
)
|
Reduced
common
shares outstanding
|
|
|
0.08
|
|
|
0.18
|
|
Non-core
asset
sales/impairments – 2006
|
|
|
(0.01
|
)
|
|
0.03
|
|
PPUC
NUG
Accounting Adjustment – 2006
|
|
|
0.02
|
|
|
0.02
|
|
Non-core
asset
sales -- 2007
|
|
|
0.04
|
|
|
0.04
|
|
Saxton
decommissioning regulatory asset – 2007
|
|
|
-
|
|
|
0.05
|
|
Trust
securities impairment – 2007
|
|
|
-
|
|
|
(0.03
|
)
|
Basic
Earnings
Per Share – 2007
|
|
$
|
1.36
|
|
$
|
3.39
|
|
Regulatory
Matters
Ohio
On
August 15, 2007,
the PUCO approved a stipulation that creates a green pricing option for
customers of the Ohio Companies. The stipulation was filed on May 29, 2007
by
the Ohio Companies, the PUCO Staff, and the OCC. The Green Resource Program
will
enable customers to support the development of alternative energy resources
through their voluntary participation in this alternative to the Ohio Companies’
standard service offer for generation supply. The Green Resource Program will
be
established through the Ohio Companies’ purchase of Renewable Energy
Certificates (RECs) at prices determined through a competitive bidding process
monitored by the PUCO.
On
August 16, 2007,
the PUCO held a technical conference for interested parties to gain a better
understanding of the Ohio Companies’ competitive generation supply plan proposal
filed with the PUCO on July 10, 2007. The proposal seeks approval to conduct
a
competitive bidding process to provide generation service, beginning January
1,
2009, to customers who choose not to purchase electricity from an alternative
supplier. The proposal is currently pending before the PUCO.
On
August 29, 2007,
the Supreme Court of Ohio upheld findings by the PUCO approving several
provisions of the Ohio Companies’ RCP. The Court, however, remanded the portion
of the order that authorized the Ohio Companies to collect deferred fuel costs
through future distribution rates back to the PUCO for further consideration.
The Court found recovery of competitive generation service costs through
noncompetitive distribution rates unlawful. The PUCO’s order had authorized the
Ohio Companies to defer increased fuel costs incurred from January 1, 2006
through December 31, 2008, including interest on the deferred balances, and
to recover these deferred costs over a 25-year period beginning in 2009. On
September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with
the Court on the issue of the deferred fuel costs. On September 10, 2007,
the Ohio Companies filed an Application on remand with the PUCO proposing that
the increased fuel costs be recovered through two generation-related fuel cost
recovery riders during the period of October 2007 through December 2008, subject
to reconciliation which is expected to continue through the first quarter of
2009. This matter is currently pending before the PUCO. Although unable to
predict the ultimate outcome of this matter, the Ohio Companies intend to
continue deferring the fuel costs pursuant to the RCP, pending the Court’s
disposition of the Motion for Reconsideration and the PUCO’s action with respect
Ohio Companies’ Application.
On
September 25,
2007, the Ohio Governor’s proposed energy plan was officially introduced into
the Ohio Senate. The bill proposes to revise state energy policy to address
electric generation pricing after 2008, establish advanced energy portfolio
standards and energy efficiency standards, and create GHG emission reporting
and
carbon control planning requirements. The bill also proposes to move to a
“hybrid” system for determining rates for PLR service in which electric
utilities would provide regulated generation service unless they satisfy a
statutory burden to demonstrate the existence of a competitive market for retail
electricity. The Senate Energy & Public Utilities Committee which has been
conducting hearings on the bill and receiving testimony from interested parties,
including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer
groups, utility executives and others. On October 4, 2007, FirstEnergy’s
Chief Executive Officer provided testimony to the Committee citing several
concerns with the current version of the bill, including its lack of context
in
which to establish prices. He recommended that the PUCO be provided the clear
statutory authority to negotiate rate plans, and in the event that negotiations
do not result in rate plan agreements, a competitive bidding process be utilized
to establish generation prices for customers that do not choose alternative
suppliers. He also proposed that the PUCO’s statutory authority be expanded to
promote societal programs such as energy efficiency, demand response, renewable
power, and infrastructure improvements. Several proposed amendments to the
bill
have been submitted, including those from Ohio’s investor-owned electric
utilities. A substitute version of the bill, which incorporated certain of
the
proposed amendments, was introduced into the Senate Energy & Public
Utilities Committee on October 25, 2007.
Pennsylvania
On
September 21 and
October 5, 2007, responsive and reply briefs, respectively, were filed by the
parties in the appeal of the PPUC’s January 2007 transition rate plan order to
the Pennsylvania Commonwealth Court. Met-Ed and Penelec have appealed the PPUC’s
decision on the denial of generation rate relief and on a consolidated income
tax adjustment related to the cost of capital, while other parties appealed
the
PPUC’s decision on transmission rate relief. Oral arguments are expected to take
place in late 2007 or early 2008.
On
September 28,
2007, a Joint Petition for Settlement was filed with the PPUC for approval
of
Penn’s Interim Default Service Supply Plan for the three-year period covering
June 1, 2008, through May 31, 2011. For customers who choose not to
shop, the plan provides for Penn to obtain market-based generation supply
through an RFP by rate class for residential and commercial customers, with
industrial customers being supplied through short-term markets. The settlement
agreement resolves all issues in the proceeding, except those regarding
incremental uncollectible accounts expense, and is either supported, or not
opposed, by all parties. A PPUC hearing was held on September 11, 2007 on the
uncollectible expense issue. An ALJ recommended decision is expected shortly
with a PPUC Order expected in late November or early December.
Generation
Perry
On
August 21, 2007,
FENOC announced plans to expand used nuclear fuel storage capacity at the Perry
Nuclear Power Plant. The plan calls for installing above-ground, airtight steel
and concrete cylindrical canisters, cooled by natural air circulation, to store
used fuel assemblies. Initially, six canisters will be installed,
with the capability to add up to 74 additional canisters as needed. Construction
of the new fuel storage system, which is expected to cost approximately $30
million, is scheduled to begin in the spring of 2008, with completion planned
for 2010.
Beaver
Valley
On
October 24, 2007,
Beaver Valley Unit 1 returned to service following completion of its scheduled
refueling outage that began on September 24, 2007. During the outage several
improvement projects were completed, including reinforcing welds on the
pressurizer, spray lines and safety relief valves, increasing the size of the
containment sump strainer, and replacing a reactor coolant pump motor. The
ten-year in-service inspection of the reactor vessel was also completed with
no
significant issues identified. Beaver Valley Unit 1 operated for 378 consecutive
days when it was taken off line for the outage. In late August 2007, FENOC
filed
applications with the NRC seeking renewal of the operating licenses for Beaver
Valley Units 1 and 2 for an additional 20 years, which would extend the
operating licenses to January 29, 2036 for Unit 1 and May 27, 2047 for Unit
2.
Financial
Matters
On
July 13, 2007,
FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW
interest in Unit 1 of the Bruce Mansfield Plant. The terms of the agreement
provide for an approximate 33-year lease of the unit. FirstEnergy used the
net,
after-tax proceeds of approximately $1.2 billion to repay short-term debt that
was used to fund its recent $900 million share repurchase program and $300
million pension contribution. FES’ registration obligations under the
registration rights agreement applicable to the transaction were satisfied
in
September 2007, at which time the transaction was classified as an operating
lease under GAAP for FES and FirstEnergy. The $1.1 billion book gain from
the transaction was deferred and will be amortized ratably over the lease term.
FGCO continues to operate the plant under the terms of the
agreement.
On
August 30, 2007,
Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion
of the net proceeds from the issuance and sale of the senior notes was used
to
fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy.
The remainder was used to repay short-term borrowings and for general corporate
purposes.
On
October 4, 2007,
FGCO and NGC closed on the issuance of $427 million of pollution control revenue
bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the
fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued
on behalf of the Ohio Companies. This transaction brings the total amount of
PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to
approximately $1.9 billion, with approximately $265 million remaining to be
transferred. The transfer of these PCRBs supports the intra-system generation
asset transfer that was completed in 2005.
FIRSTENERGY’S
BUSINESS
FirstEnergy
is a
diversified energy company headquartered in Akron, Ohio, that operates primarily
through three core business segments (see Results of Operations).
·
|
Energy
Delivery Services transmits and distributes electricity through
FirstEnergy's eight utility operating companies, serving 4.5 million
customers within 36,100 square miles of Ohio, Pennsylvania and New
Jersey
and purchases power for its PLR requirements in Pennsylvania and
New
Jersey. This business segment derives its revenues principally from
the
delivery of electricity within FirstEnergy’s service areas, cost recovery
of regulatory assets and the sale of electric generation service
to
non-shopping retail customers under the PLR obligations in its
Pennsylvania and New Jersey franchise areas. Its net income
reflects the commodity costs of securing electricity from the competitive
energy services segment under partial requirements purchased power
agreements with FES and non-affiliated power suppliers, including
associated transmission costs.
|
·
|
Competitive
Energy Services supplies the electric power needs of end-use
customers through retail and wholesale arrangements, including associated
company power sales to meet all or a portion of the PLR requirements
of
FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive
retail sales to customers primarily in Ohio, Pennsylvania, Maryland
and
Michigan. This business segment owns or leases and operates FirstEnergy's
generating facilities and also purchases electricity to meet sales
obligations. The segment's net income is primarily derived from affiliated
company power sales and non-affiliated electric generation sales
revenues
less the related costs of electricity generation, including purchased
power and net transmission and ancillary costs charged by PJM and
MISO to
deliver energy to the segment’s
customers.
|
·
|
Ohio
Transitional Generation Services supplies the electric power
needs of non-shopping customers under the PLR requirements of
FirstEnergy's Ohio Companies. The segment's net income is primarily
derived from electric generation sales revenues less the cost of
power
purchased from the competitive energy services segment through a
full-requirements PSA arrangement with FES, including net transmission
and
ancillary costs charged by MISO to deliver energy to retail
customers.
|
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 14 to the consolidated financial statements. Net income
by major business segment was as follows:
|
|
Three
Months Ended September 30,
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
Increase
|
|
|
|
Increase
|
|
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions, except per share amounts)
|
|
Net
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By
Business Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
delivery services
|
|
$
|
269
|
|
$
|
280
|
|
$
|
(11
|
)
|
$
|
695
|
|
$
|
702
|
|
$
|
(7
|
)
|
Competitive
energy services
|
|
|
148
|
|
|
169
|
|
|
(21
|
)
|
|
388
|
|
|
302
|
|
|
86
|
|
Ohio
transitional generation services
|
|
|
16
|
|
|
27
|
|
|
(11
|
)
|
|
69
|
|
|
88
|
|
|
(19
|
)
|
Other
and
reconciling adjustments*
|
|
|
(20
|
)
|
|
(22
|
)
|
|
2
|
|
|
(111
|
)
|
|
(113
|
)
|
|
2
|
|
Total
|
|
$
|
413
|
|
$
|
454
|
|
$
|
(41
|
)
|
$
|
1,041
|
|
$
|
979
|
|
$
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
1.36
|
|
$
|
1.40
|
|
$
|
(0.04
|
)
|
$
|
3.39
|
|
$
|
3.00
|
|
$
|
0.39
|
|
Discontinued
operations
|
|
|
-
|
|
|
0.01
|
|
|
(0.01
|
)
|
|
-
|
|
|
(0.01
|
)
|
|
0.01
|
|
Net
earnings
per basic share
|
|
$
|
1.36
|
|
$
|
1.41
|
|
$
|
(0.05
|
)
|
$
|
3.39
|
|
$
|
2.99
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
1.34
|
|
$
|
1.39
|
|
$
|
(0.05
|
)
|
$
|
3.35
|
|
$
|
2.98
|
|
$
|
0.37
|
|
Discontinued
operations
|
|
|
-
|
|
|
0.01
|
|
|
(0.01
|
)
|
|
-
|
|
|
(0.01
|
)
|
|
0.01
|
|
Net
earnings
per diluted share
|
|
$
|
1.34
|
|
$
|
1.40
|
|
$
|
(0.06
|
)
|
$
|
3.35
|
|
$
|
2.97
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Represents other operating segments and reconciling adjustments including
interest expense on holding company debt and corporate support services revenues
and expenses.
Summary
of Results of Operations – Third Quarter of 2007 Compared with the Third Quarter
of 2006
Financial
results
for FirstEnergy's major business segments in the third quarter of 2007 and
2006
were as follows:
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
Third
Quarter 2007 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
2,340
|
|
|
$ |
338
|
|
|
$ |
716
|
|
|
$ |
-
|
|
|
$ |
3,394
|
|
Other
|
|
|
180
|
|
|
|
32
|
|
|
|
7
|
|
|
|
28
|
|
|
|
247
|
|
Internal
|
|
|
-
|
|
|
|
806
|
|
|
|
-
|
|
|
|
(806 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
2,520
|
|
|
|
1,176
|
|
|
|
723
|
|
|
|
(778 |
) |
|
|
3,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
1,116
|
|
|
|
554
|
|
|
|
631
|
|
|
|
(806 |
) |
|
|
1,495
|
|
Other
operating expenses
|
|
|
436
|
|
|
|
264
|
|
|
|
80
|
|
|
|
(24 |
) |
|
|
756
|
|
Provision
for
depreciation
|
|
|
102
|
|
|
|
51
|
|
|
|
-
|
|
|
|
9
|
|
|
|
162
|
|
Amortization
of regulatory assets
|
|
|
279
|
|
|
|
-
|
|
|
|
9
|
|
|
|
-
|
|
|
|
288
|
|
Deferral
of
new regulatory assets
|
|
|
(82 |
) |
|
|
-
|
|
|
|
(25 |
) |
|
|
-
|
|
|
|
(107 |
) |
General
taxes
|
|
|
166
|
|
|
|
26
|
|
|
|
1
|
|
|
|
4
|
|
|
|
197
|
|
Total
Expenses
|
|
|
2,017
|
|
|
|
895
|
|
|
|
696
|
|
|
|
(817 |
) |
|
|
2,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
503
|
|
|
|
281
|
|
|
|
27
|
|
|
|
39
|
|
|
|
850
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
58
|
|
|
|
5
|
|
|
|
-
|
|
|
|
(33 |
) |
|
|
30
|
|
Interest
expense
|
|
|
(120 |
) |
|
|
(44 |
) |
|
|
-
|
|
|
|
(39 |
) |
|
|
(203 |
) |
Capitalized
interest
|
|
|
3
|
|
|
|
5
|
|
|
|
-
|
|
|
|
1
|
|
|
|
9
|
|
Total
Other
Expense
|
|
|
(59 |
) |
|
|
(34 |
) |
|
|
-
|
|
|
|
(71 |
) |
|
|
(164 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
Income
Taxes
|
|
|
444
|
|
|
|
247
|
|
|
|
27
|
|
|
|
(32 |
) |
|
|
686
|
|
Income
taxes
|
|
|
175
|
|
|
|
99
|
|
|
|
11
|
|
|
|
(12 |
) |
|
|
273
|
|
Net
Income
|
|
$ |
269
|
|
|
$ |
148
|
|
|
$ |
16
|
|
|
$ |
(20 |
) |
|
$ |
413
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
Third
Quarter 2006 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
2,120
|
|
|
$ |
313
|
|
|
$ |
682
|
|
|
$ |
-
|
|
|
$ |
3,115
|
|
Other
|
|
|
186
|
|
|
|
40
|
|
|
|
8
|
|
|
|
15
|
|
|
|
249
|
|
Internal
|
|
|
-
|
|
|
|
762
|
|
|
|
-
|
|
|
|
(762 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
2,306
|
|
|
|
1,115
|
|
|
|
690
|
|
|
|
(747 |
) |
|
|
3,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
960
|
|
|
|
515
|
|
|
|
604
|
|
|
|
(762 |
) |
|
|
1,317
|
|
Other
operating expenses
|
|
|
468
|
|
|
|
218
|
|
|
|
76
|
|
|
|
(4 |
) |
|
|
758
|
|
Provision
for
depreciation
|
|
|
97
|
|
|
|
49
|
|
|
|
-
|
|
|
|
7
|
|
|
|
153
|
|
Amortization
of regulatory assets
|
|
|
237
|
|
|
|
-
|
|
|
|
6
|
|
|
|
-
|
|
|
|
243
|
|
Deferral
of
new regulatory assets
|
|
|
(107 |
) |
|
|
-
|
|
|
|
(46 |
) |
|
|
-
|
|
|
|
(153 |
) |
General
taxes
|
|
|
157
|
|
|
|
21
|
|
|
|
5
|
|
|
|
4
|
|
|
|
187
|
|
Total
Expenses
|
|
|
1,812
|
|
|
|
803
|
|
|
|
645
|
|
|
|
(755 |
) |
|
|
2,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
494
|
|
|
|
312
|
|
|
|
45
|
|
|
|
8
|
|
|
|
859
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
80
|
|
|
|
18
|
|
|
|
-
|
|
|
|
(52 |
) |
|
|
46
|
|
Interest
expense
|
|
|
(109 |
) |
|
|
(52 |
) |
|
|
-
|
|
|
|
(24 |
) |
|
|
(185 |
) |
Capitalized
interest
|
|
|
4
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(2 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2 |
) |
Total
Other
Expense
|
|
|
(27 |
) |
|
|
(31 |
) |
|
|
-
|
|
|
|
(76 |
) |
|
|
(134 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
Income
Taxes
|
|
|
467
|
|
|
|
281
|
|
|
|
45
|
|
|
|
(68 |
) |
|
|
725
|
|
Income
taxes
|
|
|
187
|
|
|
|
112
|
|
|
|
18
|
|
|
|
(44 |
) |
|
|
273
|
|
Income
from
continuing operations
|
|
|
280
|
|
|
|
169
|
|
|
|
27
|
|
|
|
(24 |
) |
|
|
452
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
2
|
|
Net
Income
|
|
$ |
280
|
|
|
$ |
169
|
|
|
$ |
27
|
|
|
$ |
(22 |
) |
|
$ |
454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between Third Quarter 2007 and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
Quarter 2006 Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
220
|
|
|
$ |
25
|
|
|
$ |
34
|
|
|
$ |
-
|
|
|
$ |
279
|
|
Other
|
|
|
(6 |
) |
|
|
(8 |
) |
|
|
(1 |
) |
|
|
13
|
|
|
|
(2 |
) |
Internal
|
|
|
-
|
|
|
|
44
|
|
|
|
-
|
|
|
|
(44 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
214
|
|
|
|
61
|
|
|
|
33
|
|
|
|
(31 |
) |
|
|
277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
156
|
|
|
|
39
|
|
|
|
27
|
|
|
|
(44 |
) |
|
|
178
|
|
Other
operating expenses
|
|
|
(32 |
) |
|
|
46
|
|
|
|
4
|
|
|
|
(20 |
) |
|
|
(2 |
) |
Provision
for
depreciation
|
|
|
5
|
|
|
|
2
|
|
|
|
-
|
|
|
|
2
|
|
|
|
9
|
|
Amortization
of regulatory assets
|
|
|
42
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
45
|
|
Deferral
of
new regulatory assets
|
|
|
25
|
|
|
|
-
|
|
|
|
21
|
|
|
|
-
|
|
|
|
46
|
|
General
taxes
|
|
|
9
|
|
|
|
5
|
|
|
|
(4 |
) |
|
|
-
|
|
|
|
10
|
|
Total
Expenses
|
|
|
205
|
|
|
|
92
|
|
|
|
51
|
|
|
|
(62 |
) |
|
|
286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
9
|
|
|
|
(31 |
) |
|
|
(18 |
) |
|
|
31
|
|
|
|
(9 |
) |
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(22 |
) |
|
|
(13 |
) |
|
|
-
|
|
|
|
19
|
|
|
|
(16 |
) |
Interest
expense
|
|
|
(11 |
) |
|
|
8
|
|
|
|
-
|
|
|
|
(15 |
) |
|
|
(18 |
) |
Capitalized
interest
|
|
|
(1 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
1
|
|
|
|
2
|
|
Subsidiaries'
preferred stock dividends
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Total
Other
Expense
|
|
|
(32 |
) |
|
|
(3 |
) |
|
|
-
|
|
|
|
5
|
|
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
Income
Taxes
|
|
|
(23 |
) |
|
|
(34 |
) |
|
|
(18 |
) |
|
|
36
|
|
|
|
(39 |
) |
Income
taxes
|
|
|
(12 |
) |
|
|
(13 |
) |
|
|
(7 |
) |
|
|
32
|
|
|
|
-
|
|
Income
from
continuing operations
|
|
|
(11 |
) |
|
|
(21 |
) |
|
|
(11 |
) |
|
|
4
|
|
|
|
(39 |
) |
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2 |
) |
|
|
(2 |
) |
Net
Income
|
|
$ |
(11 |
) |
|
$ |
(21 |
) |
|
$ |
(11 |
) |
|
$ |
2
|
|
|
$ |
(41 |
) |
Energy
Delivery Services – Third
Quarter 2007 Compared to Third Quarter 2006
Net
income decreased
$11 million (or 4%) to $269 million in the third quarter of 2007
compared to $280 million in the third quarter of 2006, primarily due to
increased purchased power costs and higher amortization of regulatory assets,
partially offset by higher revenues and reduced other operating
expenses.
Revenues
–
The
increase in total revenues resulted from the following sources:
|
|
Three
Months Ended
|
|
|
|
|
|
September
30,
|
|
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The
change in distribution KWH deliveries by customer class are summarized in the
following table:
Electric
Distribution KWH Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Distribution KWH Deliveries
|
|
|
|
The
reduction in
distribution services revenues was primarily due to distribution rate decreases
for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision
(see
Outlook – State Regulatory Matters – Pennsylvania).
The
following table
summarizes the price and volume factors contributing to the $201 million
increase in generation revenues in the third quarter of 2007 compared to
2006:
Sources
of Change in Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 5.9% decrease in sales volumes
|
|
$
|
(50
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 95% increase in sales volumes
|
|
|
86
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Generation Sales
|
|
$
|
201
|
|
The
increase in
retail generation prices during the third quarter of 2007 compared to 2006
was
primarily due to increased generation rates for JCP&L resulting from the New
Jersey BGS auction and an increase in NUGC rates authorized by the NJBPU.
Wholesale generation sales increased principally as a result of Met-Ed and
Penelec selling additional available power into the PJM market beginning in
January 2007.
Transmission
revenues increased $42 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of
transmission cost recovery. Met-Ed and Penelec defer the difference between
revenues from their transmission rider and transmission costs incurred, with
no
material effect to current period earnings (see Outlook – State Regulatory
Matters – Pennsylvania).
Expenses
–
The
net increases in revenues discussed above were offset by a $205 million
increase in expenses due to the following:
|
·
|
Purchased
power costs were $157 million
higher in the third quarter of 2007 due to higher unit costs, increased
volumes purchased and a decrease in purchased power cost deferrals.
The
increased unit costs reflected the effect of higher JCP&L purchased
power unit prices resulting from the BGS auction. The increased KWH
purchases in 2007 primarily resulted from more sales to the PJM wholesale
market by Met-Ed and Penelec. Deferred purchased power costs
were lower due to higher generation charges to JCP&L
customers. The following table summarizes the sources of
changes in purchased power costs:
|
Sources
of Change in Purchased Power
|
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
Purchased
Power:
|
|
|
|
|
Change
due to increased unit costs
|
|
$
|
97
|
|
Change
due to increased volume
|
|
|
42
|
|
Decrease
in NUG costs deferred
|
|
|
18
|
|
Net
Increase in Purchased Power Costs
|
|
$
|
157
|
|
|
·
|
Amortization
of regulatory assets increased $42 million
compared to 2006 due primarily to recovery of deferred BGS costs
through
higher NUGC revenues for JCP&L as discussed
above.
|
|
·
|
The
deferral
of new regulatory assets during the third quarter of 2007 was
$25 million lower than in 2006 due in part to $40 million in
reduced deferrals of transmission related PJM costs. The reduced
deferral
in the third quarter of 2007 was attributable to greater recovery
of PJM
costs in the 2007 period under the transmission service charge rider
(see
Outlook – State Regulatory Matters - Pennsylvania). The reduction in
deferred PJM costs was partially offset by higher distribution deferrals
under the RCP.
|
·
Other
operating expenses decreased $32 million,
partially offsetting the above increases, due to the net effects
of:
-
|
A
decrease of
$21 million in transmission expenses caused by the expiration of
transmission hedging instruments and reduced financial transmission
rights
revenue.
|
-
A
decrease in
operation and maintenance expenses of $19 million
primarily due to lower employee labor and benefit costs ($10 million) lower
uncollectible
expenses related to customer receivables ($4 million) and lower leased equipment
costs ($3 million).
-
An
increase in miscellaneous operating expenses ($9 million)
resulting from increased corporate support billings from FESC.
Other
Expense –
Other
expense
increased $32 million in 2007 compared to the third quarter of 2006
primarily due to lower investment income of $22 million resulting from
the repayment of notes receivable from affiliates since the third quarter of
2006, and increased interest expense of $11 million related in part to new
debt issuances by CEI, JCP&L and Penelec.
Competitive
Energy Services – Third
Quarter 2007 Compared to Third Quarter 2006
Net
income for this
segment was $148 million in the third
quarter of 2007 compared to $169 million in the same period
last year. Increased fuel and purchased power costs and other operating
expenses, partially offset by higher revenues, led to the $21 million
decrease.
Revenues
–
Total
revenues
increased $61 million in the third quarter of 2007 compared to the same
period in 2006. This increase primarily resulted from increased affiliated
sales
to the Ohio Companies, Met-Ed and Penelec as well as higher unit prices from
the
Ohio Companies. These increases were partially offset by lower sales to Penn
as
a result of the implementation of its competitive solicitation process in 2007.
Higher retail revenues resulted from increased KWH sales in the MISO market,
partially offset by reduced volume in the PJM market.
Increased
non-affiliated wholesale revenues primarily reflected capacity revenues earned
in PJM’s new capacity market. The capacity market was initiated in June 2007 to
encourage the development of capacity resources in PJM. Lower wholesale sales
to
non-affiliates partially offset these increases due to decreased generation
available for the non-affiliated wholesale market.
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The
following tables
summarize the price and volume factors contributing to changes in revenues
from
generation sales:
|
|
Increase
|
|
Source
of Change in Non-Affiliated Generation
Sales
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 0.2% increase in sales
volumes
|
|
$
|
1
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 11% decrease in sales
volumes
|
|
|
(15
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Source
of Change in Affiliated Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect
of 2% increase in sales
volumes
|
|
$
|
12
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect
of 8% increase in sales
volumes
|
|
|
13
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Affiliated Generation Sales
|
|
|
|
|
Expenses
-
Total
expenses were
$92 million higher in the third quarter of 2007 due to the net effect of
the following factors:
|
·
|
Purchased
power costs increased $55 million due primarily to higher volumes for
replacement power related to a forced outage at Perry in the third
quarter
of 2007 and higher market prices. The sources of change in purchased
power
costs are summarized in the following
table:
|
Source
of Change in Purchased Power
|
|
Increase
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
Change
due to increased unit
costs
|
|
$
|
14
|
|
Change
due to 18% increase in
volume
|
|
|
31
|
|
Change
due to new PJM capacity market
|
|
|
10
|
|
Total
Increase in Purchased Power Costs
|
|
$
|
55
|
|
|
·
|
Fuel
costs
were $16 million lower primarily due to lower coal prices ($8
million), reduced emission allowance costs ($5 million) and a decrease
in
natural gas consumed resulting from reduced combustion turbine generation
($2 million).
|
|
·
|
Fossil
operating costs were $32 million higher in 2007 primarily due to the
absence of gains on the sales of emissions allowances recognized
in
2006.
|
|
·
|
Miscellaneous
operating expenses were $13 million higher primarily due to increased
contractor expenses related to the Beaver Valley Unit 1 outage and
corporate support billings from
FESC.
|
|
·
|
Higher
general
taxes of $5 million resulted from increased gross receipts taxes and
property taxes.
|
Ohio
Transitional Generation Services –
Third Quarter 2007 Compared to Third Quarter 2006
Net
income decreased
$11 million to $16 million
in the third quarter of 2007 compared to $27 million
in the same period last year. Higher purchased power costs were partially offset
by higher generation revenues.
Revenues
–
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
September
30,
|
|
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
Increase
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following table
summarizes the price and volume factors contributing to the increase in
generation sales revenues from retail customers:
Source
of Change in Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Effect
of 2% increase in sales
volumes
|
|
$
|
10
|
|
Change
in prices
|
|
|
|
|
Total
Increase in Retail Generation Sales
|
|
|
|
|
|
|
|
|
|
The
increase in
generation sales was primarily due to higher weather-related usage in the third
quarter of 2007 resulting from slightly higher than normal cooling degree days
during the period. Average prices increased slightly due to customer usage
patterns and higher composite unit prices for returning customers.
Expenses
-
Purchased
power
costs were $27 million higher due primarily to higher unit costs for power
purchased from FES. The factors contributing to the higher costs are summarized
in the following table:
Source
of Change in Purchased Power
|
|
Increase
|
|
|
|
(In
millions)
|
|
Purchases
from
non-affiliates:
|
|
|
|
|
Change
due to increased unit
costs
|
|
$
|
-
|
|
Change
due to volume
|
|
|
1
|
|
|
|
|
1
|
|
Purchases
from
FES:
|
|
|
|
|
Change
due to increased unit
costs
|
|
|
14
|
|
Change
due to volume
|
|
|
12
|
|
|
|
|
26
|
|
Total
Increase
in Purchased Power Costs
|
|
$
|
27
|
|
The
increase in
volumes purchased was due to the higher retail generation sales
requirements. The higher unit costs resulted from the provision of
the full-requirements PSA with FES under which purchased power unit costs
reflected the increases in the Ohio Companies’ retail generation sales unit
prices.
The
deferral of new
regulatory assets decreased by $21 million in the third quarter of 2007
compared to 2006 due to reduced cost deferrals under the Ohio Companies’
RCP.
Other
–
Third
Quarter 2007 Compared to
Third Quarter 2006
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 $2 million
increase in FirstEnergy’s net income in the third quarter of 2007 compared to
the same quarter of 2006. The increase was primarily due to the sale of First
Communications ($13 million, net of taxes) offset by higher financing costs
of
$14 million.
Summary
of Results of Operations – First Nine Months of 2007 Compared with the First
Nine Months of 2006
Financial
results
for FirstEnergy's major business segments in the first nine months of 2007
and
2006 were as follows:
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
First
Nine Months 2007 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
6,148
|
|
|
$ |
973
|
|
|
$ |
1,942
|
|
|
$ |
-
|
|
|
$ |
9,063
|
|
Other
|
|
|
507
|
|
|
|
116
|
|
|
|
26
|
|
|
|
11
|
|
|
|
660
|
|
Internal
|
|
|
-
|
|
|
|
2,210
|
|
|
|
-
|
|
|
|
(2,210 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
6,655
|
|
|
|
3,299
|
|
|
|
1,968
|
|
|
|
(2,199 |
) |
|
|
9,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
2,838
|
|
|
|
1,461
|
|
|
|
1,712
|
|
|
|
(2,210 |
) |
|
|
3,801
|
|
Other
operating expenses
|
|
|
1,255
|
|
|
|
839
|
|
|
|
218
|
|
|
|
(57 |
) |
|
|
2,255
|
|
Provision
for
depreciation
|
|
|
301
|
|
|
|
153
|
|
|
|
-
|
|
|
|
23
|
|
|
|
477
|
|
Amortization
of regulatory assets
|
|
|
765
|
|
|
|
-
|
|
|
|
20
|
|
|
|
-
|
|
|
|
785
|
|
Deferral
of
new regulatory assets
|
|
|
(299 |
) |
|
|
-
|
|
|
|
(100 |
) |
|
|
-
|
|
|
|
(399 |
) |
General
taxes
|
|
|
486
|
|
|
|
81
|
|
|
|
3
|
|
|
|
19
|
|
|
|
589
|
|
Total
Expenses
|
|
|
5,346
|
|
|
|
2,534
|
|
|
|
1,853
|
|
|
|
(2,225 |
) |
|
|
7,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
1,309
|
|
|
|
765
|
|
|
|
115
|
|
|
|
26
|
|
|
|
2,215
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
190
|
|
|
|
13
|
|
|
|
1
|
|
|
|
(111 |
) |
|
|
93
|
|
Interest
expense
|
|
|
(347 |
) |
|
|
(144 |
) |
|
|
(1 |
) |
|
|
(101 |
) |
|
|
(593 |
) |
Capitalized
interest
|
|
|
7
|
|
|
|
13
|
|
|
|
-
|
|
|
|
1
|
|
|
|
21
|
|
Total
Other
Expense
|
|
|
(150 |
) |
|
|
(118 |
) |
|
|
-
|
|
|
|
(211 |
) |
|
|
(479 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
Income
Taxes
|
|
|
1,159
|
|
|
|
647
|
|
|
|
115
|
|
|
|
(185 |
) |
|
|
1,736
|
|
Income
taxes
|
|
|
464
|
|
|
|
259
|
|
|
|
46
|
|
|
|
(74 |
) |
|
|
695
|
|
Net
Income
|
|
$ |
695
|
|
|
$ |
388
|
|
|
$ |
69
|
|
|
$ |
(111 |
) |
|
$ |
1,041
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
First
Nine Months 2006 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
5,434
|
|
|
$ |
955
|
|
|
$ |
1,790
|
|
|
$ |
-
|
|
|
$ |
8,179
|
|
Other
|
|
|
442
|
|
|
|
122
|
|
|
|
18
|
|
|
|
60
|
|
|
|
642
|
|
Internal
|
|
|
14
|
|
|
|
1,997
|
|
|
|
-
|
|
|
|
(2,011 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
5,890
|
|
|
|
3,074
|
|
|
|
1,808
|
|
|
|
(1,951 |
) |
|
|
8,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
2,343
|
|
|
|
1,416
|
|
|
|
1,558
|
|
|
|
(2,011 |
) |
|
|
3,306
|
|
Other
operating expenses
|
|
|
1,197
|
|
|
|
838
|
|
|
|
185
|
|
|
|
10
|
|
|
|
2,230
|
|
Provision
for
depreciation
|
|
|
282
|
|
|
|
143
|
|
|
|
-
|
|
|
|
20
|
|
|
|
445
|
|
Amortization
of regulatory assets
|
|
|
650
|
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
|
665
|
|
Deferral
of
new regulatory assets
|
|
|
(275 |
) |
|
|
-
|
|
|
|
(104 |
) |
|
|
-
|
|
|
|
(379 |
) |
General
taxes
|
|
|
459
|
|
|
|
70
|
|
|
|
7
|
|
|
|
17
|
|
|
|
553
|
|
Total
Expenses
|
|
|
4,656
|
|
|
|
2,467
|
|
|
|
1,661
|
|
|
|
(1,964 |
) |
|
|
6,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
1,234
|
|
|
|
607
|
|
|
|
147
|
|
|
|
13
|
|
|
|
2,001
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
244
|
|
|
|
35
|
|
|
|
-
|
|
|
|
(159 |
) |
|
|
120
|
|
Interest
expense
|
|
|
(310 |
) |
|
|
(148 |
) |
|
|
(1 |
) |
|
|
(69 |
) |
|
|
(528 |
) |
Capitalized
interest
|
|
|
11
|
|
|
|
9
|
|
|
|
-
|
|
|
|
1
|
|
|
|
21
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(9 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
(6 |
) |
Total
Other
Expense
|
|
|
(64 |
) |
|
|
(104 |
) |
|
|
(1 |
) |
|
|
(224 |
) |
|
|
(393 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
Income
Taxes
|
|
|
1,170
|
|
|
|
503
|
|
|
|
146
|
|
|
|
(211 |
) |
|
|
1,608
|
|
Income
taxes
|
|
|
468
|
|
|
|
201
|
|
|
|
58
|
|
|
|
(102 |
) |
|
|
625
|
|
Income
from
continuing operations
|
|
|
702
|
|
|
|
302
|
|
|
|
88
|
|
|
|
(109 |
) |
|
|
983
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4 |
) |
|
|
(4 |
) |
Net
Income
|
|
$ |
702
|
|
|
$ |
302
|
|
|
$ |
88
|
|
|
$ |
(113 |
) |
|
$ |
979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between First Nine Months 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
First Nine Months 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Results Increase (Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
714
|
|
|
$ |
18
|
|
|
$ |
152
|
|
|
$ |
-
|
|
|
$ |
884
|
|
Other
|
|
|
65
|
|
|
|
(6 |
) |
|
|
8
|
|
|
|
(49 |
) |
|
|
18
|
|
Internal
|
|
|
(14 |
) |
|
|
213
|
|
|
|
-
|
|
|
|
(199 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
765
|
|
|
|
225
|
|
|
|
160
|
|
|
|
(248 |
) |
|
|
902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
495
|
|
|
|
45
|
|
|
|
154
|
|
|
|
(199 |
) |
|
|
495
|
|
Other
operating expenses
|
|
|
58
|
|
|
|
1
|
|
|
|
33
|
|
|
|
(67 |
) |
|
|
25
|
|
Provision
for
depreciation
|
|
|
19
|
|
|
|
10
|
|
|
|
-
|
|
|
|
3
|
|
|
|
32
|
|
Amortization
of regulatory assets
|
|
|
115
|
|
|
|
-
|
|
|
|
5
|
|
|
|
-
|
|
|
|
120
|
|
Deferral
of
new regulatory assets
|
|
|
(24 |
) |
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
(20 |
) |
General
taxes
|
|
|
27
|
|
|
|
11
|
|
|
|
(4 |
) |
|
|
2
|
|
|
|
36
|
|
Total
Expenses
|
|
|
690
|
|
|
|
67
|
|
|
|
192
|
|
|
|
(261 |
) |
|
|
688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
75
|
|
|
|
158
|
|
|
|
(32 |
) |
|
|
13
|
|
|
|
214
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(54 |
) |
|
|
(22 |
) |
|
|
1
|
|
|
|
48
|
|
|
|
(27 |
) |
Interest
expense
|
|
|
(37 |
) |
|
|
4
|
|
|
|
-
|
|
|
|
(32 |
) |
|
|
(65 |
) |
Capitalized
interest
|
|
|
(4 |
) |
|
|
4
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Subsidiaries'
preferred stock dividends
|
|
|
9
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3 |
) |
|
|
6
|
|
Total
Other
Expense
|
|
|
(86 |
) |
|
|
(14 |
) |
|
|
1
|
|
|
|
13
|
|
|
|
(86 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
Income
Taxes
|
|
|
(11 |
) |
|
|
144
|
|
|
|
(31 |
) |
|
|
26
|
|
|
|
128
|
|
Income
taxes
|
|
|
(4 |
) |
|
|
58
|
|
|
|
(12 |
) |
|
|
28
|
|
|
|
70
|
|
Income
from
continuing operations
|
|
|
(7 |
) |
|
|
86
|
|
|
|
(19 |
) |
|
|
(2 |
) |
|
|
58
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4
|
|
|
|
4
|
|
Net
Income
|
|
$ |
(7 |
) |
|
$ |
86
|
|
|
$ |
(19 |
) |
|
$ |
2
|
|
|
$ |
62
|
|
Energy
Delivery Services – First Nine
Months of 2007 Compared to First Nine Months of 2006
Net
income decreased
$7 million (or 1%) to $695 million in the first nine months of 2007
compared to $702 million in the first nine months of 2006, primarily due to
increased revenues partially offset by higher operating expenses and other
expenses.
Revenues
–
The
increase in total revenues resulted from the following sources:
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
Increase
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
change in distribution deliveries by customer class is summarized in the
following table:
Electric
Distribution KWH Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Distribution KWH Deliveries
|
|
|
|
|
The
increase in
electric distribution deliveries to customers was primarily due to higher
weather-related usage during the first nine months of 2007 compared to the
same
period of 2006 (heating degree days increased by 13.7% and cooling degree days
increased by 9.5%). The higher revenues from increased distribution deliveries
were partially offset by distribution rate decreases for Met-Ed and Penelec
as a
result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory
Matters – Pennsylvania).
The
following table
summarizes the price and volume factors contributing to the $572 million
increase in non-affiliated generation sales revenues in 2007 compared to
2006:
Sources
of Change in Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 2% decrease in sales volumes
|
|
$
|
(38
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 118% increase in sales volumes
|
|
|
232
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Generation Sales
|
|
$
|
572
|
|
The
decrease in
retail generation sales volumes was primarily due to an increase in customer
shopping in Penn’s service territory in the first nine months of 2007. The
increase in retail generation prices during the first nine months of 2007
compared to 2006 was primarily due to increased generation rates for JCP&L
resulting from the New Jersey BGS auction process and an increase in NUGC rates
authorized by the NJBPU. Wholesale generation sales increased principally as
a
result of Met-Ed and Penelec selling additional available power into the PJM
market beginning in January 2007.
Transmission
revenues increased $169 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of
transmission cost recovery. Met-Ed and Penelec defer the difference between
revenues from their transmission rider and transmission costs incurred, with
no
material effect on current period earnings (see Outlook – State Regulatory
Matters – Pennsylvania).
Expenses
–
The
increases in revenues discussed above were partially offset by a
$690 million increase in expenses due to the following:
|
·
|
Purchased
power costs were $495 million
higher in the first nine months of 2007 due to higher unit costs
and
volumes purchased. The increased unit costs reflected the effect
of higher
JCP&L costs resulting from the BGS auction process. The increased
purchases in 2007 were due primarily to higher sales to the wholesale
market. The following table summarizes the sources of changes
in purchased power costs:
|
Sources
of Change in Purchased Power
|
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
Purchased
Power:
|
|
|
|
|
Change
due to increased unit costs
|
|
$
|
261
|
|
Change
due to increased volume
|
|
|
174
|
|
Decrease
in NUG costs deferred
|
|
|
60
|
|
Net
Increase in Purchased Power Costs
|
|
$
|
495
|
|
|
·
|
Other
operating expenses increased $58 million due
to the
net effects of:
|
-
|
An
increase of $80 million in
MISO and
PJM transmission expenses, resulting primarily from higher congestion
costs.
|
-
|
A decrease in miscellaneous operating expenses of $10 million primarily
due
to changes in the assessment of regulatory fees and employee benefits
from
FESC.
|
-
|
A
decrease in operation and maintenance expenses of $9 million primarily
due
to increased labor activities devoted to construction projects in
2007.
|
|
·
|
Amortization
of regulatory assets increased $115 million compared
to
2006 due primarily to recovery of deferred BGS costs through higher
NUGC
rates for JCP&L as discussed
above.
|
|
·
|
The
deferral
of new regulatory assets during the first nine months of 2007 was
$24 million higher in 2007 primarily due to the deferral of
previously expensed decommissioning costs of $27 million related
to
the Saxton nuclear research facility (see Outlook – State Regulatory
Matters - Pennsylvania), increased RCP distribution deferrals of
$23 million, offset by a reduction in deferred PJM transmission costs
of $30 million.
|
·
|
Depreciation
expense increased $19 million and property taxes increased
$27 million due primarily to property additions since the third
quarter of 2006.
|
Other
Expense –
Other
expense
increased $86 million
in 2007 compared to the first nine months of 2006 primarily due to
lower investment income of $54 million resulting from
the
repayment of notes receivable from affiliates since the third quarter of 2006
and increased interest expense of $37 million related to new
debt
issuances by CEI, JCP&L and Penelec.
Competitive
Energy Services – First
Nine Months of 2007 Compared to First Nine Months of
2006
Net
income for this
segment was $388 million
in the first nine months of 2007 compared to $302 million
in the same period last year. This increase reflects an improvement in gross
generation margin and lower nuclear production costs, which were partially
offset by increased depreciation and general taxes and reduced investment
income.
Revenues
–
Total
revenues
increased $225 million
in the first nine months of 2007 compared to the same period in 2006. This
increase primarily resulted from higher unit prices under affiliated generation
sales to the Ohio Companies and increased retail sales, which were partially
offset by lower non-affiliated wholesale sales.
The
higher retail
revenues resulted from increased sales in both the MISO and PJM markets. The
increase in MISO retail sales primarily reflect FES’ increased sales to shopping
customers in Penn’s service territory. Lower non-affiliated wholesale revenues
reflected the effect of decreased generation available for the non-affiliated
wholesale market due to increased affiliated company power sales under the
Ohio
Companies’ full-requirements PSA and the partial-requirements power sales
agreement with Met-Ed and Penelec.
The
increased
affiliated company generation revenues were due to higher unit prices and
increased sales volumes. The increase in PSA sales to the Ohio Companies was
due
to their higher retail generation sales requirements. The higher unit prices
resulted from the provision of the full-requirements PSA under which PSA rates
reflect the increases in the Ohio Companies’ retail generation rates. The higher
sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec
generation sales requirements. These increases were partially offset by lower
sales to Penn due to the implementation of its competitive solicitation process
in 2007.
The
increase in reported segment revenues resulted from the following
sources:
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
revenues decreased $25 million due to reduced retail load in the MISO
market, lower transmission rates and reduced financial transmission rights
auction revenue.
The
following tables
summarize the price and volume factors contributing to changes in revenues
from
generation sales:
|
|
Increase
|
|
Source
of Change in Non-Affiliated Generation
Sales
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 12% increase in sales
volumes
|
|
$
|
52
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 26% decrease in sales
volumes
|
|
|
(131
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
)
|
Net
Increase
in Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
Source
of Change in Affiliated Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect
of 4% increase in sales
volumes
|
|
$
|
56
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect
of 12% increase in sales
volumes
|
|
|
54
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Affiliated Generation Sales
|
|
|
|
|
Expenses
-
Total
expenses
increased $67 million in the first nine months of 2007 due to the following
factors:
|
·
|
Purchased
power costs increased $86 million due principally to higher volumes
for replacement power related to the forced outages at Bruce Mansfield
and
Perry.
|
|
·
|
Higher
fossil
operating costs of $43 million due to the absence of gains from the
sale of emissions allowances recognized in 2006 ($24 million) and
increased scheduled maintenance outages ($13
million).
|
|
·
|
Higher
depreciation expenses of $10 million were due to property
additions.
|
|
·
|
Higher
general
taxes of $11 million resulted from increased gross receipts taxes and
property taxes.
|
Partially
offsetting
the higher costs were:
|
·
|
Fuel
costs
were $41 million lower primarily due to reduced coal costs and
emission allowance costs offset by increases in nuclear fuel and
natural
gas costs. Coal costs were reduced due to a $14 million inventory
adjustment and $23 million of reduced coal consumption reflecting
lower generation. Reduced emission allowance costs ($18 million) were
partially offset by increased natural gas costs ($4 million) due to
increased consumption and nuclear fuel costs ($8 million) due to
increased consumption and higher
prices.
|
·
Nuclear
operating costs were $54 million lower due to fewer outages in 2007
compared to 2006 and reduced employee benefit costs.
Other
Expense –
Total
other
expense in the first nine months of 2007 was $14 million higher
than the 2006 period primarily due to decreased earnings on nuclear
decommissioning trust investments (including a $16 million impairment in
2007).
Ohio
Transitional Generation Services –
First Nine Months of 2007 Compared to First Nine Months of
2006
Net
income for this segment decreased to $69 million in the first
nine
months of 2007 from $88 million in the same period last year. Higher
operating expenses, primarily for purchased power, were partially offset by
higher generation revenues.
Revenues
–
The
increase in reported segment revenues resulted from the following
sources:
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The
following table
summarizes the price and volume factors contributing to the increase in sales
revenues from retail customers:
Source
of Change in Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 4% increase in sales
volumes
|
|
$
|
66
|
|
Change
in prices
|
|
|
|
|
Total
Increase in Retail Generation Sales
|
|
|
|
|
The
increase in
generation sales was primarily due to higher weather-related usage in the first
nine months of 2007 compared to the same period of 2006, as discussed above,
and
reduced customer shopping. Average prices increased primarily due to higher
composite unit prices for returning customers. The percentage of generation
services provided by alternative suppliers to total sales delivered by the
Ohio
Companies in their service areas decreased by 6.4 percentage
points from the same period last year.
Expenses
-
Purchased
power
costs were $153 million
higher due primarily to higher unit costs for power purchased from FES. The
factors contributing to the higher costs are summarized in the following
table:
Source
of Change in Purchased Power
|
|
Increase
|
|
|
|
(In
millions)
|
|
Purchases
from
non-affiliates:
|
|
|
|
|
Change
due to increased unit
costs
|
|
$
|
6
|
|
Change
due to volume
purchased
|
|
|
2
|
|
|
|
|
8
|
|
Purchases
from
FES:
|
|
|
|
|
Change
due to increased unit
costs
|
|
|
89
|
|
Change
due to volume
purchased
|
|
|
56
|
|
|
|
|
145
|
|
Total
Increase
in Purchased Power Costs
|
|
$
|
153
|
|
The
increase in
purchases was due to the higher retail generation sales
requirements. The higher unit costs reflect the increases in the Ohio
Companies’ retail generation rates, as provided for under the PSA with
FES.
Other
operating
expenses increased $33 million primarily due to MISO transmission-related
expenses. The difference between transmission revenues accrued and transmission
expenses incurred is deferred, resulting in no material impact to current period
earnings.
Other
–
First
Nine Months of 2007
Compared to First Nine Months of 2006
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 $2 million
increase in FirstEnergy’s net income in the first nine months of 2007. The
increase was primarily due to the sale of First Communications ($13 million,
net
of taxes), the absence of subsidiaries’ preferred stock dividends in 2007
($6 million) and the absence of a $4 million
loss included in 2006 results from discontinued operations (see
Note 4).
CAPITAL
RESOURCES AND LIQUIDITY
FirstEnergy’s
business is capital intensive, requiring significant resources to fund operating
expenses, construction expenditures, scheduled debt maturities and interest
and
dividend payments. During 2007 and in subsequent years, FirstEnergy expects
to
satisfy these requirements with a combination of cash from operations and funds
from the capital markets. FirstEnergy also expects that borrowing capacity
under
credit facilities will continue to be available to manage working capital
requirements during those periods.
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 and certain of
its
subsidiaries also have access to $2.75 billion of short-term financing
under a revolving credit facility which expires in 2011. Under the
terms of the facility, FirstEnergy is permitted to have up to $1.5 billion
in outstanding borrowings at any time, subject to the facility cap of $2.75
billion of aggregate outstanding borrowings by it and its subsidiaries that
are
also parties to such facility. In the first nine months of 2007, FirstEnergy
received $1.8 billion of cash dividends and return of capital from its
subsidiaries and paid $464 million in cash dividends to common
shareholders. With the exception of Met-Ed, which is currently in an accumulated
deficit position, there are no material restrictions on the payment of cash
dividends by the subsidiaries of FirstEnergy.
On
March 2, 2007,
FirstEnergy repurchased approximately 14.4 million shares, or approximately
4.5%, of its outstanding common stock at an initial price of approximately
$900
million pursuant to an accelerated share repurchase
program. FirstEnergy acquired these shares under its previously
announced authorization to repurchase up to 16 million shares of its common
stock. The share repurchase was funded with short-term borrowings, which have
since been repaid with the proceeds from the Bruce Mansfield Unit 1 sale and
leaseback transaction.
On
July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1, representing 779 MW of net demonstrated
capacity. The purchase price of approximately $1.329 billion (net after-tax
proceeds of approximately $1.2 billion) for the undivided interest was funded
through a combination of equity investments by affiliates of AIG Financial
Products Corp. and Union Bank of California, N.A. in six lessor trusts and
proceeds from the sale of $1.135 billion aggregate principal amount of 6.85%
pass through certificates due 2034. A like principal amount of
secured notes maturing June 1, 2034 were issued by the lessor trusts to the
pass
through trust that issued and sold the certificates. The lessor
trusts leased the undivided interest back to FGCO for a term of approximately
33
years under substantially identical leases. FES has unconditionally and
irrevocably guaranteed all of FGCO’s obligations under each of the
leases. The notes and certificates are not guaranteed by FES or FGCO,
but the notes are secured by, among other things, each lessor’s undivided
interest in Unit 1, rights and interests under the applicable lease and rights
and interests under other related agreements. FES’ registration obligations
under the registration rights agreement applicable to the $1.135 billion
principal amount of pass through certificates issued in connection with the
transaction were satisfied in September 2007, at which time the transaction
was
classified as an operating lease under GAAP for FES and FirstEnergy. This
transaction generated tax capital gains of approximately $752 million.
Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances
in the third quarter of 2007, with a corresponding reduction to goodwill (see
Note 3).
As
of
September 30, 2007, FirstEnergy had $30 million of cash and cash
equivalents compared with $90 million as of December 31, 2006. The
major sources of changes in these balances are summarized below.
Cash
Flows From Operating Activities
FirstEnergy's
consolidated net cash from operating activities is provided primarily by its
energy delivery services and competitive energy services businesses (see Results
of Operations above). Net cash provided from operating activities was $1.2
billion in the first nine months of 2007 and 2006 summarized as
follows:
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
1,041
|
|
$
|
979
|
|
Non-cash
charges
|
|
|
358
|
|
|
497
|
|
Pension
trust
contribution
|
|
|
(300
|
)
|
|
-
|
|
Working
capital and other
|
|
|
52
|
|
|
(233
|
)
|
|
|
$
|
1,151
|
|
$
|
1,243
|
|
Net
cash provided
from operating activities decreased by $92 million in the first nine months
of
2007 compared to the first nine months of 2006 primarily due to a $300 million
pension trust contribution in 2007 and a $139 million change in non-cash
charges, partially offset by a $285 million change in working capital and
other and a $62 million increase in net income (see Results of Operations
above). The decrease in non-cash charges and increase from working capital
primarily reflects changes to deferred income taxes and accrued taxes related
to
the Bruce Mansfield Unit 1 sale and leaseback transaction discussed above.
Excluding the tax effects of the sale and leaseback transaction, the changes
in
working capital and other primarily resulted from a $322 million increase
in receivables due to higher sales, partially offset by $92 million from
reduced materials and supplies inventories due primarily to lower coal inventory
levels and $78 million of decreased payments for accounts payable,
reflecting a change in the timing of payments from the first nine months of
2006.
Cash
Flows From Financing Activities
In
the first nine
months of 2007, cash used for financing activities was $1.4 billion compared
to
$444 million in the first nine months of 2006. The increase was primarily due
to
more common shares repurchased in 2007 than in 2006 and the repayment of
short-term borrowings in 2007. The following table summarizes security issuances
and redemptions.
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
Securities
Issued or Redeemed
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
New
issues
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
-
|
|
$
|
253
|
|
Secured
notes
|
|
|
-
|
|
|
382
|
|
Unsecured
notes
|
|
|
1,100
|
|
|
600
|
|
|
|
$
|
1,100
|
|
$
|
1,235
|
|
Redemptions
|
|
|
|
|
|
|
|
First
mortgage
bonds
|
|
$
|
287
|
|
$
|
1
|
|
Pollution
control notes
|
|
|
4
|
|
|
311
|
|
Senior
secured
notes
|
|
|
203
|
|
|
181
|
|
Unsecured
notes
|
|
|
153
|
|
|
500
|
|
Common
stock
|
|
|
918
|
|
|
600
|
|
Preferred
stock
|
|
|
-
|
|
|
107
|
|
|
|
$
|
1,565
|
|
$
|
1,700
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
(535
|
)
|
$
|
482
|
|
FirstEnergy
had
approximately $573 million of short-term indebtedness as of
September 30, 2007 compared to approximately $1.1 billion as of
December 31, 2006. Available bank borrowing capability as of
September 30, 2007 included the following:
Borrowing
Capability (In millions)
|
|
|
|
Short-term
credit facilities(1)
|
|
$
|
2,870
|
|
Accounts
receivable financing facilities
|
|
|
550
|
|
Utilized
|
|
|
(570
|
)
|
LOCs
|
|
|
(337
|
)
|
Net
available
capability
|
|
$
|
2,513
|
|
|
|
|
|
|
(1)
Includes
the $2.75 billion revolving credit facility described below, a
$100 million revolving credit facility that expires in December 2009
and a $20 million uncommitted line of
credit.
|
As
of September 30,
2007, the Ohio Companies and Penn had the aggregate capability to issue
approximately $3.1 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, CEI and TE is 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, CEI and TE to incur additional secured debt not
otherwise permitted by a specified exception of up to $543 million,
$459 million and $112 million, respectively, as of September 30,
2007. JCP&L satisfied the provision of its senior note indenture for the
release of all FMBs held as collateral for senior notes in May 2007,
subsequently repaid its other remaining FMBs and, effective September 14,
2007, discharged and released its mortgage indenture.
The
applicable
earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L
are currently inoperative. In the event that any of them issues preferred stock
in the future, the applicable earnings coverage test will govern the amount
of
preferred stock that may be issued. 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
of September 30,
2007, approximately $1.0 billion of capacity remained unused under an existing
FirstEnergy shelf registration statement filed with the SEC in 2003 to support
future securities issuances. The shelf registration provides the flexibility
to
issue and sell various types of securities, including common stock, debt
securities, and share purchase contracts and related share purchase units.
As of
September 30, 2007, OE had approximately $400 million of capacity remaining
unused under a shelf registration for unsecured debt securities filed with
the
SEC in 2006.
FirstEnergy
and
certain of its subsidiaries are parties to a $2.75 billion five-year
revolving credit facility (included in the borrowing capability table above).
FirstEnergy may request an increase in the total commitments available under
this facility up to a maximum of $3.25 billion. Commitments under the
facility are available until August 24, 2011, unless the lenders agree, at
the request of the Borrowers, to two additional one-year extensions. Generally,
borrowings under the facility must be repaid within 364 days. Available amounts
for each Borrower are subject to a specified sub-limit, as well as applicable
regulatory and other limitations.
The
following table
summarizes the borrowing sub-limits for each borrower under the facility, as
well as the limitations on short-term indebtedness applicable to each borrower
under current regulatory approvals and applicable statutory and/or charter
limitations:
|
|
Revolving
|
|
Regulatory
and
|
|
|
|
Credit
Facility
|
|
Other
Short-Term
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
$
|
2,750
|
|
$
|
-
|
(2)
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
41
|
|
CEI
|
|
|
250
|
(3)
|
|
500
|
|
TE
|
|
|
250
|
(3)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
423
|
|
Met-Ed
|
|
|
250
|
|
|
250
|
(4)
|
Penelec
|
|
|
250
|
|
|
250
|
(4)
|
FES
|
|
|
250
|
|
|
-
|
(2)
|
ATSI
|
|
|
-
|
(5)
|
|
50
|
|
|
(1)
|
As
of
September 30, 2007.
|
|
(2)
|
No
regulatory
approvals, statutory or charter limitations
applicable.
|
|
(3)
|
Borrowing
sub-limits for CEI and TE may be increased to up to $500 million by
delivering notice to the administrative agent that such borrower
has
senior unsecured debt ratings of at least BBB by S&P and Baa2 by
Moody’s.
|
|
(4)
|
Excluding
amounts which may be borrowed under the regulated money
pool.
|
|
(5)
|
The
borrowing
sub-limit for ATSI may be increased up to $100 million by delivering
notice to the administrative agent that either (i) such borrower
has
senior unsecured debt ratings of at least BBB- by S&P and Baa3 by
Moody’s or (ii) FirstEnergy has guaranteed the obligations of such
borrower under the facility.
|
The
revolving credit
facility, combined with an aggregate $550 million ($255 million unused as of
September 30, 2007) of accounts receivable financing facilities for OE,
CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet
working capital requirements and for other general corporate purposes 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.
The
revolving credit
facility contains financial covenants requiring each borrower to maintain a
consolidated debt to total capitalization ratio of no more than 65%, measured
at
the end of each fiscal quarter. As of September 30, 2007, FirstEnergy and
its subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy
|
|
57
|
%
|
OE
|
|
47
|
%
|
Penn
|
|
21
|
%
|
CEI
|
|
60
|
%
|
TE
|
|
55
|
%
|
JCP&L
|
|
31
|
%
|
Met-Ed
|
|
46
|
%
|
Penelec
|
|
50
|
%
|
FES
|
|
48
|
%
|
The
revolving credit
facility does not contain provisions that either restrict the ability to borrow
or accelerate repayment of outstanding advances as a result of any change in
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to the credit ratings of the company
borrowing the funds.
FirstEnergy's
regulated companies also have the ability to borrow from each other and the
holding company to meet their short-term working capital requirements. A similar
but separate arrangement exists among FirstEnergy's unregulated companies.
FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money
pool
agreements must repay the principal amount of the loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from their respective pool and is based
on the average cost of funds available through the pool. The average interest
rate for borrowings in the first nine months of 2007 was 5.66% for the regulated
companies’ money pool and 5.65% for 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, FES’ and the
Companies’ securities ratings as of October 18, 2007. The ratings outlook
from Moody’s is stable for FES and positive for all other companies. The ratings
outlook from S&P on all securities is negative.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa2
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB+
|
|
Baa2
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
|
|
|
|
|
|
TE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
|
|
|
|
|
|
Penn
|
|
Senior
secured
|
|
A-
|
|
Baa1
|
|
|
|
|
|
|
|
JCP&L
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
FES
|
|
Corporate
Credit/Issuer Rating
|
|
BBB
|
|
Baa2
|
On
February 21,
2007, FirstEnergy made a $700 million equity investment in FES, all of
which was subsequently contributed to FGCO and used to pay down generation
asset
transfer-related promissory notes owed to the Ohio Companies and Penn. OE used
its $500 million of proceeds to repurchase shares of its common stock from
FirstEnergy.
On
March 27, 2007,
CEI issued $250 million of 5.70% unsecured senior notes due 2017. The
proceeds of the offering were used to reduce CEI’s short-term borrowings and for
general corporate purposes.
On
May 21, 2007,
JCP&L issued $550 million of senior unsecured debt securities, consisting of
$250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior
notes due 2037. A portion of the proceeds of the offering were used
to redeem outstanding FMB of JCP&L comprised of $125 million principal
amount of 7.50% series and $150 million principal amount of 6.75%
series. On July 1, 2007, JCP&L also redeemed all
$12.2 million outstanding principal amount of its remaining series of FMB.
In addition, $125 million of proceeds were used to repurchase shares of its
common stock from FirstEnergy. The remaining proceeds were used for
general corporate purposes.
As
described above,
on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided
interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax
proceeds of approximately $1.2 billion from the transaction were used to repay
short-term borrowings from, and to invest in, the FirstEnergy non-utility money
pool. The repayments and investment allowed FES to reduce its investment in
that
money pool in order to repay approximately $250 million of external bank
borrowings and fund a $600 million equity repurchase from FirstEnergy.
FirstEnergy used these funds to reduce its external short term borrowings as
discussed above.
On
August 30, 2007,
Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion
of the net proceeds from the issuance and sale of the senior notes were used
to
fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy.
The remaining net proceeds were used to repay short-term borrowings and for
general corporate purposes.
On
October 4, 2007,
FGCO and NGC closed on the issuance of $427 million of pollution control revenue
bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the
fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued
on behalf of the Ohio Companies. This transaction brings the total amount of
PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to
approximately $1.9 billion, with approximately $265 million remaining to be
transferred. The transfer of these PCRBs supports the intra-system generation
asset transfer that was completed in 2005.
Cash
Flows From Investing
Activities
Net
cash flows
provided from investing activities resulted principally from the proceeds from
the Bruce Mansfield Unit 1 sale and leaseback transaction, partially offset
by
property additions. Energy delivery services expenditures for property additions
primarily include expenditures related to transmission and distribution
facilities. Capital expenditures by the competitive energy services segment
are
principally generation-related. The following table summarizes investing
activities for the nine months ended September 30, 2007 and 2006 by
segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Provided
from (Used for) Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
Inter-Segment
reconciling items
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-Segment
reconciling items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
the first nine
months of 2007, net cash provided from investing activities was
$231 million compared to $822 million used for investing activities in
the first nine months of 2006. The change was principally due to $1.3 billion
in
proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction
described above. Partially offsetting the cash proceeds from the sale
and leaseback transaction was a $137 million increase in property additions
and
a $61 million decrease in cash provided from cash investments, primarily from
the use of restricted cash investments to repay debt during 2006.
During
the remaining
three months of 2007, capital requirements for property additions and capital
leases are expected to be approximately $460 million. FirstEnergy and the
Companies have additional requirements of approximately $10 million for maturing
long-term debt during the remainder of 2007. These cash requirements are
expected to be satisfied from a combination of internal cash, short-term credit
arrangements, and funds raised in the capital markets.
FirstEnergy's
capital spending for the period 2007-2011 is expected to be nearly
$8.0 billion (excluding nuclear fuel), of which approximately
$1.5 billion applies to 2007. Investments for additional nuclear fuel
during the 2007-2011 period are estimated to be approximately $1.2 billion,
of which about $95 million applies to 2007. During the same period,
FirstEnergy's nuclear fuel investments are expected to be reduced by
approximately $810 million and $100 million, respectively, as the nuclear fuel
is consumed.
GUARANTEES
AND OTHER ASSURANCES
As
part of normal
business activities, FirstEnergy enters into various agreements on behalf of
its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds, and LOCs. Some
of
the guaranteed contracts contain collateral provisions that are contingent
upon
FirstEnergy’s credit ratings.
As
of
September 30, 2007, FirstEnergy’s maximum exposure to potential future
payments under outstanding guarantees and other assurances approximated
$4.7 billion, as summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees of Subsidiaries
|
|
|
|
Energy
and
Energy-Related Contracts (1)
|
|
$
|
647
|
|
LOC
(long-term
debt) – interest coverage (2)
|
|
|
9
|
|
Other
(3)
|
|
|
575
|
|
|
|
|
1,231
|
|
|
|
|
|
|
Subsidiaries’
Guarantees
|
|
|
|
|
Energy
and
Energy-Related Contracts
|
|
|
37
|
|
LOC
(long-term
debt) – interest coverage (2)
|
|
|
3
|
|
Other
(4)
|
|
|
2,686
|
|
|
|
|
2,726
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
75
|
|
LOC
(long-term
debt) – interest coverage (2)
|
|
|
5
|
|
LOC
(non-debt)
(5)(6)
|
|
|
690
|
|
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
$
|
4,727
|
|
|
(1)
|
Issued
for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
Reflects
the
interest coverage portion of LOCs issued in support of floating-rate
pollution control revenue bonds with various maturities. The principal
amount of floating-rate pollution control revenue bonds of
$1.6 billion is reflected in long-term debt on FirstEnergy’s
consolidated balance sheets.
|
|
(3)
|
Includes
guarantees of $300 million for OVEC obligations and $80 million
for nuclear decommissioning funding
assurances.
|
|
(4)
|
Includes
FES’
guarantee of FGCO’s obligations under the sale and leaseback of Bruce
Mansfield Unit 1.
|
|
(5)
|
Includes
$71 million issued for various terms pursuant to LOC capacity
available under FirstEnergy’s revolving credit
facility.
|
|
(6)
|
Includes
approximately $194 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
in connection with the sale and leaseback of Beaver Valley Unit 2
by OE
and $134 million pledged in connection with the sale and leaseback of
Perry Unit 1 by OE.
|
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved
in
energy commodity activities principally to facilitate normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy to fulfill the obligations of
its
subsidiaries directly involved in these energy and energy-related transactions
or financings where the law might otherwise limit the counterparties' claims.
If
demands of a counterparty were to exceed the ability of a subsidiary to satisfy
existing obligations, FirstEnergy’s guarantee enables the counterparty's legal
claim to be satisfied by FirstEnergy’s other assets. The likelihood that such
parental guarantees will increase amounts otherwise paid by FirstEnergy to
meet
its obligations incurred in connection with ongoing energy and energy-related
contracts is remote.
While
these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or “material adverse event” the immediate posting of cash collateral
or provision of an LOC may be required of the subsidiary. As of
September 30, 2007, FirstEnergy’s maximum exposure under these collateral
provisions was $442 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 ($27 million as of September 30, 2007), which is renewable and
declines yearly based upon the senior outstanding debt of TEBSA. The LOC was
reduced to $19 million on October 15, 2007.
As
described above,
on July 13, 2007, FGCO completed a sale and leaseback transaction for its
93.825% undivided interest in the Bruce Mansfield Plant Unit 1. FES has
unconditionally and irrevocably guaranteed all of FGCO’s obligations under each
of the leases. The related lessor notes and pass through certificates
are not guaranteed by FES or FGCO, but the notes are secured by, among other
things, each lessor trust’s undivided interest in Unit 1, rights and interests
under the applicable lease and rights and interests under other related
agreements, including FES’ lease guaranty.
OFF-BALANCE
SHEET ARRANGEMENTS
FES
and the Ohio
Companies have obligations that are not included on FirstEnergy’s Consolidated
Balance Sheets related to sale and leaseback arrangements involving Perry
Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are
satisfied through operating lease payments. As of September 30, 2007, the
present value of these sale and leaseback operating lease commitments, net
of
trust investments, total $2.0 billion.
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 for risk management activities throughout the
company.
Commodity
Price
Risk
FirstEnergy
is
exposed to financial and market risks resulting from the fluctuation of interest
rates and commodity prices -- electricity, energy transmission, natural gas,
coal, nuclear fuel and emission allowances. 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 tables 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. The change in the fair value of commodity derivative contracts related
to
energy production during the three months and nine months ended September 30,
2007 is summarized in the following table:
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
September
30, 2007
|
|
September
30, 2007
|
|
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
|
$
|
(845
|
)
|
$
|
(12
|
)
|
$
|
(857
|
)
|
$
|
(1,140
|
)
|
$
|
(17
|
)
|
$
|
(1,157
|
)
|
Additions/change
in value of existing contracts
|
|
(38
|
)
|
|
-
|
|
|
(38
|
)
|
|
69
|
|
|
(6
|
)
|
|
63
|
|
Settled
contracts
|
|
47
|
|
|
5
|
|
|
52
|
|
|
235
|
|
|
16
|
|
|
251
|
|
Outstanding
net liability at end of period (1)
|
|
(836
|
)
|
|
(7
|
)
|
|
(843
|
)
|
|
(836
|
)
|
|
(7
|
)
|
|
(843
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Liabilities at End of Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
swaps (2)
|
|
-
|
|
|
(8
|
)
|
|
(8
|
)
|
|
-
|
|
|
(8
|
)
|
|
(8
|
)
|
Net
Liabilities - Derivative Contracts
at
End
of Period
|
$
|
(836
|
)
|
$
|
(15
|
)
|
$
|
(851
|
)
|
$
|
(836
|
)
|
$
|
(15
|
)
|
$
|
(851
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
4
|
|
$
|
-
|
|
$
|
4
|
|
$
|
4
|
|
$
|
-
|
|
$
|
4
|
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
$
|
-
|
|
$
|
5
|
|
$
|
5
|
|
$
|
-
|
|
$
|
10
|
|
$
|
10
|
|
Regulatory
assets (net)
|
$
|
(5
|
)
|
$
|
-
|
|
$
|
(5
|
)
|
$
|
(300
|
)
|
$
|
-
|
|
$
|
(300
|
)
|
(1)
|
Includes
$836 million in non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
(2)
|
Interest
rate
swaps are treated as cash flow or fair value hedges (see Interest
Rate
Swap Agreements below).
|
(3)
|
Represents
the
change in value of existing contracts, settled contracts and changes
in
techniques/assumptions.
|
Derivatives
are
included on the Consolidated Balance Sheet as of September 30, 2007 as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
non-current liabilities
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
The
valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, FirstEnergy relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. FirstEnergy uses these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of commodity derivative
contracts as of September 30, 2007 are summarized by year in the following
table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Fair
Value by Contract Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
Prices
actively quoted(2)
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Other
external
sources(3)
|
|
|
(60
|
)
|
|
(239
|
)
|
|
(173
|
)
|
|
(150
|
)
|
|
-
|
|
|
-
|
|
|
(622
|
)
|
Prices
based
on models
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
)
|
|
|
)
|
Total(4)
|
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
(1) For
the last quarter of 2007.
(2) Exchange
traded.
(3) Broker
quote sheets.
(4)
Includes
$836 million in non-hedge commodity derivative contracts (primarily with
NUGs), which are offset by a regulatory asset.
FirstEnergy
performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of September 30, 2007. Based on derivative contracts held as of
September 30, 2007, an adverse 10% change in commodity prices would
decrease net income by approximately $6 million during the next 12
months.
Interest
Rate Swap Agreements- Fair
Value Hedges
FirstEnergy
utilizes
fixed-for-floating interest rate swap agreements as part of its ongoing effort
to manage the interest rate risk associated with its debt portfolio. These
derivatives are treated as fair value hedges of fixed-rate, long-term debt
issues – protecting against the risk of changes in the fair value of fixed-rate
debt instruments due to lower interest rates. Swap maturities, call options,
fixed interest rates and interest payment dates match those of the underlying
obligations. During the first nine months of 2007, FirstEnergy paid
$8 million to terminate swaps with a notional amount $150 million as its
subsidiary redeemed the associated hedged debt. The loss was
recognized as interest expense during the nine-month period. As of
September 30, 2007, the debt underlying the $600 million outstanding
notional amount of interest rate swaps had a weighted average fixed interest
rate of 5.11%, which the swaps have converted to a current weighted average
variable rate of 5.72%.
|
|
September
30, 2007
|
|
December
31, 2006
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
Fair
value
hedges
|
|
$
|
|
|
|
|
|
$
|
|
|
$
|
|
|
|
|
|
$
|
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
) |
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
) |
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 anticipated future issuances
of fixed-rate, long-term debt securities for one or more of its consolidated
subsidiaries in 2007 and 2008. These derivatives are treated as cash flow
hedges, protecting against the risk of changes in future interest payments
resulting from changes in benchmark U.S. Treasury rates between the date of
hedge inception and the date of the debt issuance. During the first nine months
of 2007, FirstEnergy terminated forward swaps with an aggregate notional value
of $1.6 billion. FirstEnergy paid $20 million in cash related to the
terminations, which will be recognized over the terms of the associated future
debt. There was no ineffective portion associated with the loss. As of
September 30, 2007, FirstEnergy had outstanding forward swaps with an
aggregate notional amount of $400 million and an aggregate fair value of
$5 million.
|
|
September
30, 2007
|
|
December
31, 2006
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
Cash
flow
hedges
|
|
$
|
|
|
|
|
|
$
|
|
|
$
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
Price
Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their market
value of approximately $1.4 billion as of September 30, 2007 and
December 31, 2006. A hypothetical 10% decrease in prices quoted by stock
exchanges would result in a $139 million reduction in
fair value as of September 30, 2007.
CREDIT
RISK
Credit
risk is the
risk of an obligor’s failure to meet the terms of any investment contract, loan
agreement or otherwise perform as agreed. Credit risk arises from all activities
in which success depends on issuer, borrower or counterparty performance,
whether reflected on or off the balance sheet. FirstEnergy engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.
FirstEnergy
maintains credit policies with respect to its counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of its credit program, FirstEnergy aggressively
manages the quality of its portfolio of energy contracts, evidenced by a current
weighted average risk rating for energy contract counterparties of BBB+
(S&P). As of September 30, 2007, the largest credit concentration with one
party (currently rated investment grade) represented 10.9% of FirstEnergy‘s
total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of
credit exposures, net of collateral and reserves, were with investment-grade
counterparties as of September 30, 2007.
Outlook
State
Regulatory
Matters
In
Ohio, New Jersey
and Pennsylvania, laws applicable to electric industry restructuring contain
similar provisions that are reflected in the Companies' respective state
regulatory plans. These provisions include:
·
|
restructuring
the electric generation business and allowing the Companies' customers
to
select a competitive electric generation supplier other than the
Companies;
|
|
|
·
|
establishing
or defining the PLR obligations to customers in the Companies' service
areas;
|
|
|
·
|
providing
the
Companies with the opportunity to recover potentially stranded investment
(or transition costs) not otherwise recoverable in a competitive
generation market;
|
|
|
·
|
itemizing
(unbundling) the price of electricity into its component elements
–
including generation, transmission, distribution and stranded costs
recovery charges;
|
|
|
·
|
continuing
regulation of the Companies' transmission and distribution systems;
and
|
|
|
·
|
requiring
corporate separation of regulated and unregulated business
activities.
|
The
Companies and
ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and
NJBPU
have authorized for recovery from customers in future periods or for which
authorization is probable. Without the probability of such authorization, costs
currently recorded as regulatory assets would have been charged to income as
incurred. Regulatory assets that do not earn a current return totaled
approximately $227 million as of September 30, 2007 (JCP&L -
$93 million, Met-Ed - $43 million and Penelec - $91 million).
Regulatory assets not earning a current return will be recovered by 2014 for
JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses
regulatory assets by company:
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
717
|
|
$
|
741
|
|
$
|
(24
|
)
|
CEI
|
|
|
856
|
|
|
855
|
|
|
1
|
|
TE
|
|
|
215
|
|
|
248
|
|
|
(33
|
)
|
JCP&L
|
|
|
1,758
|
|
|
2,152
|
|
|
(394
|
)
|
Met-Ed
|
|
|
459
|
|
|
409
|
|
|
50
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec
had
net regulatory liabilities of approximately $77 million
and
$96 million as of September 30, 2007 and December 31,
2006,
respectively. These net regulatory liabilities are included in
Other
Non-current Liabilities on the Consolidated Balance
Sheets.
|
Regulatory
assets by
source are as follows:
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
2,583
|
|
$
|
3,266
|
|
$
|
(683
|
)
|
Customer
shopping incentives
|
|
|
537
|
|
|
603
|
|
|
(66
|
)
|
Customer
receivables for future income taxes
|
|
|
257
|
|
|
217
|
|
|
40
|
|
Societal
benefits charge
|
|
|
(11
|
)
|
|
11
|
|
|
(22
|
)
|
Loss
on
reacquired debt
|
|
|
58
|
|
|
43
|
|
|
15
|
|
Employee
postretirement benefits
|
|
|
41
|
|
|
47
|
|
|
(6
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and
spent fuel
disposal costs
|
|
|
(118
|
)
|
|
(145
|
)
|
|
27
|
|
Asset
removal
costs
|
|
|
(177
|
)
|
|
(168
|
)
|
|
(9
|
)
|
Property
losses and unrecovered plant costs
|
|
|
11
|
|
|
19
|
|
|
(8
|
)
|
MISO/PJM
transmission costs
|
|
|
309
|
|
|
213
|
|
|
96
|
|
Fuel
costs -
RCP
|
|
|
175
|
|
|
113
|
|
|
62
|
|
Distribution
costs - RCP
|
|
|
298
|
|
|
155
|
|
|
143
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
Reliability
Initiatives
In
late 2003 and
early 2004, a series of letters, reports and recommendations were issued from
various entities, including governmental, industry and ad hoc reliability
entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force)
regarding enhancements to regional reliability. In 2004, FirstEnergy completed
implementation of all actions and initiatives related to enhancing area
reliability, improving voltage and reactive management, operator readiness
and
training and emergency response preparedness recommended for completion in
2004.
On July 14, 2004, NERC independently verified that FirstEnergy had
implemented the various initiatives to be completed by June 30 or summer
2004, with minor exceptions noted by FirstEnergy, which exceptions are now
essentially complete. FirstEnergy is proceeding with the implementation of
the
recommendations that were to be completed subsequent to 2004 and will continue
to periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new equipment or material upgrades to
existing equipment. The FERC or other applicable government agencies and
reliability entities may, however, take a different view as to recommended
enhancements or may recommend additional enhancements in the future, which
could
require additional, material expenditures.
As
a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU
adopted an MOU that set out specific tasks related to service reliability to
be
performed by JCP&L and a timetable for completion and endorsed JCP&L’s
ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a
stipulation that incorporates the final report of an SRM who made
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The stipulation also incorporates the Executive Summary and
Recommendation portions of the final report of a focused audit of JCP&L’s
Planning and Operations and Maintenance programs and practices. 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. 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 served,
among other things, partly to amend the Federal Power Act by adding a new
Section 215, which requires that a new ERO establish and enforce reliability
standards for the bulk-power system, subject to review by the FERC.
Subsequently, the FERC certified NERC as the ERO, approved NERC's Compliance
Monitoring and Enforcement Program and approved a set of reliability standards,
which became mandatory and enforceable on June 18, 2007 with penalties and
sanctions for noncompliance. The FERC also approved a delegation agreement
between NERC and ReliabilityFirst Corporation, one of eight Regional
Entities that carry out enforcement for NERC. All of FirstEnergy’s
facilities are located within the ReliabilityFirst region.
To
date, FERC has
approved 83 of the 107 reliability standards proposed by NERC. Nevertheless,
the
FERC has directed NERC to submit improvements to 56 of the 83 approved standards
and has endorsed NERC's process for developing reliability standards and its
associated work plan. On May 4, 2007, NERC submitted 24 proposed Violation
Risk
Factors that would operate as a system of weighting the risk to the power grid
associated with a particular reliability standard violation. The FERC issued
an
order approving 22 of those factors on June 26, 2007. Further, NERC adopted
eight cyber security standards and filed them with the FERC for approval. On
December 11, 2006, the FERC Staff provided its preliminary assessment of
the cyber security standards and cited various deficiencies in the proposed
standards. Numerous parties, including FirstEnergy, provided comments on the
preliminary assessment. The standards remain pending before the FERC.
Separately, on July 20, 2007, the FERC issued a NOPR proposing to adopt eight
related Critical Infrastructure Protection Reliability Standards. On October
5,
2007, numerous parties, including FirstEnergy, provided comments on the proposed
Critical Infrastructure Protection standards. These standards, and FirstEnergy’s
comments thereon, are pending before FERC.
FirstEnergy
believes
it is in compliance with all current NERC reliability standards. However, based
upon a review of the FERC's guidance to NERC in its March 16, 2007 Final Rule
on
Mandatory Reliability Standards, it appears that the FERC may eventually adopt
stricter standards than those just approved. The financial impact of complying
with the new standards cannot be determined at this time. However, the EPACT
required that all prudent costs incurred to comply with the new reliability
standards be recovered in rates. If FirstEnergy is unable to meet the
reliability standards for its bulk power system in the future, it could have
a
material adverse effect on FirstEnergy’s and its subsidiaries’ financial
condition, results of operations and cash flows.
On
April 18-20,
2007, ReliabilityFirst performed a routine compliance audit of
FirstEnergy's bulk-power system within the Midwest ISO region and found
FirstEnergy to be in full compliance with all audited reliability
standards. Similarly, ReliabilityFirst has scheduled a
compliance audit of FirstEnergy's bulk-power system within the PJM region in
2008. FirstEnergy does not expect any material adverse impact to its financial
condition as a result of these audits.
Ohio
The
Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005
seeking approval of the RCP, a supplement to the RSP. On November 4, 2005,
the
Ohio Companies filed a supplemental stipulation with the PUCO, which constituted
an additional component of the RCP filed on September 9, 2005. 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. 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 2007 through 2010:
Amortization
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
(In
millions)
|
|
2007
|
|
$
|
176
|
|
$
|
108
|
|
$
|
92
|
|
$
|
376
|
|
2008
|
|
|
209
|
|
|
126
|
|
|
113
|
|
|
448
|
|
2009
|
|
|
-
|
|
|
217
|
|
|
-
|
|
|
217
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Several
parties
subsequently filed appeals to the Supreme Court of Ohio in connection with
certain portions of the RCP approved by the PUCO. In its order, the PUCO
authorized the Ohio Companies to recover certain increased fuel costs through
a
fuel rider and to defer certain other increased fuel costs, all such costs
to be
incurred from January 1, 2006 through December 31, 2008, including interest
on
the deferred balances. The order also provided for recovery of the deferred
costs over a 25-year period through distribution rates, which was expected
to
begin on January 1, 2009 for OE and TE, and approximately May 2009 for
CEI. Through September 30, 2007, the deferred fuel costs, including
interest, were $89 million, $61 million and $26 million for OE, CEI and TE,
respectively.
On
August 29, 2007,
the Supreme Court of Ohio concluded that the PUCO violated certain provisions
of
the Ohio Revised Code by permitting the Ohio Companies “to collect deferred
increased fuel costs through future distribution rate cases, or to alternatively
use excess fuel-cost recovery to reduce deferred distribution-related expenses”
because fuel costs are a component of generation service, not distribution
service, and because the Court concluded the PUCO did not address whether the
deferral of fuel costs was anticompetitive. The Court remanded the
matter to the PUCO for further consideration consistent with the Court’s Opinion
on this issue and affirmed the PUCO’s Order in all other respects. On
September 7, 2007, the Ohio Companies filed a Motion for Reconsideration
with the Court. On September 10, 2007 the Ohio Companies filed an
Application with the PUCO that requests the implementation of two
generation-related fuel cost riders to collect the increased fuel costs that
were previously authorized to be deferred. The Ohio Companies requested the
riders become effective in October 2007 and end in December 2008, subject to
reconciliation which is expected to continue through the first quarter of 2009.
This matter is currently pending before the PUCO. Although unable to predict
the
ultimate outcome of this matter, the Ohio Companies intend to continue deferring
the fuel costs pursuant to the RCP, pending the Court’s disposition of the
Motion for Reconsideration and the PUCO’s action with respect to the Ohio
Companies’ Application.
On
August 31, 2005,
the PUCO approved a rider recovery mechanism through which the Ohio Companies
may recover all MISO transmission and ancillary service related costs incurred
during each year ending June 30. Pursuant to the PUCO’s order, the Ohio
Companies, on May 1, 2007, filed revised riders, which became effective on
July
1, 2007. The revised riders represent an increase over the amounts
collected through the 2006 riders of approximately $64 million
annually. If it is subsequently determined by the PUCO that
adjustments to the rider as filed are necessary, such adjustments, with carrying
costs, will be incorporated into the 2008 transmission rider
filing.
On
May 8, 2007, the
Ohio Companies filed with the PUCO a notice of intent to file for an increase
in
electric distribution rates. The Ohio Companies filed the application and rate
request with the PUCO on June 7, 2007. The requested increase is expected to
be
more than offset by the elimination or reduction of transition charges at the
time the rates go into effect and would result in lowering the overall
non-generation portion of the bill for most Ohio customers. The
distribution rate increases reflect capital expenditures since the Ohio
Companies’ last distribution rate proceedings, increases in operating and
maintenance expenses and recovery of regulatory assets created by deferrals
that
were approved in prior cases. On August 6, 2007, the Ohio Companies updated
their filing supporting a distribution rate increase of $332 million to the
PUCO to establish the test period data that will be used as the basis for
setting rates in that proceeding. The PUCO Staff is expected to issue its report
in the case in the fourth quarter of 2007 with evidentiary hearings to follow
in
early 2008. The PUCO order is expected to be issued in the second quarter of
2008. The new rates would become effective January 1, 2009 for OE and TE, and
approximately May 2009 for CEI.
On
July 10, 2007,
the Ohio Companies filed an application with the PUCO requesting approval of
a
comprehensive supply plan for providing generation service to customers who
do
not purchase electricity from an alternative supplier, beginning January 1,
2009. The proposed competitive bidding process would average the results of
multiple bidding sessions conducted at different times during the year. The
final price per kilowatt-hour would reflect an average of the prices resulting
from all bids. In their filing, the Ohio Companies offered two alternatives
for
structuring the bids, either by customer class or a “slice-of-system” approach.
The proposal provides the PUCO with an option to phase in generation price
increases for residential tariff groups who would experience a change in their
average total price of 15 percent or more. The PUCO held a technical conference
on August 16, 2007 regarding the filing. Comments by intervenors in the case
were filed on September 5, 2007. The PUCO Staff filed comments on
September 21, 2007. Parties filed reply comments on October 12,
2007. The Ohio Companies requested that the PUCO issue an order by November
1, 2007, to provide sufficient time to conduct the bidding process.
On
September 25,
2007, the Ohio Governor’s proposed energy plan was officially introduced into
the Ohio Senate. The bill proposes to revise state energy policy to address
electric generation pricing after 2008, establish advanced energy portfolio
standards and energy efficiency standards, and create GHG emissions reporting
and carbon control planning requirements. The bill also proposes to move to
a
“hybrid” system for determining rates for PLR service in which electric
utilities would provide regulated generation service unless they satisfy a
statutory burden to demonstrate the existence of a competitive market for retail
electricity. The Senate Energy & Public Utilities Committee has been
conducting hearings on the bill and receiving testimony from interested parties,
including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer
groups, utility executives and others. Several proposed amendments to the bill
have been submitted, including those from Ohio’s investor-owned electric
utilities. A substitute version of the bill, which incorporated certain of
the
proposed amendments, was introduced into the Senate Energy & Public
Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, such
legislation may have on its operations or those of the Ohio
Companies.
Pennsylvania
Met-Ed
and Penelec
have been purchasing a portion of their PLR requirements from FES through a
partial requirements wholesale power sales agreement and various amendments.
Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's
exposure to high wholesale power prices by providing power at a fixed price
for
their uncommitted PLR capacity and energy requirements during the term of these
agreements with FES.
On
September 26, 2006, Met-Ed and Penelec successfully conducted a competitive
RFP for a portion of their PLR obligation for the period December 1, 2006
through December 31, 2008. FES was one of the successful bidders in that
RFP process and on September 26, 2006 entered into a supplier master agreement
to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market
prices that were substantially higher than the fixed price in the partial
requirements agreements.
Based
on the outcome
of the 2006 comprehensive transition rate filing, as described below, Met-Ed,
Penelec and FES agreed to restate the partial requirements power sales agreement
effective January 1, 2007. The restated agreement incorporates the same fixed
price for residual capacity and energy supplied by FES as in the prior
arrangements between the parties, and automatically extends for successive
one
year terms unless any party gives 60 days’ notice prior to the end of the year.
The restated agreement also allows Met-Ed and Penelec to sell the output of
NUG
energy to the market and requires FES to provide energy at fixed prices to
replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec
to
satisfy their PLR obligations. The parties also have separately terminated
the
supplier master agreements in connection with the restatement of the partial
requirements agreement. Accordingly, the energy that would have been supplied
under the supplier master agreement will now be provided under the restated
partial requirements agreement. The fixed price under the restated agreement
is
expected to remain below wholesale market prices during the term of the
agreement.
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.
Based on the PPUC’s January 11, 2007 order described below, if FES ultimately
determines to terminate, reduce, or significantly modify the agreement prior
to
the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely
regulatory relief is not likely to be granted by the PPUC.
Met-Ed
and Penelec
made a comprehensive transition rate filing with the PPUC on April 10, 2006
to address a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals had been
approved, annual revenues would have increased by $216 million and
$157 million, respectively. That filing included, 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 then existing
FES agreement was to be phased out. Met-Ed and Penelec also requested approval
of a January 12, 2005 petition for the deferral of transmission-related
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.
Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG
stranded costs were also included in the filing. On May 4, 2006, the PPUC
consolidated the remand of the FirstEnergy and GPU merger proceeding, related
to
the quantification and allocation of merger savings, with the comprehensive
transition rate filing case.
The
PPUC entered its
Opinion and Order in the comprehensive rate filing proceeding on January 11,
2007. The order approved the recovery of transmission costs, including the
transmission-related deferral for January 1, 2006 through January 10, 2007,
when
new transmission rates were effective, and determined that no merger savings
from prior years should be considered in determining customers’ rates. The
request for increases in generation supply rates was denied as were the
requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs.
The order decreased Met-Ed’s and Penelec’s distribution rates by
$80 million and $19 million, respectively. These decreases were offset
by the increases allowed for the recovery of transmission expenses and the
transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton
decommissioning costs was granted and, in January 2007, Met-Ed and Penelec
recognized income of $15 million and $12 million, respectively, to
establish regulatory assets for those previously expensed decommissioning costs.
Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for
Penelec ($50 million). Met-Ed and Penelec filed a Petition for
Reconsideration on January 26, 2007 on the issues of consolidated tax savings
and rate of return on equity. Other parties filed Petitions for Reconsideration
on transmission (including congestion), transmission deferrals and rate design
issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s,
Penelec’s and the other parties’ petitions for procedural purposes. Due to that
ruling, the period for appeals to the Commonwealth Court of Pennsylvania was
tolled until 30 days after the PPUC entered a subsequent order ruling on the
substantive issues raised in the petitions. On March 1, 2007, the PPUC issued
three orders: (1) a tentative order regarding the reconsideration by the PPUC
of
its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed,
Penelec and the OCA and denying in part and accepting in part the MEIUG’s and
PICA’s Petition for Reconsideration; and (3) an order approving the compliance
filing. Comments to the PPUC for reconsideration of its order were filed on
March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007,
making minor changes to rate design as agreed upon by Met-Ed, Penelec and
certain other parties.
On
March 30, 2007,
MEIUG and PICA filed a Petition for Review with the Commonwealth Court of
Pennsylvania asking the court to review the PPUC’s determination on transmission
(including congestion) and the transmission deferral. Met-Ed and Penelec filed
a
Petition for Review on April 13, 2007 on the issues of consolidated tax savings
and the requested generation rate increase. The OCA filed its
Petition for Review on April 13, 2007, on the issues of transmission
(including congestion) and recovery of universal service costs from only the
residential rate class. On June 19, 2007, initial briefs were filed and
responsive briefs were filed through September 21, 2007. Reply briefs
were filed on October 5, 2007. Oral arguments are expected to take place in
late
2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of
congestion, it could have a material adverse effect on the financial condition
and results of operations of Met-Ed, Penelec and FirstEnergy.
As
of September 30,
2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the
2006 comprehensive transition rate case, the 1998 Restructuring Settlement
(including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement
Stipulation were $496 million and $58 million, respectively. During the
PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in
2006, it noted a modification to the NUG purchased power stranded cost
accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC
Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG
cost
balances as if the stranded cost accounting methodology modification had not
been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax
charge of approximately $10.3 million in the third quarter of 2006,
representing incremental costs deferred under the revised methodology in 2005.
Met-Ed and Penelec continue to believe that the stranded cost accounting
methodology modification is appropriate and on August 24, 2006 filed a petition
with the PPUC pursuant to its order for authorization to reflect the stranded
cost accounting methodology modification effective January 1, 1999. Hearings
on
this petition were held in February 2007 and briefing was completed on March
28,
2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's
and Penelec’s request to modify their NUG stranded cost accounting methodology.
The companies filed exceptions to the initial decision on May 23, 2007 and
replies to those exceptions were filed on June 4, 2007. It is not known when
the
PPUC may issue a final decision in this matter.
On
May 2, 2007, Penn
filed a plan with the PPUC for the procurement of PLR supply from June 2008
through May 2011. The filing proposes multiple, competitive RFPs with staggered
delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the
residential and commercial classes. The proposal phases out existing promotional
rates and eliminates the declining block and the demand components on generation
rates for residential and commercial customers. The industrial class PLR service
will be provided through an hourly-priced service provided by Penn. Quarterly
reconciliation of the differences between the costs of supply and revenues
from
customers is also proposed. On
September 28, 2007, Penn filed a Joint Petition for Settlement resolving all
but
one issue in the case. Briefs were also filed on September 28, 2007
on the unresolved issue of incremental uncollectible accounts expense. The
settlement is either supported, or not opposed, by all parties. The PPUC is
expected to act on the settlement and the unresolved issue in late November
or
early December 2007 for the initial RFP to take place in January
2008.
On
February 1, 2007,
the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces
of
proposed legislation that, according to the Governor, is designed to reduce
energy costs, promote energy independence and stimulate the economy. Elements
of
the EIS include the installation of smart meters, funding for solar panels
on
residences and small businesses, conservation programs to meet demand growth,
a
requirement that electric distribution companies acquire power that results
in
the “lowest reasonable rate on a long-term basis,” the utilization of
micro-grids and an optional three year phase-in of rate increases. On July
17,
2007 the Governor signed into law two pieces of energy legislation. The first
amended the Alternative Energy Portfolio Standards Act of 2004 to, among other
things, increase the percentage of solar energy that must be supplied at the
conclusion of an electric distribution company’s transition period. The second
law allows electric distribution companies, at their sole discretion, to enter
into long term contracts with large customers and to build or acquire interests
in electric generation facilities specifically to supply long-term contracts
with such customers. A special legislative session on energy was convened in
mid-September 2007 to consider other aspects of the EIS. The final form of
any
legislation arising from the special legislative session is uncertain.
Consequently, FirstEnergy is unable to predict what impact, if any, such
legislation may have on its operations.
New
Jersey
JCP&L
is
permitted to defer for future collection from customers the amounts by which
its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of September 30, 2007, the accumulated deferred
cost balance totaled approximately $330 million.
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 NJBPU
proceedings has not yet been set.
On
August 1,
2005, the NJBPU established a proceeding to determine whether additional
ratepayer protections are required at the state level in light of the repeal
of
PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October
2,
2006 that 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.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an
additional draft proposal on March 31, 2006 addressing various issues
including access to books and records, ring-fencing, cross subsidization,
corporate governance and related matters. With the approval of the NJBPU Staff,
the affected utilities jointly submitted an alternative proposal on June 1,
2006. Comments on the alternative proposal were submitted on June 15, 2006.
On November 3, 2006, the Staff circulated a revised draft proposal to
interested stakeholders. Another revised draft was circulated by the NJBPU
Staff
on February 8, 2007.
New
Jersey statutes
require that the state periodically undertake a planning process, known as
the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement
of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President
and
includes representatives of several State departments. In October 2006, the
current EMP process was initiated with the issuance of a proposed set of
objectives which, as to electricity, included the following:
·
Reduce
the total projected electricity demand by 20% by 2020;
·
|
Meet
22.5% of
New Jersey’s electricity needs with renewable energy resources by that
date;
|
·
Reduce
air pollution related to energy use;
·
Encourage
and
maintain economic growth and development;
·
|
Achieve
a 20% reduction in both Customer Average Interruption Duration Index
and
System Average Interruption Frequency Index by
2020;
|
·
|
Maintain
unit
prices for electricity to no more than +5% of the regional average
price
(region includes New York, New Jersey, Pennsylvania, Delaware, Maryland
and the District of Columbia); and
|
·
Eliminate
transmission congestion by 2020.
Comments
on the
objectives and participation in the development of the EMP have been solicited
and a number of working groups have been formed to obtain input from a broad
range of interested stakeholders including utilities, environmental groups,
customer groups, and major customers. EMP working groups addressing (1) energy
efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing
issues have completed their assigned tasks of data gathering and analysis and
have provided reports to the EMP Committee. Public stakeholder meetings were
held in the fall of 2006 and in early 2007, and further public meetings are
expected later in 2007. A final draft of the EMP is expected to be presented
to
the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome
of this process nor determine the impact, if any, such legislation may have
on
its operations or those of JCP&L.
On
February 13,
2007, the NJBPU Staff informally issued a draft proposal relating to changes
to
the regulations addressing electric distribution service reliability and quality
standards. Meetings between the NJBPU Staff and interested
stakeholders to discuss the proposal were held and additional, revised informal
proposals were subsequently circulated by the Staff. On September 4,
2007, proposed regulations were published in the New Jersey Register, which
proposal will be subsequently considered by the NJBPU following comments which
were due on September 26, 2007. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, such
regulations may have on its operations or those of JCP&L.
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 participated in the
FERC hearings held in May 2006 concerning the calculation and imposition of
the
SECA charges. The presiding judge issued an initial decision on August 10,
2006,
rejecting the compliance filings made by the RTOs and transmission owners,
ruling on various issues and directing new compliance filings. This decision
is
subject to review and approval by the FERC. Briefs addressing the initial
decision were filed on September 11, 2006 and October 20, 2006. A final order
could be issued by the FERC in the fourth quarter of 2007.
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, BG&E and Pepco Holdings, Inc. requested a formula
rate for transmission service provided within their respective zones. Hearings
were held and numerous parties appeared and litigated various issues; including
AEP, which filed in opposition proposing to create a "postage stamp" rate for
high voltage transmission facilities across PJM. At the conclusion of the
hearings, the ALJ issued an initial decision adopting the FERC 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. Numerous
parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and
recommendations. On April 19, 2007, the FERC issued an order
rejecting the ALJ’s findings and recommendations in nearly every respect. The
FERC found that the PJM transmission owners’ existing “license plate” rate
design was just and reasonable and ordered that the current license plate rates
for existing transmission facilities be retained. On the issue of rates for
new
transmission facilities, the FERC directed that costs for new transmission
facilities that are rated at 500 kV or higher are to be socialized throughout
the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to
be
allocated on a “beneficiary pays” basis. Nevertheless, the FERC found
that PJM’s current beneficiary-pays cost allocation methodology is not
sufficiently detailed and, in a related order that also was issued on April
19,
2007, directed that hearings be held for the purpose of establishing a just
and
reasonable cost allocation methodology for inclusion in PJM’s
tariff.
On
May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007
Order. Subsequently, FirstEnergy and other parties filed pleadings
opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if
sustained on rehearing and appeal, will prevent the allocation of the cost
of
existing transmission facilities of other utilities to JCP&L, Met-Ed and
Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce future
transmission costs shifting to the JCP&L, Met-Ed and Penelec
zones.
New
FERC Transmission Rate
Design Filings
On
August 1, 2007, a
number of filings were made with the FERC by transmission owning utilities
in
the MISO and PJM footprint that could affect the transmission rates paid by
FirstEnergy’s operating companies and FES.
FirstEnergy
joined
in a filing made by the MISO transmission owners that would maintain the
existing “license plate” rates for transmission service within MISO provided
over existing transmission facilities. FirstEnergy also joined in a
filing made by both the MISO and PJM transmission owners proposing to continue
the elimination of transmission rates associated with service over existing
transmission facilities between MISO and PJM. If adopted by the FERC,
these filings would not affect the rates charged to load-serving FirstEnergy
affiliates for transmission service over existing transmission
facilities. In a related filing, MISO and MISO transmission owners
requested that the current MISO pricing for new transmission facilities that
spreads 20% of the cost of new 345 kV and higher transmission facilities across
the entire MISO footprint be maintained (known as the RECB Process). Each of
these filings was supported by the majority of transmission owners in either
MISO or PJM, as applicable.
The
Midwest
Stand-Alone Transmission Companies made a filing under Section 205 of the
Federal Power Act requesting that 100% of the cost of new qualifying 345 kV
and
higher transmission facilities be spread throughout the entire MISO
footprint. Further, Indianapolis Power and Light Company separately
moved the FERC to reopen the record to address the cost allocation for the
RECB
Process. If either proposal is adopted by the FERC, it could shift a
greater portion of the cost of new 345 kV and higher transmission facilities
to
the FirstEnergy footprint in MISO, and increase the transmission rates paid
by
load-serving FirstEnergy affiliates in MISO.
On
September 17,
2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power
Act
seeking to have the entire transmission rate design and cost allocation methods
used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory,
and to have FERC fix a uniform regional transmission rate design and cost
allocation method for the entire MISO and PJM “SuperRegion” that regionalizes
the cost of new and existing transmission facilities operated at voltages of
345
kV and above. Lower voltage facilities would continue to be recovered
in the host utility transmission rate zone through a license plate
rate. AEP requests a refund effective October 1, 2007, or
alternatively, February 1, 2008. The effect of this proposal, if
adopted by FERC, would be to shift significant costs to the FirstEnergy zones
in
MISO and PJM. FirstEnergy believes that most of these costs would
ultimately be recoverable in retail rates. On October 12, 2007, BG&E
filed a motion to dismiss AEP’s complaint. On October 16, 2007, the
Organization of MISO States filed comments urging the FERC to dismiss AEP’s
complaint. Interventions and protests to AEP’s complaint and answers to
BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and
other transmission owners filed protests to AEP’s complaint and support for
BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint
with the cases above, and FirstEnergy expects it to be resolved on the same
timeline as those cases.
Any
increase in
rates charged for transmission service to FirstEnergy affiliates is dependent
upon the outcome of these proceedings at FERC. All or some of these
proceedings may be consolidated by the FERC and set for hearing. The
outcome of these cases cannot be predicted. Any material adverse
impact on FirstEnergy would depend upon the ability of the load-serving
FirstEnergy affiliates to recover increased transmission costs in their retail
rates. FirstEnergy believes that current retail rate mechanisms in
place for PLR service for the Ohio Companies and for Met-Ed and Penelec would
permit them to pass through increased transmission charges in their retail
rates. Increased transmission charges in the JCP&L and Penn
transmission zones would be the responsibility of competitive electric retail
suppliers, including FES.
MISO
Ancillary Services
Market and Balancing Area Consolidation Filing
MISO
made a filing
on September 14, 2007 to establish Ancillary Services markets for regulation,
spinning and supplemental reserves to consolidate the existing 24 balancing
areas within the MISO footprint, and to establish MISO as the NERC registered
balancing authority for the region. An effective date of June 1, 2008
was requested in the filing.
MISO’s
previous
filing to establish an Ancillary Services market was rejected without prejudice
by FERC on June 22, 2007, subject to MISO making certain modifications in its
filing. FirstEnergy believes that MISO’s September 14 filing generally
addresses the FERC’s directives. FirstEnergy supports the proposal to
establish markets for Ancillary Services and consolidate existing balancing
areas, but filed objections on specific aspects of the MISO
proposal. Interventions and protests to MISO’s filing were made with
FERC on October 15, 2007.
Order
No. 890 on Open Access
Transmission Tariffs
On
February 16,
2007, the FERC issued a final rule (Order No. 890) that revises its decade-old
open access transmission regulations and policies. The FERC explained
that the final rule is intended to strengthen non-discriminatory access to
the
transmission grid, facilitate FERC enforcement, and provide for a more open
and
coordinated transmission planning process. The final rule became
effective on May 14, 2007. MISO, PJM and ATSI will be filing revised
tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff
filings to the FERC on October 11, 2007. As a market participant in both MISO
and PJM, FirstEnergy will conform its business practices to each respective
revised tariff.
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 become both
probable and reasonably estimable.
Clean
Air Act Compliance
FirstEnergy
is
required to meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500
for
each day the unit is in violation. The EPA has an interim enforcement policy
for
SO2 regulations
in Ohio that allows for compliance based on a 30-day averaging period.
FirstEnergy believes it is currently in compliance with this policy, but cannot
predict what action the EPA may take in the future with respect to the interim
enforcement policy.
The
EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006 alleging violations to various sections of the Clean Air Act.
FirstEnergy has disputed those alleged violations based on its Clean Air Act
permit, the Ohio SIP and other information provided at an August 2006 meeting
with the EPA. The EPA has several enforcement options (administrative compliance
order, administrative penalty order, and/or judicial, civil or criminal action)
and has indicated that such option may depend on the time needed to achieve
and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding the opacity limit applicable to
the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy
complies
with SO2
reduction requirements under the Clean Air Act Amendments of 1990 by burning
lower-sulfur fuel, generating more electricity from lower-emitting plants,
and/or using emission allowances. NOX reductions
required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX reductions
at
FirstEnergy's facilities. The EPA's NOX Transport
Rule
imposes uniform reductions of NOX emissions
(an
approximate 85% reduction in utility plant NOX emissions
from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX budgets
established
under SIPs through combustion controls and post-combustion controls, including
Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.
On
May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal Clean Air Act, alleging violations
of
air pollution laws at the Mansfield Plant, including opacity limitations. Prior
to the receipt of this notice, the Mansfield Plant was subject to a Consent
Order and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with
the
applicable laws will continue. On October 16, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. FirstEnergy is currently studying
PennFuture’s complaint.
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
allowed 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 generation facilities
will
be subject to caps on SO2 and NOX
emissions, whereas
its New Jersey fossil 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, allowing new and non-emitting generating
facilities (including renewables and nuclear) to be entitled to their
proportionate share of the allowances. Consequently, FirstEnergy will be
disadvantaged if these model rules were implemented as proposed because
FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation
is not recognized under the input-based allocation.
Pennsylvania
has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. Pennsylvania’s mercury
regulation would deprive FES of mercury emission allowances that were to be
allocated to the Mansfield Plant under the CAMR and that would otherwise be
available for achieving FirstEnergy system-wide compliance. It is anticipated
that compliance with these regulations, if approved by the EPA and implemented,
would not require the addition of mercury controls at the Mansfield Plant,
FirstEnergy’s only coal-fired Pennsylvania power plant, until 2015, if at
all.
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,
and is now owned by FGCO. 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 the New Source Review, or NSR, 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 Sammis NSR litigation. This settlement agreement, which is in
the
form of a consent decree, was approved by the court on July 11, 2005, and
requires reductions of NOX and SO2
emissions at the
Sammis, Burger, Eastlake and Mansfield 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 Sammis NSR
Litigation consent decree. Capital expenditures necessary to complete
requirements of the Sammis NSR Litigation settlement agreement are currently
estimated to be $1.7 billion for 2007 through 2011 ($400 million of which
is expected to be spent during 2007, with the largest portion of the remaining
$1.3 billion expected to be spent in 2008 and 2009).
The
Sammis NSR
Litigation consent decree also requires FirstEnergy to spend up to
$25 million toward environmentally beneficial projects, $14 million of
which is satisfied by entering into 93 MW (or 23 MW if federal tax credits
are
not applicable) of wind energy purchased power agreements with a 20-year term.
An initial 16 MW of the 93 MW consent decree obligation was satisfied
during 2006.
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. At the international
level, efforts have begun to develop climate change agreements for post-2012
GHG
reductions. 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.
At
the federal
level, members of Congress have introduced several bills seeking to reduce
emissions of GHG in the United States. State activities, primarily
the northeastern states participating in the Regional Greenhouse Gas Initiative
and western states led by California, have coordinated efforts to develop
regional strategies to control emissions of certain GHGs.
On
April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2 emissions
from automobiles as “air pollutants” under the Clean Air Act. Although this
decision did not address CO2 emissions
from
electric generating plants, the EPA has similar authority under the Clean Air
Act to regulate “air pollutants” from those and other facilities. Also on
April 2, 2007, the United States Supreme Court ruled that changes in annual
emissions (in tons/year) rather than changes in hourly emissions rate (in
kilograms/hour) must be used to determine whether an emissions increase triggers
NSR. Subsequently, the EPA proposed to change the NSR regulations, on
May 8, 2007, to utilize changes in the hourly emission rate (in
kilograms/hour) to determine whether an emissions increase triggers
NSR.
FirstEnergy
cannot
currently estimate the financial impact of climate change policies, although
potential legislative or regulatory programs restricting 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 life is drawn into a facility's cooling
water system. On January 26, 2007, the federal Court of Appeals for the Second
Circuit remanded portions of the rulemaking dealing with impingement mortality
and entrainment back to EPA for further rulemaking and eliminated the
restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended
this rule, noting that until further rulemaking occurs, permitting authorities
should continue the existing practice of applying their best professional
judgment (BPJ) to minimize impacts on fish and shellfish from cooling water
intake structures. FirstEnergy is evaluating various control options and their
costs and effectiveness. Depending on the outcome of such studies, the EPA’s
further rulemaking and any action taken by the states exercising BPJ, 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.
Under
NRC
regulations, FirstEnergy must ensure that adequate funds will be available
to
decommission its nuclear facilities. As of September 30, 2007,
FirstEnergy had approximately $1.5 billion invested in external trusts to
be used for the decommissioning and environmental remediation of Davis-Besse,
Beaver Valley and Perry. As part of the application to the NRC to
transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy
agreed to contribute another $80 million to these trusts by 2010. Consistent
with NRC guidance, utilizing a “real” rate of return on these funds of
approximately 2% over inflation, these trusts are expected to exceed the minimum
decommissioning funding requirements set by the NRC. Conservatively, these
estimates do not include any rate of return that the trusts may earn over the
20-year plant useful life extensions that FirstEnergy plans to seek for these
facilities.
The
Companies have
been named as PRPs at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of September
30, 2007, 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 $89 million have been accrued through
September 30, 2007.
Other
Legal
Proceedings
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.
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
in
July 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, NJ, based on a
common incident involving the failure of the bushings of two large transformers
in the Red Bank substation resulting in planned and unplanned outages in the
area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify
the class based on a very limited number of class members who incurred damages
and also filed a motion for summary judgment on the remaining plaintiffs’ claims
for negligence, breach of contract and punitive damages. In July 2006, the
New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division which, in March 2007, reversed the decertification of the Red Bank
class and remanded this matter back to the Trial Court to allow plaintiffs
sufficient time to establish a damage model or individual proof of
damages. JCP&L filed a petition for allowance of an appeal of the
Appellate Division ruling to the New Jersey Supreme Court which was denied
in
May 2007. Proceedings are continuing in the Superior
Court. FirstEnergy is defending this class action but is unable
to predict the outcome of this matter. No liability has been accrued
as of September 30, 2007.
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
that could require additional material expenditures.
FirstEnergy
companies also are defending four separate complaint cases before the PUCO
relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various
FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for
claims paid to insureds for damages allegedly arising as a result of the loss
of
power on August 14, 2003. A fifth case in which a carrier sought
reimbursement for claims paid to insureds was voluntarily dismissed by the
claimant in April 2007. A sixth case involving the claim of a non-customer
seeking reimbursement for losses incurred when its store was burglarized on
August 14, 2003 was dismissed. The four cases remaining were consolidated
for hearing by the PUCO in an order dated March 7, 2006. In that
order the PUCO also limited the litigation to service-related claims by
customers of the Ohio operating companies; dismissed FirstEnergy as a defendant;
and ruled that the U.S.-Canada Power System Outage Task Force Report was not
admissible into evidence. In response to a motion for rehearing filed by one
of
the claimants, the PUCO ruled on April 26, 2006 that the insurance company
claimants, as insurers, may 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 amended complaints and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have been
set for hearing on January 8, 2008.
FirstEnergy
is 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 FirstEnergy is 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
May 14, 2007, the
Office of Enforcement of the NRC issued a Demand for Information to FENOC
following FENOC’s reply to an April 2, 2007 NRC request for information about
two reports prepared by expert witnesses for an insurance arbitration related
to
Davis-Besse. The NRC indicated that this information was needed for the NRC
“to
determine whether an Order or other action should be taken pursuant to 10 CFR
2.202, to provide reasonable assurance that FENOC will continue to operate
its
licensed facilities in accordance with the terms of its licenses and the
Commission’s regulations.” FENOC was directed to submit the information to the
NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand
for Information reaffirming that it accepts full responsibility for the mistakes
and omissions leading up to the damage to the reactor vessel head and that
it
remains committed to operating Davis-Besse and FirstEnergy’s other nuclear
plants safely and responsibly. The NRC held a public meeting on June 27, 2007
with FENOC to discuss FENOC’s response to the Demand for Information. In
follow-up discussions, FENOC was requested to provide supplemental information
to clarify certain aspects of the Demand for Information response and provide
additional details regarding plans to implement the commitments made therein.
FENOC submitted this supplemental response to the NRC on July 16, 2007. On
August 15, 2007, the NRC issued a confirmatory order imposing these
commitments. FENOC must inform the NRC’s Office of Enforcement after it
completes the key commitments embodied in the NRC’s order. FENOC’s compliance
with these commitments is subject to future NRC review.
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
August 22, 2005,
a class action complaint was filed against OE in Jefferson County,
Ohio Common Pleas Court, seeking compensatory and punitive damages to be
determined at trial based on claims of negligence and eight other tort counts
alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs
are also seeking injunctive relief to eliminate harmful emissions and repair
property damage and the institution of a medical monitoring program for class
members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify
this case as a class action and, accordingly, did not appoint the plaintiffs
as
class representatives or their counsel as class counsel. On July 30, 2007,
plaintiffs’ counsel voluntarily withdrew their request for reconsideration of
the April 5, 2007 Court order denying class certification and the Court
heard oral argument on the plaintiffs’ motion to amend their complaint which OE
has opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend
their complaint. The plaintiffs have appealed the Court’s denial of the motion
for certification as a class action and motion to amend their
complaint.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. The arbitration
panel provided additional rulings regarding damages during a September 2007
hearing and it is anticipated that he will issue a final order in late 2007.
JCP&L intends to re-file an appeal again in federal district court once the
damages associated with this case are identified at an individual employee
level. JCP&L recognized a liability for the potential $16 million award
in 2005.
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.
NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
SFAS
157 – “Fair Value
Measurements”
In
September 2006,
the FASB issued SFAS 157 that establishes how companies should measure fair
value when they are required to use a fair value measure for recognition or
disclosure purposes under GAAP. This Statement addresses the need for increased
consistency and comparability in fair value measurements and for expanded
disclosures about fair value measurements. The key changes to current practice
are: (1) the definition of fair value which focuses on an exit price rather
than
entry price; (2) the methods used to measure fair value such as emphasis that
fair value is a market-based measurement, not an entity-specific measurement,
as
well as the inclusion of an adjustment for risk, restrictions and credit
standing; and (3) the expanded disclosures about fair value measurements. This
Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
FirstEnergy is currently evaluating the impact of this Statement on its
financial statements.
|
SFAS
159 –
“The Fair Value Option for Financial Assets and Financial Liabilities
–
Including an amendment of FASB Statement No.
115”
|
In
February 2007,
the FASB issued SFAS 159, which provides companies with an option to report
selected financial assets and liabilities at fair value. This
Statement requires companies to provide additional information that will help
investors and other users of financial statements to more easily understand
the
effect of the company’s choice to use fair value on its earnings. The
Standard also requires companies to display the fair value of those assets
and
liabilities for which the company has chosen to use fair value on the face
of
the balance sheet. This guidance does not eliminate disclosure
requirements included in other accounting standards, including requirements
for
disclosures about fair value measurements included in SFAS 157 and
SFAS 107. This Statement is effective for financial statements issued
for fiscal years beginning after November 15, 2007, and interim periods
within those years. FirstEnergy is currently evaluating the impact of this
Statement on its financial statements.
EITF
06-11 – “Accounting for Income Tax
Benefits of Dividends or Share-based Payment Awards”
In
June 2007, the
FASB released EITF 06-11, which provides guidance on the appropriate accounting
for income tax benefits related to dividends earned on nonvested share units
that are charged to retained earnings under SFAS 123(R). The
consensus requires that an entity recognize the realized tax benefit associated
with the dividends on nonvested shares as an increase to APIC. This amount
should be included in the APIC pool, which is to be used when an entity’s
estimate of forfeitures increases or actual forfeitures exceed its estimates,
at
which time the tax benefits in the APIC pool would be reclassified to the income
statement. The consensus is effective for income tax benefits of
dividends declared during fiscal years beginning after December 15,
2007. EITF 06-11 is not expected to have a material effect on
FirstEnergy’s financial statements.
FSP
FIN 39-1 – “Amendment of FASB
Interpretation No. 39”
In
April 2007, the
FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to
offset fair value amounts recognized for the right to reclaim cash collateral
(a
receivable) or the obligation to return cash collateral (a payable) against
fair
value amounts recognized for derivative instruments that have been offset under
the same master netting arrangement as the derivative
instruments. This FSP is effective for fiscal years beginning after
November 15, 2007, with early application permitted. The effects of applying
the
guidance in this FSP should be recognized as a retrospective change in
accounting principle for all financial statements presented. FirstEnergy is
currently evaluating the impact of this FSP on its financial statements but
it
is not expected to have a material impact.
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006 |
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
to affiliates
|
|
$ |
805,372
|
|
|
$ |
762,106
|
|
|
$ |
2,209,743
|
|
|
$ |
1,997,096
|
|
Other
|
|
|
365,536
|
|
|
|
347,474
|
|
|
|
1,048,189
|
|
|
|
1,063,026
|
|
Total
revenues
|
|
|
1,170,908
|
|
|
|
1,109,580
|
|
|
|
3,257,932
|
|
|
|
3,060,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
301,786
|
|
|
|
315,521
|
|
|
|
804,201
|
|
|
|
844,913
|
|
Purchased
power from non-affiliates
|
|
|
228,755
|
|
|
|
173,620
|
|
|
|
577,831
|
|
|
|
477,249
|
|
Purchased
power from affiliates
|
|
|
62,508
|
|
|
|
55,647
|
|
|
|
209,576
|
|
|
|
188,698
|
|
Other
operating expenses
|
|
|
235,033
|
|
|
|
198,716
|
|
|
|
731,774
|
|
|
|
774,767
|
|
Provision
for
depreciation
|
|
|
48,500
|
|
|
|
46,894
|
|
|
|
145,030
|
|
|
|
135,414
|
|
General
taxes
|
|
|
22,242
|
|
|
|
17,609
|
|
|
|
64,870
|
|
|
|
55,550
|
|
Total
expenses
|
|
|
898,824
|
|
|
|
808,007
|
|
|
|
2,533,282
|
|
|
|
2,476,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
272,084
|
|
|
|
301,573
|
|
|
|
724,650
|
|
|
|
583,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
12,655
|
|
|
|
27,662
|
|
|
|
47,756
|
|
|
|
44,843
|
|
Interest
expense to affiliates
|
|
|
(9,641 |
) |
|
|
(41,416 |
) |
|
|
(61,904 |
) |
|
|
(122,664 |
) |
Interest
expense - other
|
|
|
(31,794 |
) |
|
|
(7,914 |
) |
|
|
(70,845 |
) |
|
|
(17,880 |
) |
Capitalized
interest
|
|
|
5,131
|
|
|
|
2,389
|
|
|
|
12,763
|
|
|
|
8,698
|
|
Total
other
expense
|
|
|
(23,649 |
) |
|
|
(19,279 |
) |
|
|
(72,230 |
) |
|
|
(87,003 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
248,435
|
|
|
|
282,294
|
|
|
|
652,420
|
|
|
|
496,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
93,671
|
|
|
|
106,175
|
|
|
|
243,736
|
|
|
|
184,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
154,764
|
|
|
|
176,119
|
|
|
|
408,684
|
|
|
|
311,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(1,360 |
) |
|
|
-
|
|
|
|
(4,080 |
) |
|
|
-
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
4,863
|
|
|
|
(6,257 |
) |
|
|
9,451
|
|
|
|
(6,376 |
) |
Change
in
unrealized gain on available for sale securities
|
|
|
21,263
|
|
|
|
20,945
|
|
|
|
80,053
|
|
|
|
29,266
|
|
Other
comprehensive income
|
|
|
24,766
|
|
|
|
14,688
|
|
|
|
85,424
|
|
|
|
22,890
|
|
Income
tax
expense related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
8,915
|
|
|
|
5,453
|
|
|
|
30,474
|
|
|
|
8,548
|
|
Other
comprehensive income, net of tax
|
|
|
15,851
|
|
|
|
9,235
|
|
|
|
54,950
|
|
|
|
14,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
170,615
|
|
|
$ |
185,354
|
|
|
$ |
463,634
|
|
|
$ |
326,298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Solutions Corp. are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
2
|
|
|
$ |
2
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,007,000 and $7,938,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
144,443
|
|
|
|
129,843
|
|
Associated
companies
|
|
|
285,462
|
|
|
|
235,532
|
|
Other
(less
accumulated provisions of $9,000 and $5,593,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
5,416
|
|
|
|
4,085
|
|
Notes
receivable from associated companies
|
|
|
242,612
|
|
|
|
752,919
|
|
Materials
and
supplies, at average cost
|
|
|
441,066
|
|
|
|
460,239
|
|
Prepayments
and other
|
|
|
83,825
|
|
|
|
57,546
|
|
|
|
|
1,202,826
|
|
|
|
1,640,166
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
8,183,578
|
|
|
|
8,355,344
|
|
Less
-
Accumulated provision for depreciation
|
|
|
3,852,896
|
|
|
|
3,818,268
|
|
|
|
|
4,330,682
|
|
|
|
4,537,076
|
|
Construction
work in progress
|
|
|
596,879
|
|
|
|
339,886
|
|
|
|
|
4,927,561
|
|
|
|
4,876,962
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
1,342,083
|
|
|
|
1,238,272
|
|
Long-term
notes receivable from associated companies
|
|
|
62,900
|
|
|
|
62,900
|
|
Other
|
|
|
39,964
|
|
|
|
72,509
|
|
|
|
|
1,444,947
|
|
|
|
1,373,681
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
240,182
|
|
|
|
-
|
|
Goodwill
|
|
|
24,248
|
|
|
|
24,248
|
|
Property
taxes
|
|
|
44,111
|
|
|
|
44,111
|
|
Pension
assets
|
|
|
9,449
|
|
|
|
-
|
|
Other
|
|
|
70,638
|
|
|
|
39,839
|
|
|
|
|
388,628
|
|
|
|
108,198
|
|
|
|
$ |
7,963,962
|
|
|
$ |
7,999,007
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
1,469,721
|
|
|
$ |
1,469,660
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
237,070
|
|
|
|
1,022,197
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
432,695
|
|
|
|
556,049
|
|
Other
|
|
|
177,820
|
|
|
|
136,631
|
|
Accrued
taxes
|
|
|
537,060
|
|
|
|
113,231
|
|
Other
|
|
|
163,239
|
|
|
|
100,941
|
|
|
|
|
3,017,605
|
|
|
|
3,398,709
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 750 shares-
|
|
|
|
|
|
|
|
|
7
and 8 shares
outstanding, respectively
|
|
|
1,163,934
|
|
|
|
1,050,302
|
|
Accumulated
other comprehensive income
|
|
|
166,673
|
|
|
|
111,723
|
|
Retained
earnings
|
|
|
1,038,412
|
|
|
|
697,338
|
|
Total
common
stockholder's equity
|
|
|
2,369,019
|
|
|
|
1,859,363
|
|
Long-term
debt
|
|
|
505,196
|
|
|
|
1,614,222
|
|
|
|
|
2,874,215
|
|
|
|
3,473,585
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Deferred
gain
on sale and leaseback transaction
|
|
|
1,068,769
|
|
|
|
-
|
|
Accumulated
deferred income taxes
|
|
|
-
|
|
|
|
121,449
|
|
Accumulated
deferred investment tax credits
|
|
|
62,275
|
|
|
|
65,751
|
|
Asset
retirement obligation
|
|
|
797,357
|
|
|
|
760,228
|
|
Retirement
benefits
|
|
|
53,505
|
|
|
|
103,027
|
|
Property
taxes
|
|
|
44,433
|
|
|
|
44,433
|
|
Other
|
|
|
45,803
|
|
|
|
31,825
|
|
|
|
|
2,072,142
|
|
|
|
1,126,713
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
7,963,962
|
|
|
$ |
7,999,007
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they related to FirstEnergy
Solutions Corp. are an integral part of these
|
balance
sheets.
|
|
|
|
|
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
408,684
|
|
|
$ |
311,956
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
145,030
|
|
|
|
135,414
|
|
Nuclear
fuel
and lease amortization
|
|
|
75,102
|
|
|
|
66,360
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(381,042 |
) |
|
|
47,188
|
|
Investment
impairment
|
|
|
14,296
|
|
|
|
-
|
|
Accrued
compensation and retirement benefits
|
|
|
3,414
|
|
|
|
13,704
|
|
Commodity
derivative transactions, net
|
|
|
4,913
|
|
|
|
46,500
|
|
Gain
on asset
sales
|
|
|
(12,105 |
) |
|
|
(35,973 |
) |
Cash
collateral, net
|
|
|
(19,798 |
) |
|
|
20,643
|
|
Pension
trust
contribution
|
|
|
(64,020 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(30,172 |
) |
|
|
(46,063 |
) |
Materials
and
supplies
|
|
|
48,123
|
|
|
|
(1,683 |
) |
Prepayments
and other current assets
|
|
|
(5,118 |
) |
|
|
211
|
|
Increase
(decrease) in operating liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(108,949 |
) |
|
|
(162,502 |
) |
Accrued
taxes
|
|
|
424,100
|
|
|
|
77,524
|
|
Accrued
interest
|
|
|
14,355
|
|
|
|
2,431
|
|
Other
|
|
|
(36,498 |
) |
|
|
(17,605 |
) |
Net
cash
provided from operating activities
|
|
|
480,315
|
|
|
|
458,105
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
|
251,945
|
|
Equity
contributions from parent
|
|
|
710,468
|
|
|
|
-
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
|
66,817
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(600,000 |
) |
|
|
-
|
|
Long-term
debt
|
|
|
(1,110,174 |
) |
|
|
(253,240
|
) |
Short-term
borrowings, net
|
|
|
(785,127 |
) |
|
|
-
|
|
Common
stock
dividend payments
|
|
|
(67,000 |
) |
|
|
-
|
|
Net
cash
provided from (used for) financing activities
|
|
|
(1,851,833 |
) |
|
|
65,522
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(482,907 |
) |
|
|
(427,298 |
) |
Proceeds
from
asset sales
|
|
|
12,990
|
|
|
|
20,437
|
|
Proceeds
from
sale and leaseback transaction
|
|
|
1,328,919
|
|
|
|
-
|
|
Sales
of
investment securities held in trusts
|
|
|
521,535
|
|
|
|
886,863
|
|
Purchases
of
investment securities held in trusts
|
|
|
(521,535 |
) |
|
|
(886,863 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
510,307
|
|
|
|
(88,292 |
) |
Other
|
|
|
2,209
|
|
|
|
(28,474 |
) |
Net
cash
provided from (used for) investing activities
|
|
|
1,371,518
|
|
|
|
(523,627 |
) |
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
2
|
|
|
|
2
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
2
|
|
|
$ |
2
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Solutions Corp. are an
|
integral
part
of these statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
FirstEnergy Solutions Corp.:
We
have reviewed the
accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and
its
subsidiaries as of September 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2007 and 2006 and the consolidated statement of
cash
flows for the nine-month periods ended September 30, 2007 and
2006. These interim financial statements are the responsibility of
the Company’s management.
We
conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting Oversight Board,
the objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an
opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, and the related consolidated statements of income, capitalization,
common stockholder’s equity, and cash flows 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 defined benefit pension and
other postretirement benefit plans as of December 31, 2006 as discussed in
Note
3 to those consolidated financial statements) dated April 11, 2007,except as
to
Note 12, which is as of August 6, 2007, we expressed an unqualified opinion
on
those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet information
as of December 31, 2006, is fairly stated in all material respects in relation
to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
FIRSTENERGY
SOLUTIONS CORP.
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF
RESULTS OF OPERATIONS
FES
is a wholly
owned subsidiary of FirstEnergy. FES provides energy-related products and
services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through
its
subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and
hydroelectric generation facilities and owns FirstEnergy’s nuclear generation
facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy,
operates and maintains the nuclear generating facilities.
FES’
revenues
are
primarily from the sale of electricity (provided from FES’ generating facilities
and through purchased power arrangements) to affiliated utility companies to
meet all or a portion of their PLR requirements. These affiliated power sales
include a full-requirements PSA with OE, CEI and TE to supply each of their
PLR
obligations through 2008, at prices that take into consideration their
respective PUCO authorized billing rates. FES also has a partial requirements
wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to
supply a portion of each of their respective PLR obligations at fixed prices
through 2010. The fixed prices under the partial requirements agreement are
expected to remain below wholesale market prices during the term of the
agreement. FES also supplies the majority of the PLR requirements of Penn at
market-based rates as a result of a competitive solicitation conducted by Penn.
FES’ existing contractual obligations to Penn expire on May 31, 2008, but
could continue if FES successfully bids in future competitive solicitations.
FES’ revenues also include competitive retail and wholesale sales to
non-affiliated customers in Ohio, Pennsylvania, Maryland and
Michigan.
Results
of Operations
In
the first nine
months of 2007, net income increased to $409 million from $312 million in the
first nine months of 2006. The increase in net income was primarily due to
higher revenues and lower fuel and other operating expenses, partially offset
by
higher purchased power costs.
Revenues
Revenues
increased
by $198 million
in the first nine months of 2007 compared to the same period in 2006 due to
increases in revenues from non-affiliated retail generation sales and affiliated
wholesale sales, partially offset by lower non-affiliated wholesale sales.
Retail generation sales revenues increased as a result of higher unit prices
and
increased KWH sales. Higher unit prices primarily reflected higher generation
rates in the MISO and PJM markets where FES is an alternative supplier.
Increased KWH sales to FES’ commercial and industrial customers during the first
nine months of 2007 were partially offset by a decrease in sales to residential
customers returning to FES’ Ohio utility affiliates for their generation
requirements. Affiliated wholesale revenues were higher as a result of increased
sales and higher unit prices for sales to the Ohio Companies.
Non-affiliated
wholesale revenues decreased as a result of lower generation available for
the
non-affiliated market due to increased affiliated company power sales
requirements under the Ohio Companies’ full-requirements PSA and the
partial-requirements power sales agreement with Met-Ed and Penelec.
The
increase in
sales to the Ohio Companies was due to their higher retail generation sales
requirements. Higher unit prices resulted from the provision of the
full-requirements PSA under which PSA rates reflect the increase in the Ohio
Companies’ retail generation rates. The higher sales to the Pennsylvania
Companies were due to increased Met-Ed and Penelec generation sales
requirements. These increases were partially offset by lower sales to Penn
as a
result of the implementation of its competitive solicitation process in
2007.
Transmission
revenue
decreased $25 million due to reduced retail load in the MISO market, lower
transmission rates and reduced financial transmission rights auction
revenue.
Changes
in revenues
in the first nine months of 2007 from the same period of 2006 are summarized
below:
|
|
Nine Months
Ended
|
|
|
|
|
|
Sept
30,
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The
following tables
summarize the price and volume factors contributing to changes in revenues
from
non-affiliated and affiliated sales in the first nine months of 2007 compared
to
the same period last year:
|
|
Increase
|
|
Source
of Change in Non-Affiliated Generation
Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 12% increase in sales
volumes
|
|
$
|
52
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 26% decrease in sales
volumes
|
|
|
(131
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
)
|
Net
Increase
in Non-Affiliated Generation Revenues
|
|
|
|
|
Source
of Change in Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect
of 4% increase in sales
volumes
|
|
$
|
56
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect
of 12% increase in sales
volumes
|
|
|
54
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Affiliated Generation Revenues
|
|
|
|
|
Expenses
Total
expenses
increased by $57 million in the first nine months of 2007 compared with the
same period of 2006. The following table summarizes the factors contributing
to
the changes in fuel and purchased power costs in the first nine months of 2007
from the same period last year:
Source
of Change in Fuel and Purchased Power
|
|
|
|
|
|
(In
millions)
|
|
Nuclear
Fuel:
|
|
|
|
|
Change
due to increased unit
costs
|
|
$
|
3
|
|
Change
due to volume
consumed
|
|
|
5
|
|
|
|
|
8
|
|
Fossil
Fuel:
|
|
|
|
|
Change
due to decreased unit
costs
|
|
|
(4
|
)
|
Change
due to volume
consumed
|
|
|
(45
|
)
|
|
|
|
(49
|
)
|
Purchased
Power:
|
|
|
|
|
Change
due to increased unit
costs
|
|
|
51
|
|
Change
due to volume
purchased
|
|
|
71
|
|
|
|
|
122
|
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
|
|
|
Fossil
fuel costs
decreased $49 million in the first nine months of 2007 primarily as a result
of
reduced coal and emission allowance costs. Coal costs were lower due to a $14
million inventory adjustment as a result of an interim physical inventory and
$23 million from reduced coal consumption reflecting lower generation as a
result of planned maintenance outages at Sammis Units 6 and 7 and Eastlake
Unit
5 and forced outage at Mansfield Unit 1.
The
lower fossil
fuel costs were partially offset by higher nuclear fuel costs of $8 million.
Higher nuclear fuel costs were due to higher unit costs and increased nuclear
generation in the first nine months of 2007 as compared to the same period
of
2006.
Purchased
power
costs increased as a result of increased volumes purchased and higher unit
prices. Volumes purchased in the first nine months of 2007 increased by 10.6%
due to the outages at the Sammis, Eastlake, Mansfield and Perry
plants. Other operating expenses decreased by $43 million in the
first nine months of 2007 from the same period of 2006 primarily due to lower
nuclear operating costs as a result of fewer outages in 2007 compared to 2006
and reduced employee benefit costs.
Depreciation
expense
increased by $10 million in the first nine months of 2007 primarily due to
fossil and nuclear property additions subsequent to the third quarter of
2006.
General
taxes
increased by $9 million in the first nine months of 2007 compared to the
same period of 2006 as a result of higher property taxes and gross receipts
taxes.
Other
Expense
Other
expense
decreased by $15 million in the first nine months of 2007 from the same periods
of 2006 primarily as a result of lower interest expense. Lower interest expense
reflected the repayment of GAT-related notes to associated companies, partially
offset by the issuance of lower-cost pollution control debt subsequent to
October 1, 2006.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to FES.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to FES.
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
638,336
|
|
|
$ |
642,294
|
|
|
$ |
1,802,110
|
|
|
$ |
1,745,699
|
|
Excise
tax
collections
|
|
|
30,472
|
|
|
|
31,379
|
|
|
|
89,077
|
|
|
|
87,269
|
|
Total
revenues
|
|
|
668,808
|
|
|
|
673,673
|
|
|
|
1,891,187
|
|
|
|
1,832,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,821
|
|
|
|
2,954
|
|
|
|
8,148
|
|
|
|
8,726
|
|
Purchased
power
|
|
|
364,709
|
|
|
|
395,560
|
|
|
|
1,037,200
|
|
|
|
971,613
|
|
Nuclear
operating costs
|
|
|
41,783
|
|
|
|
44,995
|
|
|
|
130,951
|
|
|
|
129,585
|
|
Other
operating costs
|
|
|
100,265
|
|
|
|
108,362
|
|
|
|
285,871
|
|
|
|
290,776
|
|
Provision
for
depreciation
|
|
|
19,482
|
|
|
|
18,399
|
|
|
|
57,440
|
|
|
|
53,962
|
|
Amortization
of regulatory assets
|
|
|
53,026
|
|
|
|
49,717
|
|
|
|
144,569
|
|
|
|
147,022
|
|
Deferral
of
new regulatory assets
|
|
|
(41,417 |
) |
|
|
(44,962 |
) |
|
|
(132,410 |
) |
|
|
(123,285 |
) |
General
taxes
|
|
|
46,158
|
|
|
|
47,826
|
|
|
|
141,296
|
|
|
|
137,652
|
|
Total
expenses
|
|
|
586,827
|
|
|
|
622,851
|
|
|
|
1,673,065
|
|
|
|
1,616,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
81,981
|
|
|
|
50,822
|
|
|
|
218,122
|
|
|
|
216,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
19,827
|
|
|
|
32,993
|
|
|
|
67,803
|
|
|
|
98,853
|
|
Miscellaneous
income
|
|
|
670
|
|
|
|
1,639
|
|
|
|
3,362
|
|
|
|
835
|
|
Interest
expense
|
|
|
(20,311 |
) |
|
|
(24,597 |
) |
|
|
(62,749 |
) |
|
|
(60,195 |
) |
Capitalized
interest
|
|
|
136
|
|
|
|
698
|
|
|
|
398
|
|
|
|
1,832
|
|
Subsidiary's
preferred stock dividend requirements
|
|
|
-
|
|
|
|
(156 |
) |
|
|
-
|
|
|
|
(467 |
) |
Total
other
income
|
|
|
322
|
|
|
|
10,577
|
|
|
|
8,814
|
|
|
|
40,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
82,303
|
|
|
|
61,399
|
|
|
|
226,936
|
|
|
|
257,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
34,089
|
|
|
|
17,902
|
|
|
|
79,074
|
|
|
|
91,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
48,214
|
|
|
|
43,497
|
|
|
|
147,862
|
|
|
|
166,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS AND
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REDEMPTION
PREMIUM
|
|
|
-
|
|
|
|
51
|
|
|
|
-
|
|
|
|
4,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$ |
48,214
|
|
|
$ |
43,446
|
|
|
$ |
147,862
|
|
|
$ |
162,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
48,214
|
|
|
$ |
43,497
|
|
|
$ |
147,862
|
|
|
$ |
166,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirment benefits
|
|
|
(3,423 |
) |
|
|
-
|
|
|
|
(10,270 |
) |
|
|
-
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
2,442
|
|
|
|
3,795
|
|
|
|
7,415
|
|
|
|
5,467
|
|
Other
comprehensive income (loss)
|
|
|
(981 |
) |
|
|
3,795
|
|
|
|
(2,855 |
) |
|
|
5,467
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(573 |
) |
|
|
1,369
|
|
|
|
(1,688 |
) |
|
|
1,972
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(408 |
) |
|
|
2,426
|
|
|
|
(1,167 |
) |
|
|
3,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
47,806
|
|
|
$ |
45,923
|
|
|
$ |
146,695
|
|
|
$ |
170,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Ohio
Edison
Company are an integral part of these
|
|
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
727
|
|
|
$ |
712
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,518,000 and
$15,033,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
271,680
|
|
|
|
234,781
|
|
Associated
companies
|
|
|
167,686
|
|
|
|
141,084
|
|
Other
(less
accumulated provisions of $5,548,000 and $1,985,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
20,093
|
|
|
|
13,496
|
|
Notes
receivable from associated companies
|
|
|
626,841
|
|
|
|
458,647
|
|
Prepayments
and other
|
|
|
17,148
|
|
|
|
13,606
|
|
|
|
|
1,104,175
|
|
|
|
862,326
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,722,468
|
|
|
|
2,632,207
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,053,942
|
|
|
|
1,021,918
|
|
|
|
|
1,668,526
|
|
|
|
1,610,289
|
|
Construction
work in progress
|
|
|
42,494
|
|
|
|
42,016
|
|
|
|
|
1,711,020
|
|
|
|
1,652,305
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
365,767
|
|
|
|
1,219,325
|
|
Investment
in
lease obligation bonds
|
|
|
274,077
|
|
|
|
291,393
|
|
Nuclear
plant
decommissioning trusts
|
|
|
128,168
|
|
|
|
118,209
|
|
Other
|
|
|
36,756
|
|
|
|
38,160
|
|
|
|
|
804,768
|
|
|
|
1,667,087
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
717,311
|
|
|
|
741,564
|
|
Pension
assets
|
|
|
106,682
|
|
|
|
68,420
|
|
Property
taxes
|
|
|
60,080
|
|
|
|
60,080
|
|
Unamortized
sale and leaseback costs
|
|
|
46,384
|
|
|
|
50,136
|
|
Other
|
|
|
44,457
|
|
|
|
18,696
|
|
|
|
|
974,914
|
|
|
|
938,896
|
|
|
|
$ |
4,594,877
|
|
|
$ |
5,120,614
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
442,264
|
|
|
$ |
159,852
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
-
|
|
|
|
113,987
|
|
Other
|
|
|
52,609
|
|
|
|
3,097
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
200,104
|
|
|
|
115,252
|
|
Other
|
|
|
17,766
|
|
|
|
13,068
|
|
Accrued
taxes
|
|
|
141,516
|
|
|
|
187,306
|
|
Accrued
interest
|
|
|
17,435
|
|
|
|
24,712
|
|
Other
|
|
|
101,543
|
|
|
|
64,519
|
|
|
|
|
973,237
|
|
|
|
681,793
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares -
|
|
|
|
|
|
|
|
|
60
and 80
shares outstanding, respectively
|
|
|
1,220,173
|
|
|
|
1,708,441
|
|
Accumulated
other comprehensive income
|
|
|
2,041
|
|
|
|
3,208
|
|
Retained
earnings
|
|
|
257,870
|
|
|
|
260,736
|
|
Total
common
stockholder's equity
|
|
|
1,480,084
|
|
|
|
1,972,385
|
|
Long-term
debt
and other long-term obligations
|
|
|
836,430
|
|
|
|
1,118,576
|
|
|
|
|
2,316,514
|
|
|
|
3,090,961
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
676,784
|
|
|
|
674,288
|
|
Accumulated
deferred investment tax credits
|
|
|
17,856
|
|
|
|
20,532
|
|
Asset
retirement obligations
|
|
|
92,157
|
|
|
|
88,223
|
|
Retirement
benefits
|
|
|
159,096
|
|
|
|
167,379
|
|
Deferred
revenues - electric service programs
|
|
|
59,255
|
|
|
|
86,710
|
|
Other
|
|
|
299,978
|
|
|
|
310,728
|
|
|
|
|
1,305,126
|
|
|
|
1,347,860
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
4,594,877
|
|
|
$ |
5,120,614
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Ohio
Edison
Company are an integral part of
|
|
|
|
|
|
these
balance
sheets.
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
147,862
|
|
|
$ |
166,536
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
57,440
|
|
|
|
53,962
|
|
Amortization
of regulatory assets
|
|
|
144,569
|
|
|
|
147,022
|
|
Deferral
of
new regulatory assets
|
|
|
(132,410 |
) |
|
|
(123,285 |
) |
Amortization
of lease costs
|
|
|
28,567
|
|
|
|
28,600
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(29,155 |
) |
|
|
(27,850 |
) |
Accrued
compensation and retirement benefits
|
|
|
(34,572 |
) |
|
|
2,985
|
|
Pension
trust
contribution
|
|
|
(20,261 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(70,098 |
) |
|
|
26,198
|
|
Prepayments
and other current assets
|
|
|
(3,542 |
) |
|
|
(4,172 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
89,550
|
|
|
|
(24,937 |
) |
Accrued
taxes
|
|
|
(37,355 |
) |
|
|
(27,826 |
) |
Accrued
interest
|
|
|
(7,277 |
) |
|
|
12,839
|
|
Electric
service prepayment programs
|
|
|
(27,455 |
) |
|
|
(24,975 |
) |
Other
|
|
|
7,260
|
|
|
|
2,570
|
|
Net
cash
provided from operating activities
|
|
|
113,123
|
|
|
|
207,667
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
|
592,763
|
|
Equity
contributions from parent
|
|
|
11,621
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(500,000 |
) |
|
|
(500,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(63,893 |
) |
Long-term
debt
|
|
|
(1,190 |
) |
|
|
(138,085 |
) |
Short-term
borrowings, net
|
|
|
(64,475 |
) |
|
|
(177,595 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(150,000 |
) |
|
|
(73,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(1,369 |
) |
Net
cash used
for financing activities
|
|
|
(704,044 |
) |
|
|
(361,179 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(109,461 |
) |
|
|
(94,278 |
) |
Sales
of
investment securities held in trusts
|
|
|
31,624
|
|
|
|
32,826
|
|
Purchases
of
investment securities held in trusts
|
|
|
(33,586 |
) |
|
|
(34,209 |
) |
Loan
repayments from associated companies, net
|
|
|
685,364
|
|
|
|
148,199
|
|
Cash
investments
|
|
|
17,316
|
|
|
|
93,900
|
|
Other
|
|
|
(321 |
) |
|
|
6,848
|
|
Net
cash
provided from investing activities
|
|
|
590,936
|
|
|
|
153,286
|
|
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
15
|
|
|
|
(226 |
) |
Cash
and cash
equivalents at beginning of period
|
|
|
712
|
|
|
|
929
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
727
|
|
|
$ |
703
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Ohio
Edison
Company are an integral
|
|
part
of these
statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of Ohio
Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of Ohio Edison Company and its
subsidiaries as of September 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2007 and 2006 and the consolidated statement of
cash
flows for the nine-month periods ended September 30, 2007 and
2006. 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
(United States), the objective of which is the expression of an opinion
regarding the financial statements taken as a whole. Accordingly, we
do not express such an opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006, and
conditional asset retirement obligations as of December 31, 2005 as discussed
in
Note 3, Note 2(G) and Note 11 to the consolidated financial statements)
dated February 27, 2007, we expressed an unqualified opinion on those
consolidated financial statements. In our opinion, the information
set forth in the accompanying consolidated balance sheet information as of
December 31, 2006, is fairly stated in all material respects in relation to
the
consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
OHIO
EDISON
COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
OE
is a wholly owned
electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary,
Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated
electric distribution services. OE also provides generation services to those
customers electing to retain OE as their power supplier. OE’s power supply
requirements are provided by FES – an affiliated company.
Results
of Operations
In
the first nine
months of 2007, earnings on common stock decreased to $148
million from $162 million in the same period of
2006. The decrease in earnings primarily resulted from higher purchased power costs and
lower other income, partially offset by higher electric sales
revenues.
Revenues
Revenues increased by $58
million or 3.2% in the first nine months of 2007 compared with
the same period in 2006, primarily due to a $65 million increase in retail
generation revenues, partially offset by decreases in revenues from distribution
throughput of $16 million.
Higher
retail
generation revenues from residential customers reflected increased sales volume
and the impact of higher average unit prices. Weather conditions in
the first nine months of 2007 compared to the same period in 2006
contributed to the higher KWH sales to residential customers (heating degree
days increased 11.5% and 8.4% and cooling degree days increased by 26.9% and
25.2% in OE’s and Penn’s service territories, respectively). Commercial retail
generation revenues increased primarily due to higher average unit prices,
partially offset by reduced KWH sales. Average prices increased due to the
higher generation prices that were effective in January 2007 under Penn’s
competitive RFP process. Retail generation revenues from the industrial sector
decreased primarily due to an increase in customer shopping in Penn’s service
territory in the first nine months of 2007 as compared to the same period in
2006. The percentage of shopping customers increased to 27.7 percent in the
first nine months of 2007 from 15.8 percent in the first nine months of
2006.
Changes
in retail
generation sales and revenues in the first nine months of 2007 from the
corresponding period of 2006 are summarized in the following
tables:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
7.4
|
%
|
Commercial
|
|
|
(1.4
|
)%
|
Industrial
|
|
|
(16.0
|
)%
|
Net
Decrease in Generation Sales
|
|
|
(3.7
|
)%
|
Retail
Generation Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
80
|
|
Commercial
|
|
|
23
|
|
Industrial
|
|
|
(38
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
65
|
|
A
small increase in
distribution revenues from residential customers was more than offset by
decreases in distribution revenues from commercial and industrial customers.
The
increase from residential customers reflected higher deliveries due to the
favorable weather conditions described above in the first nine months of 2007
as
compared to the same period in 2006, partially offset by lower composite unit
prices. Reduced distribution revenues from commercial customers in the first
nine months of 2007 resulted from lower unit prices, partially offset by
increased KWH deliveries. Distribution revenues from industrial customers
decreased in the first nine months of 2007 as a result of lower unit prices
and
reduced KWH deliveries.
Changes
in
distribution KWH deliveries and revenues in the first nine months of 2007 from
the corresponding period of 2006 are summarized in the following
tables.
Distribution
KWH Deliveries
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
5.8
|
%
|
Commercial
|
|
|
3.3
|
%
|
Industrial
|
|
|
(2.2
|
)%
|
Net
Increase in Distribution Deliveries
|
|
|
2.2
|
%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
Commercial
|
|
|
(5
|
)
|
Industrial
|
|
|
(13
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(16
|
)
|
Expenses
Total
expenses
increased by $57 million in the first nine months of 2007 from the same period
of 2006. The following table presents changes from the prior year by expense
category.
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
65
|
|
Nuclear
operating costs
|
|
|
1
|
|
Other
operating costs
|
|
|
(5
|
)
|
Provision
for
depreciation
|
|
|
3
|
|
Amortization
of regulatory assets
|
|
|
(2
|
)
|
Deferral
of
new regulatory assets
|
|
|
(9
|
)
|
General
taxes
|
|
|
4
|
|
Net
Increase in Expenses
|
|
$
|
57
|
|
Higher
purchased
power costs in the first nine months of 2007 primarily reflected higher unit
prices under Penn’s competitive RFP process and OE’s PSA with FES. The decrease
in other operating costs for the first nine months of 2007 was primarily due
to
lower employee benefit expenses, partially offset by higher transmission
expenses related to MISO operations. Higher depreciation expense in the first
nine months of 2007 reflected capital additions subsequent
to the third quarter of 2006. The increase in the deferral of new regulatory
assets for the first nine months of 2007 was primarily due to increases in
MISO cost deferrals and RCP distribution cost deferrals, partially offset by
lower RCP fuel cost deferrals. General taxes were higher in the first nine
months of 2007 as compared to the same period last year as a
result of higher real and personal property taxes and KWH excise
taxes.
Other
Income
Other
income
decreased $32 million in the first nine months of 2007 as compared with the
same
period of 2006 primarily due to reductions in interest income on
notes receivable resulting from principal payments from associated companies
since the third quarter of 2006. Higher interest expense also contributed to
the
decrease in other income in the first nine months of 2007, with interest
expense associated with OE’s issuance of $600 million of long-term debt in June
2006 being partially offset by debt redemptions since the third
quarter of 2006.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of other legal proceedings applicable to OE.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to OE.
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
510,577
|
|
|
$ |
497,336
|
|
|
$ |
1,366,396
|
|
|
$ |
1,304,525
|
|
Excise
tax
collections
|
|
|
18,514
|
|
|
|
18,587
|
|
|
|
53,009
|
|
|
|
51,579
|
|
Total
revenues
|
|
|
529,091
|
|
|
|
515,923
|
|
|
|
1,419,405
|
|
|
|
1,356,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
12,160
|
|
|
|
12,748
|
|
|
|
39,683
|
|
|
|
39,724
|
|
Purchased
power
|
|
|
216,194
|
|
|
|
229,779
|
|
|
|
575,520
|
|
|
|
531,490
|
|
Other
operating costs
|
|
|
85,114
|
|
|
|
81,510
|
|
|
|
243,140
|
|
|
|
222,841
|
|
Provision
for
depreciation
|
|
|
18,913
|
|
|
|
17,524
|
|
|
|
56,094
|
|
|
|
45,775
|
|
Amortization
of regulatory assets
|
|
|
42,077
|
|
|
|
38,826
|
|
|
|
110,253
|
|
|
|
99,832
|
|
Deferral
of
new regulatory assets
|
|
|
(37,692 |
) |
|
|
(39,060 |
) |
|
|
(114,708 |
) |
|
|
(101,283 |
) |
General
taxes
|
|
|
37,930
|
|
|
|
34,228
|
|
|
|
110,922
|
|
|
|
100,808
|
|
Total
expenses
|
|
|
374,696
|
|
|
|
375,555
|
|
|
|
1,020,904
|
|
|
|
939,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
154,395
|
|
|
|
140,368
|
|
|
|
398,501
|
|
|
|
416,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
13,805
|
|
|
|
24,715
|
|
|
|
47,816
|
|
|
|
76,325
|
|
Miscellaneous
income (expense)
|
|
|
(760 |
) |
|
|
813
|
|
|
|
3,197
|
|
|
|
6,209
|
|
Interest
expense
|
|
|
(34,423 |
) |
|
|
(34,774 |
) |
|
|
(107,430 |
) |
|
|
(104,140 |
) |
Capitalized
interest
|
|
|
309
|
|
|
|
836
|
|
|
|
655
|
|
|
|
2,346
|
|
Total
other
expense
|
|
|
(21,069 |
) |
|
|
(8,410 |
) |
|
|
(55,762 |
) |
|
|
(19,260 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
133,326
|
|
|
|
131,958
|
|
|
|
342,739
|
|
|
|
397,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
54,610
|
|
|
|
48,496
|
|
|
|
131,525
|
|
|
|
150,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
78,716
|
|
|
|
83,462
|
|
|
|
211,214
|
|
|
|
246,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
1,202
|
|
|
|
-
|
|
|
|
3,607
|
|
|
|
-
|
|
Income
tax
expense related to other comprehensive income
|
|
|
356
|
|
|
|
-
|
|
|
|
1,068
|
|
|
|
-
|
|
Other
comprehensive income, net of tax
|
|
|
846
|
|
|
|
-
|
|
|
|
2,539
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
79,562
|
|
|
$ |
83,462
|
|
|
$ |
213,753
|
|
|
$ |
246,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Cleveland
Electric Illuminating Company are an integral
|
|
part
of these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
234
|
|
|
$ |
221
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,057,000 and $6,783,000
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
304,608
|
|
|
|
245,193
|
|
Associated
companies
|
|
|
53,564
|
|
|
|
249,735
|
|
Other
|
|
|
21,331
|
|
|
|
14,240
|
|
Notes
receivable from associated companies
|
|
|
41,054
|
|
|
|
27,191
|
|
Prepayments
and other
|
|
|
1,510
|
|
|
|
2,314
|
|
|
|
|
422,301
|
|
|
|
538,894
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,199,913
|
|
|
|
2,136,766
|
|
Less
-
Accumulated provision for depreciation
|
|
|
844,600
|
|
|
|
819,633
|
|
|
|
|
1,355,313
|
|
|
|
1,317,133
|
|
Construction
work in progress
|
|
|
55,382
|
|
|
|
46,385
|
|
|
|
|
1,410,695
|
|
|
|
1,363,518
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
265,660
|
|
|
|
486,634
|
|
Investment
in
lessor notes
|
|
|
463,433
|
|
|
|
519,611
|
|
Other
|
|
|
10,302
|
|
|
|
13,426
|
|
|
|
|
739,395
|
|
|
|
1,019,671
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521
|
|
|
|
1,688,521
|
|
Regulatory
assets
|
|
|
855,618
|
|
|
|
854,588
|
|
Pension
assets
|
|
|
16,791
|
|
|
|
-
|
|
Property
taxes
|
|
|
65,000
|
|
|
|
65,000
|
|
Other
|
|
|
42,993
|
|
|
|
33,306
|
|
|
|
|
2,668,923
|
|
|
|
2,641,415
|
|
|
|
$ |
5,241,314
|
|
|
$ |
5,563,498
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
266,271
|
|
|
$ |
120,569
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
73,459
|
|
|
|
218,134
|
|
Other
|
|
|
100,000
|
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
237,072
|
|
|
|
365,678
|
|
Other
|
|
|
6,194
|
|
|
|
7,194
|
|
Accrued
taxes
|
|
|
132,941
|
|
|
|
128,829
|
|
Accrued
interest
|
|
|
41,393
|
|
|
|
19,033
|
|
Lease
market
valuation liability
|
|
|
58,750
|
|
|
|
60,200
|
|
Other
|
|
|
44,931
|
|
|
|
52,101
|
|
|
|
|
961,011
|
|
|
|
971,738
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
|
67,930,743
shares outstanding
|
|
|
873,037
|
|
|
|
860,133
|
|
Accumulated
other comprehensive loss
|
|
|
(101,892 |
) |
|
|
(104,431 |
) |
Retained
earnings
|
|
|
620,155
|
|
|
|
713,201
|
|
Total
common
stockholder's equity
|
|
|
1,391,300
|
|
|
|
1,468,903
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,670,898
|
|
|
|
1,805,871
|
|
|
|
|
3,062,198
|
|
|
|
3,274,774
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
461,410
|
|
|
|
470,707
|
|
Accumulated
deferred investment tax credits
|
|
|
18,994
|
|
|
|
20,277
|
|
Lease
market
valuation liability
|
|
|
491,085
|
|
|
|
547,800
|
|
Retirement
benefits
|
|
|
110,620
|
|
|
|
122,862
|
|
Deferred
revenues - electric service programs
|
|
|
34,768
|
|
|
|
51,588
|
|
Other
|
|
|
101,228
|
|
|
|
103,752
|
|
|
|
|
1,218,105
|
|
|
|
1,316,986
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
5,241,314
|
|
|
$ |
5,563,498
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Cleveland
Electric Illuminating Company
|
are
an
integral part of these balance sheets.
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
211,214
|
|
|
$ |
246,927
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
56,094
|
|
|
|
45,775
|
|
Amortization
of regulatory assets
|
|
|
110,253
|
|
|
|
99,832
|
|
Deferral
of
new regulatory assets
|
|
|
(114,708 |
) |
|
|
(101,283 |
) |
Deferred
rents
and lease market valuation liability
|
|
|
(46,327 |
) |
|
|
(55,166 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(40,964 |
) |
|
|
(9,513 |
) |
Accrued
compensation and retirement benefits
|
|
|
2,575
|
|
|
|
2,681
|
|
Pension
trust
contribution
|
|
|
(24,800 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
140,359
|
|
|
|
189
|
|
Prepayments
and other current assets
|
|
|
661
|
|
|
|
(387 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(143,210 |
) |
|
|
29,681
|
|
Accrued
taxes
|
|
|
4,545
|
|
|
|
(14,588 |
) |
Accrued
interest
|
|
|
22,360
|
|
|
|
12,427
|
|
Electric
service prepayment programs
|
|
|
(16,819 |
) |
|
|
(13,623 |
) |
Other
|
|
|
2,996
|
|
|
|
(5,270 |
) |
Net
cash
provided from operating activities
|
|
|
164,229
|
|
|
|
237,682
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
247,424
|
|
|
|
-
|
|
Equity
contributions from parent
|
|
|
12,756
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(223,555 |
) |
|
|
(118,295 |
) |
Short-term
borrowings, net
|
|
|
(59,328 |
) |
|
|
(58,819 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(304,000 |
) |
|
|
(118,000 |
) |
Net
cash used
for financing activities
|
|
|
(326,703 |
) |
|
|
(295,114 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(100,583 |
) |
|
|
(89,771 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(13,863 |
) |
|
|
108,034
|
|
Collection
of
principal on long-term notes receivable
|
|
|
220,974
|
|
|
|
-
|
|
Redemption
of
lessor notes
|
|
|
56,177
|
|
|
|
44,553
|
|
Other
|
|
|
(218 |
) |
|
|
(5,368 |
) |
Net
cash
provided from investing activities
|
|
|
162,487
|
|
|
|
57,448
|
|
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
13
|
|
|
|
16
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
221
|
|
|
|
207
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
234
|
|
|
$ |
223
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Cleveland
Electric Illuminating Company
|
are
an
integral part of these statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of The
Cleveland Electric Illuminating Company:
We
have reviewed the
accompanying consolidated balance sheet of The Cleveland Electric Illuminating
Company and its subsidiaries as of September 30, 2007 and the related
consolidated statements of income and comprehensive income for each of the
three-month and nine-month periods ended September 30, 2007 and 2006 and the
consolidated statement of cash flows for the nine-month periods ended September
30, 2007 and 2006. These interim financial statements are the
responsibility of the Company’s management.
We
conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting Oversight Board,
the objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an
opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006, and conditional
asset retirement obligations as of December 31, 2005, as discussed in Note
3,
Note 2(G) and Note 11 to those consolidated financial statements) dated February
27, 2007, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31, 2006,
is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
CEI
is a wholly
owned, electric utility subsidiary of FirstEnergy. CEI conducts business in
northeastern 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.
Results
of Operations
Net
income in the
first nine months of 2007 decreased to $211 million from $247 million
in the same period of 2006. The decrease resulted primarily from higher
purchased power costs and other operating costs, partially offset by higher
revenues.
Revenues
Revenues
increased
by $63 million or 5% in the first nine months of 2007 compared to the same
period of 2006 primarily due to higher retail generation and wholesale
revenues. Retail generation revenues increased by $38 million due to
increased KWH sales and higher composite unit prices for all customer
classes. More weather-related usage in the first nine months of 2007
compared to the same period of 2006 primarily contributed to the increased
KWH
sales in the residential and commercial sectors (cooling degree days increased
19% and heating degree days increased 15% from the same period in
2006). Increased KWH sales in the industrial sector reflected a
slight decrease in customer shopping.
Wholesale
generation
revenues increased by $17 million in the first nine months of 2007 compared
to
the corresponding period of 2006. The increase was primarily due to
higher unit prices for PSA sales. CEI sells power from its leasehold interests
in the Bruce Mansfield plant to FGCO.
Increases
in retail
generation sales and revenues in the first nine months of 2007 compared to
the
corresponding period of 2006 are summarized in the following
tables:
Retail
Generation KWH Sales
|
|
Increase
|
|
|
|
|
|
|
Residential
|
|
|
4.3
|
%
|
Commercial
|
|
|
6.0
|
%
|
Industrial
|
|
|
1.2
|
%
|
Increase in Retail Generation Sales
|
|
|
3.2
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
9
|
|
Commercial
|
|
|
15
|
|
Industrial
|
|
|
14
|
|
Increase
in Generation Revenues
|
|
$
|
38
|
|
Revenues
from
distribution throughput increased by $5 million in the first nine months of
2007
compared to the same period of 2006 primarily due to increased KWH deliveries
to
all customer classes, partially offset by lower composite unit prices for the
industrial sector. Increased KWH deliveries were primarily a result of the
weather in 2007 as described above.
Changes
in
distribution KWH deliveries and revenues in the first nine months of 2007
compared to the corresponding period of 2006 are summarized in the following
tables.
Distribution
KWH Deliveries
|
|
Increase
|
|
|
|
|
|
|
Residential
|
|
|
4.5
|
%
|
Commercial
|
|
|
3.7
|
%
|
Industrial
|
|
|
0.7
|
%
|
Increase
in Distribution Deliveries
|
|
|
2.5
|
%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
6
|
|
Commercial
|
|
|
6
|
|
Industrial
|
|
|
(7
|
)
|
Net
Increase in Distribution Revenues
|
|
$
|
5
|
|
Expenses
Total
expenses
increased by $82 million in the first nine months of 2007 compared to the same
period of 2006. The following table presents the change from the prior year
by
expense category:
Expenses -
Changes
|
|
Increase
(Decrease)
|
|
|
|
(in
millions)
|
|
Purchased
power costs
|
|
$
|
44
|
|
Other
operating costs
|
|
|
20
|
|
Provision
for
depreciation
|
|
|
10
|
|
Amortization
of regulatory assets
|
|
|
11
|
|
Deferral
of
new regulatory assets
|
|
|
(13
|
)
|
General
taxes
|
|
|
10
|
|
Net
Increase in Expenses
|
|
$
|
82
|
|
Higher
purchased
power costs in the first nine months of 2007 compared to the corresponding
period of 2006 primarily reflect higher unit prices associated with the PSA
with
FES and an increase in purchased power to meet CEI’s higher retail generation
sales requirements. Higher other operating costs in the first nine months of
2007 compared to the same period of 2006 reflect increases in MISO transmission
related expenses due to increased transmission volumes. The increased
depreciation in the first nine months of 2007 is primarily due to property
additions since the third quarter of 2006 and the absence of a credit adjustment
in the second quarter of 2006 that related to prior periods ($6.5 million
pre-tax, $4 million net of tax).
The
increased
amortization of regulatory assets in the first nine months of 2007 compared
to
the corresponding period of 2006 was due to increased transition cost
amortization reflecting the higher KWH sales discussed above. The
increase in the deferral of new regulatory assets in the first nine months
of
2007 reflect a higher level of MISO costs that were deferred in excess of
transmission revenues recognized and increased distribution cost deferrals
under
CEI’s RCP. General taxes were higher in the first nine months of 2007
compared to the same period of 2006 primarily as a result of higher real and
personal property taxes.
Other
Expense
Other
expense
increased by $37 million in the first nine months of 2007 compared to the
corresponding period of 2006 primarily due to lower investment income on
associated company notes receivable in 2007. CEI received principal repayments
from FGCO and NGC subsequent to the third quarter of 2006 on notes receivable
related to the generation asset transfers.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to CEI.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to CEI.
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
261,736
|
|
|
$ |
254,979
|
|
|
$ |
728,429
|
|
|
$ |
684,992
|
|
Excise
tax
collections
|
|
|
7,926
|
|
|
|
7,858
|
|
|
|
22,026
|
|
|
|
21,420
|
|
Total
revenues
|
|
|
269,662
|
|
|
|
262,837
|
|
|
|
750,455
|
|
|
|
706,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
8,784
|
|
|
|
9,399
|
|
|
|
29,392
|
|
|
|
28,799
|
|
Purchased
power
|
|
|
112,502
|
|
|
|
112,389
|
|
|
|
304,947
|
|
|
|
268,468
|
|
Nuclear
operating costs
|
|
|
17,705
|
|
|
|
19,252
|
|
|
|
53,272
|
|
|
|
54,450
|
|
Other
operating costs
|
|
|
47,212
|
|
|
|
44,253
|
|
|
|
136,297
|
|
|
|
124,396
|
|
Provision
for
depreciation
|
|
|
9,231
|
|
|
|
8,386
|
|
|
|
27,475
|
|
|
|
24,723
|
|
Amortization
of regulatory assets
|
|
|
30,460
|
|
|
|
27,336
|
|
|
|
79,284
|
|
|
|
73,909
|
|
Deferral
of
new regulatory assets
|
|
|
(15,645 |
) |
|
|
(15,340 |
) |
|
|
(47,373 |
) |
|
|
(43,186 |
) |
General
taxes
|
|
|
11,912
|
|
|
|
13,406
|
|
|
|
38,646
|
|
|
|
38,590
|
|
Total
expenses
|
|
|
222,161
|
|
|
|
219,081
|
|
|
|
621,940
|
|
|
|
570,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
47,501
|
|
|
|
43,756
|
|
|
|
128,515
|
|
|
|
136,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
6,721
|
|
|
|
9,724
|
|
|
|
21,255
|
|
|
|
28,449
|
|
Miscellaneous
expense
|
|
|
(2,153 |
) |
|
|
(1,933 |
) |
|
|
(7,309 |
) |
|
|
(6,543 |
) |
Interest
expense
|
|
|
(8,786 |
) |
|
|
(4,940 |
) |
|
|
(25,205 |
) |
|
|
(13,614 |
) |
Capitalized
interest
|
|
|
220
|
|
|
|
277
|
|
|
|
467
|
|
|
|
835
|
|
Total
other
income (expense)
|
|
|
(3,998 |
) |
|
|
3,128
|
|
|
|
(10,792 |
) |
|
|
9,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
43,503
|
|
|
|
46,884
|
|
|
|
117,723
|
|
|
|
145,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
18,435
|
|
|
|
17,706
|
|
|
|
44,924
|
|
|
|
54,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
25,068
|
|
|
|
29,178
|
|
|
|
72,799
|
|
|
|
90,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
|
1,161
|
|
|
|
-
|
|
|
|
3,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$ |
25,068
|
|
|
$ |
28,017
|
|
|
$ |
72,799
|
|
|
$ |
86,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
25,068
|
|
|
$ |
29,178
|
|
|
$ |
72,799
|
|
|
$ |
90,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
574
|
|
|
|
-
|
|
|
|
1,720
|
|
|
|
-
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
1,946
|
|
|
|
1,379
|
|
|
|
1,656
|
|
|
|
432
|
|
Other
comprehensive income
|
|
|
2,520
|
|
|
|
1,379
|
|
|
|
3,376
|
|
|
|
432
|
|
Income
tax
expense related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
902
|
|
|
|
498
|
|
|
|
1,193
|
|
|
|
156
|
|
Other
comprehensive income, net of tax
|
|
|
1,618
|
|
|
|
881
|
|
|
|
2,183
|
|
|
|
276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
26,686
|
|
|
$ |
30,059
|
|
|
$ |
74,982
|
|
|
$ |
90,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Toledo
Edison Company are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
20
|
|
|
$ |
22
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
|
|
|
335
|
|
|
|
772
|
|
Associated
companies
|
|
|
31,180
|
|
|
|
13,940
|
|
Other
(less
accumulated provisions of $518,000 and $430,000,
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
3,600
|
|
|
|
3,831
|
|
Notes
receivable from associated companies
|
|
|
79,188
|
|
|
|
100,545
|
|
Prepayments
and other
|
|
|
627
|
|
|
|
851
|
|
|
|
|
114,950
|
|
|
|
119,961
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
913,191
|
|
|
|
894,888
|
|
Less
-
Accumulated provision for depreciation
|
|
|
406,949
|
|
|
|
394,225
|
|
|
|
|
506,242
|
|
|
|
500,663
|
|
Construction
work in progress
|
|
|
26,665
|
|
|
|
16,479
|
|
|
|
|
532,907
|
|
|
|
517,142
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Investment
in
lessor notes
|
|
|
154,674
|
|
|
|
169,493
|
|
Long-term
notes receivable from associated companies
|
|
|
92,700
|
|
|
|
128,858
|
|
Nuclear
plant
decommissioning trusts
|
|
|
64,598
|
|
|
|
61,094
|
|
Other
|
|
|
1,778
|
|
|
|
1,871
|
|
|
|
|
313,750
|
|
|
|
361,316
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576
|
|
|
|
500,576
|
|
Regulatory
assets
|
|
|
214,896
|
|
|
|
247,595
|
|
Pension
assets
|
|
|
5,962
|
|
|
|
-
|
|
Property
taxes
|
|
|
22,010
|
|
|
|
22,010
|
|
Other
|
|
|
29,427
|
|
|
|
30,042
|
|
|
|
|
772,871
|
|
|
|
800,223
|
|
|
|
$ |
1,734,478
|
|
|
$ |
1,798,642
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
55,134
|
|
|
$ |
30,000
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
103,250
|
|
|
|
84,884
|
|
Other
|
|
|
4,043
|
|
|
|
4,021
|
|
Notes
payable
to associated companies
|
|
|
190,758
|
|
|
|
153,567
|
|
Accrued
taxes
|
|
|
52,865
|
|
|
|
47,318
|
|
Lease
market
valuation liability
|
|
|
23,655
|
|
|
|
24,600
|
|
Other
|
|
|
32,906
|
|
|
|
37,551
|
|
|
|
|
462,611
|
|
|
|
381,941
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
$5 par value, authorized 60,000,000 shares -
|
|
|
|
|
|
29,402,054
shares outstanding
|
|
|
147,010
|
|
|
|
147,010
|
|
Other
paid-in
capital
|
|
|
172,949
|
|
|
|
166,786
|
|
Accumulated
other comprehensive loss
|
|
|
(34,621 |
) |
|
|
(36,804 |
) |
Retained
earnings
|
|
|
157,139
|
|
|
|
204,423
|
|
Total
common
stockholder's equity
|
|
|
442,477
|
|
|
|
481,415
|
|
Long-term
debt
|
|
|
303,220
|
|
|
|
358,281
|
|
|
|
|
745,697
|
|
|
|
839,696
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
141,813
|
|
|
|
161,024
|
|
Accumulated
deferred investment tax credits
|
|
|
10,389
|
|
|
|
11,014
|
|
Lease
market
valuation liability
|
|
|
192,774
|
|
|
|
218,800
|
|
Retirement
benefits
|
|
|
77,275
|
|
|
|
77,843
|
|
Asset
retirement obligations
|
|
|
27,899
|
|
|
|
26,543
|
|
Deferred
revenues - electric service programs
|
|
|
15,896
|
|
|
|
23,546
|
|
Other
|
|
|
60,124
|
|
|
|
58,235
|
|
|
|
|
526,170
|
|
|
|
577,005
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
1,734,478
|
|
|
$ |
1,798,642
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to The
Toledo
Edison Company are |
|
an
integral part of these balance sheets.
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
72,799
|
|
|
$ |
90,556
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
27,475
|
|
|
|
24,723
|
|
Amortization
of regulatory assets
|
|
|
79,284
|
|
|
|
73,909
|
|
Deferral
of
new regulatory assets
|
|
|
(47,373 |
) |
|
|
(43,186 |
) |
Deferred
rents
and lease market valuation liability
|
|
|
(23,551 |
) |
|
|
(27,114 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(32,530 |
) |
|
|
(28,603 |
) |
Accrued
compensation and retirement benefits
|
|
|
3,493
|
|
|
|
2,766
|
|
Pension
trust
contribution
|
|
|
(7,659 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(13,368 |
) |
|
|
(25,069 |
) |
Prepayments
and other current assets
|
|
|
224
|
|
|
|
(75 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
9,515
|
|
|
|
1,102
|
|
Accrued
taxes
|
|
|
7,463
|
|
|
|
3,458
|
|
Accrued
interest
|
|
|
3,444
|
|
|
|
(709 |
) |
Electric
service prepayment programs
|
|
|
(7,650 |
) |
|
|
(6,744 |
) |
Other
|
|
|
1,953
|
|
|
|
1,716
|
|
Net
cash
provided from operating activities
|
|
|
73,519
|
|
|
|
66,730
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
37,191
|
|
|
|
113,886
|
|
Equity
contribution from parent
|
|
|
6,125
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
|
(30,000 |
) |
Long-term
debt
|
|
|
(30,014 |
) |
|
|
(53,650 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(120,000 |
) |
|
|
(50,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(3,597 |
) |
Net
cash used
for financing activities
|
|
|
(106,698 |
) |
|
|
(23,361 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(41,573 |
) |
|
|
(45,661 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
21,438
|
|
|
|
(61,549 |
) |
Collection
of
principal on long-term notes receivable
|
|
|
36,077
|
|
|
|
53,766
|
|
Redemption
of
lessor notes
|
|
|
14,819
|
|
|
|
9,275
|
|
Sales
of
investment securities held in trusts
|
|
|
39,260
|
|
|
|
50,255
|
|
Purchases
of
investment securities held in trusts
|
|
|
(39,557 |
) |
|
|
(50,433 |
) |
Other
|
|
|
2,713
|
|
|
|
983
|
|
Net
cash
provided from (used for) investing activities
|
|
|
33,177
|
|
|
|
(43,364 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(2 |
) |
|
|
5
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
22
|
|
|
|
15
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
20
|
|
|
$ |
20
|
|
|
|
|
|
|
|
|
|
|
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
subsidiary as of September 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2007 and 2006 and the consolidated statement of
cash
flows for the nine-month periods ended September 30, 2007 and
2006. These interim financial statements are the responsibility of
the Company’s management.
We
conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting Oversight Board,
the objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an
opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006 as discussed
in
Note 3 to those consolidated financial statements) dated February 27, 2007,
we
expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31, 2006,
is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
THE
TOLEDO
EDISON COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
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.
Results
of Operations
Earnings
on common
stock in the first nine months of 2007 decreased to $73 million from $87 million
in the same period of 2006. The decrease resulted primarily from higher
purchased power and other operating costs and increased interest expense,
partially offset by higher electric sales revenues.
Revenues
Revenues
increased
$44 million or 6.2% in the first nine months of 2007 compared to the same period
of 2006 primarily due to increases in retail generation revenues ($24 million),
wholesale generation revenues ($11 million) and distribution revenues ($6
million). Retail generation revenues increased in the first nine months of
2007
due to higher average prices and increased sales volume across all customer
classes compared to the same period of 2006. Average prices increased primarily
due to higher composite unit prices for retail generation shopping customers
returning to TE. The increase in sales volume also reflects increased
weather-related usage in the first nine months of 2007 (heating and cooling
degree days increased 15.2% and 7.2%, respectively, from the same period of
2006).
The
increase in
wholesale revenues resulted primarily from increased KWH sales to associated
companies and higher unit prices. TE sells KWH from its leasehold interests
in
Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO,
respectively.
Increases
in retail
electric generation KWH sales and revenues in the first nine months of 2007
from
the same period of 2006 are summarized in the following tables.
Retail
Generation KWH Sales
|
|
Increase
|
|
|
|
|
|
|
Residential
|
|
|
8.0
|
%
|
Commercial
|
|
|
3.1
|
%
|
Industrial
|
|
|
1.0
|
%
|
Increase
in Retail Generation Sales
|
|
|
3.1
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
8
|
|
Commercial
|
|
|
4
|
|
Industrial
|
|
|
12
|
|
Increase
in Retail Generation Revenues
|
|
$
|
24
|
|
Revenues
from
distribution throughput increased by $6 million in the first nine months of
2007
compared to the same period in 2006 due to higher KWH deliveries to all customer
sectors, partially offset by lower average unit prices for industrial customers.
The higher KWH deliveries to residential and commercial customers in the first
nine months of 2007 reflected the weather impacts described above.
Changes
in
distribution KWH deliveries and revenues in the first nine months of 2007 from
the same period of 2006 are summarized in the following tables.
Distribution
KWH Deliveries
|
|
Increase
|
|
|
|
|
|
|
Residential
|
|
|
5.5
|
%
|
Commercial
|
|
|
2.6
|
%
|
Industrial
|
|
|
1.1
|
%
|
Increase
in Distribution Deliveries
|
|
|
2.5
|
%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
7
|
|
Commercial
|
|
|
3
|
|
Industrial
|
|
|
(4
|
)
|
Net
Increase in Distribution Revenues
|
|
$
|
6
|
|
Expenses
Total
expenses
increased $52 million in the first nine months of 2007 from the same period
of
2006. The following table presents changes from the prior year by expense
category:
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
$
|
|
|
|
|
|
|
)
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
|
|
Amortization
of regulatory assets
|
|
|
|
|
Deferral
of
new regulatory assets
|
|
|
|
|
|
|
|
|
|
Higher
purchased
power costs in the first nine months of 2007 compared to the same period of
2006
reflected higher unit prices associated with the PSA with FES and an increase
in
KWH purchases to meet the higher retail generation sales requirements. Other
operating costs were higher due to an $11 million increase in MISO network
transmission expenses in the first nine months of 2007. Depreciation expense
was
higher due to an increase in depreciable property, reflecting plant additions
since the third quarter of 2006. Higher amortization of regulatory assets was
due to increased amortization of transition cost deferrals ($3 million) and
MISO
transmission deferrals ($2 million). The change in the deferral of new
regulatory assets was primarily due to increased deferrals for MISO transmission
expenses ($7 million) and RCP distribution costs ($4 million),
partially offset by lower RCP fuel cost deferrals
($5 million).
Other
Expense
Other
expense
increased $20 million in the first nine months of 2007 compared to the same
period of 2006 primarily due to lower investment income and higher interest
expense. The decrease in investment income resulted primarily from the principal
repayments since the third quarter of 2006 on notes receivable from associated
companies. The higher interest expense is principally associated with new
long-term debt issued in November 2006.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to TE.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to TE.
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
1,018,049
|
|
|
$ |
895,389
|
|
|
$ |
2,457,146
|
|
|
$ |
2,059,499
|
|
Excise
tax
collections
|
|
|
15,168
|
|
|
|
15,679
|
|
|
|
39,849
|
|
|
|
38,845
|
|
Total
revenues
|
|
|
1,033,217
|
|
|
|
911,068
|
|
|
|
2,496,995
|
|
|
|
2,098,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
654,418
|
|
|
|
546,125
|
|
|
|
1,505,420
|
|
|
|
1,204,880
|
|
Other
operating costs
|
|
|
87,010
|
|
|
|
90,578
|
|
|
|
236,225
|
|
|
|
245,711
|
|
Provision
for
depreciation
|
|
|
22,032
|
|
|
|
21,099
|
|
|
|
63,867
|
|
|
|
62,553
|
|
Amortization
of regulatory assets
|
|
|
107,837
|
|
|
|
78,052
|
|
|
|
296,955
|
|
|
|
210,323
|
|
General
taxes
|
|
|
18,631
|
|
|
|
19,187
|
|
|
|
51,183
|
|
|
|
49,691
|
|
Total
expenses
|
|
|
889,928
|
|
|
|
755,041
|
|
|
|
2,153,650
|
|
|
|
1,773,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
143,289
|
|
|
|
156,027
|
|
|
|
343,345
|
|
|
|
325,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
2,967
|
|
|
|
2,091
|
|
|
|
9,266
|
|
|
|
8,162
|
|
Interest
expense
|
|
|
(24,666 |
) |
|
|
(21,437 |
) |
|
|
(71,576 |
) |
|
|
(62,420 |
) |
Capitalized
interest
|
|
|
483
|
|
|
|
1,004
|
|
|
|
1,559
|
|
|
|
2,933
|
|
Total
other
expense
|
|
|
(21,216 |
) |
|
|
(18,342 |
) |
|
|
(60,751 |
) |
|
|
(51,325 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
122,073
|
|
|
|
137,685
|
|
|
|
282,594
|
|
|
|
273,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
46,275
|
|
|
|
58,316
|
|
|
|
118,637
|
|
|
|
120,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
75,798
|
|
|
|
79,369
|
|
|
|
163,957
|
|
|
|
153,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
|
917
|
|
|
|
-
|
|
|
|
1,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$ |
75,798
|
|
|
$ |
78,452
|
|
|
$ |
163,957
|
|
|
$ |
152,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
75,798
|
|
|
$ |
79,369
|
|
|
$ |
163,957
|
|
|
$ |
153,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(2,114 |
) |
|
|
-
|
|
|
|
(6,344 |
) |
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
69
|
|
|
|
100
|
|
|
|
235
|
|
|
|
207
|
|
Other
comprehensive income (loss)
|
|
|
(2,045 |
) |
|
|
100
|
|
|
|
(6,109 |
) |
|
|
207
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(994 |
) |
|
|
41
|
|
|
|
(2,973 |
) |
|
|
84
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(1,051 |
) |
|
|
59
|
|
|
|
(3,136 |
) |
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
74,747
|
|
|
$ |
79,428
|
|
|
$ |
160,821
|
|
|
$ |
153,478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
77
|
|
|
$ |
41
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,821,000 and $3,524,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
396,700
|
|
|
|
254,046
|
|
Associated
companies
|
|
|
369
|
|
|
|
11,574
|
|
Other
(less
accumulated provisions of $718,000 and $204,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
62,235
|
|
|
|
40,023
|
|
Notes
receivable - associated companies
|
|
|
22,734
|
|
|
|
24,456
|
|
Materials
and
supplies, at average cost
|
|
|
1,915
|
|
|
|
2,043
|
|
Prepaid
taxes
|
|
|
41,670
|
|
|
|
13,333
|
|
Other
|
|
|
14,080
|
|
|
|
18,076
|
|
|
|
|
539,780
|
|
|
|
363,592
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
4,122,325
|
|
|
|
4,029,070
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,490,846
|
|
|
|
1,473,159
|
|
|
|
|
2,631,479
|
|
|
|
2,555,911
|
|
Construction
work in progress
|
|
|
84,199
|
|
|
|
78,728
|
|
|
|
|
2,715,678
|
|
|
|
2,634,639
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
fuel
disposal trust
|
|
|
172,278
|
|
|
|
171,045
|
|
Nuclear
plant
decommissioning trusts
|
|
|
177,217
|
|
|
|
164,108
|
|
Other
|
|
|
2,075
|
|
|
|
2,047
|
|
|
|
|
351,570
|
|
|
|
337,200
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
1,757,516
|
|
|
|
2,152,332
|
|
Goodwill
|
|
|
1,826,190
|
|
|
|
1,962,361
|
|
Pension
assets
|
|
|
43,183
|
|
|
|
14,660
|
|
Other
|
|
|
15,124
|
|
|
|
17,781
|
|
|
|
|
3,642,013
|
|
|
|
4,147,134
|
|
|
|
$ |
7,249,041
|
|
|
$ |
7,482,565
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
26,680
|
|
|
$ |
32,683
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
155,395
|
|
|
|
186,540
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
22,399
|
|
|
|
80,426
|
|
Other
|
|
|
211,788
|
|
|
|
160,359
|
|
Accrued
taxes
|
|
|
25,793
|
|
|
|
1,451
|
|
Accrued
interest
|
|
|
27,520
|
|
|
|
14,458
|
|
Cash
collateral from suppliers
|
|
|
68
|
|
|
|
32,311
|
|
Other
|
|
|
85,746
|
|
|
|
96,139
|
|
|
|
|
555,389
|
|
|
|
604,367
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
$10 par value, authorized 16,000,000 shares-
|
|
|
|
|
|
|
|
|
14,421,637
and
15,009,335 shares outstanding, respectively
|
|
|
144,216
|
|
|
|
150,093
|
|
Other
paid-in
capital
|
|
|
2,657,775
|
|
|
|
2,908,279
|
|
Accumulated
other comprehensive loss
|
|
|
(47,390 |
) |
|
|
(44,254 |
) |
Retained
earnings
|
|
|
266,342
|
|
|
|
145,480
|
|
Total
common
stockholder's equity
|
|
|
3,020,943
|
|
|
|
3,159,598
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,568,296
|
|
|
|
1,320,341
|
|
|
|
|
4,589,239
|
|
|
|
4,479,939
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
872,305
|
|
|
|
1,182,108
|
|
Accumulated
deferred income taxes
|
|
|
762,782
|
|
|
|
803,944
|
|
Nuclear
fuel
disposal costs
|
|
|
190,524
|
|
|
|
183,533
|
|
Asset
retirement obligations
|
|
|
88,334
|
|
|
|
84,446
|
|
Other
|
|
|
190,468
|
|
|
|
144,228
|
|
|
|
|
2,104,413
|
|
|
|
2,398,259
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
7,249,041
|
|
|
$ |
7,482,565
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Jersey
Central Power & Light Company are an
|
|
|
|
|
|
integral
part
of these balance sheets.
|
|
|
|
|
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
163,957
|
|
|
$ |
153,355
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
63,867
|
|
|
|
62,553
|
|
Amortization
of regulatory assets
|
|
|
296,955
|
|
|
|
210,323
|
|
Deferred
purchased power and other costs
|
|
|
(157,201 |
) |
|
|
(213,621 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(23,786 |
) |
|
|
25,217
|
|
Accrued
compensation and retirement benefits
|
|
|
(17,543 |
) |
|
|
(4,196 |
) |
Cash
collateral returned to suppliers
|
|
|
(32,243 |
) |
|
|
(108,926 |
) |
Pension
trust
contribution
|
|
|
(17,800 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(153,660 |
) |
|
|
(50,337 |
) |
Materials
and
supplies
|
|
|
127
|
|
|
|
86
|
|
Prepaid
taxes
|
|
|
(28,337 |
) |
|
|
(29,923 |
) |
Other
current
assets
|
|
|
2,079
|
|
|
|
(2,118 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(6,598 |
) |
|
|
(8,131 |
) |
Accrued
taxes
|
|
|
29,318
|
|
|
|
(16,992 |
) |
Accrued
interest
|
|
|
13,062
|
|
|
|
16,296
|
|
Tax
collections payable
|
|
|
(12,478 |
) |
|
|
(10,316 |
) |
Other
|
|
|
(7,440 |
) |
|
|
(4,814 |
) |
Net
cash
provided from operating activities
|
|
|
112,279
|
|
|
|
18,456
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
549,999
|
|
|
|
382,400
|
|
Equity
contribution from parent
|
|
|
4,636
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(324,256 |
) |
|
|
(162,157 |
) |
Short-term
borrowings, net
|
|
|
(31,145 |
) |
|
|
(44,162 |
) |
Common
stock
|
|
|
(125,000 |
) |
|
|
-
|
|
Preferred
stock
|
|
|
-
|
|
|
|
(13,461 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(43,000 |
) |
|
|
(45,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(354 |
) |
Net
cash
provided from financing activities
|
|
|
31,234
|
|
|
|
117,266
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(144,668 |
) |
|
|
(123,540 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
1,722
|
|
|
|
(8,638 |
) |
Sales
of
investment securities held in trusts
|
|
|
169,649
|
|
|
|
169,676
|
|
Purchases
of
investment securities held in trusts
|
|
|
(171,820 |
) |
|
|
(171,847 |
) |
Other
|
|
|
1,640
|
|
|
|
(1,417 |
) |
Net
cash used
for investing activities
|
|
|
(143,477 |
) |
|
|
(135,766 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
36
|
|
|
|
(44 |
) |
Cash
and cash
equivalents at beginning of period
|
|
|
41
|
|
|
|
102
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
77
|
|
|
$ |
58
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Jersey
Central Power & Light Company
|
|
are
an
integral part of these statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of Jersey
Central Power & Light Company:
We
have reviewed the
accompanying consolidated balance sheet of Jersey Central Power & Light
Company and its subsidiaries as of September 30, 2007 and the related
consolidated statements of income and comprehensive income for each of the
three-month and nine-month periods ended September 30, 2007 and 2006 and the
consolidated statement of cash flows for the nine-month periods ended September
30, 2007 and 2006. These interim financial statements are the
responsibility of the Company’s management.
We
conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting Oversight Board,
the objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an
opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006, as discussed
in
Note 3 to those consolidated financial statements) dated February 27, 2007,
we
expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31, 2006,
is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
JERSEY
CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF
RESULTS OF OPERATIONS
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.
Results
of Operations
Earnings
on common
stock increased to $164 million in the first nine months of 2007 compared to
$152 million for the same period in 2006. The increase was primarily due to
higher revenues and lower other operating costs, partially offset by higher
purchased power costs and increased amortization of regulatory
assets.
Revenues
Revenues
increased
$399 million or 19% in the first nine months of 2007 compared with the same
period of 2006. Retail and wholesale generation revenues increased by $250
million and $49 million, respectively, in the first nine months of
2007.
Retail
generation
revenues from all customer classes increased in the first nine months of 2007
compared to 2006 due to higher unit prices resulting from the BGS auctions
effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales.
Sales volume increased as a result of weather conditions in the first nine
months of 2007 (heating degree days were 15.8% higher than the first nine months
of 2006 and cooling degree days decreased slightly). Industrial generation
KWH
sales declined in the first nine months of 2007 from the same period in 2006
due
to an increase in customer shopping.
Wholesale
generation
revenues increased $49 million in the first nine months of 2007 due to higher
market prices, partially offset by a 3.0% decrease in sales volume compared
with
the first nine months of 2006.
Changes
in retail
generation KWH sales and revenues by customer class in the first nine months
of
2007 compared to the same period of 2006 are summarized in the following
table:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
2.3
|
%
|
Commercial
|
|
|
1.6
|
%
|
Industrial
|
|
|
(7.0
|
)%
|
Net
Increase in Generation Sales
|
|
|
1.6
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
145
|
|
Commercial
|
|
|
100
|
|
Industrial
|
|
|
5
|
|
Increase
in Generation Revenues
|
|
$
|
250
|
|
Distribution
revenues increased in the first nine months of 2007 compared to the same period
of 2006 due to higher composite unit prices and increased KWH deliveries,
reflecting the weather impacts described above. The higher unit prices resulted
from an NUGC rate increase effective in December 2006.
Changes
in
distribution KWH deliveries and revenues in the first nine months of 2007
compared to the corresponding period of 2006 are summarized in the following
tables.
Distribution
KWH Deliveries
|
|
Increase
|
|
|
|
|
|
|
|
Residential
|
|
|
|
2.3
|
%
|
Commercial
|
|
|
|
3.3
|
%
|
Industrial
|
|
|
|
1.1
|
%
|
Increase
in Distribution Deliveries
|
|
|
|
2.6
|
%
|
Distribution
Revenues
|
|
|
Increase
|
|
|
|
|
(In
millions)
|
Residential
|
|
|
$
|
35
|
|
Commercial
|
|
|
|
38
|
|
Industrial
|
|
|
|
6
|
|
Increase
in Distribution Revenues
|
|
|
$
|
79
|
|
The
higher revenues
for the first nine months of 2007 also included $20 million of increased
revenues resulting from the August 2006 securitization of deferred costs
associated with JCP&L’s BGS supply.
Expenses
Total
expenses
increased by $380 million in the first nine months of 2007 as compared to the
same period of 2006. The following table presents changes from the prior year
by
expense category:
Expenses -
Changes
|
|
|
Increase
(Decrease)
|
|
|
|
|
(In
millions)
|
Purchased
power costs
|
|
|
$
|
300
|
|
Other
operating costs
|
|
|
|
(9
|
)
|
Provision
for
depreciation
|
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
|
87
|
|
General
Taxes
|
|
|
|
1
|
|
Net
increase in expenses
|
|
|
$
|
380
|
|
The
increase in
purchased power costs primarily reflected higher unit prices resulting from
the
June 2006 and June 2007 BGS auctions. Other operating costs decreased $9 million
in the first nine months of 2007 primarily due to lower employee benefit costs.
Amortization of regulatory assets increased $87 million in the first nine months
of 2007 due to higher cost recovery associated with the December 2006 NUGC
rate
increase.
Other
Expenses
Other
expenses
increased $9 million in the first nine months of 2007 from the same period
in
2006 primarily due to interest expense associated with JCP&L’s $550 million
issuance of Senior Notes in May 2007.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of other legal proceedings applicable to JCP&L.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
JCP&L.
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
391,083
|
|
|
$ |
337,750
|
|
|
$ |
1,087,460
|
|
|
$ |
898,320
|
|
Gross
receipts
tax collections
|
|
|
19,524
|
|
|
|
18,431
|
|
|
|
55,146
|
|
|
|
51,293
|
|
Total
revenues
|
|
|
410,607
|
|
|
|
356,181
|
|
|
|
1,142,606
|
|
|
|
949,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
209,842
|
|
|
|
184,508
|
|
|
|
584,249
|
|
|
|
487,465
|
|
Other
operating costs
|
|
|
106,104
|
|
|
|
108,740
|
|
|
|
315,227
|
|
|
|
229,394
|
|
Provision
for
depreciation
|
|
|
11,154
|
|
|
|
10,197
|
|
|
|
31,969
|
|
|
|
31,390
|
|
Amortization
of regulatory assets
|
|
|
36,853
|
|
|
|
33,560
|
|
|
|
101,965
|
|
|
|
89,277
|
|
Deferral
of
new regulatory assets
|
|
|
(19,151 |
) |
|
|
(44,213 |
) |
|
|
(93,772 |
) |
|
|
(89,794 |
) |
General
taxes
|
|
|
21,986
|
|
|
|
21,362
|
|
|
|
63,208
|
|
|
|
60,578
|
|
Total
expenses
|
|
|
366,788
|
|
|
|
314,154
|
|
|
|
1,002,846
|
|
|
|
808,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
43,819
|
|
|
|
42,027
|
|
|
|
139,760
|
|
|
|
141,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
7,239
|
|
|
|
8,053
|
|
|
|
22,740
|
|
|
|
25,767
|
|
Miscellaneous
income
|
|
|
1,366
|
|
|
|
1,477
|
|
|
|
3,973
|
|
|
|
5,881
|
|
Interest
expense
|
|
|
(13,291 |
) |
|
|
(12,291 |
) |
|
|
(38,471 |
) |
|
|
(35,546 |
) |
Capitalized
interest
|
|
|
292
|
|
|
|
355
|
|
|
|
940
|
|
|
|
966
|
|
Total
other
expense
|
|
|
(4,394 |
) |
|
|
(2,406 |
) |
|
|
(10,818 |
) |
|
|
(2,932 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
39,425
|
|
|
|
39,621
|
|
|
|
128,942
|
|
|
|
138,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
14,737
|
|
|
|
14,631
|
|
|
|
53,145
|
|
|
|
55,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
24,688
|
|
|
|
24,990
|
|
|
|
75,797
|
|
|
|
82,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(1,452 |
) |
|
|
-
|
|
|
|
(4,357 |
) |
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
83
|
|
|
|
83
|
|
|
|
251
|
|
|
|
251
|
|
Other
comprehensive income (loss)
|
|
|
(1,369 |
) |
|
|
83
|
|
|
|
(4,106 |
) |
|
|
251
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(693 |
) |
|
|
34
|
|
|
|
(2,078 |
) |
|
|
104
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(676 |
) |
|
|
49
|
|
|
|
(2,028 |
) |
|
|
147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
24,012
|
|
|
$ |
25,039
|
|
|
$ |
73,769
|
|
|
$ |
83,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
126
|
|
|
$ |
130
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,740,000 and $4,153,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
154,622
|
|
|
|
127,084
|
|
Associated
companies
|
|
|
23,728
|
|
|
|
3,604
|
|
Other
|
|
|
18,043
|
|
|
|
8,107
|
|
Notes
receivable from associated companies
|
|
|
34,620
|
|
|
|
31,109
|
|
Prepaid
taxes
|
|
|
5,755
|
|
|
|
13,533
|
|
Other
|
|
|
1,976
|
|
|
|
1,424
|
|
|
|
|
238,870
|
|
|
|
184,991
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
1,976,453
|
|
|
|
1,920,563
|
|
Less
-
Accumulated provision for depreciation
|
|
|
755,018
|
|
|
|
739,719
|
|
|
|
|
1,221,435
|
|
|
|
1,180,844
|
|
Construction
work in progress
|
|
|
21,124
|
|
|
|
18,466
|
|
|
|
|
1,242,559
|
|
|
|
1,199,310
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
290,349
|
|
|
|
269,777
|
|
Other
|
|
|
1,360
|
|
|
|
1,362
|
|
|
|
|
291,709
|
|
|
|
271,139
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
426,368
|
|
|
|
496,129
|
|
Regulatory
assets
|
|
|
458,566
|
|
|
|
409,095
|
|
Pension
assets
|
|
|
26,239
|
|
|
|
7,261
|
|
Other
|
|
|
38,653
|
|
|
|
46,354
|
|
|
|
|
949,826
|
|
|
|
958,839
|
|
|
|
$ |
2,722,964
|
|
|
$ |
2,614,279
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
-
|
|
|
$ |
50,000
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
254,826
|
|
|
|
141,501
|
|
Other
|
|
|
80,000
|
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
24,807
|
|
|
|
100,232
|
|
Other
|
|
|
55,186
|
|
|
|
59,077
|
|
Accrued
taxes
|
|
|
9,033
|
|
|
|
11,300
|
|
Accrued
interest
|
|
|
7,343
|
|
|
|
7,496
|
|
Other
|
|
|
26,960
|
|
|
|
22,825
|
|
|
|
|
458,155
|
|
|
|
392,431
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
|
859,500
shares
outstanding
|
|
|
1,207,634
|
|
|
|
1,276,075
|
|
Accumulated
other comprehensive loss
|
|
|
(28,544 |
) |
|
|
(26,516 |
) |
Accumulated
deficit
|
|
|
(158,873 |
) |
|
|
(234,620 |
) |
Total
common
stockholder's equity
|
|
|
1,020,217
|
|
|
|
1,014,939
|
|
Long-term
debt
and other long-term obligations
|
|
|
542,100
|
|
|
|
542,009
|
|
|
|
|
1,562,317
|
|
|
|
1,556,948
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
393,169
|
|
|
|
387,456
|
|
Accumulated
deferred investment tax credits
|
|
|
8,623
|
|
|
|
9,244
|
|
Nuclear
fuel
disposal costs
|
|
|
43,038
|
|
|
|
41,459
|
|
Asset
retirement obligations
|
|
|
158,302
|
|
|
|
151,107
|
|
Retirement
benefits
|
|
|
15,830
|
|
|
|
19,522
|
|
Other
|
|
|
83,530
|
|
|
|
56,112
|
|
|
|
|
702,492
|
|
|
|
664,900
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
2,722,964
|
|
|
$ |
2,614,279
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral part
|
|
of
these
balance sheets.
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
75,797
|
|
|
$ |
82,981
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
31,969
|
|
|
|
31,390
|
|
Amortization
of regulatory assets
|
|
|
101,965
|
|
|
|
89,277
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(53,276 |
) |
|
|
(53,406 |
) |
Deferral
of
new regulatory assets
|
|
|
(93,772 |
) |
|
|
(89,794 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
20,514
|
|
|
|
27,895
|
|
Accrued
compensation and retirement benefits
|
|
|
(14,404 |
) |
|
|
(6,007 |
) |
Cash
collateral
|
|
|
1,650
|
|
|
|
(21,500 |
) |
Pension
trust
contribution
|
|
|
(11,012 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(57,599 |
) |
|
|
27,680
|
|
Prepayments
and other current assets
|
|
|
7,227
|
|
|
|
(8,247 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(79,316 |
) |
|
|
(1,553 |
) |
Accrued
taxes
|
|
|
1,787
|
|
|
|
(10,451 |
) |
Accrued
interest
|
|
|
(153 |
) |
|
|
(308 |
) |
Other
|
|
|
5,436
|
|
|
|
(1,777 |
) |
Net
cash
provided from (used for) operating activities
|
|
|
(63,187 |
) |
|
|
66,180
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
193,324
|
|
|
|
116,624
|
|
Equity
contribution from parent
|
|
|
1,237
|
|
|
|
- |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(50,000 |
) |
|
|
(100,000 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
-
|
|
|
|
(5,000 |
) |
Net
cash
provided from financing activities
|
|
|
144,561
|
|
|
|
11,624
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(74,812 |
) |
|
|
(65,332 |
) |
Sales
of
investment securities held in trusts
|
|
|
153,943
|
|
|
|
146,841
|
|
Purchases
of
investment securities held in trusts
|
|
|
(156,623 |
) |
|
|
(153,953 |
) |
Loans
to
associated companies, net
|
|
|
(3,511 |
) |
|
|
(4,853 |
) |
Other
|
|
|
(375 |
) |
|
|
(494 |
) |
Net
cash used
for investing activities
|
|
|
(81,378 |
) |
|
|
(77,791 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(4 |
) |
|
|
13
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
130
|
|
|
|
120
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
126
|
|
|
$ |
133
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral
|
|
part
of these
statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Metropolitan Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of Metropolitan Edison Company and
its
subsidiaries as of September 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2007 and 2006 and the consolidated statement of
cash
flows for the nine-month periods ended September 30, 2007 and
2006. These interim financial statements are the responsibility of
the Company’s management.
We
conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting Oversight Board,
the objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an
opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006, and conditional
asset retirement obligations as of December 31, 2005, as discussed in Note
3,
Note 2(G) and Note 9 to those consolidated financial statements) dated February
27, 2007, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31, 2006,
is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
METROPOLITAN
EDISON COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF
RESULTS OF OPERATIONS
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 for the
first nine months of 2007 decreased to $76 million from $83 million in the
first
nine months of 2006. The decrease was primarily due to higher purchased power
costs and other operating costs, partially offset by higher
revenues.
Revenues
Revenues
increased
by $193 million, or 20.3%, in the first nine months of 2007 compared with the
first nine months of 2006. This increase was primarily due to higher
distribution revenues and wholesale generation revenues.
In
the first nine
months of 2007, retail generation revenues increased by $19 million primarily
due to higher KWH sales in all customer sectors. The increase in retail
generation revenues in the residential and commercial sectors primarily resulted
from higher weather-related usage in the first nine months of 2007 as compared
to the same period of 2006 (heating degree days increased by 17.1% and cooling
degree days increased by 7.1%).
Increases
in retail
generation sales and revenues in the first nine months of 2007 compared to
the
same period of 2006 are summarized in the following tables:
Retail
Generation KWH Sales
|
|
Increase
|
|
|
|
|
|
|
Residential
|
|
|
5.6
|
%
|
Commercial
|
|
|
4.0
|
%
|
Industrial
|
|
|
0.6
|
%
|
Increase
in Retail Generation Sales
|
|
|
3.6
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
11
|
|
Commercial
|
|
|
8
|
|
Industrial
|
|
|
-
|
|
Increase
in Retail Generation Revenues
|
|
$
|
19
|
|
Wholesale
revenues
increased by $107 million in the first nine months of 2007 compared with the
same period of 2006 due to Met-Ed selling additional available power into the
PJM market beginning in January 2007.
Revenues
from
distribution throughput increased by $55 million in the first nine months of
2007 compared to the same period in 2006. The increase was due to higher KWH
deliveries, reflecting the effect of the weather discussed above, and an
increase in composite unit prices resulting from the January 2007 PPUC
authorization to increase transmission rates, partially offset by a decrease
in
distribution rates.
Increases
in
distribution KWH deliveries and revenues in the first nine months of 2007
compared to the same period of 2006 are summarized in the following
tables:
Distribution
KWH Deliveries
|
|
Increase
|
|
|
|
|
|
|
Residential
|
|
|
5.6
|
%
|
Commercial
|
|
|
4.0
|
%
|
Industrial
|
|
|
0.2
|
%
|
Increase
in Distribution Deliveries
|
|
|
3.5
|
%
|
|
|
|
|
Distribution
Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
38
|
|
Commercial
|
|
|
5
|
|
Industrial
|
|
|
12
|
|
Increase
in Distribution Revenues
|
|
$
|
55
|
|
PJM
transmission
revenues increased by $18 million in the first nine months of 2007 as a result
of higher transmission volumes and additional PJM auction revenue rights,
compared to the prior year period. Met-Ed defers the difference between revenue
from its transmission rider and transmission costs incurred, resulting in no
material effect to current period earnings.
Expenses
Total
expenses
increased by $195 million in the first nine months of 2007 compared to the
same
period of 2006. The following table presents changes from the prior year by
expense category:
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
97
|
|
Other
operating costs
|
|
|
86
|
|
Amortization
of regulatory assets
|
|
|
13
|
|
Deferral
of
new regulatory assets
|
|
|
(4
|
)
|
General
taxes
|
|
|
3
|
|
Net
increase in expenses
|
|
$
|
195
|
|
Purchased
power
costs increased in the first nine months of 2007 by $97 million due to
higher volumes purchased to source higher generation sales, combined with higher
composite unit costs. Other operating costs increased in the first nine months
of 2007 primarily due to higher congestion costs and other transmission expenses
associated with the increased transmission volumes discussed above ($83 million)
and increased expenses ($3 million) related to Met-Ed’s customer assistance
programs.
Amortization
of
regulatory assets increased in the first nine months of 2007 primarily due
to
the recovery (through Met-Ed’s transmission rider discussed above) of certain
transmission costs deferred in 2006 and the amortization of the Saxton nuclear
research facility’s decommissioning costs as authorized by the PPUC in January
2007. The deferral of new regulatory assets increased in the first nine months
of 2007 primarily due to the deferral of previously expensed Saxton
decommissioning costs of $15 million (see Legal Proceedings), partially offset
by lower PJM transmission deferrals.
In
the first nine
months of 2007, general taxes increased primarily due to higher gross receipts
taxes.
On
October 1,
2007, Met-Ed sold 100% of its interest in York Haven Power Company for
$5 million. The sale is subject to regulatory accounting and will not have
a material impact on Met-Ed’s earnings in the fourth quarter of
2007.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to Met-Ed.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
Met-Ed.
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
336,798
|
|
|
$ |
287,633
|
|
|
$ |
991,769
|
|
|
$ |
813,860
|
|
Gross
receipts
tax collections
|
|
|
16,637
|
|
|
|
15,787
|
|
|
|
48,989
|
|
|
|
46,311
|
|
Total
revenues
|
|
|
353,435
|
|
|
|
303,420
|
|
|
|
1,040,758
|
|
|
|
860,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
203,247
|
|
|
|
165,921
|
|
|
|
588,583
|
|
|
|
474,437
|
|
Other
operating costs
|
|
|
51,571
|
|
|
|
65,165
|
|
|
|
169,299
|
|
|
|
151,640
|
|
Provision
for
depreciation
|
|
|
12,566
|
|
|
|
11,828
|
|
|
|
36,678
|
|
|
|
36,269
|
|
Amortization
of regulatory assets, net
|
|
|
20,861
|
|
|
|
3,825
|
|
|
|
32,648
|
|
|
|
19,804
|
|
General
taxes
|
|
|
19,433
|
|
|
|
18,593
|
|
|
|
57,634
|
|
|
|
55,440
|
|
Total
expenses
|
|
|
307,678
|
|
|
|
265,332
|
|
|
|
884,842
|
|
|
|
737,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
45,757
|
|
|
|
38,088
|
|
|
|
155,916
|
|
|
|
122,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
1,483
|
|
|
|
2,182
|
|
|
|
5,035
|
|
|
|
6,179
|
|
Interest
expense
|
|
|
(14,017 |
) |
|
|
(11,840 |
) |
|
|
(38,426 |
) |
|
|
(33,975 |
) |
Capitalized
interest
|
|
|
194
|
|
|
|
363
|
|
|
|
737
|
|
|
|
1,132
|
|
Total
other
expense
|
|
|
(12,340 |
) |
|
|
(9,295 |
) |
|
|
(32,654 |
) |
|
|
(26,664 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
33,417
|
|
|
|
28,793
|
|
|
|
123,262
|
|
|
|
95,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
10,387
|
|
|
|
10,733
|
|
|
|
49,025
|
|
|
|
39,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
23,030
|
|
|
|
18,060
|
|
|
|
74,237
|
|
|
|
56,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(2,825 |
) |
|
|
-
|
|
|
|
(8,475 |
) |
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
16
|
|
|
|
17
|
|
|
|
49
|
|
|
|
49
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
10
|
|
|
|
14
|
|
|
|
(6 |
) |
|
|
(4 |
) |
Other
comprehensive income (loss)
|
|
|
(2,799 |
) |
|
|
31
|
|
|
|
(8,432 |
) |
|
|
45
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(1,294 |
) |
|
|
13
|
|
|
|
(3,894 |
) |
|
|
20
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(1,505 |
) |
|
|
18
|
|
|
|
(4,538 |
) |
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
21,525
|
|
|
$ |
18,078
|
|
|
$ |
69,699
|
|
|
$ |
56,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Pennsylvania
Electric Company are an integral
|
|
|
|
|
|
part
of these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
38
|
|
|
$ |
44
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,094,000 and $3,814,000
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
138,007
|
|
|
|
126,639
|
|
Associated
companies
|
|
|
21,872
|
|
|
|
49,728
|
|
Other
|
|
|
19,047
|
|
|
|
16,367
|
|
Notes
receivable from associated companies
|
|
|
17,170
|
|
|
|
19,548
|
|
Prepaid
taxes
|
|
|
7,268
|
|
|
|
3,016
|
|
Other
|
|
|
1,724
|
|
|
|
1,220
|
|
|
|
|
205,126
|
|
|
|
216,562
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,188,553
|
|
|
|
2,141,324
|
|
Less
-
Accumulated provision for depreciation
|
|
|
824,141
|
|
|
|
809,028
|
|
|
|
|
1,364,412
|
|
|
|
1,332,296
|
|
Construction
work in progress
|
|
|
26,835
|
|
|
|
22,124
|
|
|
|
|
1,391,247
|
|
|
|
1,354,420
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
137,896
|
|
|
|
125,216
|
|
Non-utility
generation trusts
|
|
|
147,745
|
|
|
|
99,814
|
|
Other
|
|
|
531
|
|
|
|
531
|
|
|
|
|
286,172
|
|
|
|
225,561
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
777,904
|
|
|
|
860,716
|
|
Pension
assets
|
|
|
34,484
|
|
|
|
11,474
|
|
Other
|
|
|
34,371
|
|
|
|
36,059
|
|
|
|
|
846,759
|
|
|
|
908,249
|
|
|
|
$ |
2,729,304
|
|
|
$ |
2,704,792
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
$ |
187,313
|
|
|
$ |
199,231
|
|
Other
|
|
|
65,000
|
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
107,666
|
|
|
|
92,020
|
|
Other
|
|
|
46,283
|
|
|
|
47,629
|
|
Accrued
taxes
|
|
|
3,091
|
|
|
|
11,670
|
|
Accrued
interest
|
|
|
13,832
|
|
|
|
7,224
|
|
Other
|
|
|
24,481
|
|
|
|
21,178
|
|
|
|
|
447,666
|
|
|
|
378,952
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
$20 par value, authorized 5,400,000 shares-
|
|
|
|
|
|
|
|
|
4,427,577
and
5,290,596 shares outstanding, respectively
|
|
|
88,552
|
|
|
|
105,812
|
|
Other
paid-in
capital
|
|
|
925,229
|
|
|
|
1,189,434
|
|
Accumulated
other comprehensive loss
|
|
|
(11,731 |
) |
|
|
(7,193 |
) |
Retained
earnings
|
|
|
39,195
|
|
|
|
90,005
|
|
Total
common
stockholder's equity
|
|
|
1,041,245
|
|
|
|
1,378,058
|
|
Long-term
debt
and other long-term obligations
|
|
|
777,020
|
|
|
|
477,304
|
|
|
|
|
1,818,265
|
|
|
|
1,855,362
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
77,441
|
|
|
|
96,151
|
|
Asset
retirement obligations
|
|
|
80,589
|
|
|
|
76,924
|
|
Accumulated
deferred income taxes
|
|
|
183,598
|
|
|
|
193,662
|
|
Retirement
benefits
|
|
|
51,289
|
|
|
|
50,328
|
|
Other
|
|
|
70,456
|
|
|
|
53,413
|
|
|
|
|
463,373
|
|
|
|
470,478
|
|
COMMITMENTS
AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
|
|
$ |
2,729,304
|
|
|
$ |
2,704,792
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Electric Company are an
|
|
integral
part
of these balance sheets.
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
74,237
|
|
|
$ |
56,666
|
|
Adjustments
to
reconcile net income to net cash from operating activities
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
36,678
|
|
|
|
36,269
|
|
Amortization
of regulatory assets
|
|
|
43,601
|
|
|
|
40,854
|
|
Deferral
of
new regulatory assets
|
|
|
(10,953 |
) |
|
|
(21,050 |
) |
Deferred
costs
recoverable as regulatory assets
|
|
|
(54,228 |
) |
|
|
(56,272 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
8,065
|
|
|
|
14,518
|
|
Accrued
compensation and retirement benefits
|
|
|
(16,032 |
) |
|
|
2,807
|
|
Cash
collateral
|
|
|
50
|
|
|
|
-
|
|
Pension
trust
contribution
|
|
|
(13,436 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
13,809
|
|
|
|
22,719
|
|
Prepayments
and other current assets
|
|
|
(4,757 |
) |
|
|
(2,977 |
) |
Increase
(decrease) in operating liabilities
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
14,299
|
|
|
|
(15,555 |
) |
Accrued
taxes
|
|
|
(6,191 |
) |
|
|
(9,841 |
) |
Accrued
interest
|
|
|
6,608
|
|
|
|
5,468
|
|
Other
|
|
|
2,653
|
|
|
|
(2,188 |
) |
Net
cash
provided from operating activities
|
|
|
94,403
|
|
|
|
71,418
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
|
297,149
|
|
|
|
-
|
|
Short-term
borrowings, net
|
|
|
53,082
|
|
|
|
21,278
|
|
Equity
contribution from parent
|
|
|
1,261
|
|
|
|
-
|
|
Redemptions
and Repayments
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
(200,000 |
) |
|
|
-
|
|
Dividend
Payments
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
(125,000 |
) |
|
|
(5,000 |
) |
Net
cash
provided from financing activities
|
|
|
26,492
|
|
|
|
16,278
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(70,076 |
) |
|
|
(81,228 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
2,378
|
|
|
|
(2,976 |
) |
Sales
of
investment securities held in trust
|
|
|
94,292
|
|
|
|
83,601
|
|
Purchases
of
investment securities held in trust
|
|
|
(144,167 |
) |
|
|
(83,601 |
) |
Other,
net
|
|
|
(3,328 |
) |
|
|
(3,480 |
) |
Net
cash used
for investing activities
|
|
|
(120,901 |
) |
|
|
(87,684 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(6 |
) |
|
|
12
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
44
|
|
|
|
35
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
38
|
|
|
$ |
47
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Electric Company are an
|
|
integral
part
of these statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Pennsylvania Electric Company:
We
have reviewed the
accompanying consolidated balance sheet of Pennsylvania Electric Company and
its
subsidiaries as of September 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and nine-month
periods ended September 30, 2007 and 2006 and the consolidated statement of
cash
flows for the nine-month periods ended September 30, 2007 and
2006. These interim financial statements are the responsibility of
the Company’s management.
We
conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting Oversight Board,
the objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an
opinion.
Based
on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States
of
America.
We
previously
audited in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2006, 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 defined benefit pension
and other postretirement benefit plans as of December 31, 2006, and conditional
asset retirement obligations as of December 31, 2005, as discussed in Note
3,
Note 2(G) and Note 9 to those consolidated financial statements) dated February
27, 2007, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31, 2006,
is
fairly stated in all material respects in relation to the consolidated balance
sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
October
31,
2007
PENNSYLVANIA
ELECTRIC COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF
RESULTS OF OPERATIONS
Penelec
is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts business
in
northern 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
In
the first nine
months of 2007, net income increased to $74 million, compared to $57 million
in
the first nine months of 2006. The increase in net income was primarily due
to
higher revenues, partially offset by increased purchased power costs and other
operating costs.
Revenues
Revenues
increased
by $181 million, or 21.0%, in the first nine months of 2007 compared to the
same
period last year. The increase was primarily due to higher distribution revenues
and wholesale generation revenues.
Retail
generation
revenues increased $15 million for the first nine months of 2007 primarily
due
to higher KWH sales to all customer classes. The increase in retail generation
revenues in the residential and commercial sectors was primarily impacted by
weather in the first nine months of 2007 (heating degree days increased 11.0%
and cooling degree days increased 14.1% as compared to the same time period
of
2006).
Increases
in retail
generation sales and revenues in first nine months of 2007 compared to the
corresponding period of 2006 are summarized in the following
tables:
Retail
Generation KWH Sales
|
|
Increase
|
|
|
|
|
|
Residential
|
|
|
3.6
|
%
|
Commercial
|
|
|
3.6
|
%
|
Industrial
|
|
|
0.1
|
%
|
Increase
in Retail Generation Sales
|
|
|
2.5
|
%
|
|
|
|
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
6
|
|
Commercial
|
|
|
8
|
|
Industrial
|
|
|
1
|
|
Increase
in Retail Generation Revenues
|
|
$
|
15
|
|
Wholesale
revenues
increased $123 million in the first nine months of 2007, compared with the
same
period of 2006 due to Penelec selling additional available power into the PJM
market beginning in January 2007.
Revenues
from
distribution throughput increased $37 million in the first nine months of 2007
due to higher KWH deliveries to residential and commercial customers reflecting
the effect of the weather discussed above and an increase in composite unit
prices for residential and industrial customers resulting from a January 2007
PPUC authorization to increase transmission rates, partially offset by a
decrease in distribution rates.
Changes
in
distribution KWH deliveries and revenues in the first nine months of 2007
compared to the same period in 2006 are summarized in the following
tables:
|
|
Increase
|
|
Distribution
KWH Deliveries
|
|
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
3.6
|
%
|
Commercial
|
|
|
3.6
|
%
|
Industrial
|
|
|
(1.3
|
)%
|
Net
Increase in Distribution Deliveries
|
|
|
1.9
|
%
|
|
|
Increase
|
|
Distribution Revenues
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
37
|
|
Commercial
|
|
|
(4
|
)
|
Industrial
|
|
|
4
|
|
Net
Increase in Distribution Revenues
|
|
$
|
37
|
|
PJM
transmission
revenues increased by $6 million in the first nine months of 2007 compared
to
the same period in 2006 due to higher transmission volumes and additional PJM
auction revenue rights in 2007. Penelec defers the difference between revenue
from its transmission rider and transmission costs incurred, with no material
effect to current period earnings.
Expenses
Total
expenses
increased by $147 million in the first nine months of 2007 compared with the
same period in 2006. The following table presents changes from the prior year
by
expense category:
|
|
|
Expenses
- Changes
|
|
Increase
|
|
|
(In
millions)
|
Purchased
power costs
|
|
$
|
114
|
Other
operating costs
|
|
|
18
|
Amortization
of regulatory assets, net
|
|
|
13
|
General
taxes
|
|
|
2
|
Increase
in Expenses
|
|
$
|
147
|
Purchased
power
costs increased by $114 million, or 24.1% in the first nine months of 2007,
compared to the same period of 2006. The increase was due primarily to higher
volumes purchased to source higher retail and wholesale generation sales
combined with higher composite unit costs. Other operating costs increased
by
$18 million in the first nine months of 2007 principally due to higher
congestion costs and other transmission expenses associated with the increased
transmission volumes discussed above.
Net
amortization of
regulatory assets increased in the first nine months of 2007 primarily due
to
the recovery (through Penelec’s transmission rider discussed above) of certain
transmission costs deferred in 2006 and lower transmission cost deferrals in
2007, partially offset by the deferral of new regulatory assets for previously
expensed decommissioning costs of $12 million associated with the Saxton nuclear
research facility as authorized by the PPUC in January 2007 (see Legal
Proceedings).
General
taxes
increased $2 million in the first nine months of 2007 as compared to 2006,
primarily due to higher gross receipts taxes.
Legal
Proceedings
See
the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to Penelec.
New
Accounting Standards and Interpretations
See
the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
Penelec.
COMBINED
MANAGEMENT’S DISCUSSION
AND
ANALYSIS
OF REGISTRANT SUBSIDIARIES
The
following is a
combined presentation of certain disclosures referenced in Management’s
Narrative Analysis of Results of Operations of FES and the Companies. This
information should be read in conjunction with (i) FES’ and the Companies’
respective Consolidated Financial Statements and Management’s Narrative Analysis
of Results of Operations; (ii) the Notes to Consolidated Financial Statements
as
they relate to FES and the Companies; and (iii) the Companies’ respective 2006
Annual Reports on Form 10-K.
Regulatory
Matters (Applicable to each of the
Companies)
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 $227 million as of September 30, 2007 (JCP&L -
$93 million, Met-Ed - $43 million and Penelec - $91 million).
Regulatory assets not earning a current return will be recovered by 2014 for
JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses
regulatory assets by company:
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
717
|
|
$
|
741
|
|
$
|
(24
|
)
|
CEI
|
|
|
856
|
|
|
855
|
|
|
1
|
|
TE
|
|
|
215
|
|
|
248
|
|
|
(33
|
)
|
JCP&L
|
|
|
1,758
|
|
|
2,152
|
|
|
(394
|
)
|
Met-Ed
|
|
|
459
|
|
|
409
|
|
|
50
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec
had
net regulatory liabilities of approximately $77 million
and
$96 million as of September 30, 2007 and December 31,
2006,
respectively. These net regulatory liabilities are included in
Other
Non-current Liabilities on the Consolidated Balance
Sheets.
|
Ohio
(Applicable
to
OE, CEI and TE)
The
Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005
seeking approval of the RCP, a supplement to the RSP. On November 4, 2005,
the
Ohio Companies filed a supplemental stipulation with the PUCO, which constituted
an additional component of the RCP filed on September 9, 2005. 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. 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 2007 through 2010:
Amortization
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
(In
millions)
|
|
2007
|
|
$
|
176
|
|
$
|
108
|
|
$
|
92
|
|
$
|
376
|
|
2008
|
|
|
209
|
|
|
126
|
|
|
113
|
|
|
448
|
|
2009
|
|
|
-
|
|
|
217
|
|
|
-
|
|
|
217
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Several
parties subsequently filed appeals to the Supreme Court of Ohio in connection
with certain portions of the RCP approved by the PUCO. In its order, the PUCO
authorized the Ohio Companies to recover certain increased fuel costs through
a
fuel rider and to defer certain other increased fuel costs, all such costs
to be
incurred from January 1, 2006 through December 31, 2008, including interest
on
the deferred balances. The order also provided for recovery of the deferred
costs over a 25-year period through distribution rates, which was expected
to
begin on January 1, 2009 for OE and TE, and approximately May 2009 for
CEI. Through September 30, 2007, the deferred fuel costs, including
interest, were $89 million, $61 million and $26 million for OE, CEI and TE,
respectively.
On
August 29, 2007,
the Supreme Court of Ohio concluded that the PUCO violated certain provisions
of
the Ohio Revised Code by permitting the Ohio Companies “to collect deferred
increased fuel costs through future distribution rate cases, or to alternatively
use excess fuel-cost recovery to reduce deferred distribution-related expenses”
because fuel costs are a component of generation service, not distribution
service, and because the Court concluded the PUCO did not address whether the
deferral of fuel costs was anticompetitive. The Court remanded the
matter to the PUCO for further consideration consistent with the Court’s Opinion
on this issue and affirmed the PUCO’s Order in all other respects. On
September 7, 2007, the Ohio Companies filed a Motion for Reconsideration
with the Court. On September 10, 2007 the Ohio Companies filed an
Application with the PUCO that requests the implementation of two
generation-related fuel cost riders to collect the increased fuel costs that
were previously authorized to be deferred. The Ohio Companies requested the
riders become effective in October 2007 and end in December 2008, subject to
reconciliation which is expected to continue through the first quarter of 2009.
This matter is currently pending before the PUCO. Although unable to predict
the
ultimate outcome of this matter, the Ohio Companies intend to continue deferring
the fuel costs pursuant to the RCP, pending the Court’s disposition of the
Motion for Reconsideration and the PUCO’s action with respect to the Ohio
Companies’ Application.
On
August 31, 2005,
the PUCO approved a rider recovery mechanism through which the Ohio Companies
may recover all MISO transmission and ancillary service related costs incurred
during each year ending June 30. Pursuant to the PUCO’s order, the Ohio
Companies, on May 1, 2007, filed revised riders, which became effective on
July
1, 2007. The revised riders represent an increase over the amounts
collected through the 2006 riders of approximately $64 million
annually. If it is subsequently determined by the PUCO that
adjustments to the rider as filed are necessary, such adjustments, with carrying
costs, will be incorporated into the 2008 transmission rider
filing.
On
May 8, 2007, the
Ohio Companies filed with the PUCO a notice of intent to file for an increase
in
electric distribution rates. The Ohio Companies filed the application and rate
request with the PUCO on June 7, 2007. The requested increase is expected to
be
more than offset by the elimination or reduction of transition charges at the
time the rates go into effect and would result in lowering the overall
non-generation portion of the bill for most Ohio customers. The
distribution rate increases reflect capital expenditures since the Ohio
Companies’ last distribution rate proceedings, increases in operating and
maintenance expenses and recovery of regulatory assets created by deferrals
that
were approved in prior cases. On August 6, 2007, the Ohio Companies updated
their filing supporting a distribution rate increase of $332 million to the
PUCO to establish the test period data that will be used as the basis for
setting rates in that proceeding. The PUCO Staff is expected to issue its report
in the case in the fourth quarter of 2007 with evidentiary hearings to follow
in
early 2008. The PUCO order is expected to be issued in the second quarter of
2008. The new rates would become effective January 1, 2009 for OE and TE,
and approximately May 2009 for CEI.
On
July 10, 2007,
the Ohio Companies filed an application with the PUCO requesting approval of
a
comprehensive supply plan for providing generation service to customers who
do
not purchase electricity from an alternative supplier, beginning January 1,
2009. The proposed competitive bidding process would average the results of
multiple bidding sessions conducted at different times during the year. The
final price per kilowatt-hour would reflect an average of the prices resulting
from all bids. In their filing, the Ohio Companies offered two alternatives
for
structuring the bids, either by customer class or a “slice-of-system” approach.
The proposal provides the PUCO with an option to phase in generation price
increases for residential tariff groups who would experience a change in their
average total price of 15 percent or more. The PUCO held a technical conference
on August 16, 2007 regarding the filing. Comments by intervenors in the case
were filed on September 5, 2007. The PUCO Staff filed comments on
September 21, 2007. Parties filed reply comments on October 12,
2007. The Ohio Companies requested that the PUCO issue an order by November
1, 2007, to provide sufficient time to conduct the bidding process.
On
September 25,
2007, the Ohio Governor’s proposed energy plan was officially introduced into
the Ohio Senate. The bill proposes to revise state energy policy to address
electric generation pricing after 2008, establish advanced energy portfolio
standards and energy efficiency standards, and create GHG emissions reporting
and carbon control planning requirements. The bill also proposes to move to
a
“hybrid” system for determining rates for PLR service in which electric
utilities would provide regulated generation service unless they satisfy a
statutory burden to demonstrate the existence of a competitive market for retail
electricity. The Senate Energy & Public Utilities Committee has been
conducting hearings on the bill and receiving testimony from interested parties,
including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer
groups, utility executives and others. Several proposed amendments to the bill
have been submitted, including those from Ohio’s investor-owned electric
utilities. A substitute version of the bill, which incorporated certain of
the
proposed amendments, was introduced into the Senate Energy & Public
Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, such
legislation may have on its operations or those of the Ohio
Companies.
Pennsylvania
(Applicable to FES, Met-Ed, Penelec and Penn)
Met-Ed
and Penelec
have been purchasing a portion of their PLR requirements from FES through a
partial requirements wholesale power sales agreement and various amendments.
Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's
exposure to high wholesale power prices by providing power at a fixed price
for
their uncommitted PLR capacity and energy requirements during the term of these
agreements with FES.
On
September 26, 2006, Met-Ed and Penelec successfully conducted a competitive
RFP for a portion of their PLR obligation for the period December 1, 2006
through December 31, 2008. FES was one of the successful bidders in that
RFP process and on September 26, 2006 entered into a supplier master agreement
to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market
prices that were substantially higher than the fixed price in the partial
requirements agreements.
Based
on the outcome
of the 2006 comprehensive transition rate filing, as described below, Met-Ed,
Penelec and FES agreed to restate the partial requirements power sales agreement
effective January 1, 2007. The restated agreement incorporates the same fixed
price for residual capacity and energy supplied by FES as in the prior
arrangements between the parties, and automatically extends for successive
one
year terms unless any party gives 60 days’ notice prior to the end of the year.
The restated agreement also allows Met-Ed and Penelec to sell the output of
NUG
energy to the market and requires FES to provide energy at fixed prices to
replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec
to
satisfy their PLR obligations. The parties also have separately terminated
the
supplier master agreements in connection with the restatement of the partial
requirements agreement. Accordingly, the energy that would have been supplied
under the supplier master agreement will now be provided under the restated
partial requirements agreement. The fixed price under the restated agreement
is
expected to remain below wholesale market prices during the term of the
agreement.
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.
Based on the PPUC’s January 11, 2007 order described below, if FES ultimately
determines to terminate, reduce, or significantly modify the agreement prior
to
the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely
regulatory relief is not likely to be granted by the PPUC.
Met-Ed
and Penelec
made a comprehensive transition rate filing with the PPUC on April 10, 2006
to address a number of transmission, distribution and supply issues. If Met-Ed's
and Penelec's preferred approach involving accounting deferrals had been
approved, annual revenues would have increased by $216 million and
$157 million, respectively. That filing included, 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 then existing
FES agreement was to be phased out. Met-Ed and Penelec also requested approval
of a January 12, 2005 petition for the deferral of transmission-related
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.
Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG
stranded costs were also included in the filing. On May 4, 2006, the PPUC
consolidated the remand of the FirstEnergy and GPU merger proceeding, related
to
the quantification and allocation of merger savings, with the comprehensive
transition rate filing case.
The
PPUC entered its
Opinion and Order in the comprehensive rate filing proceeding on January 11,
2007. The order approved the recovery of transmission costs, including the
transmission-related deferral for January 1, 2006 through January 10, 2007,
when
new transmission rates were effective, and determined that no merger savings
from prior years should be considered in determining customers’ rates. The
request for increases in generation supply rates was denied as were the
requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs.
The order decreased Met-Ed’s and Penelec’s distribution rates by
$80 million and $19 million, respectively. These decreases were offset
by the increases allowed for the recovery of transmission expenses and the
transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton
decommissioning costs was granted and, in January 2007, Met-Ed and Penelec
recognized income of $15 million and $12 million, respectively, to
establish regulatory assets for those previously expensed decommissioning costs.
Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for
Penelec ($50 million). Met-Ed and Penelec filed a Petition for
Reconsideration on January 26, 2007 on the issues of consolidated tax savings
and rate of return on equity. Other parties filed Petitions for Reconsideration
on transmission (including congestion), transmission deferrals and rate design
issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s,
Penelec’s and the other parties’ petitions for procedural purposes. Due to that
ruling, the period for appeals to the Commonwealth Court of Pennsylvania was
tolled until 30 days after the PPUC entered a subsequent order ruling on the
substantive issues raised in the petitions. On March 1, 2007, the PPUC issued
three orders: (1) a tentative order regarding the reconsideration by the PPUC
of
its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed,
Penelec and the OCA and denying in part and accepting in part the MEIUG’s and
PICA’s Petition for Reconsideration; and (3) an order approving the compliance
filing. Comments to the PPUC for reconsideration of its order were filed on
March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007,
making minor changes to rate design as agreed upon by Met-Ed, Penelec and
certain other parties.
On
March 30, 2007,
MEIUG and PICA filed a Petition for Review with the Commonwealth Court of
Pennsylvania asking the court to review the PPUC’s determination on transmission
(including congestion) and the transmission deferral. Met-Ed and Penelec filed
a
Petition for Review on April 13, 2007 on the issues of consolidated tax savings
and the requested generation rate increase. The OCA filed its
Petition for Review on April 13, 2007, on the issues of transmission
(including congestion) and recovery of universal service costs from only the
residential rate class. On June 19, 2007, initial briefs were filed and
responsive briefs were filed through September 21, 2007. Reply briefs
were filed on October 5, 2007. Oral arguments are expected to take place in
late
2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of
congestion, it could have a material adverse effect on the financial condition
and results of operations of Met-Ed, Penelec and FirstEnergy.
As
of September 30,
2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the
2006 comprehensive transition rate case, the 1998 Restructuring Settlement
(including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement
Stipulation were $496 million and $58 million, respectively. During the
PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in
2006, it noted a modification to the NUG purchased power stranded cost
accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC
Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG
cost
balances as if the stranded cost accounting methodology modification had not
been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax
charge of approximately $10.3 million in the third quarter of 2006,
representing incremental costs deferred under the revised methodology in 2005.
Met-Ed and Penelec continue to believe that the stranded cost accounting
methodology modification is appropriate and on August 24, 2006 filed a petition
with the PPUC pursuant to its order for authorization to reflect the stranded
cost accounting methodology modification effective January 1, 1999. Hearings
on
this petition were held in February 2007 and briefing was completed on March
28,
2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's
and Penelec’s request to modify their NUG stranded cost accounting methodology.
The companies filed exceptions to the initial decision on May 23, 2007 and
replies to those exceptions were filed on June 4, 2007. It is not known when
the
PPUC may issue a final decision in this matter.
On
May 2, 2007, Penn
filed a plan with the PPUC for the procurement of PLR supply from June 2008
through May 2011. The filing proposes multiple, competitive RFPs with staggered
delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the
residential and commercial classes. The proposal phases out existing promotional
rates and eliminates the declining block and the demand components on generation
rates for residential and commercial customers. The industrial class PLR service
will be provided through an hourly-priced service provided by Penn. Quarterly
reconciliation of the differences between the costs of supply and revenues
from
customers is also proposed. On
September 28, 2007, Penn filed a Joint Petition for Settlement resolving all
but
one issue in the case. Briefs were also filed on September 28, 2007,
on the unresolved issue of incremental uncollectible accounts expense. The
settlement is either supported, or not opposed, by all parties. The PPUC is
expected to act on the settlement and the unresolved issue in late November
or
early December 2007 for the initial RFP to take place in January
2008.
On
February 1, 2007,
the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces
of
proposed legislation that, according to the Governor, is designed to reduce
energy costs, promote energy independence and stimulate the economy. Elements
of
the EIS include the installation of smart meters, funding for solar panels
on
residences and small businesses, conservation programs to meet demand growth,
a
requirement that electric distribution companies acquire power that results
in
the “lowest reasonable rate on a long-term basis,” the utilization of
micro-grids and an optional three year phase-in of rate increases. On July
17,
2007 the Governor signed into law two pieces of energy legislation. The first
amended the Alternative Energy Portfolio Standards Act of 2004 to, among other
things, increase the percentage of solar energy that must be supplied at the
conclusion of an electric distribution company’s transition period. The second
law allows electric distribution companies, at their sole discretion, to enter
into long term contracts with large customers and to build or acquire interests
in electric generation facilities specifically to supply long-term contracts
with such customers. A special legislative session on energy was convened in
mid-September 2007 to consider other aspects of the EIS. The final form of
any
legislation arising from the special legislative session is uncertain.
Consequently, FirstEnergy is unable to predict what impact, if any, such
legislation may have on its operations.
New
Jersey
(Applicable to JCP&L)
JCP&L
is
permitted to defer for future collection from customers the amounts by which
its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of September 30, 2007, the accumulated deferred
cost balance totaled approximately $330 million.
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 NJBPU
proceedings has not yet been set.
On
August 1,
2005, the NJBPU established a proceeding to determine whether additional
ratepayer protections are required at the state level in light of the repeal
of
PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October
2,
2006 that 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.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an
additional draft proposal on March 31, 2006 addressing various issues
including access to books and records, ring-fencing, cross subsidization,
corporate governance and related matters. With the approval of the NJBPU Staff,
the affected utilities jointly submitted an alternative proposal on June 1,
2006. Comments on the alternative proposal were submitted on June 15, 2006.
On November 3, 2006, the Staff circulated a revised draft proposal to
interested stakeholders. Another revised draft was circulated by the NJBPU
Staff
on February 8, 2007.
New
Jersey statutes
require that the state periodically undertake a planning process, known as
the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement
of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President
and
includes representatives of several State departments. In October 2006, the
current EMP process was initiated with the issuance of a proposed set of
objectives which, as to electricity, included the following:
· Reduce
the total
projected electricity demand by 20% by 2020;
·
|
Meet
22.5% of
New Jersey’s electricity needs with renewable energy resources by that
date;
|
· Reduce
air pollution
related to energy use;
· Encourage
and
maintain economic growth and development;
·
|
Achieve
a 20%
reduction in both Customer Average Interruption Duration Index and
System
Average Interruption Frequency Index by
2020;
|
·
|
Maintain
unit
prices for electricity to no more than +5% of the regional average
price
(region includes New York, New Jersey, Pennsylvania, Delaware, Maryland
and the District of Columbia); and
|
· Eliminate
transmission congestion by 2020.
Comments
on the
objectives and participation in the development of the EMP have been solicited
and a number of working groups have been formed to obtain input from a broad
range of interested stakeholders including utilities, environmental groups,
customer groups, and major customers. EMP working groups addressing (1) energy
efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing
issues have completed their assigned tasks of data gathering and analysis and
have provided reports to the EMP Committee. Public stakeholder meetings were
held in the fall of 2006 and in early 2007, and further public meetings are
expected later in 2007. A final draft of the EMP is expected to be presented
to
the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome
of this process nor determine the impact, if any, such legislation may have
on
its operations or those of JCP&L.
On
February 13,
2007, the NJBPU Staff informally issued a draft proposal relating to changes
to
the regulations addressing electric distribution service reliability and quality
standards. Meetings between the NJBPU Staff and interested
stakeholders to discuss the proposal were held and additional, revised informal
proposals were subsequently circulated by the Staff. On September 4,
2007, proposed regulations were published in the New Jersey Register, which
proposal will be subsequently considered by the NJBPU following comments which
were due on September 26, 2007. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, such
regulations may have on its operations or those of JCP&L.
FERC
Matters
(Applicable to FES and each of the Companies)
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 participated in the
FERC hearings held in May 2006 concerning the calculation and imposition of
the
SECA charges. The presiding judge issued an initial decision on August 10,
2006,
rejecting the compliance filings made by the RTOs and transmission owners,
ruling on various issues and directing new compliance filings. This decision
is
subject to review and approval by the FERC. Briefs addressing the initial
decision were filed on September 11, 2006 and October 20, 2006. A final order
could be issued by the FERC in the fourth quarter of 2007.
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, BG&E and Pepco Holdings, Inc. requested a formula
rate for transmission service provided within their respective zones. Hearings
were held and numerous parties appeared and litigated various issues; including
AEP, which filed in opposition proposing to create a "postage stamp" rate for
high voltage transmission facilities across PJM. At the conclusion of the
hearings, the ALJ issued an initial decision adopting the FERC 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. Numerous
parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and
recommendations. On April 19, 2007, the FERC issued an order
rejecting the ALJ’s findings and recommendations in nearly every respect. The
FERC found that the PJM transmission owners’ existing “license plate” rate
design was just and reasonable and ordered that the current license plate rates
for existing transmission facilities be retained. On the issue of rates for
new
transmission facilities, the FERC directed that costs for new transmission
facilities that are rated at 500 kV or higher are to be socialized throughout
the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to
be
allocated on a “beneficiary pays” basis. Nevertheless, the FERC found
that PJM’s current beneficiary-pays cost allocation methodology is not
sufficiently detailed and, in a related order that also was issued on April
19,
2007, directed that hearings be held for the purpose of establishing a just
and
reasonable cost allocation methodology for inclusion in PJM’s
tariff.
On
May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007
Order. Subsequently, FirstEnergy and other parties filed pleadings
opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if
sustained on rehearing and appeal, will prevent the allocation of the cost
of
existing transmission facilities of other utilities to JCP&L, Met-Ed and
Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce future
transmission costs shifting to the JCP&L, Met-Ed and Penelec
zones.
New
FERC
Transmission Rate Design Filings
On
August 1, 2007, a
number of filings were made with the FERC by transmission owning utilities
in
the MISO and PJM footprint that could affect the transmission rates paid by
FirstEnergy’s operating companies and FES.
FirstEnergy
joined
in a filing made by the MISO transmission owners that would maintain the
existing “license plate” rates for transmission service within MISO provided
over existing transmission facilities. FirstEnergy also joined in a
filing made by both the MISO and PJM transmission owners proposing to continue
the elimination of transmission rates associated with service over existing
transmission facilities between MISO and PJM. If adopted by the FERC,
these filings would not affect the rates charged to load-serving FirstEnergy
affiliates for transmission service over existing transmission
facilities. In a related filing, MISO and MISO transmission owners
requested that the current MISO pricing for new transmission facilities that
spreads 20% of the cost of new 345 kV and higher transmission facilities across
the entire MISO footprint be maintained (known as the RECB Process). Each of
these filings was supported by the majority of transmission owners in either
MISO or PJM, as applicable.
The
Midwest
Stand-Alone Transmission Companies made a filing under Section 205 of the
Federal Power Act requesting that 100% of the cost of new qualifying 345 kV
and
higher transmission facilities be spread throughout the entire MISO
footprint. Further, Indianapolis Power and Light Company separately
moved the FERC to reopen the record to address the cost allocation for the
RECB
Process. If either proposal is adopted by the FERC, it could shift a
greater portion of the cost of new 345 kV and higher transmission facilities
to
the FirstEnergy footprint in MISO, and increase the transmission rates paid
by
load-serving FirstEnergy affiliates in MISO.
On
September 17,
2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power
Act
seeking to have the entire transmission rate design and cost allocation methods
used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory,
and to have FERC fix a uniform regional transmission rate design and cost
allocation method for the entire MISO and PJM “SuperRegion” that regionalizes
the cost of new and existing transmission facilities operated at voltages of
345
kV and above. Lower voltage facilities would continue to be recovered
in the host utility transmission rate zone through a license plate rate. AEP
requests a refund effective October 1, 2007, or alternatively, February 1,
2008. The effect of this proposal, if adopted by FERC, would be to
shift significant costs to the FirstEnergy zones in MISO and
PJM. FirstEnergy believes that most of these costs would ultimately
be recoverable in retail rates. On October 12, 2007, BG&E filed a
motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of
MISO States filed comments urging the FERC to dismiss AEP’s complaint.
Interventions and protests to AEP’s complaint and answers to BG&E’s motion
to dismiss were due October 29, 2007. FirstEnergy and other transmission
owners filed protests to AEP’s complaint and support for BG&E’s motion to
dismiss. AEP has asked for consolidation of its complaint with the cases above,
and FirstEnergy expects it to be resolved on the same timeline as those
cases.
Any
increase in
rates charged for transmission service to FirstEnergy affiliates is dependent
upon the outcome of these proceedings at FERC. All or some of these
proceedings may be consolidated by the FERC and set for hearing. The
outcome of these cases cannot be predicted. Any material adverse
impact on FirstEnergy would depend upon the ability of the load-serving
FirstEnergy affiliates to recover increased transmission costs in their retail
rates. FirstEnergy believes that current retail rate mechanisms in
place for PLR service for the Ohio Companies and for Met-Ed and Penelec would
permit them to pass through increased transmission charges in their retail
rates. Increased transmission charges in the JCP&L and Penn
transmission zones would be the responsibility of competitive electric retail
suppliers, including FES.
MISO
Ancillary
Services Market and Balancing Area Consolidation Filing
MISO
made a filing
on September 14, 2007 to establish Ancillary Services markets for regulation,
spinning and supplemental reserves to consolidate the existing 24 balancing
areas within the MISO footprint, and to establish MISO as the NERC registered
balancing authority for the region. An effective date of June 1, 2008
was requested in the filing.
MISO’s
previous
filing to establish an Ancillary Services market was rejected without prejudice
by FERC on June 22, 2007, subject to MISO making certain modifications in its
filing. FirstEnergy believes that MISO’s September 14 filing generally
addresses the FERC’s directives. FirstEnergy supports the proposal to
establish markets for Ancillary Services and consolidate existing balancing
areas, but filed objections on specific aspects of the MISO
proposal. Interventions and protests to MISO’s filing were made with
FERC on October 15, 2007.
Order
No. 890 on
Open Access Transmission Tariffs
On
February 16,
2007, the FERC issued a final rule (Order No. 890) that revises its decade-old
open access transmission regulations and policies. The FERC explained
that the final rule is intended to strengthen non-discriminatory access to
the
transmission grid, facilitate FERC enforcement, and provide for a more open
and
coordinated transmission planning process. The final rule became
effective on May 14, 2007. MISO, PJM and ATSI will be filing revised
tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff
filings to the FERC on October 11, 2007. As a market participant in both MISO
and PJM, FirstEnergy will conform its business practices to each respective
revised tariff.
Environmental
Matters
FES
and the
Companies accrue environmental liabilities only when they conclude that it
is
probable that they have an obligation for such costs and can reasonably estimate
the amount of such costs. Unasserted claims are reflected in FES’ and the
Companies’ determination of environmental liabilities and are accrued in the
period that they become both probable and reasonably estimable.
Clean
Air Act
Compliance (Applicable to FES)
FES
is required to
meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500
for
each day the unit is in violation. The EPA has an interim enforcement policy
for
SO2 regulations
in Ohio that allows for compliance based on a 30-day averaging period. FES
believes it is currently in compliance with this policy, but cannot predict
what
action the EPA may take in the future with respect to the interim enforcement
policy.
The
EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006 alleging violations to various sections of the Clean Air Act. FES
has
disputed those alleged violations based on its Clean Air Act permit, the Ohio
SIP and other information provided at an August 2006 meeting with the EPA.
The
EPA has several enforcement options (administrative compliance order,
administrative penalty order, and/or judicial, civil or criminal action) and
has
indicated that such option may depend on the time needed to achieve and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding the opacity limit applicable to
the common stack for Bay Shore Units 2, 3 and 4.
FES
complies with
SO2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX reductions
required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX reductions
at FES'
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. FES
believes its facilities are also complying with the NOX budgets
established
under SIPs through combustion controls and post-combustion controls, including
Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.
On
May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal Clean Air Act, alleging violations
of
air pollution laws at the Mansfield Plant, including opacity limitations. Prior
to the receipt of this notice, the Mansfield Plant was subject to a Consent
Order and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with
the
applicable laws will continue. On October 16, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. FirstEnergy is currently studying
PennFuture’s complaint.
National
Ambient Air Quality
Standards (Applicable to FES)
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
allowed 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). FES’
Michigan,
Ohio and Pennsylvania fossil generation facilities will be subject to
caps on SO2 and
NOX emissions,
whereas its New Jersey fossil 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 FES operates affected facilities.
Mercury
Emissions (Applicable to FES)
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. FES' future cost of compliance with these
regulations may be substantial and will depend on how they are ultimately
implemented by the states in which FES 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. FES would prefer an
output-based generation-neutral methodology in which allowances are allocated
based on megawatts of power produced, allowing new and non-emitting generating
facilities (including renewables and nuclear) to be entitled to their
proportionate share of the allowances. Consequently, FES will be disadvantaged
if these model rules were implemented as proposed because FES’ substantial
reliance on non-emitting (largely nuclear) generation is not recognized under
the input-based allocation.
Pennsylvania
has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. Pennsylvania’s mercury
regulation would deprive FES of mercury emission allowances that were to be
allocated to the Mansfield Plant under the CAMR and that would otherwise be
available for achieving FirstEnergy system-wide compliance. It is anticipated
that compliance with these regulations, if approved by the EPA and implemented,
would not require the addition of mercury controls at the Mansfield Plant,
FES’
only coal-fired Pennsylvania power plant, until 2015, if at all.
W.
H. Sammis Plant
(Applicable to FES, OE and Penn)
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,
and is now owned by FGCO. 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 the New Source Review, or NSR, 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 Sammis NSR litigation. This settlement agreement, which is in
the
form of a consent decree, was approved by the court on July 11, 2005, and
requires reductions of NOX and SO2
emissions at the
Sammis, Burger, Eastlake and Mansfield 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 Sammis NSR
Litigation consent decree. Capital expenditures necessary to complete
requirements of the Sammis NSR Litigation settlement agreement are currently
estimated to be $1.7 billion for 2007 through 2011 ($400 million of which
is expected to be spent during 2007, with the largest portion of the remaining
$1.3 billion expected to be spent in 2008 and 2009).
The
Sammis NSR
Litigation consent decree also requires FirstEnergy to spend up to
$25 million toward environmentally beneficial projects, $14 million of
which is satisfied by entering into 93 MW (or 23 MW if federal tax credits
are
not applicable) of wind energy purchased power agreements with a 20-year term.
An initial 16 MW of the 93 MW consent decree obligation was satisfied
during 2006.
Climate
Change
(Applicable to FES)
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. At the international
level, efforts have begun to develop climate change agreements for post-2012
GHG
reductions. 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.
At
the federal
level, members of Congress have introduced several bills seeking to reduce
emissions of GHG in the United States. State activities, primarily
the northeastern states participating in the Regional Greenhouse Gas Initiative
and western states led by California, have coordinated efforts to develop
regional strategies to control emissions of certain GHGs.
On
April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2 emissions
from automobiles as “air pollutants” under the Clean Air Act. Although this
decision did not address CO2 emissions
from
electric generating plants, the EPA has similar authority under the Clean Air
Act to regulate “air pollutants” from those and other facilities. Also on
April 2, 2007, the United States Supreme Court ruled that changes in annual
emissions (in tons/year) rather than changes in hourly emissions rate (in
kilograms/hour) must be used to determine whether an emissions increase triggers
NSR. Subsequently, the EPA proposed to change the NSR regulations, on
May 8, 2007, to utilize changes in the hourly emission rate (in
kilograms/hour) to determine whether an emissions increase triggers
NSR.
FES
cannot currently
estimate the financial impact of climate change policies, although potential
legislative or regulatory programs restricting CO2 emissions
could
require significant capital and other expenditures. The CO2 emissions
per KWH of
electricity generated by FES 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
(Applicable to FES)
Various
water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FES' plants. In addition, Ohio, New
Jersey and Pennsylvania have water quality standards applicable to FES'
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 life is drawn into a facility's cooling
water system. On January 26, 2007, the federal Court of Appeals for the Second
Circuit remanded portions of the rulemaking dealing with impingement mortality
and entrainment back to EPA for further rulemaking and eliminated the
restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended
this rule, noting that until further rulemaking occurs, permitting authorities
should continue the existing practice of applying their best professional
judgment (BPJ) to minimize impacts on fish and shellfish from cooling water
intake structures. FES is evaluating various control options and their costs
and
effectiveness. Depending on the outcome of such studies, the EPA’s further
rulemaking and any action taken by the states exercising BPJ, the future cost
of
compliance with these standards may require material capital
expenditures.
Regulation
of Hazardous
Waste (Applicable to FES and each of the
Companies)
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.
Under
NRC
regulations, FirstEnergy must ensure that adequate funds will be available
to
decommission its nuclear facilities. As of September 30, 2007,
FirstEnergy had approximately $1.5 billion invested in external trusts to
be used for the decommissioning and environmental remediation of Davis-Besse,
Beaver Valley and Perry. As part of the application to the NRC to
transfer the ownership of these nuclear facilities to NGC in 2005, FirstEnergy
agreed to contribute another $80 million to these trusts by 2010. Consistent
with NRC guidance, utilizing a “real” rate of return on these funds of
approximately 2% over inflation, these trusts are expected to exceed the minimum
decommissioning funding requirements set by the NRC. Conservatively, these
estimates do not include any rate of return that the trusts may earn over the
20-year plant useful life extensions that FirstEnergy plans to seek for these
facilities.
The
Companies have
been named as PRPs at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of September
30, 2007, 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 $89 million (JCP&L - $60 million, TE
- $3 million, CEI - $1 million, and FirstEnergy Corp. -
$25 million) have been accrued through September 30,
2007.
Other
Legal Proceedings
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.
Power
Outages and Related
Litigation (Applicable to FES and each of the
Companies)
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
in
July 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, NJ, based on a
common incident involving the failure of the bushings of two large transformers
in the Red Bank substation resulting in planned and unplanned outages in the
area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify
the class based on a very limited number of class members who incurred damages
and also filed a motion for summary judgment on the remaining plaintiffs’ claims
for negligence, breach of contract and punitive damages. In July 2006, the
New
Jersey Superior Court dismissed the punitive damage claim and again decertified
the class based on the fact that a vast majority of the class members did not
suffer damages and those that did would be more appropriately addressed in
individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate
Division which, in March 2007, reversed the decertification of the Red Bank
class and remanded this matter back to the Trial Court to allow plaintiffs
sufficient time to establish a damage model or individual proof of
damages. JCP&L filed a petition for allowance of an appeal of the
Appellate Division ruling to the New Jersey Supreme Court which was denied
in
May 2007. Proceedings are continuing in the Superior
Court. FirstEnergy is defending this class action but is unable
to predict the outcome of this matter. No liability has been accrued
as of September 30, 2007.
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
that could require additional material expenditures.
FirstEnergy
companies also are defending four separate complaint cases before the PUCO
relating to the August 14, 2003 power outages. Two of those 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. Two 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 cases, the carrier seeks reimbursement from various
FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for
claims paid to insureds for damages allegedly arising as a result of the loss
of
power on August 14, 2003. A fifth case in which a carrier sought
reimbursement for claims paid to insureds was voluntarily dismissed by the
claimant in April 2007. A sixth case involving the claim of a non-customer
seeking reimbursement for losses incurred when its store was burglarized on
August 14, 2003 was dismissed. The four cases remaining were consolidated
for hearing by the PUCO in an order dated March 7, 2006. In that
order the PUCO also limited the litigation to service-related claims by
customers of the Ohio operating companies; dismissed FirstEnergy as a defendant;
and ruled that the U.S.-Canada Power System Outage Task Force Report was not
admissible into evidence. In response to a motion for rehearing filed by one
of
the claimants, the PUCO ruled on April 26, 2006 that the insurance company
claimants, as insurers, may 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 amended complaints and the named
FirstEnergy companies have answered and also have filed a motion to dismiss
each
action. On September 27, 2006, the PUCO dismissed certain parties and claims
and
otherwise ordered the complaints to go forward to hearing. The cases have been
set for hearing on January 8, 2008.
FirstEnergy
is 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 FirstEnergy is 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 (Applicable to FES)
On
May 14, 2007, the
Office of Enforcement of the NRC issued a Demand for Information to FENOC
following FENOC’s reply to an April 2, 2007 NRC request for information about
two reports prepared by expert witnesses for an insurance arbitration related
to
Davis-Besse. The NRC indicated that this information was needed for the NRC
“to
determine whether an Order or other action should be taken pursuant to 10 CFR
2.202, to provide reasonable assurance that FENOC will continue to operate
its
licensed facilities in accordance with the terms of its licenses and the
Commission’s regulations.” FENOC was directed to submit the information to the
NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand
for Information reaffirming that it accepts full responsibility for the mistakes
and omissions leading up to the damage to the reactor vessel head and that
it
remains committed to operating Davis-Besse and FirstEnergy’s other nuclear
plants safely and responsibly. The NRC held a public meeting on June 27, 2007
with FENOC to discuss FENOC’s response to the Demand for Information. In
follow-up discussions, FENOC was requested to provide supplemental information
to clarify certain aspects of the Demand for Information response and provide
additional details regarding plans to implement the commitments made therein.
FENOC submitted this supplemental response to the NRC on July 16, 2007. On
August 15, 2007, the NRC issued a confirmatory order imposing these
commitments. FENOC must inform the NRC’s Office of Enforcement after it
completes the key commitments embodied in the NRC’s order. FENOC’s compliance
with these commitments is subject to future NRC review.
Other
Legal Matters
(Applicable to OE and JCP&L)
On
August 22, 2005,
a class action complaint was filed against OE in Jefferson County,
Ohio Common Pleas Court, seeking compensatory and punitive damages to be
determined at trial based on claims of negligence and eight other tort counts
alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs
are also seeking injunctive relief to eliminate harmful emissions and repair
property damage and the institution of a medical monitoring program for class
members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify
this case as a class action and, accordingly, did not appoint the plaintiffs
as
class representatives or their counsel as class counsel. On July 30, 2007,
plaintiffs’ counsel voluntarily withdrew their request for reconsideration of
the April 5, 2007 Court order denying class certification and the Court
heard oral argument on the plaintiffs’ motion to amend their complaint which OE
has opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend
their complaint. The plaintiffs have appealed the Court’s denial of the motion
for certification as a class action and motion to amend their
complaint.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. The arbitration
panel provided additional rulings regarding damages during a September 2007
hearing and it is anticipated that he will issue a final order in late 2007.
JCP&L intends to re-file an appeal again in federal district court once the
damages associated with this case are identified at an individual employee
level. JCP&L recognized a liability for the potential $16 million award
in 2005.
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.
New
Accounting Standards and
Interpretations (Applicable to FES and each
of the Companies)
SFAS
157 – “Fair Value
Measurements”
In
September 2006,
the FASB issued SFAS 157 that establishes how companies should measure fair
value when they are required to use a fair value measure for recognition or
disclosure purposes under GAAP. This Statement addresses the need for increased
consistency and comparability in fair value measurements and for expanded
disclosures about fair value measurements. The key changes to current practice
are: (1) the definition of fair value which focuses on an exit price rather
than
entry price; (2) the methods used to measure fair value such as emphasis that
fair value is a market-based measurement, not an entity-specific measurement,
as
well as the inclusion of an adjustment for risk, restrictions and credit
standing; and (3) the expanded disclosures about fair value measurements. This
Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those years.
FES and the Companies are currently evaluating the impact of this Statement
on
their financial statements.
|
SFAS
159 –
“The Fair Value Option for Financial Assets and Financial Liabilities
–
Including an amendment of FASB Statement No.
115”
|
In
February 2007,
the FASB issued SFAS 159, which provides companies with an option to report
selected financial assets and liabilities at fair value. This
Statement requires companies to provide additional information that will help
investors and other users of financial statements to more easily understand
the
effect of the company’s choice to use fair value on its earnings. The
Standard also requires companies to display the fair value of those assets
and
liabilities for which the company has chosen to use fair value on the face
of
the balance sheet. This guidance does not eliminate disclosure
requirements included in other accounting standards, including requirements
for
disclosures about fair value measurements included in SFAS 157 and
SFAS 107. This Statement is effective for financial statements issued
for fiscal years beginning after November 15, 2007, and interim periods
within those years. FES and the Companies are currently evaluating the impact
of
this Statement on their financial statements.
EITF
06-11 – “Accounting for Income Tax
Benefits of Dividends or Share-based Payment Awards”
In
June 2007, the
FASB released EITF 06-11, which provides guidance on the appropriate accounting
for income tax benefits related to dividends earned on nonvested share units
that are charged to retained earnings under SFAS 123(R). The
consensus requires that an entity recognize the realized tax benefit associated
with the dividends on nonvested shares as an increase to additional paid-in
capital (APIC). This amount should be included in the APIC pool, which is to
be
used when an entity’s estimate of forfeitures increases or actual forfeitures
exceed its estimates, at which time the tax benefits in the APIC pool would
be
reclassified to the income statement. The consensus is effective for
income tax benefits of dividends declared during fiscal years beginning after
December 15, 2007. EITF 06-11 is not expected to have a material
impact on FES’ or the Companies’ financial statements.
FSP
FIN 39-1 – “Amendment of FASB
Interpretation No. 39”
In
April 2007, the
FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to
offset fair value amounts recognized for the right to reclaim cash collateral
(a
receivable) or the obligation to return cash collateral (a payable) against
fair
value amounts recognized for derivative instruments that have been offset under
the same master netting arrangement as the derivative
instruments. This FSP is effective for fiscal years beginning after
November 15, 2007, with early application permitted. The effects of applying
the
guidance in this FSP should be recognized as a retrospective change in
accounting principle for all financial statements presented. FES and the
Companies are currently evaluating the impact of this FSP on their financial
statements but it is not expected to have a material impact.
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
See
“Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Market Risk Information” in Item 2 above.
ITEM
4.
CONTROLS AND PROCEDURES
(a) EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
The
applicable
registrant's chief executive officer and chief financial officer have reviewed
and evaluated the registrant's disclosure controls and procedures. The term
disclosure controls and procedures means controls and other procedures of a
registrant that are designed to ensure that information required to be disclosed
by the registrant in the reports that it files or submits under the Securities
Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized
and reported, within the time periods specified in the Securities and Exchange
Commission's rules and forms. Disclosure controls and procedures include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by an issuer in the reports that it files or submits
under that Act is accumulated and communicated to the registrant's management,
including its principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure. Based on that evaluation, those officers have concluded
that the applicable registrant's disclosure controls and procedures are
effective and were designed to bring to their attention material information
relating to the registrant and its consolidated subsidiaries by others within
those entities.
(b) CHANGES
IN INTERNAL CONTROLS
During
the quarter
ended September 30, 2007, 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, 2006 for
a discussion of the risk factors of FirstEnergy and the subsidiary registrants.
For the quarter ended September 30, 2007, 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.
|
|
|
|
|
|
July
1-31,
|
|
August
1-31,
|
|
September
1-30,
|
|
Third
|
|
|
|
|
|
|
|
|
|
|
|
Total
Number
of Shares Purchased (a)
|
|
29,656
|
|
83,448
|
|
253,701
|
|
366,805
|
|
Average
Price
Paid per Share
|
|
$66.00
|
|
$62.95
|
|
$61.85
|
|
$62.44
|
|
Total
Number
of Shares Purchased
|
|
|
|
|
|
|
|
|
|
As
Part of Publicly Announced
Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
Number
(or Approximate Dollar
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value)
of Shares that May Yet
Be
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Under the Plans or
Programs
|
|
|
1,629,890
|
|
|
1,629,890
|
|
|
1,629,890
|
|
|
1,629,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Share
amounts
reflect purchases on the open market to satisfy FirstEnergy's obligations
to deliver common stock under its Executive
and
Director Incentive Compensation Plan, Deferred Compensation Plan
for
Outside Directors, Executive Deferred Compensation
Plan, Savings Plan and Stock Investment Plan. In addition, such amounts
reflect shares tendered by employees to
pay the
exercise price or withholding taxes upon exercise of stock options
granted
under the Executive and Director Incentive Compensation
Plan and shares purchased as part of publicly announced
plans.
|
|
|
(b)
|
FirstEnergy
publicly announced, on January 30, 2007, a plan to repurchase up to
16 million shares of its common stock through June 30,
2008. On March 2, 2007, FirstEnergy repurchased approximately
14.4 million shares, or 4.5%, of its outstanding common
stock
under this plan through an accelerated share repurchase program with
an
affiliate of Morgan Stanley and Co., Incorporated
at an initial price of $62.63 per
share.
|
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
|
|
|
10.1
|
Amendment
to
Agreement for Engineering, Procurement and Construction of Air Quality
Control Systems by and between FirstEnergy Generation Corp. and Bechtel
Power Corporation dated September 14, 2007 (Form 8-K dated September
18,
2007)*
|
|
|
|
10.2
|
FirstEnergy
Corp. Executive Deferred Compensation Plan as amended September 18,
2007
(Form
8-K
dated September 21, 2007)
|
|
|
|
10.3
|
FirstEnergy
Corp. Supplemental Executive Retirement Plan as amended September
18,
2007
(Form
8-K
dated September 21, 2007)
|
|
|
|
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-14(a)
|
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350
|
|
|
FES
|
|
|
|
12
|
Fixed
charge
ratios
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
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-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
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-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
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-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350
|
|
JCP&L
|
|
|
|
12
|
Fixed
charge
ratios
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
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-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350
|
Penelec
|
|
|
4.1
|
Form
of
Pennsylvania Electric Company 6.05% Senior Notes due 2017 (incorporated
by
reference to a Form 8-K dated August 31, 2007)
|
|
10.1
|
Registration
Rights Agreement, dated as of August 30, 2007, among Pennsylvania
Electric
Company and Citigroup Global Markets Inc., Lehman Brothers Inc. and
Scotia
Capital (USA) Inc., as representatives of the several initial purchasers
named in the Purchase Agreement (incorporated by reference to a Form
8-K
dated August 31, 2007)
|
|
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-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350
|
*
Confidential treatment has been requested for certain portions of the Exhibit.
Omitted portions have been filed separately with the SEC.
Pursuant
to
reporting requirements of respective financings, FirstEnergy, FES, OE,
JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an
exhibit to this Form 10-Q.
Pursuant
to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this
Form 10-Q any instrument with respect to long-term debt if the respective
total amount of securities authorized thereunder does not exceed 10% of its
respective total assets, but each hereby agrees to furnish to the SEC on request
any such documents.
SIGNATURES
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.
October
31,
2007
|
FIRSTENERGY
CORP.
|
|
Registrant
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
Registrant
|
|
|
|
OHIO
EDISON COMPANY
|
|
Registrant
|
|
|
|
THE
CLEVELAND ELECTRIC
|
|
ILLUMINATING
COMPANY
|
|
Registrant
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
Registrant
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
Registrant
|
|
|
|
Harvey
L.
Wagner
|
|
Vice
President, Controller
|
|
and
Chief
Accounting Officer
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
Registrant
|
|
|
|
|
|
|
|
|
|
Paulette
R.
Chatman
|
|
Controller
|
|
(Principal
Accounting Officer)
|