UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D. C. 20549
FORM
10-Q
(Mark
One)
[X] QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the
quarterly period ended June 30, 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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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 ( )
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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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
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CLASS
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FirstEnergy
Corp., $.10 par value
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304,835,407
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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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5,290,596
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FirstEnergy
Corp. is
the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company common
stock.
This
combined Form
10-Q is separately filed by FirstEnergy 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.
This
Form 10-Q
includes forward-looking statements based on information currently available
to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
“anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets
for
energy services, changing energy and commodity market prices, replacement
power
costs being higher than anticipated or inadequately hedged, the continued
ability of FirstEnergy’s regulated utilities to collect transition and other
charges or to recover increased transmission costs, maintenance costs being
higher than anticipated, legislative and regulatory changes (including revised
environmental requirements), and the legal and regulatory changes resulting
from
the implementation of the EPACT (including, but not limited to, the repeal
of
the PUHCA), the uncertainty of the timing and amounts of the capital
expenditures needed to, among other things, implement the Air Quality Compliance
Plan (including that such amounts could be higher than anticipated) or levels
of
emission reductions related to the Consent Decree resolving the New Source
Review litigation, adverse regulatory or legal decisions and outcomes
(including, but not limited to, the revocation of necessary licenses or
operating permits and oversight) by the NRC (including, but not limited to,
the
Demand for Information issued to FENOC on May 14, 2007) as disclosed in
FirstEnergy’s 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 Rate Stabilization Plan) and the PPUC (including Penn’s default
service plan filing), the resolution of the Petitions for Review filed with
the
Commonwealth Court of Pennsylvania with respect to the transition rate plan
filing for Met-Ed and Penelec, the continuing availability and operation
of
generating units, the ability of generating units to continue to operate
at, or
near full capacity, the inability to accomplish or realize anticipated benefits
from strategic goals (including employee workforce initiatives), the anticipated
benefits from voluntary pension plan contributions, the ability to improve
electric commodity margins and to experience growth in the distribution
business, the ability to access the public securities and other capital markets
and the cost of such capital, the outcome, cost and other effects of present
and
potential legal and administrative proceedings and claims related to the
August 14, 2003 regional power outage, any final adjustment in the purchase
price per share under the accelerated share repurchase program announced
March 2, 2007, the risks and other factors discussed from time to time in
the
registrants’ SEC filings, and other similar factors. 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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1-25
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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26
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Consolidated
Statements of Comprehensive Income
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27
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Consolidated
Balance Sheets
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28
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Consolidated
Statements of Cash Flows
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29
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Report
of
Independent Registered Public Accounting Firm
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30
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Management's
Discussion and Analysis of Financial Condition and
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31-71
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Results
of Operations
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Ohio
Edison
Company
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Consolidated
Statements of Income and Comprehensive Income
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72
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Consolidated
Balance Sheets
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73
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Consolidated
Statements of Cash Flows
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74
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Report
of
Independent Registered Public Accounting Firm
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75
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Management's
Discussion and Analysis of Financial Condition and
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76-79
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Results
of Operations
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The
Cleveland Electric
Illuminating Company
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Consolidated
Statements of Income and Comprehensive Income
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80
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Consolidated
Balance Sheets
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81
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Consolidated
Statements of Cash Flows
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82
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Report
of
Independent Registered Public Accounting Firm
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83
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Management's
Discussion and Analysis of Financial Condition and
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84-87
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Results
of Operations
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The
Toledo 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
Discussion and Analysis of Financial Condition and
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92-95
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Results
of Operations
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Jersey
Central Power & Light
Company
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Consolidated
Statements of Income and Comprehensive Income
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96
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Consolidated
Balance Sheets
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97
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Consolidated
Statements of Cash Flows
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98
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Report
of
Independent Registered Public Accounting Firm
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99
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Management's
Discussion and Analysis of Financial Condition and
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100-103
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Results
of Operations
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TABLE
OF
CONTENTS (Cont'd)
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Pages
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Metropolitan
Edison
Company
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Consolidated
Statements of Income and Comprehensive Income
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104
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Consolidated
Balance Sheets
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105
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Consolidated
Statements of Cash Flows
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106
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Report
of
Independent Registered Public Accounting Firm
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107
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Management's
Discussion and Analysis of Financial Condition and
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108-111
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Results
of Operations
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Pennsylvania
Electric
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
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114
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Report
of
Independent Registered Public Accounting Firm
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115
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Management's
Discussion and Analysis of Financial Condition and
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116-119
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Results
of Operations
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Combined
Management’s Discussion
and Analysis of Registrant Subsidiaries
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120-132
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk.
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133
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Item
4. Controls
and Procedures.
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133
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Part
II. Other Information
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Item
1. Legal
Proceedings.
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134
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Item
1A. Risk
Factors.
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134
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Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds.
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134
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Item
4. Submission
of Matters to a Vote of Security Holders.
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134-135
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Item
6. Exhibits.
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135-137
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GLOSSARY
OF
TERMS
The
following abbreviations and acronyms are used in this report to identify
FirstEnergy Corp. and its current and former subsidiaries:
ATSI
|
American
Transmission Systems, Inc., owns and operates transmission
facilities
|
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CEI
|
The
Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
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Companies
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OE,
CEI, TE,
JCP&L, Met-Ed and Penelec
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FENOC
|
FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
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FES
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FirstEnergy
Solutions Corp., provides energy-related products and
services
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FESC
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FirstEnergy
Service Company, provides legal, financial, and other corporate
support
services
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FGCO
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FirstEnergy
Generation Corp., owns and operates non-nuclear generating
facilities
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FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
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FSG
|
FirstEnergy
Facilities Services Group, LLC, former parent company of several
heating,
ventilation,
air
conditioning and energy management companies
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GPU
|
GPU,
Inc.,
former parent of JCP&L, Met-Ed and Penelec, which merged with
FirstEnergy on
November 7,
2001
|
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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
|
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JCP&L
Transition
Funding
II
|
JCP&L
Transition Funding II LLC, a Delaware limited liability company
and issuer
of transition bonds
|
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Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
|
|
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
|
|
PNBV
|
PNBV
Capital
Trust, a special purpose entity created by OE in 1996
|
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Shippingport
|
Shippingport
Capital Trust, a special purpose entity created by CEI and TE in
1997
|
|
TE
|
The
Toledo
Edison Company, an Ohio electric utility operating
subsidiary
|
|
TEBSA
|
Termobarranquilla
S.A., Empresa de Servicios Publicos
|
|
|
|
|
The
following
abbreviations and acronyms are used to identify frequently used
terms in
this report:
|
|
|
|
|
ALJ
|
Administrative
Law Judge
|
|
AOCL
|
Accumulated
Other Comprehensive Loss
|
|
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
|
ECO
|
Electro-Catalytic
Oxidation
|
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”
|
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
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”
|
Fitch
|
Fitch
Ratings,
Ltd.
|
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
|
NOAC
|
Northwest
Ohio
Aggregation Coalition
|
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
|
|
RTC
|
Regulatory
Transition Charge
|
|
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
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
|
|
UCS
|
Union
of
Concerned Scientists
|
|
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
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 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 3). As discussed in Note 12, interim
period segment reporting in 2006 was reclassified to conform with the current
year business segment organizations and operations. 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 7)
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) are accounted for under the equity
method. Under the equity method, the interest in the entity is reported as
an
investment in the Consolidated Balance Sheets and the percentage share of
the
entity’s earnings is reported in the Consolidated Statements of Income. Certain
prior year amounts have been reclassified to conform to the current year
presentation.
The
consolidated
financial statements as of June 30, 2007 and for the three-month and
six-month periods ended June 30, 2007 and 2006 have been reviewed by
PricewaterhouseCoopers LLP, an independent registered public accounting firm.
Their report (dated August 6, 2007) is included on page 28. 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 Act.
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 with an affiliate of Morgan Stanley
and
Co., Incorporated 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 approximately one year. The
basic
and diluted earnings per share calculations for the second quarter and first
six
months of 2007 reflect the impact associated with the March 2007 accelerated
share repurchase program. 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
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
Reconciliation
of Basic and Diluted Earnings per Share
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
338
|
|
$
|
312
|
|
$
|
628
|
|
$
|
531
|
|
Discontinued
operations
|
|
|
-
|
|
|
(8
|
)
|
|
-
|
|
|
(6
|
)
|
Redemption
premium on subsidiary preferred stock
|
|
|
-
|
|
|
(3
|
)
|
|
-
|
|
|
(3
|
)
|
Net
earnings
available for common shareholders
|
|
$
|
338
|
|
$
|
301
|
|
$
|
628
|
|
$
|
522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares
of common stock outstanding – Basic
|
|
|
304
|
|
|
328
|
|
|
309
|
|
|
328
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
4
|
|
|
2
|
|
|
4
|
|
|
2
|
|
Average
shares
of common stock outstanding – Dilutive
|
|
|
308
|
|
|
330
|
|
|
313
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from
continuing operations
|
|
$
|
1.11
|
|
$
|
0.94
|
|
$
|
2.03
|
|
$
|
1.61
|
|
Discontinued
operations
|
|
|
-
|
|
|
(0.02
|
)
|
|
-
|
|
|
(0.02
|
)
|
Net
earnings
per basic share
|
|
$
|
1.11
|
|
$
|
0.92
|
|
$
|
2.03
|
|
$
|
1.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from
continuing operations
|
|
$
|
1.10
|
|
$
|
0.93
|
|
$
|
2.01
|
|
$
|
1.60
|
|
Discontinued
operations
|
|
|
-
|
|
|
(0.02
|
)
|
|
-
|
|
|
(0.02
|
)
|
Net
earnings
per diluted share
|
|
$
|
1.10
|
|
$
|
0.91
|
|
$
|
2.01
|
|
$
|
1.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3. 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
second
quarter and six months ended June 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 $34 million and $174 million in the second
quarter and first six 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 six months ended
June 30, 2006:
|
|
Three
Months
|
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
FSG
subsidiaries
|
|
$
|
(8
|
)
|
$
|
(8
|
)
|
MYR
|
|
|
-
|
|
|
2
|
|
Total
|
|
$
|
(8
|
)
|
$
|
(6
|
)
|
4. 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 $45 million included in AOCL as of June 30, 2007, for derivative
hedging activity, as compared to $58 million as of December 31, 2006,
resulted from a net $2 million decrease related to current hedging activity
and an $11 million decrease due to net hedge losses reclassified into
earnings during the six months ended June 30, 2007. Based on current estimates,
approximately $17 million (after tax) of the net deferred losses on
derivative instruments in AOCL as of June 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 six months of
2007,
FirstEnergy unwound swaps with a total notional value of $150 million for
which it incurred $8 million in cash losses, which will be recognized over
the remaining maturity of each hedged security as interest expense. As of
June
30, 2007, FirstEnergy had interest rate swaps with an aggregate notional
value
of $600 million and a fair value of $(30) million.
During
2006 and the
first six 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 during 2007
and
2008 as outstanding debt matures. These derivatives are treated as cash flow
hedges, protecting against the risk of changes in future interest payments
resulting from changes in benchmark U.S. Treasury rates between the date
of
hedge inception and the date of the debt issuance. During the first six months
of 2007, FirstEnergy terminated swaps with a notional value of $950 million
for which it paid $2 million, all of which were deemed effective.
FirstEnergy will recognize the loss over the life of the associated future
debt.
As of June 30, 2007, FirstEnergy had forward swaps with an aggregate notional
amount of $250 million and a fair value of
$6 million.
5. 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 June 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 June 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 six months
ended
June 30, 2007 and 2006, respectively.
Three
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
|
(In
millions)
|
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
April
1, 2007
|
|
$
|
1,208
|
|
$
|
89
|
|
$
|
2
|
|
$
|
27
|
|
$
|
86
|
|
$
|
153
|
|
$
|
78
|
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Accretion
|
|
|
21
|
|
|
2
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
3
|
|
|
1
|
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
(1
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Balance,
June
30, 2007
|
|
$
|
1,228
|
|
$
|
91
|
|
$
|
2
|
|
$
|
27
|
|
$
|
87
|
|
$
|
156
|
|
$
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
April
1, 2006
|
|
$
|
1,148
|
|
$
|
84
|
|
$
|
8
|
|
$
|
25
|
|
$
|
81
|
|
$
|
144
|
|
$
|
73
|
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Liabilities
settled
|
|
|
(6
|
)
|
|
-
|
|
|
(6
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Accretion
|
|
|
18
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
1
|
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Balance,
June
30, 2006
|
|
$
|
1,160
|
|
$
|
85
|
|
$
|
2
|
|
$
|
26
|
|
$
|
82
|
|
$
|
146
|
|
$
|
74
|
|
|
Six
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
|
(In
millions)
|
|
|
ARO
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2007
|
|
$
|
1,190
|
|
$
|
88
|
|
$
|
2
|
|
$
|
27
|
|
$
|
84
|
|
$
|
151
|
|
$
|
77
|
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Accretion
|
|
|
39
|
|
|
3
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
5
|
|
|
2
|
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
(1
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Balance,
June
30, 2007
|
|
$
|
1,228
|
|
$
|
91
|
|
$
|
2
|
|
$
|
27
|
|
$
|
87
|
|
$
|
156
|
|
$
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2006
|
|
$
|
1,126
|
|
$
|
83
|
|
$
|
8
|
|
$
|
25
|
|
$
|
80
|
|
$
|
142
|
|
$
|
72
|
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Liabilities
settled
|
|
|
(6
|
)
|
|
-
|
|
|
(6
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Accretion
|
|
|
36
|
|
|
2
|
|
|
-
|
|
|
1
|
|
|
2
|
|
|
4
|
|
|
2
|
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cashflows
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Balance,
June
30, 2006
|
|
$
|
1,160
|
|
$
|
85
|
|
$
|
2
|
|
$
|
26
|
|
$
|
82
|
|
$
|
146
|
|
$
|
74
|
|
|
6. PENSION
AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy
provides
noncontributory defined benefit pension plans that cover substantially all
of
its employees. The trusteed plans provide defined benefits based on years
of
service and compensation levels. FirstEnergy’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 six months ended
June
30, 2007 and 2006 consisted of the following:
|
|
Three
Months Ended
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Pension
Benefits
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
21
|
|
$
|
21
|
|
$
|
42
|
|
$
|
41
|
|
Interest
cost
|
|
|
71
|
|
|
66
|
|
|
142
|
|
|
133
|
|
Expected
return on plan assets
|
|
|
(113
|
)
|
|
(99
|
)
|
|
(225
|
)
|
|
(198
|
)
|
Amortization
of prior service cost
|
|
|
3
|
|
|
2
|
|
|
5
|
|
|
5
|
|
Recognized
net
actuarial loss
|
|
|
11
|
|
|
15
|
|
|
21
|
|
|
29
|
|
Net
periodic
cost (credit)
|
|
$
|
(7
|
)
|
$
|
5
|
|
$
|
(15
|
)
|
$
|
10
|
|
|
|
Three
Months Ended
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Other
Postretirement Benefits
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
5
|
|
$
|
9
|
|
$
|
10
|
|
$
|
17
|
|
Interest
cost
|
|
|
17
|
|
|
26
|
|
|
34
|
|
|
52
|
|
Expected
return on plan assets
|
|
|
(12
|
)
|
|
(12
|
)
|
|
(25
|
)
|
|
(23
|
)
|
Amortization
of prior service cost
|
|
|
(37
|
)
|
|
(19
|
)
|
|
(74
|
)
|
|
(37
|
)
|
Recognized
net
actuarial loss
|
|
|
11
|
|
|
14
|
|
|
23
|
|
|
27
|
|
Net
periodic
cost (credit)
|
|
$
|
(16
|
)
|
$
|
18
|
|
$
|
(32
|
)
|
$
|
36
|
|
Pension
and other
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. FirstEnergy’s subsidiaries capitalize employee
benefits related to construction projects. The net periodic pension and other
postretirement benefit costs (including amounts capitalized) recognized by
each
of the Companies for the three months and six months ended June 30, 2007
and
2006 were as follows:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Pension
Benefit Cost (Credit)
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
(3.9
|
)
|
$
|
(1.5
|
)
|
$
|
(7.9
|
)
|
$
|
(2.9
|
)
|
CEI
|
|
|
0.3
|
|
|
1.0
|
|
|
0.6
|
|
|
1.9
|
|
TE
|
|
|
(0.1
|
)
|
|
0.2
|
|
|
(0.1
|
)
|
|
0.4
|
|
JCP&L
|
|
|
(2.2
|
)
|
|
(1.4
|
)
|
|
(4.3
|
)
|
|
(2.7
|
)
|
Met-Ed
|
|
|
(1.7
|
)
|
|
(1.7
|
)
|
|
(3.4
|
)
|
|
(3.5
|
)
|
Penelec
|
|
|
(2.5
|
)
|
|
(1.3
|
)
|
|
(5.1
|
)
|
|
(2.7
|
)
|
Other
FirstEnergy subsidiaries
|
|
|
2.6
|
|
|
9.9
|
|
|
5.1
|
|
|
20.0
|
|
|
|
$
|
(7.5
|
)
|
$
|
5.2
|
|
$
|
(15.1
|
)
|
$
|
10.5
|
|
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
Other
Postretirement Benefit Cost (Credit)
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
(2.6
|
)
|
$
|
4.2
|
|
$
|
(5.3
|
)
|
$
|
8.4
|
|
CEI
|
|
|
0.9
|
|
|
2.8
|
|
|
1.9
|
|
|
5.5
|
|
TE
|
|
|
1.2
|
|
|
2.0
|
|
|
2.4
|
|
|
4.0
|
|
JCP&L
|
|
|
(4.0
|
)
|
|
0.6
|
|
|
(8.0
|
)
|
|
1.2
|
|
Met-Ed
|
|
|
(2.6
|
)
|
|
0.7
|
|
|
(5.1
|
)
|
|
1.5
|
|
Penelec
|
|
|
(3.1
|
)
|
|
1.8
|
|
|
(6.3
|
)
|
|
3.6
|
|
Other
FirstEnergy subsidiaries
|
|
|
(5.7
|
)
|
|
6.1
|
|
|
(11.4
|
)
|
|
12.1
|
|
|
|
$
|
(15.9
|
)
|
$
|
18.2
|
|
$
|
(31.8
|
)
|
$
|
36.3
|
|
7. VARIABLE
INTEREST ENTITIES
FIN
46R addresses
the consolidation of VIEs, including special-purpose entities, that are not
controlled through voting interests or in which the equity investors do not
bear
the entity's residual economic risks and rewards. FirstEnergy and its
subsidiaries consolidate VIEs when they are determined to be the VIE's primary
beneficiary as defined by FIN 46R.
Leases
FirstEnergy’s
consolidated financial statements include PNBV and Shippingport, VIEs created
in
1996 and 1997, respectively, to refinance debt originally issued in connection
with sale and leaseback transactions. PNBV and Shippingport financial data
are
included in the consolidated financial statements of OE and CEI,
respectively.
PNBV
was established
to purchase a portion of the lease obligation bonds issued in connection
with
OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver
Valley Unit 2. OE used debt and available funds to purchase the notes issued
by
PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated
third
party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary
of OE. Shippingport was established to purchase all of the lease obligation
bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and
leaseback transaction in 1987. CEI and TE used debt and available funds to
purchase the notes issued by Shippingport.
OE,
CEI and TE are
exposed to losses under the applicable sale-leaseback agreements upon the
occurrence of certain contingent events that each company considers unlikely
to
occur. OE, CEI and TE each have a maximum exposure to loss under these
provisions of approximately $851 million, $790 million and
$790 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 $619 million,
$82 million and $442 million, respectively, that would not be payable
if the casualty value payments are made.
Power
Purchase
Agreements
In
accordance with
FIN 46R, FirstEnergy evaluated its power purchase agreements and determined
that
certain NUG entities may be VIEs to the extent they own a plant that sells
substantially all of its output to the Companies and the contract price for
power is correlated with the plant’s variable costs of production. FirstEnergy,
through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately
30 long-term power purchase agreements with NUG entities. The agreements
were
entered into pursuant to the Public Utility Regulatory Policies Act of 1978.
FirstEnergy was not involved in the creation of, and has no equity or debt
invested in, these entities.
FirstEnergy
has
determined that for all but eight of these entities, neither JCP&L, Met-Ed
nor Penelec have variable interests in the entities or the entities are
governmental or not-for-profit organizations not within the scope of FIN
46R.
JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight
entities, which sell their output at variable prices that correlate to some
extent with the operating costs of the plants. As required by FIN 46R,
FirstEnergy periodically requests from these eight entities the information
necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or
Penelec is the primary beneficiary. FirstEnergy has been unable to obtain
the
requested information, which in most cases was deemed by the requested entity
to
be proprietary. As such, FirstEnergy applied the scope exception that exempts
enterprises unable to obtain the necessary information to evaluate entities
under FIN 46R.
Since
FirstEnergy
has no equity or debt interests in the NUG entities, its maximum exposure
to
loss relates primarily to the above-market costs it incurs for power.
FirstEnergy expects any above-market costs it incurs to be recovered from
customers. As of June 30, 2007, the net above-market loss liability projected
for these eight NUG agreements was $145 million. Purchased power costs from
these entities during the three months and six months ended June 30, 2007
and
2006 are shown in the following table:
|
|
Three
Months Ended
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
JCP&L
|
|
$
|
21
|
|
$
|
19
|
|
$
|
41
|
|
$
|
34
|
|
Met-Ed
|
|
|
12
|
|
|
16
|
|
|
27
|
|
|
33
|
|
Penelec
|
|
|
7
|
|
|
7
|
|
|
15
|
|
|
14
|
|
Total
|
|
$
|
40
|
|
$
|
42
|
|
$
|
83
|
|
$
|
81
|
|
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 June 30, 2007, $411 million of the transition bonds are
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 that is
payable from TBC collections.
8. 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 affect the
effective tax rate would be purchase accounting adjustments to goodwill upon
recognition. During the first six months of 2007, there were no material
changes
to FirstEnergy’s unrecognized tax benefits. As of June 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 12 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 six 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.
In
the first six
months of 2007, OE’s income taxes included an immaterial adjustment applicable
to prior periods of $7.2 million related to an inter-company federal tax
allocation arrangement among FirstEnergy and its subsidiaries.
9. COMMITMENTS,
GUARANTEES AND CONTINGENCIES
(A) GUARANTEES
AND OTHER
ASSURANCES
As
part of normal
business activities, FirstEnergy enters into various agreements on behalf
of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. As of
June 30, 2007, outstanding guarantees and other assurances aggregated
approximately $4.1 billion, consisting of contract guarantees -
$2.3 billion, surety bonds - $0.1 billion and LOCs - $1.7
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 $0.8 billion
(included in the $2.3 billion discussed above) as of June 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
June 30, 2007, FirstEnergy's maximum exposure under these collateral
provisions was $421 million.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of
$95 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
June 30, 2007), which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA.
On
July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Plant 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. The transaction
will be
classified as a financing under GAAP until FGCO’s and 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 are satisfied, at which time it is expected to be classified
as
an operating lease under GAAP. This transaction generated tax capital gains
of
approximately $830 million, a substantial portion of which will be offset
by existing tax capital loss carryforwards. FirstEnergy expects to
reduce its tax loss carryforward valuation allowances in the third quarter
of
2007 and anticipates an immaterial impact to net income as the majority of
the
unrecognized tax benefits will reduce goodwill.
(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 July 25, 2007, FirstEnergy and PennFuture
entered into a Tolling and Confidentiality Agreement that provides for a
60-day
negotiation period during which the parties have agreed to not file a
lawsuit.
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-fired generation facilities
will be subject to caps on SO2 and NOX
emissions, whereas
its New Jersey fossil-fired generation facility will be subject to only a
cap on
NOX emissions.
According to the EPA, SO2 emissions
will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the
rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions
in
affected states to just 2.5 million tons annually. NOX emissions
will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the
rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOX cap of
1.3
million tons annually. The future cost of compliance with these regulations
may
be substantial and will depend on how they are ultimately implemented by
the
states in which FirstEnergy operates affected facilities.
Mercury
Emissions
In
December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury
as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases. Initially, mercury emissions
will be
capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation
of SO2 and
NOX emission
caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade
program will cap nationwide mercury emissions from coal-fired power plants
at
15 tons per year by 2018. However, the final rules give states substantial
discretion in developing rules to implement these programs. In addition,
both
the CAIR and the CAMR have been challenged in the United States Court of
Appeals
for the District of Columbia. FirstEnergy's future cost of compliance with
these
regulations may be substantial and will depend on how they are ultimately
implemented by the states in which FirstEnergy operates affected
facilities.
The
model rules for
both CAIR and CAMR contemplate an input-based methodology to allocate allowances
to affected facilities. Under this approach, allowances would be allocated
based
on the amount of fuel consumed by the affected sources. FirstEnergy would
prefer
an output-based generation-neutral methodology in which allowances are allocated
based on megawatts of power produced, 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 June 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, 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 June
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 $88 million (JCP&L - $60 million, TE
- $3 million, CEI - $1 million, and other subsidiaries - $24 million) have
been accrued through June 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
on
July 8, 2004, affirming the decertification of the originally certified class,
but remanding for certification of a class limited to those customers directly
impacted by the outages of JCP&L transformers in Red Bank, 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, on March 7, 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
on
May 9, 2007. Proceedings are continuing in the Superior
Court. FirstEnergy is vigorously defending this class action but is
unable to predict the outcome of this matter. No liability has been
accrued as of June 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., 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 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.
On
October 10, 2006,
various insurance carriers refiled a complaint in Cuyahoga County Common
Pleas
Court seeking reimbursement for claims paid to numerous insureds who allegedly
suffered losses as a result of the August 14, 2003 outages. All of the insureds
appear to be non-customers. The plaintiff insurance companies are the same
claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies
and
Penn were served on October 27, 2006. On January 18, 2007, the Court
granted the Companies’ motion to dismiss the case and they have not been
appealed. However, on April 25, 2007, one of the insurance carriers
refiled the complaint naming only FirstEnergy as the defendant. On
July 30, 2007, the case was voluntarily dismissed. No estimate of
potential liability is available for any of these cases.
FirstEnergy
was also
named, along with several other entities, in a complaint in New Jersey State
Court. The allegations against FirstEnergy were based, in part, on an alleged
failure to protect the citizens of Jersey City from an electrical power outage.
None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive
pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's
motion to dismiss. The plaintiff has not appealed.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. Although 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
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take
prompt
and corrective action. On April 4, 2005, the NRC held a public meeting to
discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in
the NRC's annual assessment letter to FENOC. Similar public meetings are
held
with all nuclear power plant licensees following issuance by the NRC of their
annual assessments. According to the NRC, overall the Perry Nuclear Power
Plant
operated "in a manner that preserved public health and safety" even though
it
remained under heightened NRC oversight. During the public meeting and in
the
annual assessment, the NRC indicated that additional inspections would continue
and that the plant must improve performance to be removed from the
Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Nuclear Power Plant
and
stated that the CAL would remain open until substantial improvement was
demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight
Process. By two letters dated March 2, 2007, the NRC closed the CAL
commitments for Perry, the two outstanding white findings, and crosscutting
issues. Moreover, the NRC removed Perry from the Multiple Degraded
Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee
Response Column (regular agency oversight).
On
April 30, 2007,
the UCS filed a petition with the NRC under Section 2.206 of the NRC’s
regulations based on a report prepared at FENOC’s request by expert witnesses
for an insurance arbitration. In December 2006, the expert witnesses
for FENOC completed a report that analyzed the crack growth rates in control
rod
drive mechanism penetrations and wastage of the former reactor pressure vessel
head at Davis-Besse. Citing the findings in the expert witness'
report, the Section 2.206 petition requested that: (1) Davis-Besse be
immediately shut down; (2) that the NRC conduct an independent review of
the
consultant's report and that all pressurized water reactors be shut down
until
remedial actions can be implemented; and (3) Davis-Besse’s operating license be
revoked.
In
a letter dated
May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV)
head inspection requirements are adequate to detect RPV degradation issues
before they result in significant corrosion.” The NRC also indicated that, “no
immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to
shut down the facility). On June 18, 2007, the NRC Petition
Review Board indicated that the agency had initially denied petitioner’s other
requests, and provided an opportunity for UCS to provide additional information
prior to the final determination. By letter dated July 12, 2007, the NRC
denied the remainder of the UCS petition.
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
the expert witnesses’ report and another report. The NRC indicated that this
information is 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. FirstEnergy can provide no assurances as to the
ultimate resolution of this matter.
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 plaintiff’s motion to amend their complaint which OE
has opposed.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. JCP&L
intends to re-file an appeal again in federal district court once the damages
associated with this case are identified at an individual employee level.
JCP&L recognized a liability for the potential $16 million award in
2005. The parties met on June 27, 2007 before an arbitrator to assert their
positions regarding the finality of damages. A hearing before the arbitrator
is
set for September 7, 2007.
The
union employees
at the W. H. Sammis Plant have been working without a labor contract since
July
1, 2007. The union expects to vote on a new contract on August 9, 2007.
While it
is expected the union will ratify a new contract, FirstEnergy has a strike
mitigation plan ready in the event of a strike.
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.
10. 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
partly to amend the Federal Power Act with Section 215, which requires that
an
ERO establish and enforce reliability standards for the bulk-power system,
subject to review of 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.
While
the FERC
approved 83 of the 107 reliability standards proposed by NERC, the FERC has
directed NERC to submit improvements to 56 of them, endorsing NERC's process
for
developing reliability standards and its associated work plan. On May 4,
2007,
NERC also submitted 24 proposed Violation Risk Factors. The FERC
issued an order approving 22 of those factors on June 26, 2007. Further,
NERC
adopted eight cyber security standards that became effective on June 1,
2006 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 assessment by February 12, 2007. The standards remain pending before
the FERC. On July 20, 2007, the FERC issued a NOPR proposing to adopt
eight Critical Infrastructure Protection Reliability
Standards. Comments will not be due to the FERC until September or
October of 2007.
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 will eventually
adopt
stricter NERC reliability 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
October 21, 2003,
the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004,
the
Ohio Companies accepted the RSP as modified and approved by the PUCO in an
August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended
to
establish generation service rates beginning January 1, 2006, in response
to the
PUCO’s concerns about price and supply uncertainty following the end of the Ohio
Companies' transition plan market development period. On May 3, 2006, the
Supreme Court of Ohio issued an opinion affirming the PUCO's order in all
respects, except it remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the marketplace.
The RSP contained a provision that permitted the Ohio Companies to withdraw
and
terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio,
rejected all or part of the RSP. In such event, the Ohio Companies have 30
days
from the final order or decision to provide notice of termination. On July
20,
2006, the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding
on Remand. In their Request, the Ohio Companies provided notice of termination
to those provisions of the RSP subject to termination, subject to being
withdrawn, and also set forth a framework for addressing the Supreme Court
of
Ohio’s findings on customer participation. If the PUCO approves a resolution to
the issues raised by the Supreme Court of Ohio that is acceptable to the
Ohio
Companies, the Ohio Companies’ termination will be withdrawn and considered to
be null and void. On July 20, 2006, the OCC and NOAC also submitted to the
PUCO a conceptual proposal addressing the issue raised by the Supreme Court
of
Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies
to
file a plan in a new docket to address the Court’s concern. The Ohio Companies
filed their RSP Remand CBP on September 29, 2006. Initial comments were
filed on January 12, 2007 and reply comments were filed on January 29,
2007. In their reply comments the Ohio Companies described the highlights
of a
new tariff offering they would be willing to make available to customers
that
would allow customers to purchase renewable energy certificates associated
with
a renewable generation source, subject to PUCO approval. On May 29, 2007,
the Ohio Companies, together with the PUCO Staff and the OCC, filed a
stipulation with the PUCO agreeing to offer a standard bid product and a
green
resource tariff product. The stipulation is currently pending before the
PUCO.
No further proceedings are scheduled at this time.
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
provided an update 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 late 2007. The PUCO order is expected to
be
issued by March 9, 2008. The new rates, subject to evidentiary hearings and
approval at the PUCO, 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 Ohio Companies requested
that the PUCO issue an order by November 1, 2007, to provide sufficient time
to
conduct the bidding process. The PUCO has scheduled a technical conference
for
August 16, 2007.
(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 costs during the term of these
agreements with FES.
On
April 7,
2006, the parties entered into a tolling agreement that arose from FES’ notice
to Met-Ed and Penelec that FES elected to exercise its right to terminate
the
partial requirements agreement effective midnight December 31, 2006. On
November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7
tolling agreement pending resolution of the PPUC’s proceedings regarding the
Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006,
described below. Separately, 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 substantially exceed 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
tolling, suspension and 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 in accordance with the April 7, 2006
tolling agreement described above. Met-Ed and Penelec also requested approval
of
a January 12, 2005 petition for the deferral of transmission-related costs,
but only for those costs incurred during 2006. In this rate filing, Met-Ed
and
Penelec also requested recovery of annual transmission and related costs
incurred on or after January 1, 2007, plus the amortized portion of 2006
costs over a ten-year period, along with applicable carrying charges, through
an
adjustable rider. 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 the merger savings,
with the comprehensive transmission 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 by all
parties. Responsive briefs are due August 20, 2007, with reply briefs due
September 4, 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 June 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 $493 million and $127 million, respectively. $82 million of
Penelec’s deferral is subject to final resolution of an IRS settlement
associated with NUG trust fund proceeds. 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
late 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. The PPUC is requested to act on the proposal
no
later than November 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 will be 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 June 30, 2007, the accumulated deferred
cost
balance totaled approximately $392 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
Energy Master Plan (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;
·
Unit prices for electricity should remain 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 August 1,
2007, the NJBPU approved publication of a formal proposal in the New Jersey
Register, which proposal will be subsequently considered by the NJBPU following
a period for public comment. 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 third 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 and Electric Company 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 American Electric Power Company, Inc.,
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.
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 maintain
existing transmission rates between MISO and PJM. If accepted 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 transmission facilities across the
entire
MISO footprint be maintained. All of these filings were supported by
the majority of transmission owners in either MISO or PJM.
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
transmission facilities be spread throughout the entire MISO
footprint. If adopted by the FERC, this proposal would shift a
greater portion of the cost of new 345 kV transmission facilities to the
FirstEnergy footprint, and increase the transmission rates paid by load-serving
FirstEnergy affiliates.
American
Electric
Power (AEP) filed a letter with the FERC Commissioners stating its intent
to
file a complaint under Section 206 of the Federal Power Act challenging the
justness and reasonableness of the rate designs underlying the MISO and PJM
transmission tariffs. AEP will propose the adoption of a regional
rate design that is expected to reallocate the cost of both existing and
new
high voltage transmission facilities across the combined MISO and PJM
footprint. Based upon the position advocated by AEP in a related
proceeding, the AEP proposal is expected to result in a greater allocation
of
costs to FirstEnergy transmission zones in MISO and PJM. If approved
by the FERC, AEP’s proposal would increase the transmission rates paid by
load-serving FirstEnergy affiliates.
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.
On
February 15,
2007, MISO filed documents with the FERC to establish a market-based,
competitive ancillary services market. MISO contends that the filing
will integrate operating reserves into MISO’s existing day-ahead and real-time
settlements process, incorporate opportunity costs into these markets, address
scarcity pricing through the implementation of a demand curve methodology,
foster demand response in the provision of operating reserves, and provide
for
various efficiencies and optimization with regard to generation
dispatch. The filing also proposes amendments to existing documents
to provide for the transfer of balancing functions from existing local balancing
authorities to MISO. MISO will then carry out this reliability
function as the NERC-certified balancing authority for the MISO region with
implementation in the third or fourth quarter of 2008. FirstEnergy
filed comments on March 23, 2007, supporting the ancillary service market
in
concept, but proposing certain changes in MISO’s proposal. MISO requested FERC
action on its filing by June 2007 and the FERC issued its Order June 22,
2007.
The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not
submitted a market power analysis in support of its proposed Ancillary Services
Market and (2) MISO has not submitted a readiness plan to ensure reliability
during the transition from the current reserve and regulation system managed
by
the individual Balancing Authorities to a centralized Ancillary Services
Market
managed by MISO. MISO was ordered to remedy these deficiencies and the FERC
provided more guidance on other issues brought up in filings by stakeholders
to
assist MISO to re-file a complete proposal. This Order should facilitate
MISO’s
timetable to incorporate final revisions to ensure a market start in Spring
2008. FirstEnergy will be participating in working groups and task forces
to
ensure the Spring 2008 implementation of the Ancillary Services Market.
On
February 16,
2007, the FERC issued a final rule 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. As a market participant in both MISO
and PJM, FirstEnergy will conform its business practices to each respective
revised tariff.
11. NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
|
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.
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.
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
effect on FirstEnergy’s financial statements.
12. SEGMENT
INFORMATION
Effective
January 1, 2007, FirstEnergy has three reportable operating segments:
competitive energy services, energy delivery services and Ohio transitional
generation services. None of the aggregate “Other” segments individually meet
the criteria to be considered a reportable segment. 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 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 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, provides competitive electric sales primarily in Ohio, Pennsylvania,
Maryland and Michigan and owns 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
commodity 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
securing electric generation from the competitive energy services segment
through full requirements PSA arrangements and the net MISO transmission
revenues and expenses related to the delivery of that generation
load.
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 Items."
Segment
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
|
|
|
Reconciling
|
|
|
|
|
Three
Months Ended
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Other
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
June
30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
2,095
|
|
|
$ |
404
|
|
|
$ |
625
|
|
|
$ |
9
|
|
|
$ |
(24 |
) |
|
$ |
3,109
|
|
Internal
revenues
|
|
|
-
|
|
|
|
691
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(691 |
) |
|
|
-
|
|
Total
revenues
|
|
|
2,095
|
|
|
|
1,095
|
|
|
|
625
|
|
|
|
9
|
|
|
|
(715 |
) |
|
|
3,109
|
|
Depreciation
and amortization
|
|
|
249
|
|
|
|
51
|
|
|
|
(49 |
) |
|
|
1
|
|
|
|
5
|
|
|
|
257
|
|
Investment
income
|
|
|
62
|
|
|
|
5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(37 |
) |
|
|
30
|
|
Net
interest
charges
|
|
|
116
|
|
|
|
42
|
|
|
|
-
|
|
|
|
1
|
|
|
|
39
|
|
|
|
198
|
|
Income
taxes
|
|
|
141
|
|
|
|
96
|
|
|
|
19
|
|
|
|
(3 |
) |
|
|
(31 |
) |
|
|
222
|
|
Net
income
|
|
|
207
|
|
|
|
142
|
|
|
|
30
|
|
|
|
6
|
|
|
|
(47 |
) |
|
|
338
|
|
Total
assets
|
|
|
23,602
|
|
|
|
7,284
|
|
|
|
260
|
|
|
|
236
|
|
|
|
651
|
|
|
|
32,033
|
|
Total
goodwill
|
|
|
5,873
|
|
|
|
24
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
5,898
|
|
Property
additions
|
|
|
245
|
|
|
|
139
|
|
|
|
-
|
|
|
|
2
|
|
|
|
15
|
|
|
|
401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
1,773
|
|
|
$ |
384
|
|
|
$ |
575
|
|
|
$ |
39
|
|
|
$ |
(20 |
) |
|
$ |
2,751
|
|
Internal
revenues
|
|
|
6
|
|
|
|
623
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(629 |
) |
|
|
-
|
|
Total
revenues
|
|
|
1,779
|
|
|
|
1,007
|
|
|
|
575
|
|
|
|
39
|
|
|
|
(649 |
) |
|
|
2,751
|
|
Depreciation
and amortization
|
|
|
173
|
|
|
|
48
|
|
|
|
(29 |
) |
|
|
1
|
|
|
|
6
|
|
|
|
199
|
|
Investment
income
|
|
|
81
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(52 |
) |
|
|
31
|
|
Net
interest
charges
|
|
|
102
|
|
|
|
47
|
|
|
|
-
|
|
|
|
2
|
|
|
|
22
|
|
|
|
173
|
|
Income
taxes
|
|
|
155
|
|
|
|
67
|
|
|
|
22
|
|
|
|
2
|
|
|
|
(30 |
) |
|
|
216
|
|
Income
from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
continuing
operations
|
|
|
233
|
|
|
|
101
|
|
|
|
31
|
|
|
|
(7 |
) |
|
|
(46 |
) |
|
|
312
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8 |
) |
|
|
-
|
|
|
|
(8 |
) |
Net
income
|
|
|
233
|
|
|
|
101
|
|
|
|
31
|
|
|
|
(15 |
) |
|
|
(46 |
) |
|
|
304
|
|
Total
assets
|
|
|
24,399
|
|
|
|
6,740
|
|
|
|
231
|
|
|
|
355
|
|
|
|
853
|
|
|
|
32,578
|
|
Total
goodwill
|
|
|
5,916
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,940
|
|
Property
additions
|
|
|
177
|
|
|
|
103
|
|
|
|
-
|
|
|
|
-
|
|
|
|
12
|
|
|
|
292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
4,135
|
|
|
$ |
732
|
|
|
$ |
1,245
|
|
|
$ |
20
|
|
|
$ |
(50 |
) |
|
$ |
6,082
|
|
Internal
revenues
|
|
|
-
|
|
|
|
1,404
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,404 |
) |
|
|
-
|
|
Total
revenues
|
|
|
4,135
|
|
|
|
2,136
|
|
|
|
1,245
|
|
|
|
20
|
|
|
|
(1,454 |
) |
|
|
6,082
|
|
Depreciation
and amortization
|
|
|
469
|
|
|
|
102
|
|
|
|
(64 |
) |
|
|
2
|
|
|
|
11
|
|
|
|
520
|
|
Investment
income
|
|
|
132
|
|
|
|
8
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(78 |
) |
|
|
63
|
|
Net
interest
charges
|
|
|
223
|
|
|
|
92
|
|
|
|
1
|
|
|
|
2
|
|
|
|
60
|
|
|
|
378
|
|
Income
taxes
|
|
|
289
|
|
|
|
160
|
|
|
|
35
|
|
|
|
2
|
|
|
|
(64 |
) |
|
|
422
|
|
Net
income
|
|
|
425
|
|
|
|
240
|
|
|
|
53
|
|
|
|
7
|
|
|
|
(97 |
) |
|
|
628
|
|
Total
assets
|
|
|
23,602
|
|
|
|
7,284
|
|
|
|
260
|
|
|
|
236
|
|
|
|
651
|
|
|
|
32,033
|
|
Total
goodwill
|
|
|
5,873
|
|
|
|
24
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
5,898
|
|
Property
additions
|
|
|
400
|
|
|
|
263
|
|
|
|
-
|
|
|
|
3
|
|
|
|
31
|
|
|
|
697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
3,570
|
|
|
$ |
738
|
|
|
$ |
1,118
|
|
|
$ |
68
|
|
|
$ |
(38 |
) |
|
$ |
5,456
|
|
Internal
revenues
|
|
|
14
|
|
|
|
1,235
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,249 |
) |
|
|
-
|
|
Total
revenues
|
|
|
3,584
|
|
|
|
1,973
|
|
|
|
1,118
|
|
|
|
68
|
|
|
|
(1,287 |
) |
|
|
5,456
|
|
Depreciation
and amortization
|
|
|
430
|
|
|
|
94
|
|
|
|
(49 |
) |
|
|
2
|
|
|
|
11
|
|
|
|
488
|
|
Investment
income
|
|
|
164
|
|
|
|
17
|
|
|
|
-
|
|
|
|
1
|
|
|
|
(108 |
) |
|
|
74
|
|
Net
interest
charges
|
|
|
201
|
|
|
|
90
|
|
|
|
1
|
|
|
|
3
|
|
|
|
38
|
|
|
|
333
|
|
Income
taxes
|
|
|
281
|
|
|
|
89
|
|
|
|
40
|
|
|
|
(3 |
) |
|
|
(55 |
) |
|
|
352
|
|
Income
from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
continuing
operations
|
|
|
422
|
|
|
|
133
|
|
|
|
61
|
|
|
|
5
|
|
|
|
(90 |
) |
|
|
531
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(6 |
) |
|
|
-
|
|
|
|
(6 |
) |
Net
income
|
|
|
422
|
|
|
|
133
|
|
|
|
61
|
|
|
|
(1 |
) |
|
|
(90 |
) |
|
|
525
|
|
Total
assets
|
|
|
24,399
|
|
|
|
6,740
|
|
|
|
231
|
|
|
|
355
|
|
|
|
853
|
|
|
|
32,578
|
|
Total
goodwill
|
|
|
5,916
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,940
|
|
Property
additions
|
|
|
370
|
|
|
|
347
|
|
|
|
-
|
|
|
|
-
|
|
|
|
22
|
|
|
|
739
|
|
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.
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
utilities
|
|
$ |
2,744
|
|
|
$ |
2,341
|
|
|
$ |
5,425
|
|
|
$ |
4,681
|
|
Unregulated
businesses
|
|
|
365
|
|
|
|
410
|
|
|
|
657
|
|
|
|
775
|
|
Total
revenues
*
|
|
|
3,109
|
|
|
|
2,751
|
|
|
|
6,082
|
|
|
|
5,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
1,185
|
|
|
|
991
|
|
|
|
2,306
|
|
|
|
1,989
|
|
Other
operating expenses
|
|
|
750
|
|
|
|
718
|
|
|
|
1,499
|
|
|
|
1,471
|
|
Provision
for
depreciation
|
|
|
159
|
|
|
|
144
|
|
|
|
315
|
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
|
246
|
|
|
|
201
|
|
|
|
497
|
|
|
|
422
|
|
Deferral
of
new regulatory assets
|
|
|
(148 |
) |
|
|
(146 |
) |
|
|
(292 |
) |
|
|
(226 |
) |
General
taxes
|
|
|
189
|
|
|
|
173
|
|
|
|
392
|
|
|
|
366
|
|
Total
expenses
|
|
|
2,381
|
|
|
|
2,081
|
|
|
|
4,717
|
|
|
|
4,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
728
|
|
|
|
670
|
|
|
|
1,365
|
|
|
|
1,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
30
|
|
|
|
31
|
|
|
|
63
|
|
|
|
74
|
|
Interest
expense
|
|
|
(205 |
) |
|
|
(178 |
) |
|
|
(390 |
) |
|
|
(343 |
) |
Capitalized
interest
|
|
|
7
|
|
|
|
7
|
|
|
|
12
|
|
|
|
14
|
|
Subsidiaries’
preferred stock dividends
|
|
|
-
|
|
|
|
(2 |
) |
|
|
-
|
|
|
|
(4 |
) |
Total
other
expense
|
|
|
(168 |
) |
|
|
(142 |
) |
|
|
(315 |
) |
|
|
(259 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
|
|
|
560
|
|
|
|
528
|
|
|
|
1,050
|
|
|
|
883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
222
|
|
|
|
216
|
|
|
|
422
|
|
|
|
352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
FROM CONTINUING OPERATIONS
|
|
|
338
|
|
|
|
312
|
|
|
|
628
|
|
|
|
531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income tax expense (benefits) of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1
million and
($1) million in the three months and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
six
months
ended June 30, 2006, respectively) (Note 3)
|
|
|
-
|
|
|
|
(8 |
) |
|
|
-
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
338
|
|
|
$ |
304
|
|
|
$ |
628
|
|
|
$ |
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$ |
1.11
|
|
|
$ |
0.94
|
|
|
$ |
2.03
|
|
|
$ |
1.61
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
(0.02 |
) |
|
|
-
|
|
|
|
(0.02 |
) |
Net
earnings
per basic share
|
|
$ |
1.11
|
|
|
$ |
0.92
|
|
|
$ |
2.03
|
|
|
$ |
1.59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
304
|
|
|
|
328
|
|
|
|
309
|
|
|
|
328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$ |
1.10
|
|
|
$ |
0.93
|
|
|
$ |
2.01
|
|
|
$ |
1.60
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
(0.02 |
) |
|
|
-
|
|
|
|
(0.02 |
) |
Net
earnings
per diluted share
|
|
$ |
1.10
|
|
|
$ |
0.91
|
|
|
$ |
2.01
|
|
|
$ |
1.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
308
|
|
|
|
330
|
|
|
|
313
|
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$ |
0.50
|
|
|
$ |
0.45
|
|
|
$ |
1.00
|
|
|
$ |
0.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Includes
excise tax collections of $102 million and $90 million in the
second
quarter of 2007 and 2006, respectively, and $206
million
|
and $189 million in the six months ended June 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
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
338
|
|
|
$ |
304
|
|
|
$ |
628
|
|
|
$ |
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(11 |
) |
|
|
-
|
|
|
|
(22 |
) |
|
|
-
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
(1 |
) |
|
|
36
|
|
|
|
20
|
|
|
|
73
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
46
|
|
|
|
(24 |
) |
|
|
63
|
|
|
|
13
|
|
Other
comprehensive income
|
|
|
34
|
|
|
|
12
|
|
|
|
61
|
|
|
|
86
|
|
Income
tax
expense related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
10
|
|
|
|
4
|
|
|
|
19
|
|
|
|
31
|
|
Other
comprehensive income, net of tax
|
|
|
24
|
|
|
|
8
|
|
|
|
42
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
$ |
362
|
|
|
$ |
312
|
|
|
$ |
670
|
|
|
$ |
580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
37
|
|
|
$ |
90
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $39 million and
|
|
|
|
|
|
|
|
|
$43
million,
respectively, for uncollectible accounts)
|
|
|
1,413
|
|
|
|
1,135
|
|
Other
(less
accumulated provisions of $22 million and
|
|
|
|
|
|
|
|
|
$24
million,
respectively, for uncollectible accounts)
|
|
|
181
|
|
|
|
132
|
|
Materials
and
supplies, at average cost
|
|
|
583
|
|
|
|
577
|
|
Prepayments
and other
|
|
|
322
|
|
|
|
149
|
|
|
|
|
2,536
|
|
|
|
2,083
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
24,555
|
|
|
|
24,105
|
|
Less
-
Accumulated provision for depreciation
|
|
|
10,330
|
|
|
|
10,055
|
|
|
|
|
14,225
|
|
|
|
14,050
|
|
Construction
work in progress
|
|
|
785
|
|
|
|
617
|
|
|
|
|
15,010
|
|
|
|
14,667
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
2,092
|
|
|
|
1,977
|
|
Investments
in
lease obligation bonds
|
|
|
738
|
|
|
|
811
|
|
Other
|
|
|
734
|
|
|
|
746
|
|
|
|
|
3,564
|
|
|
|
3,534
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
5,898
|
|
|
|
5,898
|
|
Regulatory
assets
|
|
|
4,155
|
|
|
|
4,441
|
|
Pension
assets
|
|
|
297
|
|
|
|
-
|
|
Other
|
|
|
573
|
|
|
|
573
|
|
|
|
|
10,923
|
|
|
|
10,912
|
|
|
|
$ |
32,033
|
|
|
$ |
31,196
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
2,000
|
|
|
$ |
1,867
|
|
Short-term
borrowings
|
|
|
2,416
|
|
|
|
1,108
|
|
Accounts
payable
|
|
|
801
|
|
|
|
726
|
|
Accrued
taxes
|
|
|
320
|
|
|
|
598
|
|
Other
|
|
|
745
|
|
|
|
956
|
|
|
|
|
6,282
|
|
|
|
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
|
|
|
5,550
|
|
|
|
6,466
|
|
Accumulated
other comprehensive loss
|
|
|
(217 |
) |
|
|
(259 |
) |
Retained
earnings
|
|
|
3,279
|
|
|
|
2,806
|
|
Unallocated
employee stock ownership plan common stock-
|
|
|
|
|
|
|
|
|
134,681
and
521,818 shares, respectively
|
|
|
(2 |
) |
|
|
(10 |
) |
Total
common
stockholders' equity
|
|
|
8,640
|
|
|
|
9,035
|
|
Long-term
debt
and other long-term obligations
|
|
|
8,742
|
|
|
|
8,535
|
|
|
|
|
17,382
|
|
|
|
17,570
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
2,849
|
|
|
|
2,740
|
|
Asset
retirement obligations
|
|
|
1,228
|
|
|
|
1,190
|
|
Power
purchase
contract loss liability
|
|
|
877
|
|
|
|
1,182
|
|
Retirement
benefits
|
|
|
917
|
|
|
|
944
|
|
Lease
market
valuation liability
|
|
|
704
|
|
|
|
767
|
|
Other
|
|
|
1,794
|
|
|
|
1,548
|
|
|
|
|
8,369
|
|
|
|
8,371
|
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
32,033
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
628
|
|
|
$ |
525
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
315
|
|
|
|
292
|
|
Amortization
of regulatory assets
|
|
|
497
|
|
|
|
421
|
|
Deferral
of
new regulatory assets
|
|
|
(292 |
) |
|
|
(226 |
) |
Nuclear
fuel
and lease amortization
|
|
|
50
|
|
|
|
42
|
|
Deferred
purchased power and other costs
|
|
|
(185 |
) |
|
|
(239 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
85
|
|
|
|
32
|
|
Investment
impairment
|
|
|
12
|
|
|
|
12
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(92 |
) |
|
|
(105 |
) |
Accrued
compensation and retirement benefits
|
|
|
(69 |
) |
|
|
33
|
|
Commodity
derivative transactions, net
|
|
|
4
|
|
|
|
25
|
|
Gain
on asset
sales
|
|
|
(12 |
) |
|
|
(4 |
) |
Income
from
discontinued operations
|
|
|
-
|
|
|
|
6
|
|
Cash
collateral
|
|
|
(19 |
) |
|
|
(55 |
) |
Pension
trust
contribution
|
|
|
(300 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(282 |
) |
|
|
83
|
|
Materials
and
supplies
|
|
|
22
|
|
|
|
(71 |
) |
Prepayments
and other current assets
|
|
|
(157 |
) |
|
|
(159 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
28
|
|
|
|
(40 |
) |
Accrued
taxes
|
|
|
(17 |
) |
|
|
(45 |
) |
Electric
service prepayment programs
|
|
|
(36 |
) |
|
|
(29 |
) |
Other
|
|
|
(49 |
) |
|
|
(13 |
) |
Net
cash
provided from operating activities
|
|
|
131
|
|
|
|
485
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
800
|
|
|
|
1,053
|
|
Short-term
borrowings, net
|
|
|
1,308
|
|
|
|
371
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(918 |
) |
|
|
-
|
|
Preferred
stock
|
|
|
-
|
|
|
|
(30 |
) |
Long-term
debt
|
|
|
(471 |
) |
|
|
(485 |
) |
Net
controlled
disbursement activity
|
|
|
32
|
|
|
|
5
|
|
Stock-based
compensation tax benefit
|
|
|
14
|
|
|
|
-
|
|
Common
stock
dividend payments
|
|
|
(311 |
) |
|
|
(296 |
) |
Net
cash
provided from financing activities
|
|
|
454
|
|
|
|
618
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(697 |
) |
|
|
(739 |
) |
Proceeds
from
asset sales
|
|
|
12
|
|
|
|
63
|
|
Sales
of
investment securities held in trusts
|
|
|
583
|
|
|
|
959
|
|
Purchases
of
investment securities held in trusts
|
|
|
(591 |
) |
|
|
(966 |
) |
Cash
investments
|
|
|
54
|
|
|
|
118
|
|
Other
|
|
|
1
|
|
|
|
(19 |
) |
Net
cash used
for investing activities
|
|
|
(638 |
) |
|
|
(584 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(53 |
) |
|
|
519
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
90
|
|
|
|
64
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
37
|
|
|
$ |
583
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
FirstEnergy
Corp. are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholders
and Board of
Directors
of
FirstEnergy Corp.:
We
have reviewed the
accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of June 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2007 and 2006 and the consolidated statement of cash
flows for the six-month periods ended June 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, 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
August
6,
2007
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE
SUMMARY
Net
income in the
second quarter of 2007 was $338 million, or basic earnings of $1.11 per share
of
common stock ($1.10 diluted), compared with net income of $304 million, or
basic
earnings of $0.92 per share of common stock ($0.91 diluted) in the second
quarter of 2006. Net income in the first six months of 2007 was $628 million,
or
basic earnings of $2.03 per share of common stock ($2.01 diluted), compared
with
net income of $525 million, or basic earnings of $1.59 per share of common
stock
($1.58 diluted) in the first six months of 2006. The increases in FirstEnergy’s
earnings in both periods of 2007 were driven primarily by higher electric
sales
revenues, partially offset by increased fuel and purchased power costs, higher
other operating expenses and increased interest expense.
Change
in Basic Earnings Per Share
From
Prior Year Periods
|
|
Three
Months Ended June 30,
|
|
Six
Months
Ended
June 30,
|
|
|
|
|
|
|
|
|
|
Basic
Earnings
Per Share – 2006
|
|
$
|
0.92
|
|
$
|
1.59
|
|
Revenues
|
|
|
0.71
|
|
|
1.22
|
|
Fuel
and
purchased power
|
|
|
(0.38
|
)
|
|
(0.62
|
)
|
Depreciation
and amortization
|
|
|
(0.12
|
)
|
|
(0.19
|
)
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
0.08
|
|
Other
expenses
|
|
|
(0.03
|
)
|
|
(0.10
|
)
|
Non-core
asset
sales/impairments - 2006
|
|
|
0.03
|
|
|
0.03
|
|
Saxton
decommissioning regulatory asset -2007
|
|
|
-
|
|
|
0.05
|
|
Trust
securities impairment - 2007
|
|
|
(0.02
|
)
|
|
(0.03
|
)
|
Basic
Earnings
Per Share – 2007
|
|
$
|
1.11
|
|
$
|
2.03
|
|
Financial
Matters
On
July 13, 2007,
FGCO completed a $1.3 billion sale and leaseback transaction for its 779
MW
portion of the Bruce Mansfield Plant Unit 1. The terms of the agreement provide
for an approximate 33-year lease of the unit. There will be no material gain
from this transaction reflected in earnings during the third quarter of 2007.
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. FGCO will
continue to operate the plant.
On
May 21, 2007,
JCP&L issued $550 million of senior unsecured debt securities. The offering
was in two tranches, consisting of $250 million of 5.65% Senior Notes due
2017
and $300 million of 6.15% Senior Notes due 2037. The proceeds from
the transaction were used to redeem all of JCP&L’s outstanding first
mortgage bonds, repay short-term debt and repurchase common stock from
FirstEnergy.
Regulatory
Matters
Ohio
On
June 7, 2007, the
Ohio Companies filed their base distribution rate increase request and
supporting testimony with the PUCO. The requested increase (updated
on August 6, 2007) in annualized distribution revenues of approximately
$332 million is needed to recover expenses related to distribution operations
and the costs deferred under previously approved rate plans. Concurrent with
the
effective dates of the proposed distribution rate increases, the Ohio Companies
will reduce or eliminate their RTC, resulting in a net reduction of $262
million
on the regulated portion of customers’ bills. The PUCO Staff is expected to
issue its report in the case in the fourth quarter of 2007 with evidentiary
hearings to follow in late 2007. The PUCO order is expected to be
issued by March 9, 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 included in rates 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 also 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 Ohio Companies requested that the PUCO issue an order by November 1,
2007,
to provide sufficient time to conduct the bidding process.
Pennsylvania
On
May 2, 2007, Penn
made a filing with the PPUC proposing how it will procure the power supply
needed for default service customers from June 1, 2008 through May 2011.
Hearings are scheduled for September 10-11, 2007, with a recommended ALJ
decision expected by October 25, 2007. A PPUC order is expected by
November 29, 2007. The initial RFP is expected to take place in January
2008.
On
May 3, 2007, an
ALJ issued her initial decision denying 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
June 19, 2007,
initial briefs were filed with the Commonwealth Court of Pennsylvania by
all
parties in the appeal of Met-Ed’s and Penelec’s comprehensive rate
filing. Responsive briefs are due August 20, 2007, with reply briefs
due September 4, 2007. Met-Ed and Penelec appealed the PPUC’s
decision on the denial of generation rate relief and consolidated tax savings,
while other parties appealed the PPUC’s decision on transmission rate
relief. Oral arguments are expected to take place in the fourth
quarter of 2007.
Operations
Second
Quarter KWH
Sales Record - FirstEnergy set a new second quarter generation sales record
in
2007 of 32.8 billion KWH, which represents a 2.9% increase over the second
quarter of 2006. Distribution deliveries also increased in the second quarter
to
26.9 billion KWH – a 4.4% increase from the second quarter of 2006. The higher
KWH sales and distribution deliveries were primarily attributable to continued
customer growth in FirstEnergy’s service territories and weather impacts during
the quarter.
Generation
Output
Record - FirstEnergy set a new second quarter generation output record of
20.4 billion KWH in 2007, which represents a 0.4% increase over the prior
record established last year. The generation record was primarily attributable
to performance of the fossil generation fleet, which established its best
quarterly output ever.
NRC
Demand for
Information - On May 14, 2007, the NRC issued a Demand for Information related
to recent reports prepared for arbitration of an insurance claim for replacing
the damaged reactor head at the Davis-Besse Plant in 2002. FENOC responded
to
the NRC on June 13, 2007. FirstEnergy officials participated in
a public meeting with the NRC on June 27, 2007 to discuss circumstances
leading up to the Demand for Information and FENOC’s response. In follow-up
discussions, FENOC was requested to provide supplemental information to clarify
certain aspects of the Demand for Information response and to provide
supplemental details regarding plans to implement the commitments established
therein. This supplemental information was submitted to the NRC on July 16,
2007.
Perry
Plant Outage -
FirstEnergy’s Perry Nuclear Power Plant completed its regularly scheduled
refueling outage on May 13, 2007. Major work activities performed on the
1,258
MW facility included replacing approximately one-third of the fuel assemblies
in
the reactor and two of the three low-pressure turbine rotors in the main
generator. On June 29, 2007, Perry began an unplanned outage to replace a
30-ton motor in the reactor recirculation system. In addition to the motor
replacement, routine and preventive maintenance and several system inspections
will be performed during the outage to assure continued safe and reliable
operation of the plant. On July 25, 2007 the plant was returned to
service.
Environmental
Update
- On May 30, 2007, FirstEnergy announced that FGCO plans to install an ECO
system on Units 4 and 5 of its R.E. Burger Plant. Design engineering
for the new Burger Plant ECO system will begin in 2007 with an anticipated
start-up date in the first quarter of 2011. The incremental cost
installing the system at the Burger Plant instead of Bay Shore Unit 4, as
originally planned, is approximately $38 million.
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 12 to the consolidated financial statements. Net income
by major business segment was as follows:
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
Increase
|
|
|
|
Increase
|
|
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions, except per share amounts)
|
|
Net
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By
Business Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
delivery services
|
|
|
$
|
207
|
|
$
|
233
|
|
$
|
(26
|
)
|
$
|
425
|
|
$
|
422
|
|
$
|
3
|
|
Competitive
energy services
|
|
|
|
142
|
|
|
101
|
|
|
41
|
|
|
240
|
|
|
133
|
|
|
107
|
|
Ohio
transitional generation services
|
|
|
|
30
|
|
|
31
|
|
|
(1
|
)
|
|
53
|
|
|
61
|
|
|
(8
|
)
|
Other
and
reconciling adjustments*
|
|
|
|
(41
|
)
|
|
(61
|
)
|
|
20
|
|
|
(90
|
)
|
|
(91
|
)
|
|
1
|
|
Total
|
|
|
$
|
338
|
|
$
|
304
|
|
$
|
34
|
|
$
|
628
|
|
$
|
525
|
|
$
|
103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
|
$
|
1.11
|
|
$
|
0.94
|
|
$
|
0.17
|
|
$
|
2.03
|
|
$
|
1.61
|
|
$
|
0.42
|
|
Discontinued
operations
|
|
|
|
-
|
|
|
(0.02
|
)
|
|
0.02
|
|
|
-
|
|
|
(0.02
|
)
|
|
0.02
|
|
Net
earnings
per basic share
|
|
|
$
|
1.11
|
|
$
|
0.92
|
|
$
|
0.19
|
|
$
|
2.03
|
|
$
|
1.59
|
|
$
|
0.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
|
$
|
1.10
|
|
$
|
0.93
|
|
$
|
0.17
|
|
$
|
2.01
|
|
$
|
1.60
|
|
$
|
0.41
|
|
Discontinued
operations
|
|
|
|
-
|
|
|
(0.02
|
)
|
|
0.02
|
|
|
-
|
|
|
(0.02
|
)
|
|
0.02
|
|
Net
earnings
per diluted share
|
|
|
$
|
1.10
|
|
$
|
0.91
|
|
$
|
0.19
|
|
$
|
2.01
|
|
$
|
1.58
|
|
$
|
0.43
|
|
*
Represents other operating segments and reconciling items including interest
expense on holding company debt and corporate
support
services revenues and expenses.
Summary
of Results of Operations – Second Quarter of 2007 Compared with the Second
Quarter of 2006
Financial
results
for FirstEnergy's major business segments in the second quarter of 2007 and
2006
were as follows:
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
Second
Quarter 2007 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
1,933
|
|
|
$ |
359
|
|
|
$ |
612
|
|
|
$ |
-
|
|
|
$ |
2,904
|
|
Other
|
|
|
162
|
|
|
|
45
|
|
|
|
13
|
|
|
|
(15 |
) |
|
|
205
|
|
Internal
|
|
|
-
|
|
|
|
691
|
|
|
|
-
|
|
|
|
(691 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
2,095
|
|
|
|
1,095
|
|
|
|
625
|
|
|
|
(706 |
) |
|
|
3,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
879
|
|
|
|
460
|
|
|
|
537
|
|
|
|
(691 |
) |
|
|
1,185
|
|
Other
operating expenses
|
|
|
410
|
|
|
|
283
|
|
|
|
87
|
|
|
|
(30 |
) |
|
|
750
|
|
Provision
for
depreciation
|
|
|
100
|
|
|
|
51
|
|
|
|
-
|
|
|
|
8
|
|
|
|
159
|
|
Amortization
of regulatory assets
|
|
|
242
|
|
|
|
-
|
|
|
|
6
|
|
|
|
(2 |
) |
|
|
246
|
|
Deferral
of
new regulatory assets
|
|
|
(93 |
) |
|
|
-
|
|
|
|
(55 |
) |
|
|
-
|
|
|
|
(148 |
) |
General
taxes
|
|
|
155
|
|
|
|
26
|
|
|
|
1
|
|
|
|
7
|
|
|
|
189
|
|
Total
Expenses
|
|
|
1,693
|
|
|
|
820
|
|
|
|
576
|
|
|
|
(708 |
) |
|
|
2,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
402
|
|
|
|
275
|
|
|
|
49
|
|
|
|
2
|
|
|
|
728
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
62
|
|
|
|
5
|
|
|
|
-
|
|
|
|
(37 |
) |
|
|
30
|
|
Interest
expense
|
|
|
(118 |
) |
|
|
(47 |
) |
|
|
-
|
|
|
|
(40 |
) |
|
|
(205 |
) |
Capitalized
interest
|
|
|
2
|
|
|
|
5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
Total
Other
Expense
|
|
|
(54 |
) |
|
|
(37 |
) |
|
|
-
|
|
|
|
(77 |
) |
|
|
(168 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations Before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
348
|
|
|
|
238
|
|
|
|
49
|
|
|
|
(75 |
) |
|
|
560
|
|
Income
taxes
|
|
|
141
|
|
|
|
96
|
|
|
|
19
|
|
|
|
(34 |
) |
|
|
222
|
|
Net
Income
|
|
$ |
207
|
|
|
$ |
142
|
|
|
$ |
30
|
|
|
$ |
(41 |
) |
|
$ |
338
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
Second
Quarter 2006 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
1,646
|
|
|
$ |
338
|
|
|
$ |
569
|
|
|
$ |
-
|
|
|
$ |
2,553
|
|
Other
|
|
|
127
|
|
|
|
46
|
|
|
|
6
|
|
|
|
19
|
|
|
|
198
|
|
Internal
|
|
|
6
|
|
|
|
623
|
|
|
|
-
|
|
|
|
(629 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
1,779
|
|
|
|
1,007
|
|
|
|
575
|
|
|
|
(610 |
) |
|
|
2,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
690
|
|
|
|
434
|
|
|
|
496
|
|
|
|
(629 |
) |
|
|
991
|
|
Other
operating expenses
|
|
|
363
|
|
|
|
289
|
|
|
|
53
|
|
|
|
13
|
|
|
|
718
|
|
Provision
for
depreciation
|
|
|
89
|
|
|
|
48
|
|
|
|
-
|
|
|
|
7
|
|
|
|
144
|
|
Amortization
of regulatory assets
|
|
|
197
|
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
201
|
|
Deferral
of
new regulatory assets
|
|
|
(113 |
) |
|
|
-
|
|
|
|
(33 |
) |
|
|
-
|
|
|
|
(146 |
) |
General
taxes
|
|
|
144
|
|
|
|
23
|
|
|
|
2
|
|
|
|
4
|
|
|
|
173
|
|
Total
Expenses
|
|
|
1,370
|
|
|
|
794
|
|
|
|
522
|
|
|
|
(605 |
) |
|
|
2,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
409
|
|
|
|
213
|
|
|
|
53
|
|
|
|
(5 |
) |
|
|
670
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
81
|
|
|
|
2
|
|
|
|
-
|
|
|
|
(52 |
) |
|
|
31
|
|
Interest
expense
|
|
|
(101 |
) |
|
|
(50 |
) |
|
|
-
|
|
|
|
(27 |
) |
|
|
(178 |
) |
Capitalized
interest
|
|
|
4
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(5 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
(2 |
) |
Total
Other
Expense
|
|
|
(21 |
) |
|
|
(45 |
) |
|
|
-
|
|
|
|
(76 |
) |
|
|
(142 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations Before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
388
|
|
|
|
168
|
|
|
|
53
|
|
|
|
(81 |
) |
|
|
528
|
|
Income
taxes
|
|
|
155
|
|
|
|
67
|
|
|
|
22
|
|
|
|
(28 |
) |
|
|
216
|
|
Income
from
continuing operations
|
|
|
233
|
|
|
|
101
|
|
|
|
31
|
|
|
|
(53 |
) |
|
|
312
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(8 |
) |
|
|
(8 |
) |
Net
Income
|
|
$ |
233
|
|
|
$ |
101
|
|
|
$ |
31
|
|
|
$ |
(61 |
) |
|
$ |
304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between Second Quarter 2007 and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second
Quarter 2006 Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
287
|
|
|
$ |
21
|
|
|
$ |
43
|
|
|
$ |
-
|
|
|
$ |
351
|
|
Other
|
|
|
35
|
|
|
|
(1 |
) |
|
|
7
|
|
|
|
(34 |
) |
|
|
7
|
|
Internal
|
|
|
(6 |
) |
|
|
68
|
|
|
|
-
|
|
|
|
(62 |
) |
|
|
-
|
|
Total
Revenues
|
|
|
316
|
|
|
|
88
|
|
|
|
50
|
|
|
|
(96 |
) |
|
|
358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
189
|
|
|
|
26
|
|
|
|
41
|
|
|
|
(62 |
) |
|
|
194
|
|
Other
operating expenses
|
|
|
47
|
|
|
|
(6 |
) |
|
|
34
|
|
|
|
(43 |
) |
|
|
32
|
|
Provision
for
depreciation
|
|
|
11
|
|
|
|
3
|
|
|
|
-
|
|
|
|
1
|
|
|
|
15
|
|
Amortization
of regulatory assets
|
|
|
45
|
|
|
|
-
|
|
|
|
2
|
|
|
|
(2 |
) |
|
|
45
|
|
Deferral
of
new regulatory assets
|
|
|
20
|
|
|
|
-
|
|
|
|
(22 |
) |
|
|
-
|
|
|
|
(2 |
) |
General
taxes
|
|
|
11
|
|
|
|
3
|
|
|
|
(1 |
) |
|
|
3
|
|
|
|
16
|
|
Total
Expenses
|
|
|
323
|
|
|
|
26
|
|
|
|
54
|
|
|
|
(103 |
) |
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(7 |
) |
|
|
62
|
|
|
|
(4 |
) |
|
|
7
|
|
|
|
58
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(19 |
) |
|
|
3
|
|
|
|
-
|
|
|
|
15
|
|
|
|
(1 |
) |
Interest
expense
|
|
|
(17 |
) |
|
|
3
|
|
|
|
-
|
|
|
|
(13 |
) |
|
|
(27 |
) |
Capitalized
interest
|
|
|
(2 |
) |
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Subsidiaries'
preferred stock dividends
|
|
|
5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3 |
) |
|
|
2
|
|
Total
Other
Income
|
|
|
(33 |
) |
|
|
8
|
|
|
|
-
|
|
|
|
(1 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations Before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
(40 |
) |
|
|
70
|
|
|
|
(4 |
) |
|
|
6
|
|
|
|
32
|
|
Income
taxes
|
|
|
(14 |
) |
|
|
29
|
|
|
|
(3 |
) |
|
|
(6 |
) |
|
|
6
|
|
Income
from
continuing operations
|
|
|
(26 |
) |
|
|
41
|
|
|
|
(1 |
) |
|
|
12
|
|
|
|
26
|
|
Discontinued
operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8
|
|
|
|
8
|
|
Net
Income
|
|
$ |
(26 |
) |
|
$ |
41
|
|
|
$ |
(1 |
) |
|
$ |
20
|
|
|
$ |
34
|
|
Net
income increased
$3 million (or 1%) to $425 million in the first six months of 2007
compared to $422 million in the first six months of 2006, primarily due to
increased revenues partially offset by higher operating expenses and lower
investment income.
Revenues
–
The
increase in total revenues resulted from the following sources:
|
|
Six
Months Ended
|
|
|
|
|
|
June
30,
|
|
|
|
Revenues
by Type of Service
|
|
2007
|
|
2006
|
|
Increase
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
increases in distribution deliveries by customer class are summarized in
the
following table:
Electric
Distribution Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Distribution Deliveries
|
|
|
|
|
The
increase in
electric distribution deliveries to customers was primarily due to higher
weather-related usage during the first six months of 2007 compared to the
same
period of 2006 (heating degree days increased by 15.4% and cooling degree
days
increased by 39.8%). The higher revenues from increased distribution deliveries
were offset principally 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 $371 million
increase in non-affiliated generation sales revenues in 2007 compared to
2006:
Sources
of Change in Generation Sales
|
|
|
|
|
|
|
(In
millions)
|
|
|
Retail:
|
|
|
|
|
|
Effect
of 0.6% increase in customer usage
|
|
$
|
8
|
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
|
Effect
of 135% increase in KWH sales
|
|
|
141
|
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Generation Sales
|
|
$
|
371
|
|
|
The
increase in
retail generation prices during the first six 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 $129 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the January 2007 PPUC authorization
for
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
Expenses
–
The
net increases in revenues discussed above were partially offset by a
$486 million increase in expenses due to the following:
|
·
|
Purchased
power costs were $339 million
higher in the first six months of 2007 due to higher unit costs
and
volumes purchased. The increased unit prices reflected the effect
of
higher JCP&L purchased power unit costs resulting from the BGS auction
process. The increased KWH purchases in 2007 were due in part to
higher
customer usage and 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
|
|
$
|
168
|
|
|
Change
due to increased volume
|
|
|
128
|
|
|
Decrease
in NUG costs deferred
|
|
|
43
|
|
|
Net
Increase in Purchased Power Costs
|
|
$
|
339
|
|
|
|
·
|
Other
operating expenses increased $90 million due
to the
net effects of:
|
-
|
An
increase of
$101 million in
MISO and PJM transmission expenses, resulting primarily from higher
congestion costs;
|
-
|
A
decrease in
miscellaneous operating expenses of $18 million primarily
due
to reduced billings for employee benefits from FESC;
and
|
-
|
An
increase in
operation and maintenance expenses of $10 million primarily
due
to reduced employee benefits applicable to construction activities
and
storm-related costs;
|
|
·
|
Amortization
of regulatory assets increased $75 million compared
to
2006 due primarily to recovery of deferred BGS costs through higher
NUGC
rates for JCP&L as discussed above;
and
|
|
·
|
The
deferral
of new regulatory assets during the first six months of 2007 was
$49 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 deferrals of PJM transmission
expenses
of $10 million and increased RCP Distribution Deferrals of
$10 million.
|
Other
Income and Expense –
Other
income
decreased $54 million
in 2007 compared to the first six months of 2006 primarily due to lower interest
income of $32 million
resulting from the repayment of notes receivable from affiliates since the
second quarter of 2006 and increased interest expense of $26 million related to
new debt
issuances by CEI and JCP&L.
Ohio
Transitional Generation Services –
First Six Months of 2007 Compared to First Six Months of
2006
Net
income for this segment decreased to $53 million in the first
six
months of 2007 from $61 million in the same period last year. Higher
generation revenues were offset by higher operating expenses, primarily for
purchased power.
Revenues
–
The
increase in reported segment revenues resulted from the following
sources:
|
|
Six
Months Ended
|
|
|
|
|
|
June
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 6% increase in customer
usage
|
|
$
|
54
|
|
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
six 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 2 percentage
points from the same period last year.
Expenses
-
Purchased
power
costs were $127 million
higher due primarily to higher unit prices 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
|
|
$
|
7
|
|
Change
due to volume
purchased
|
|
|
1
|
|
|
|
|
8
|
|
Purchases
from
FES:
|
|
|
|
|
Change
due to increased unit
costs
|
|
|
76
|
|
Change
due to volume
purchased
|
|
|
43
|
|
|
|
|
119
|
|
Total
Increase
in Purchased Power Costs
|
|
$
|
127
|
|
The
increase in KWH
purchases 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.
Other
operating
expenses increased $29 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.
Competitive
Energy Services – First Six
Months of 2007 Compared to First Six Months of 2006
Net
income for this
segment was $240 million
in the first six months of 2007 compared to $133 million
in the same period last year. This increase reflects an improvement in gross
generation margin and lower other operating expenses, which were partially
offset by increased depreciation, general taxes and reduced investment
income.
Revenues
–
Total
revenues
increased $163 million
in the first six 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, which was partially offset by lower non-affiliated
wholesale sales.
The
higher retail
revenues resulted from increased sales in both the MISO and PJM markets.
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 KWH sales. Factors contributing to the revenue increase from PSA
sales
to the Ohio Companies are discussed under the purchased power costs analysis
in
the Ohio Transitional Generation Services results above. The higher KWH sales
to
the Pennsylvania affiliates 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:
|
|
Six
Months Ended
|
|
|
|
|
|
June
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 $19 million due to reduced retail load in the MISO
market, lower transmission rates and reduced FTR 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 19% increase in sales
volume
|
|
$
|
51
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 31% decrease in KWH
sales
|
|
|
(118
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
)
|
Net
Decrease
in Non-Affiliated Generation Sales
|
|
|
|
)
|
|
|
|
|
Source
of Change in Affiliated Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect
of 5% increase in KWH
sales
|
|
$
|
43
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect
of 14% increase in KWH
sales
|
|
|
40
|
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Net
Increase
in Affiliated Generation Sales
|
|
|
|
|
Expenses
-
Total
expenses were
$26 million lower in the first six months of 2007 due to the following
factors:
|
·
|
Fuel
costs
were $26 million lower primarily due to reduced coal costs and
emission allowance costs offset by increases in nuclear fuel and
natural
gas consumption. Coal costs were reduced due to a $14 million
inventory adjustment and $35 million of reduced coal consumption
reflecting lower generation, partially offset by a $19 million
increase in coal prices. Reduced emission allowance costs
($12 million) were more than offset by increased natural gas costs
($6 million) and nuclear fuel costs ($9 million) due to
increased generation and higher prices;
and
|
|
·
|
Nuclear
operating costs were $58 million lower due to fewer outages in 2007
compared to 2006 and reduced employee benefit
costs.
|
Partially
offsetting
the lower costs were the following:
|
·
|
Purchased
power costs increased $31 million due primarily to higher volumes
purchased;
|
|
·
|
Higher
fossil
operating costs of $12 million due to increased labor
costs;
|
|
·
|
Higher
depreciation expenses of $8 million due to property additions;
and
|
|
·
|
Higher
general
taxes of $5 million.
|
Other
Income –
Investment
income in
the first six months of 2007 was $11 million
lower than the 2006 period primarily due to decreased earnings on nuclear
decommissioning trust investments (including a $12 million
impairment).
Other
–
First
Six Months of 2007
Compared to First Six 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 $1 million
increase in FirstEnergy’s net income in the first six months of 2007. The
increase was caused by the absence of a $6 million
loss included in 2006 results from discontinued operations (see Note 3)
offset by increased interest expense in 2007 compared to 2006 due to higher
short-term borrowings.
CAPITAL
RESOURCES AND LIQUIDITY
FirstEnergy’s
business is capital intensive, requiring considerable capital 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 primarily 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 given 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 six months of 2007,
FirstEnergy received $637 million of cash dividends and return of capital
from its subsidiaries and paid $311 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, including
$500 million from bridge loan facilities that have since been
repaid.
On
July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net
demonstrated capacity. The purchase price of approximately $1.329 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 trust’s undivided interest in Unit 1, rights and
interests under the applicable lease and rights and interests under other
related agreements. The transaction will be classified as a financing
under GAAP until FGCO’s and 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 are satisfied,
at
which time it is expected to be classified as an operating lease under GAAP.
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 accelerated
share repurchase program and $300 million pension contribution. FGCO continues
to operate the plant. CEI has an existing sale and leaseback
arrangement for the remaining 51 MW portion of Bruce Mansfield Unit 1. This
transaction generated tax capital gains of approximately $830 million, a
substantial portion of which will be offset by existing tax capital loss
carryforwards. FirstEnergy will reduce its tax loss carryforward
valuation allowances in the third quarter of 2007 and anticipates an immaterial
impact to net income as the majority of the unrecognized tax benefits will
reduce goodwill.
As
of June 30,
2007, FirstEnergy had $37 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
regulated services and power supply management services businesses (see Results
of Operations above). Net cash provided from operating activities was
$131 million and $485 million in the first six months of 2007 and 2006,
respectively, summarized as follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
628
|
|
$
|
525
|
|
Non-cash
charges
|
|
|
277
|
|
|
260
|
|
Pension
trust
contribution
|
|
|
(300
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(474
|
)
|
|
(300
|
)
|
|
|
$
|
131
|
|
$
|
485
|
|
Net
cash provided
from operating activities decreased by $354 million in the first six months
of 2007 compared to the first six months of 2006 primarily due to a $300
million
pension trust contribution in 2007 and $174 million from working capital
charges, partially offset by a $103 million increase in net income (see Results
of Operations above). The decrease from working capital and other changes
primarily resulted from a $365 million increase in receivables due to
higher sales, partially offset by $93 million from reduced materials and
supplies inventories and $68 million of decreased payments for accounts
payable.
Cash
Flows From Financing
Activities
In
the first six
months of 2007, cash provided from financing activities was $454 million
compared to $618 million in the first six months of 2006. The decrease was
primarily due to the repurchase of common stock in 2007, partially offset
by
higher short-term borrowings. The following table summarizes security issuances
and redemptions.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Securities
Issued or Redeemed
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
New
issues
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
-
|
|
$
|
253
|
|
Secured
notes
|
|
|
-
|
|
|
200
|
|
Unsecured
notes
|
|
|
800
|
|
|
600
|
|
|
|
$
|
800
|
|
$
|
1,053
|
|
Redemptions
|
|
|
|
|
|
|
|
First
mortgage
bonds
|
|
$
|
275
|
|
$
|
1
|
|
Pollution
control notes
|
|
|
-
|
|
|
307
|
|
Senior
secured
notes
|
|
|
43
|
|
|
177
|
|
Unsecured
notes
|
|
|
153
|
|
|
-
|
|
Common
stock
|
|
|
918
|
|
|
-
|
|
Preferred
stock
|
|
|
-
|
|
|
30
|
|
|
|
$
|
1,389
|
|
$
|
515
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
1,308
|
|
$
|
371
|
|
FirstEnergy
had
approximately $2.4 billion of short-term indebtedness as of June 30,
2007 compared to approximately $1.1 billion as of December 31, 2006.
This increase resulted from interim funding of FirstEnergy’s $900 million
share repurchase program and $300 million pension contribution in the first
half of the year. Available bank borrowing capability as of June 30, 2007
included the following:
Borrowing
Capability (In millions)
|
|
|
|
Short-term
credit facilities(1)
|
|
$
|
3,220
|
|
Accounts
receivable financing facilities
|
|
|
550
|
|
Utilized
|
|
|
(2,413
|
)
|
LOCs
|
|
|
(339
|
)
|
Net
|
|
$
|
1,018
|
|
|
|
|
|
|
(1) Includes
the $2.75 billion revolving credit facility described below, a
$100 million revolving credit facility that expires in December 2009,
a $20 million uncommitted line of credit and $350 million bridge loan
facilities.
|
As
of June 30, 2007,
the Ohio Companies and Penn had the aggregate capability to issue approximately
$2.9 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 $463 million, $515 million and
$127 million, respectively, as of June 30, 2007. Because
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, it is no longer
required to issue FMBs as collateral for senior notes and therefore is not
limited as to the amount of senior notes it may issue.
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 June 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
June 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
|
|
|
40
|
|
CEI
|
|
|
250
|
(3)
|
|
500
|
|
TE
|
|
|
250
|
(3)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
431
|
|
Met-Ed
|
|
|
250
|
|
|
250
|
(4)
|
Penelec
|
|
|
250
|
|
|
250
|
(4)
|
FES
|
|
|
250
|
|
|
-
|
(2)
|
ATSI
|
|
|
-
|
(5)
|
|
50
|
|
|
(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 ($287 million unused as
of
June 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 June 30, 2007, FirstEnergy and its
subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy
|
|
61
|
%
|
OE
|
|
48
|
%
|
Penn
|
|
24
|
%
|
CEI
|
|
60
|
%
|
TE
|
|
56
|
%
|
JCP&L
|
|
32
|
%
|
Met-Ed
|
|
46
|
%
|
Penelec
|
|
38
|
%
|
FES
|
|
57
|
%
|
The
revolving credit
facility does not contain provisions that either restrict the ability to
borrow
or accelerate repayment of outstanding advances as a result of any change
in
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to the credit ratings of the company
borrowing the funds.
FirstEnergy's
regulated companies also have the ability to borrow from each other and the
holding company to meet their short-term working capital requirements. A
similar
but separate arrangement exists among FirstEnergy's unregulated companies.
FESC
administers these two money pools and tracks surplus funds of FirstEnergy
and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money
pool
agreements must repay the principal amount of the loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is
the
same for each company receiving a loan from their respective pool and is
based
on the average cost of funds available through the pool. The average interest
rate for borrowings in the first six months of 2007 was 5.64% for both the
regulated and the unregulated companies' money pools.
FirstEnergy’s
access
to capital markets and costs of financing are influenced by the ratings of
its
securities. The following table displays FirstEnergy’s and the
Companies’ securities ratings as of June 30, 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 stable. The rating outlook
from Fitch on CEI and Toledo Edison is positive and stable on all other
operating companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB
|
|
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
TE
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
Penn
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
JCP&L
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
A-
|
|
|
Senor
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
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 to FGCO 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.
Cash
Flows From Investing
Activities
Net
cash flows used
in investing activities resulted principally from 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
second quarter of 2007 and 2006 by segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
Inter-Segment
reconciling items
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-Segment
reconciling items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
Net
cash used for
investing activities in the first six months of 2007 increased by $54 million
compared to the same period of 2006. The increase was principally due to
a $64
million decrease in cash provided from cash investments, primarily from the
use
of restricted cash investments to repay debt during 2006. Partially
offsetting the decrease in cash provided from cash investments was a
$42 million decrease in property additions which reflects the replacement
of the steam generators and reactor head at Beaver Valley Unit 1 in
2006.
During
the second
half of 2007, capital requirements for property additions and capital leases
are
expected to be $820 million. FirstEnergy and the Companies have additional
requirements of approximately $172 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
$7.9 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 $804
million and $102 million, respectively, as the nuclear fuel is
consumed.
GUARANTEES
AND OTHER ASSURANCES
As
part of normal
business activities, FirstEnergy enters into various agreements on behalf
of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds, and LOCs. Some
of
the guaranteed contracts contain collateral provisions that are contingent
upon
FirstEnergy’s credit ratings.
As
of June 30,
2007, FirstEnergy’s maximum exposure to potential future payments under
outstanding guarantees and other assurances approximated $4.1 billion, as
summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees of Subsidiaries
|
|
|
|
Energy
and
Energy-Related Contracts (1)
|
|
$
|
800
|
|
LOC
(2)
|
|
|
864
|
|
Other
(3)
|
|
|
|
|
|
|
|
2,251
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
95
|
|
LOC
(4)(5)
|
|
|
|
|
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
|
|
|
|
(1)
|
Issued
for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
LOC’s
issued
on behalf of FGCO and NGC in support of pollution
control
revenue bonds with various maturities, which are
recognized
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
$339 million issued for various terms pursuant to LOC
capacity
available under FirstEnergy’s revolving credit facility and
an
additional
$779 million outstanding in support of pollution
control
revenue bonds issued with various maturities on behalf of
FGCO
and NGC,
which are recognized on FirstEnergy’s
consolidated
balance sheets.
|
|
(5)
|
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 June 30,
2007, FirstEnergy’s maximum exposure under these collateral provisions was
$421 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 June 30, 2007), which is renewable and
declines yearly based upon the senior outstanding debt of TEBSA.
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
The
Ohio Companies
have obligations that are not included on FirstEnergy’s Consolidated Balance
Sheets related to the sale and leaseback arrangements involving Perry
Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are
satisfied through operating lease payments. As of June 30, 2007, the present
value of these sale and leaseback operating lease commitments, net of trust
investments, total $1.1 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 six months ended June 30, 2007
is
summarized in the following table:
|
Three
Months Ended
|
|
Six
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
June
30, 2007
|
|
June
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
|
$
|
(1,028
|
)
|
$
|
1
|
|
$
|
(1,027
|
)
|
$
|
(1,140
|
)
|
$
|
(17
|
)
|
$
|
(1,157
|
)
|
Additions/change
in value of existing contracts
|
|
91
|
|
|
(11
|
)
|
|
80
|
|
|
197
|
|
|
(6
|
)
|
|
191
|
|
Settled
contracts
|
|
92
|
|
|
(2
|
)
|
|
90
|
|
|
98
|
|
|
11
|
|
|
109
|
|
Outstanding
net liability at end of period (1)
|
|
(845
|
)
|
|
(12
|
)
|
|
(857
|
)
|
|
(845
|
)
|
|
(12
|
)
|
|
(857
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Liabilities at End of Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
swaps (2)
|
|
-
|
|
|
(24
|
)
|
|
(24
|
)
|
|
-
|
|
|
(24
|
)
|
|
(24
|
)
|
Net
Liabilities - Derivative Contracts
at
End
of Period
|
$
|
(845
|
)
|
$
|
(36
|
)
|
$
|
(881
|
)
|
$
|
(845
|
)
|
$
|
(36
|
)
|
$
|
(881
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
$
|
-
|
|
$
|
(13
|
)
|
$
|
(13
|
)
|
$
|
-
|
|
$
|
5
|
|
$
|
5
|
|
Regulatory
assets (net)
|
$
|
(185
|
)
|
$
|
-
|
|
$
|
(185
|
)
|
$
|
(295
|
)
|
$
|
-
|
|
$
|
(295
|
)
|
(1)
|
Includes
$841 million in non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
|
(2)
|
Interest
rate
swaps are treated as cash flow or fair value hedges (see Interest
Rate
Swap Agreements below).
|
|
(3)
|
Represents
the
change in value of existing contracts, settled contracts and changes
in
techniques/assumptions.
|
|
Derivatives
are included on the Consolidated Balance Sheet as of June 30, 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 June 30, 2007 are summarized by year in the following
table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Fair
Value by Contract Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
Prices
actively quoted(2)
|
|
$
|
(1
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(1
|
)
|
Other
external
sources(3)
|
|
|
(112
|
)
|
|
(221
|
)
|
|
(172
|
)
|
|
(146
|
)
|
|
-
|
|
|
-
|
|
|
(651
|
)
|
Prices
based
on models
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
)
|
|
|
)
|
Total(4)
|
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
(1) For
the last two quarters of 2007.
(2) Exchange
traded.
(3) Broker
quote sheets.
|
(4)
|
Includes $841 million in non-hedge commodity derivative contracts
(primarily with NUGs), which are offset by a regulatory
asset.
|
FirstEnergy
performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near
term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash
flows
as of June 30, 2007. Based on derivative contracts held as of June 30,
2007, an adverse 10% change in commodity prices would decrease net income
by
approximately $9 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 six 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 current period. As of
June 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 6.06%.
|
|
June
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 the 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
six
months of 2007, FirstEnergy terminated forward swaps with an aggregate notional
value of $950 million. FirstEnergy paid $2 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
June 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate
notional amount of $250 million and an aggregate fair value of
$6 million.
|
|
June
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 June 30, 2007 and
December 31, 2006. A hypothetical 10% decrease in prices quoted by stock
exchanges would result in a $136 million reduction in fair value as of June
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 June 30, 2007, the largest credit concentration with one party
(currently rated investment grade) represented 11% of FirstEnergy‘s total credit
risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit
exposures, net of collateral and reserves, were with investment-grade
counterparties as of June 30, 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 $219 million as of June 30, 2007 (JCP&L -
$103 million, Met-Ed - $34 million and Penelec - $82 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:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
733
|
|
$
|
741
|
|
$
|
(8
|
)
|
CEI
|
|
|
863
|
|
|
855
|
|
|
8
|
|
TE
|
|
|
230
|
|
|
248
|
|
|
(18
|
)
|
JCP&L
|
|
|
1,825
|
|
|
2,152
|
|
|
(327
|
)
|
Met-Ed
|
|
|
464
|
|
|
409
|
|
|
55
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec
had
net regulatory liabilities of approximately $74 million
and
$96 million as of June 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:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
2,731
|
|
$
|
3,266
|
|
$
|
(535
|
)
|
Customer
shopping incentives
|
|
|
562
|
|
|
603
|
|
|
(41
|
)
|
Customer
receivables for future income taxes
|
|
|
259
|
|
|
217
|
|
|
42
|
|
Societal
benefits charge
|
|
|
(2
|
)
|
|
11
|
|
|
(13
|
)
|
Loss
on
reacquired debt
|
|
|
59
|
|
|
43
|
|
|
16
|
|
Employee
postretirement benefits
|
|
|
43
|
|
|
47
|
|
|
(4
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and
spent fuel
disposal costs
|
|
|
(114
|
)
|
|
(145
|
)
|
|
31
|
|
Asset
removal
costs
|
|
|
(173
|
)
|
|
(168
|
)
|
|
(5
|
)
|
Property
losses and unrecovered plant costs
|
|
|
13
|
|
|
19
|
|
|
(6
|
)
|
MISO/PJM
transmission costs
|
|
|
292
|
|
|
213
|
|
|
79
|
|
Fuel
costs -
RCP
|
|
|
154
|
|
|
113
|
|
|
41
|
|
Distribution
costs - RCP
|
|
|
246
|
|
|
155
|
|
|
91
|
|
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
partly to amend the Federal Power Act with Section 215, which requires that
an
ERO establish and enforce reliability standards for the bulk-power system,
subject to review of 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.
While
the FERC
approved 83 of the 107 reliability standards proposed by NERC, the FERC has
directed NERC to submit improvements to 56 of them, endorsing NERC's process
for
developing reliability standards and its associated work plan. On May 4,
2007,
NERC also submitted 24 proposed Violation Risk Factors. The FERC
issued an order approving 22 of those factors on June 26, 2007. Further,
NERC
adopted eight cyber security standards that became effective on June 1,
2006 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 assessment by February 12, 2007. The standards remain pending before
the FERC. On July 20, 2007, the FERC issued a NOPR proposing to adopt
eight Critical Infrastructure Protection Reliability
Standards. Comments will not be due to the FERC until September or
October of 2007.
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 will eventually
adopt
stricter NERC reliability 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
On
October 21, 2003,
the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004,
the
Ohio Companies accepted the RSP as modified and approved by the PUCO in an
August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended
to
establish generation service rates beginning January 1, 2006, in response
to the
PUCO’s concerns about price and supply uncertainty following the end of the Ohio
Companies' transition plan market development period. On May 3, 2006, the
Supreme Court of Ohio issued an opinion affirming the PUCO's order in all
respects, except it remanded back to the PUCO the matter of ensuring the
availability of sufficient means for customer participation in the marketplace.
The RSP contained a provision that permitted the Ohio Companies to withdraw
and
terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio,
rejected all or part of the RSP. In such event, the Ohio Companies have 30
days
from the final order or decision to provide notice of termination. On July
20,
2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding
on Remand. In their Request, the Ohio Companies provided notice of termination
to those provisions of the RSP subject to termination, subject to being
withdrawn, and also set forth a framework for addressing the Supreme Court
of
Ohio’s findings on customer participation. If the PUCO approves a resolution to
the issues raised by the Supreme Court of Ohio that is acceptable to the
Ohio
Companies, the Ohio Companies’ termination will be withdrawn and considered to
be null and void. On July 20, 2006, the OCC and NOAC also submitted to the
PUCO a conceptual proposal addressing the issue raised by the Supreme Court
of
Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies
to
file a plan in a new docket to address the Court’s concern. The Ohio Companies
filed their RSP Remand CBP on September 29, 2006. Initial comments were
filed on January 12, 2007 and reply comments were filed on January 29,
2007. In their reply comments the Ohio Companies described the highlights
of a
new tariff offering they would be willing to make available to customers
that
would allow customers to purchase renewable energy certificates associated
with
a renewable generation source, subject to PUCO approval. On May 29, 2007,
the Ohio Companies, together with the PUCO Staff and the OCC, filed a
stipulation with the PUCO agreeing to offer a standard bid product and a
green
resource tariff product. The stipulation is currently pending before the
PUCO.
No further proceedings are scheduled at this time.
The
Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005
seeking approval of the RCP, a supplement to the RSP. On November 4, 2005,
the
Ohio Companies filed a supplemental stipulation with the PUCO, which constituted
an additional component of the RCP filed on September 9, 2005. 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
Period
|
|
OE |
|
CEI |
|
TE
|
|
Total
Ohio
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
$
|
179
|
|
$
|
108
|
|
$
|
93
|
|
$
|
380
|
|
2008
|
|
|
208
|
|
|
124
|
|
|
119
|
|
|
451
|
|
2009
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
216
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
provided an update 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 late 2007. The PUCO order is expected to
be
issued by March 9, 2008. The new rates, subject to evidentiary hearings and
approval at the PUCO, 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 Ohio Companies requested
that the PUCO issue an order by November 1, 2007, to provide sufficient time
to
conduct the bidding process. The PUCO has scheduled a technical conference
for
August 16, 2007.
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 costs during the term of these
agreements with FES.
On
April 7,
2006, the parties entered into a tolling agreement that arose from FES’ notice
to Met-Ed and Penelec that FES elected to exercise its right to terminate
the
partial requirements agreement effective midnight December 31, 2006. On
November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7
tolling agreement pending resolution of the PPUC’s proceedings regarding the
Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006,
described below. Separately, 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 substantially exceed 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
tolling, suspension and 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 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 in accordance with the April 7, 2006 tolling agreement described
above. Met-Ed and Penelec also requested approval of a January 12, 2005
petition for the deferral of transmission-related costs, but only for those
costs incurred during 2006. In this rate filing, Met-Ed and Penelec also
requested recovery of annual transmission and related costs incurred on or
after
January 1, 2007, plus the amortized portion of 2006 costs over a ten-year
period, along with applicable carrying charges, through an adjustable rider.
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 the merger savings, with the comprehensive
transmission 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 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 by all
parties. Responsive briefs are due August 20, 2007, with reply briefs due
September 4, 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 June 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 $493 million and $127 million, respectively. $82 million of
Penelec’s deferral is subject to final resolution of an IRS settlement
associated with NUG trust fund proceeds. 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
late 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
would 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. The PPUC is requested to act on the proposal
no
later than November 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 will
be
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 June 30, 2007, the accumulated deferred
cost
balance totaled approximately $392 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
Energy Master Plan (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;
·
Unit
prices for electricity should remain 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 August 1,
2007, the NJBPU approved publication of a formal proposal in the New Jersey
Register, which proposal will be subsequently considered by the NJBPU following
a period for public comment. 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 third 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 and Electric Company 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 American Electric Power Company, Inc.,
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.
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 maintain
existing transmission rates between MISO and PJM. If accepted 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 transmission facilities across the
entire
MISO footprint be maintained. All of these filings were supported by
the majority of transmission owners in either MISO or PJM.
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
transmission facilities be spread throughout the entire MISO
footprint. If adopted by the FERC, this proposal would shift a
greater portion of the cost of new 345 kV transmission facilities to the
FirstEnergy footprint, and increase the transmission rates paid by load-serving
FirstEnergy affiliates.
American
Electric
Power (AEP) filed a letter with the FERC Commissioners stating its intent
to
file a complaint under Section 206 of the Federal Power Act challenging the
justness and reasonableness of the rate designs underlying the MISO and PJM
transmission tariffs. AEP will propose the adoption of a regional
rate design that is expected to reallocate the cost of both existing and
new
high voltage transmission facilities across the combined MISO and PJM
footprint. Based upon the position advocated by AEP in a related
proceeding, the AEP proposal is expected to result in a greater allocation
of
costs to FirstEnergy transmission zones in MISO and PJM. If approved
by the FERC, AEP’s proposal would increase the transmission rates paid by
load-serving FirstEnergy affiliates.
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.
On
February 15,
2007, MISO filed documents with the FERC to establish a market-based,
competitive ancillary services market. MISO contends that the filing
will integrate operating reserves into MISO’s existing day-ahead and real-time
settlements process, incorporate opportunity costs into these markets, address
scarcity pricing through the implementation of a demand curve methodology,
foster demand response in the provision of operating reserves, and provide
for
various efficiencies and optimization with regard to generation
dispatch. The filing also proposes amendments to existing documents
to provide for the transfer of balancing functions from existing local balancing
authorities to MISO. MISO will then carry out this reliability
function as the NERC-certified balancing authority for the MISO region with
implementation in the third or fourth quarter of 2008. FirstEnergy
filed comments on March 23, 2007, supporting the ancillary service market
in
concept, but proposing certain changes in MISO’s proposal. MISO requested FERC
action on its filing by June 2007 and the FERC issued its Order June 22,
2007.
The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not
submitted a market power analysis in support of its proposed Ancillary Services
Market and (2) MISO has not submitted a readiness plan to ensure reliability
during the transition from the current reserve and regulation system managed
by
the individual Balancing Authorities to a centralized Ancillary Services
Market
managed by MISO. MISO was ordered to remedy these deficiencies and the FERC
provided more guidance on other issues brought up in filings by stakeholders
to
assist MISO to re-file a complete proposal. This Order should facilitate
MISO’s
timetable to incorporate final revisions to ensure a market start in Spring
2008. FirstEnergy will be participating in working groups and task forces
to
ensure the Spring 2008 implementation of the Ancillary Services Market.
On
February 16,
2007, the FERC issued a final rule 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. 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 July 25, 2007, FirstEnergy and PennFuture
entered into a Tolling and Confidentiality Agreement that provides for a
60-day
negotiation period during which the parties have agreed to not file a
lawsuit.
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-fired generation facilities
will be subject to caps on SO2 and NOX
emissions, whereas
its New Jersey fossil-fired generation facility will be subject to only a
cap on
NOX emissions.
According to the EPA, SO2 emissions
will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the
rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions
in
affected states to just 2.5 million tons annually. NOX emissions
will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the
rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOX cap of
1.3
million tons annually. The future cost of compliance with these regulations
may
be substantial and will depend on how they are ultimately implemented by
the
states in which FirstEnergy operates affected facilities.
Mercury
Emissions
In
December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury
as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases. Initially, mercury emissions
will be
capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation
of SO2 and
NOX emission
caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade
program will cap nationwide mercury emissions from coal-fired power plants
at
15 tons per year by 2018. However, the final rules give states substantial
discretion in developing rules to implement these programs. In addition,
both
the CAIR and the CAMR have been challenged in the United States Court of
Appeals
for the District of Columbia. FirstEnergy's future cost of compliance with
these
regulations may be substantial and will depend on how they are ultimately
implemented by the states in which FirstEnergy operates affected
facilities.
The
model rules for
both CAIR and CAMR contemplate an input-based methodology to allocate allowances
to affected facilities. Under this approach, allowances would be allocated
based
on the amount of fuel consumed by the affected sources. FirstEnergy would
prefer
an output-based generation-neutral methodology in which allowances are allocated
based on megawatts of power produced, 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 June 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, 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 June
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 $88 million have been accrued through June 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
on
July 8, 2004, affirming the decertification of the originally certified class,
but remanding for certification of a class limited to those customers directly
impacted by the outages of JCP&L transformers in Red Bank, 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, on March 7, 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
on
May 9, 2007. Proceedings are continuing in the Superior
Court. FirstEnergy is vigorously defending this class action but is
unable to predict the outcome of this matter. No liability has been
accrued as of June 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., 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 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.
On
October 10, 2006,
various insurance carriers refiled a complaint in Cuyahoga County Common
Pleas
Court seeking reimbursement for claims paid to numerous insureds who allegedly
suffered losses as a result of the August 14, 2003 outages. All of the insureds
appear to be non-customers. The plaintiff insurance companies are the same
claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies
and
Penn were served on October 27, 2006. On January 18, 2007, the Court
granted the Companies’ motion to dismiss the case and they have not been
appealed. However, on April 25, 2007, one of the insurance carriers
refiled the complaint naming only FirstEnergy as the defendant. On
July 30, 2007, the case was voluntarily dismissed. No estimate of
potential liability is available for any of these cases.
FirstEnergy
was also
named, along with several other entities, in a complaint in New Jersey State
Court. The allegations against FirstEnergy were based, in part, on an alleged
failure to protect the citizens of Jersey City from an electrical power outage.
None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive
pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's
motion to dismiss. The plaintiff has not appealed.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. Although 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
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take
prompt
and corrective action. On April 4, 2005, the NRC held a public meeting to
discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in
the NRC's annual assessment letter to FENOC. Similar public meetings are
held
with all nuclear power plant licensees following issuance by the NRC of their
annual assessments. According to the NRC, overall the Perry Nuclear Power
Plant
operated "in a manner that preserved public health and safety" even though
it
remained under heightened NRC oversight. During the public meeting and in
the
annual assessment, the NRC indicated that additional inspections would continue
and that the plant must improve performance to be removed from the
Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Nuclear Power Plant
and
stated that the CAL would remain open until substantial improvement was
demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight
Process. By two letters dated March 2, 2007, the NRC closed the CAL
commitments for Perry, the two outstanding white findings, and crosscutting
issues. Moreover, the NRC removed Perry from the Multiple Degraded
Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee
Response Column (regular agency oversight).
On
April 30, 2007,
the UCS filed a petition with the NRC under Section 2.206 of the NRC’s
regulations based on a report prepared at FENOC’s request by expert witnesses
for an insurance arbitration. In December 2006, the expert witnesses
for FENOC completed a report that analyzed the crack growth rates in control
rod
drive mechanism penetrations and wastage of the former reactor pressure vessel
head at Davis-Besse. Citing the findings in the expert witness'
report, the Section 2.206 petition requested that: (1) Davis-Besse be
immediately shut down; (2) that the NRC conduct an independent review of
the
consultant's report and that all pressurized water reactors be shut down
until
remedial actions can be implemented; and (3) Davis-Besse’s operating license be
revoked.
In
a letter dated
May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV)
head inspection requirements are adequate to detect RPV degradation issues
before they result in significant corrosion.” The NRC also indicated that, “no
immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to
shut down the facility). On June 18, 2007, the NRC Petition
Review Board indicated that the agency had initially denied petitioner’s other
requests, and provided an opportunity for UCS to provide additional information
prior to the final determination. By letter dated July 12, 2007, the NRC
denied the remainder of the UCS petition.
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
the expert witnesses’ report and another report. The NRC indicated that this
information is 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. FirstEnergy can provide no assurances as to the
ultimate resolution of this matter.
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 plaintiff’s motion to amend their complaint which OE
has opposed.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. JCP&L
intends to re-file an appeal in federal district court once the damages
associated with this case are identified at an individual employee level.
JCP&L recognized a liability for the potential $16 million award in
2005. The parties met on June 27, 2007 before an arbitrator to assert their
positions regarding the finality of damages. A hearing before the arbitrator
is
set for September 7, 2007.
The
union employees
at the W. H. Sammis Plant have been working without a labor contract since
July
1, 2007. The union expects to vote on a new contract on August 9, 2007.
While it
is expected the union will ratify a new contract, FirstEnergy has a strike
mitigation plan ready in the event of a strike.
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
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.
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.
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
effect on FirstEnergy’s financial statements.
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
569,430
|
|
|
$ |
546,176
|
|
|
$ |
1,163,774
|
|
|
$ |
1,103,405
|
|
Excise
tax
collections
|
|
|
27,351
|
|
|
|
26,916
|
|
|
|
58,605
|
|
|
|
55,890
|
|
Total
revenues
|
|
|
596,781
|
|
|
|
573,092
|
|
|
|
1,222,379
|
|
|
|
1,159,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,312
|
|
|
|
2,821
|
|
|
|
5,327
|
|
|
|
5,772
|
|
Purchased
power
|
|
|
322,639
|
|
|
|
293,033
|
|
|
|
672,491
|
|
|
|
576,053
|
|
Nuclear
operating costs
|
|
|
47,654
|
|
|
|
43,506
|
|
|
|
89,168
|
|
|
|
84,590
|
|
Other
operating costs
|
|
|
97,120
|
|
|
|
91,604
|
|
|
|
185,606
|
|
|
|
182,414
|
|
Provision
for
depreciation
|
|
|
19,110
|
|
|
|
17,547
|
|
|
|
37,958
|
|
|
|
35,563
|
|
Amortization
of regulatory assets
|
|
|
46,126
|
|
|
|
43,444
|
|
|
|
91,543
|
|
|
|
97,305
|
|
Deferral
of
new regulatory assets
|
|
|
(54,344 |
) |
|
|
(42,083 |
) |
|
|
(90,993 |
) |
|
|
(78,323 |
) |
General
taxes
|
|
|
45,393
|
|
|
|
43,931
|
|
|
|
95,138
|
|
|
|
89,826
|
|
Total
expenses
|
|
|
526,010
|
|
|
|
493,803
|
|
|
|
1,086,238
|
|
|
|
993,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
70,771
|
|
|
|
79,289
|
|
|
|
136,141
|
|
|
|
166,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
21,346
|
|
|
|
32,818
|
|
|
|
47,976
|
|
|
|
65,860
|
|
Miscellaneous
income (expense)
|
|
|
2,319
|
|
|
|
(1,001 |
) |
|
|
2,692
|
|
|
|
(804 |
) |
Interest
expense
|
|
|
(21,416 |
) |
|
|
(17,366 |
) |
|
|
(42,438 |
) |
|
|
(35,598 |
) |
Capitalized
interest
|
|
|
152
|
|
|
|
643
|
|
|
|
262
|
|
|
|
1,134
|
|
Subsidiary's
preferred stock dividend requirements
|
|
|
-
|
|
|
|
(155 |
) |
|
|
-
|
|
|
|
(311 |
) |
Total
other
income
|
|
|
2,401
|
|
|
|
14,939
|
|
|
|
8,492
|
|
|
|
30,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
73,172
|
|
|
|
94,228
|
|
|
|
144,633
|
|
|
|
196,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
27,559
|
|
|
|
35,019
|
|
|
|
44,985
|
|
|
|
73,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
45,613
|
|
|
|
59,209
|
|
|
|
99,648
|
|
|
|
123,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS AND
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REDEMPTION
PREMIUM
|
|
|
-
|
|
|
|
3,587
|
|
|
|
-
|
|
|
|
4,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$ |
45,613
|
|
|
$ |
55,622
|
|
|
$ |
99,648
|
|
|
$ |
118,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
45,613
|
|
|
$ |
59,209
|
|
|
$ |
99,648
|
|
|
$ |
123,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirment benefits
|
|
|
(3,424 |
) |
|
|
-
|
|
|
|
(6,847 |
) |
|
|
-
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
5,099
|
|
|
|
(4,063 |
) |
|
|
4,973
|
|
|
|
1,672
|
|
Other
comprehensive income (loss)
|
|
|
1,675
|
|
|
|
(4,063 |
) |
|
|
(1,874 |
) |
|
|
1,672
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
388
|
|
|
|
(1,466 |
) |
|
|
(1,115 |
) |
|
|
603
|
|
Other
comprehensive income (loss), net of tax
|
|
|
1,287
|
|
|
|
(2,597 |
) |
|
|
(759 |
) |
|
|
1,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
46,900
|
|
|
$ |
56,612
|
|
|
$ |
98,889
|
|
|
$ |
124,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to Ohio
Edison
Company are an integral part of these
|
|
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
899
|
|
|
$ |
712
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,990,000 and
$15,033,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
263,316
|
|
|
|
234,781
|
|
Associated
companies
|
|
|
173,200
|
|
|
|
141,084
|
|
Other
(less
accumulated provisions of $5,090,000 and $1,985,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
13,380
|
|
|
|
13,496
|
|
Notes
receivable from associated companies
|
|
|
367,971
|
|
|
|
458,647
|
|
Prepayments
and other
|
|
|
20,482
|
|
|
|
13,606
|
|
|
|
|
839,248
|
|
|
|
862,326
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,690,282
|
|
|
|
2,632,207
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,043,183
|
|
|
|
1,021,918
|
|
|
|
|
1,647,099
|
|
|
|
1,610,289
|
|
Construction
work in progress
|
|
|
37,019
|
|
|
|
42,016
|
|
|
|
|
1,684,118
|
|
|
|
1,652,305
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
639,227
|
|
|
|
1,219,325
|
|
Investment
in
lease obligation bonds
|
|
|
274,248
|
|
|
|
291,393
|
|
Nuclear
plant
decommissioning trusts
|
|
|
125,906
|
|
|
|
118,209
|
|
Other
|
|
|
37,970
|
|
|
|
38,160
|
|
|
|
|
1,077,351
|
|
|
|
1,667,087
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
733,147
|
|
|
|
741,564
|
|
Pension
assets
|
|
|
100,682
|
|
|
|
68,420
|
|
Property
taxes
|
|
|
60,080
|
|
|
|
60,080
|
|
Unamortized
sale and leaseback costs
|
|
|
47,634
|
|
|
|
50,136
|
|
Other
|
|
|
53,914
|
|
|
|
18,696
|
|
|
|
|
995,457
|
|
|
|
938,896
|
|
|
|
$ |
4,596,174
|
|
|
$ |
5,120,614
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
335,812
|
|
|
$ |
159,852
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
-
|
|
|
|
113,987
|
|
Other
|
|
|
119,943
|
|
|
|
3,097
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
120,493
|
|
|
|
115,252
|
|
Other
|
|
|
17,907
|
|
|
|
13,068
|
|
Accrued
taxes
|
|
|
94,615
|
|
|
|
187,306
|
|
Accrued
interest
|
|
|
23,406
|
|
|
|
24,712
|
|
Other
|
|
|
61,611
|
|
|
|
64,519
|
|
|
|
|
773,787
|
|
|
|
681,793
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares -
|
|
|
|
|
|
|
|
|
60
and 80
shares outstanding, respectively
|
|
|
1,208,498
|
|
|
|
1,708,441
|
|
Accumulated
other comprehensive income
|
|
|
2,449
|
|
|
|
3,208
|
|
Retained
earnings
|
|
|
309,656
|
|
|
|
260,736
|
|
Total
common
stockholder's equity
|
|
|
1,520,603
|
|
|
|
1,972,385
|
|
Long-term
debt
and other long-term obligations
|
|
|
937,676
|
|
|
|
1,118,576
|
|
|
|
|
2,458,279
|
|
|
|
3,090,961
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
717,373
|
|
|
|
674,288
|
|
Accumulated
deferred investment tax credits
|
|
|
18,748
|
|
|
|
20,532
|
|
Asset
retirement obligations
|
|
|
90,801
|
|
|
|
88,223
|
|
Retirement
benefits
|
|
|
162,078
|
|
|
|
167,379
|
|
Deferred
revenues - electric service programs
|
|
|
67,566
|
|
|
|
86,710
|
|
Other
|
|
|
307,542
|
|
|
|
310,728
|
|
|
|
|
1,364,108
|
|
|
|
1,347,860
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
4,596,174
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
99,648
|
|
|
$ |
123,039
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
37,958
|
|
|
|
35,563
|
|
Amortization
of regulatory assets
|
|
|
91,543
|
|
|
|
97,305
|
|
Deferral
of
new regulatory assets
|
|
|
(90,993 |
) |
|
|
(78,323 |
) |
Amortization
of lease costs
|
|
|
(4,367 |
) |
|
|
(4,334 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
3,017
|
|
|
|
(17,351 |
) |
Accrued
compensation and retirement benefits
|
|
|
(25,829 |
) |
|
|
930
|
|
Pension
trust
contribution
|
|
|
(20,261 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(60,535 |
) |
|
|
66,215
|
|
Prepayments
and other current assets
|
|
|
(3,162 |
) |
|
|
(7,913 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
10,080
|
|
|
|
(45,894 |
) |
Accrued
taxes
|
|
|
(87,969 |
) |
|
|
9,378
|
|
Accrued
interest
|
|
|
(1,306 |
) |
|
|
(1,183 |
) |
Electric
service prepayment programs
|
|
|
(19,144 |
) |
|
|
(16,838 |
) |
Other
|
|
|
2,854
|
|
|
|
(8,051 |
) |
Net
cash
provided from (used for) operating activities
|
|
|
(68,466 |
) |
|
|
152,543
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
|
599,778
|
|
Short-term
borrowings, net
|
|
|
2,859
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(500,000 |
) |
|
|
-
|
|
Long-term
debt
|
|
|
(1,181 |
) |
|
|
(145,316 |
) |
Short-term
borrowings, net
|
|
|
-
|
|
|
|
(176,708 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(50,000 |
) |
|
|
(35,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(1,317 |
) |
Net
cash
provided from (used for) financing activities
|
|
|
(548,322 |
) |
|
|
241,437
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(66,607 |
) |
|
|
(63,294 |
) |
Sales
of
investment securities held in trusts
|
|
|
22,225
|
|
|
|
29,168
|
|
Purchases
of
investment securities held in trusts
|
|
|
(24,187 |
) |
|
|
(29,860 |
) |
Loan
repayments from associated companies, net
|
|
|
670,774
|
|
|
|
112,840
|
|
Cash
investments
|
|
|
-
|
|
|
|
78,248
|
|
Other
|
|
|
14,770
|
|
|
|
23,281
|
|
Net
cash
provided from investing activities
|
|
|
616,975
|
|
|
|
150,383
|
|
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
187
|
|
|
|
544,363
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
712
|
|
|
|
929
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
899
|
|
|
$ |
545,292
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Ohio Edison
Company are an integral part
|
of
these
statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of Ohio
Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of Ohio Edison Company and
its
subsidiaries as of June 30, 2007 and the related consolidated statements
of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2007 and 2006 and the consolidated statement
of cash
flows for the six-month periods ended June 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
August
6,
2007
OHIO
EDISON
COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND 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
Earnings
on common
stock in the second quarter of 2007 decreased to $46 million from $56
million in
the second quarter of 2006. In the first six months of 2007, earnings
on common
stock decreased to $100 million from $119 million in the same period
of 2006. The decrease in earnings in both periods primarily resulted
from higher
purchased power costs and lower other income, partially offset by higher
electric sales revenues and the deferral of new regulatory assets.
Revenues
Revenues
increased
by $24 million or 4.1% in the second quarter of 2007 compared with
the same
period in 2006, primarily due to higher retail generation revenues
of $15
million and wholesale generation revenues of $5 million.
Higher
retail
generation revenues from residential customers reflected increased
sales volume
and the impact of higher average unit prices. Weather conditions in
the second
quarter of 2007 compared to the same period in 2006 contributed to
the higher
KWH sales to residential customers (heating degree days increased 7.0%
and 8.5%
and cooling degree days increased by 74.5% and 83.8% 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 went
into effect 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 the second quarter of 2007 as compared
to the
same period in 2006. The percentage of shopping customers increased
to 27.6
percent during the second quarter of 2007 from 15.2 percent in the
second
quarter of 2006.
Revenues
increased
by $63 million or 5.4% in the first six months of 2007 compared with
the same
period in 2006, primarily due to higher retail generation revenues
of $63
million and wholesale generation revenues of $2 million, partially
offset by
decreases in revenues from distribution throughput of $13 million.
Retail
generation
revenues increased for residential and commercial customers due to
the higher
prices and increased sales volume. Weather conditions in the first
six months of
2007 compared to the same period in 2006 contributed to the higher
KWH sales to
residential and commercial customers (heating degree days increased
13.9% and
10.7% in OE’s and Penn’s service territories, respectively). Retail generation
revenues from the industrial sector decreased primarily due to an increase
in
customer shopping in the first six months of 2007 as compared to the
same period
in 2006. The percentage of shopping customers increased to 26.9 percent
in the
first six months of 2007 from 15.9 percent in the first six months
of
2006.
Changes
in retail
electric generation KWH sales and revenues in the second quarter and
first six
months of 2007 from the corresponding periods of 2006 are summarized
in the
following tables:
Retail
Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
9.0
|
%
|
|
10.8
|
%
|
Commercial
|
|
|
(1.3
|
)%
|
|
0.7
|
%
|
Industrial
|
|
|
(16.8
|
)%
|
|
(14.9
|
)%
|
Net
Decrease in Generation Sales
|
|
|
(4.3
|
)%
|
|
(1.7
|
)%
|
Retail
Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Residential
|
|
$
|
24
|
|
$
|
61
|
|
Commercial
|
|
|
6
|
|
|
22
|
|
Industrial
|
|
|
(15
|
)
|
|
(20
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
15
|
|
$
|
63
|
|
Increased
revenues
from distribution throughput to residential customers reflected the
impact of
weather conditions described above in the second quarter and first
six months of
2007 as compared to the same periods in 2006, partially offset by lower
composite unit prices. Reduced revenues from distribution throughput
to
commercial customers in the second quarter and first six months of
2007 resulted
from lower unit prices, partially offset by increased KWH deliveries.
Revenues
from distribution throughput to industrial customers decreased in the
second
quarter and first six months of 2007 as a result of lower unit prices
and
reduced KWH deliveries.
Changes
in
distribution KWH deliveries and revenues in the second quarter and
first six
months of 2007 from the corresponding periods of 2006 are summarized
in the
following tables.
Changes
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
7.5
|
%
|
|
8.7
|
%
|
Commercial
|
|
|
4.7
|
%
|
|
4.6
|
%
|
Industrial
|
|
|
(2.5
|
)%
|
|
(2.0
|
)%
|
Net
Increase in Distribution Deliveries
|
|
|
2.7
|
%
|
|
3.5
|
%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Residential
|
|
$
|
4
|
|
$
|
3
|
|
Commercial
|
|
|
(1
|
)
|
|
(5
|
)
|
Industrial
|
|
|
(3
|
)
|
|
(11
|
)
|
Changes
in Distribution Revenues
|
|
$
|
-
|
|
$
|
(13
|
)
|
Expenses
Total
expenses
increased by $32 million in the second quarter of 2007 and $93 million
in the
first six months of 2007 from the same periods of 2006. The following
table
presents changes from the prior year by expense category.
Expenses
– Changes
|
|
Three
Months
|
|
Six
Months
|
Increase
(Decrease)
|
|
(In
millions)
|
Purchased
power costs
|
|
$
|
30
|
|
$
|
97
|
|
Nuclear
operating costs
|
|
|
4
|
|
|
4
|
|
Other
operating costs
|
|
|
5
|
|
|
3
|
|
Provision
for
depreciation
|
|
|
1
|
|
|
2
|
|
Amortization
of regulatory assets
|
|
|
3
|
|
|
(5
|
)
|
Deferral
of
new regulatory assets
|
|
|
(12
|
)
|
|
(13
|
)
|
General
taxes
|
|
|
1
|
|
|
5
|
|
Net
Increase in Expenses
|
|
$
|
32
|
|
$
|
93
|
|
Higher
purchased
power costs in the second quarter and first six months of 2007 primarily
reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA
with FES. The increase in nuclear operating costs during the second
quarter and
first six months of 2007 was due to expenses related to the second
quarter 2007
nuclear refueling outage at the Perry Plant. The increase in other
operating
costs during the second quarter of 2007 was primarily due to higher
transmission
expenses related to MISO operations, partially offset by lower employee
benefit
expenses. Lower amortization of regulatory assets for the first six
months of
2007 was due to the completion of the generation-related transition
cost
amortization under OE’s and Penn’s respective transition plans at the end of
January 2006. The decreases in expense related to the deferral of new
regulatory
assets for the second quarter of 2007 and first six months of 2007
were
primarily due to increases in MISO cost deferrals and related interest.
General
taxes were higher in the first six 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 $13 million in the second quarter of 2007 and $22 million
in the first
six months of 2007 as compared with the same periods of 2006, primarily due
to reductions in interest income on notes receivable resulting from
principal
payments from associated companies. Higher interest expense in the
second
quarter and first six months of 2007 also contributed to the decrease
in other
income in both periods of 2007 and was largely due to OE’s issuance of $600
million of long-term debt in June 2006, partially offset by debt redemptions
that have occurred since the second quarter of 2006.
Income
Taxes
In
the first six
months of 2007, OE’s income taxes included a $7.2 million adjustment
related to an inter-company federal tax allocation arrangement between
FirstEnergy and its subsidiaries.
Capital
Resources and Liquidity
During
2007, OE
expects to meet its contractual obligations primarily with cash from
operations
and short-term credit arrangements. Borrowing capacity under OE’s credit
facilities is available to manage its working capital requirements.
Changes
in Cash Position
OE
had $899,000 of
cash and cash equivalents as of June 30, 2007 compared with $712,000
as of
December 31, 2006. The major sources for changes in these balances are
summarized below.
Cash
Flows From Operating
Activities
Net
cash provided from operating activities in the first six months
of 2007 and 2006 were as follows:
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
Non-cash
charges (credits)
|
|
|
|
)
|
|
|
|
Pension
trust
contribution
|
|
|
|
)
|
|
|
|
Working
capital and other
|
|
|
|
)
|
|
|
|
Net
cash
provided from (used for) operating activities
|
|
|
|
)
|
|
|
|
The
changes in net
income and non-cash charges are described above under “Results of Operations.”
The decrease from working capital changes primarily reflects changes
in accounts
receivable of $127 million and accrued taxes of $97 million, partially
offset by
changes in accounts payable of $56 million.
Cash
Flows From Financing
Activities
In
the first six
months of 2007, net cash used for financing activities was $548 million
compared
to $241 million provided from financing activities in the same period
last year.
This change primarily resulted from a $500 million repurchase of common
stock
from FirstEnergy, a $276 million net decrease in new financing activity
and a
$15 million increase in common stock dividends to FirstEnergy.
OE
had approximately
$369 million of cash and temporary cash investments (which include
short-term
notes receivable from associated companies) and $120 million of short-term
indebtedness as of June 30, 2007. OE has authorization from the PUCO
to incur
short-term debt of up to $500 million through bank facilities and the
utility money pool. Penn has authorization from the FERC to incur short-term
debt up to its charter limit of $39 million as of June 30, 2007, and
also has
access to bank facilities and the utility money pool.
In
February 2007,
FES made a $562 million payment on its fossil generation asset transfer
notes
owed to OE and Penn. OE used $500 million of the proceeds to repurchase
shares of its common stock from FirstEnergy.
See
the “Financing
Capability” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for additional discussion of OE’s financing
capabilities.
Cash
Flows From Investing
Activities
Net
cash provided
from investing activities increased $467 million in the first six months
of 2007
from the same period in 2006. The increase resulted primarily from
a $558
million increase in loan repayments from associated companies (including
the
$562 million payment from FES described above), partially offset by
a $78
million change in cash investments.
During
the second
half of 2007, OE’s capital spending is expected to be approximately $70 million.
OE has additional requirements of approximately $3 million for maturing
long-term debt during that period. These cash requirements are expected
to be
satisfied from a combination of cash from operations and short-term
credit
arrangements. OE’s capital spending for the period 2007-2011 is expected to be
about $769 million, of which approximately $139 million applies to
2007.
Off-Balance
Sheet Arrangements
Obligations
not
included on OE’s Consolidated Balance Sheets primarily consist of sale and
leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit
2. As of
June 30, 2007, the present value of these operating lease commitments,
net of
trust investments, was $619 million.
Equity
Price Risk
Included
in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $82 million and $80
million as of
June 30, 2007 and December 31, 2006, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in an $8
million
reduction in fair value as of June 30, 2007.
Regulatory
Matters
See
the “Regulatory
Matters” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of regulatory matters applicable
to
OE.
Environmental
Matters
See
the
“Environmental Matters” section within the Combined Management’s Discussion and
Analysis of Registrant Subsidiaries for discussion of environmental
matters
applicable to OE.
Other
Legal Proceedings
See
the “Other Legal
Proceedings” section 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
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
433,014
|
|
|
$ |
416,690
|
|
|
$ |
855,819
|
|
|
$ |
807,189
|
|
Excise
tax
collections
|
|
|
16,468
|
|
|
|
15,681
|
|
|
|
34,495
|
|
|
|
32,992
|
|
Total
revenues
|
|
|
449,482
|
|
|
|
432,371
|
|
|
|
890,314
|
|
|
|
840,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
14,332
|
|
|
|
13,413
|
|
|
|
27,523
|
|
|
|
26,976
|
|
Purchased
power
|
|
|
178,669
|
|
|
|
157,941
|
|
|
|
359,326
|
|
|
|
301,711
|
|
Other
operating costs
|
|
|
83,075
|
|
|
|
68,436
|
|
|
|
158,026
|
|
|
|
141,331
|
|
Provision
for
depreciation
|
|
|
18,713
|
|
|
|
11,050
|
|
|
|
37,181
|
|
|
|
28,251
|
|
Amortization
of regulatory assets
|
|
|
35,047
|
|
|
|
29,476
|
|
|
|
68,176
|
|
|
|
61,006
|
|
Deferral
of
new regulatory assets
|
|
|
(43,059 |
) |
|
|
(31,697 |
) |
|
|
(77,016 |
) |
|
|
(62,223 |
) |
General
taxes
|
|
|
34,098
|
|
|
|
31,510
|
|
|
|
72,992
|
|
|
|
66,580
|
|
Total
expenses
|
|
|
320,875
|
|
|
|
280,129
|
|
|
|
646,208
|
|
|
|
563,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
128,607
|
|
|
|
152,242
|
|
|
|
244,106
|
|
|
|
276,549
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
16,324
|
|
|
|
24,674
|
|
|
|
34,011
|
|
|
|
51,610
|
|
Miscellaneous
income
|
|
|
3,226
|
|
|
|
5,642
|
|
|
|
3,957
|
|
|
|
5,396
|
|
Interest
expense
|
|
|
(37,267 |
) |
|
|
(34,634 |
) |
|
|
(73,007 |
) |
|
|
(69,366 |
) |
Capitalized
interest
|
|
|
141
|
|
|
|
837
|
|
|
|
346
|
|
|
|
1,510
|
|
Total
other
expense
|
|
|
(17,576 |
) |
|
|
(3,481 |
) |
|
|
(34,693 |
) |
|
|
(10,850 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
111,031
|
|
|
|
148,761
|
|
|
|
209,413
|
|
|
|
265,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
42,082
|
|
|
|
57,709
|
|
|
|
76,915
|
|
|
|
102,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
68,949
|
|
|
|
91,052
|
|
|
|
132,498
|
|
|
|
163,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
1,203
|
|
|
|
-
|
|
|
|
2,405
|
|
|
|
-
|
|
Income
tax
expense related to other comprehensive income
|
|
|
357
|
|
|
|
-
|
|
|
|
712
|
|
|
|
-
|
|
Other
comprehensive income, net of tax
|
|
|
846
|
|
|
|
-
|
|
|
|
1,693
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
69,795
|
|
|
$ |
91,052
|
|
|
$ |
134,191
|
|
|
$ |
163,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to The Cleveland
Electric Illuminating Company are an
|
|
integral
part
of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
236
|
|
|
$ |
221
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $8,554,000 and $6,783,000
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
290,711
|
|
|
|
245,193
|
|
Associated
companies
|
|
|
59,852
|
|
|
|
249,735
|
|
Other
|
|
|
12,775
|
|
|
|
14,240
|
|
Notes
receivable from associated companies
|
|
|
24,898
|
|
|
|
27,191
|
|
Prepayments
and other
|
|
|
2,002
|
|
|
|
2,314
|
|
|
|
|
390,474
|
|
|
|
538,894
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,183,308
|
|
|
|
2,136,766
|
|
Less
-
Accumulated provision for depreciation
|
|
|
839,003
|
|
|
|
819,633
|
|
|
|
|
1,344,305
|
|
|
|
1,317,133
|
|
Construction
work in progress
|
|
|
46,543
|
|
|
|
46,385
|
|
|
|
|
1,390,848
|
|
|
|
1,363,518
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
353,293
|
|
|
|
486,634
|
|
Investment
in
lessor notes
|
|
|
463,436
|
|
|
|
519,611
|
|
Other
|
|
|
10,316
|
|
|
|
13,426
|
|
|
|
|
827,045
|
|
|
|
1,019,671
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521
|
|
|
|
1,688,521
|
|
Regulatory
assets
|
|
|
862,758
|
|
|
|
854,588
|
|
Pension
assets
|
|
|
15,124
|
|
|
|
-
|
|
Property
taxes
|
|
|
65,000
|
|
|
|
65,000
|
|
Other
|
|
|
51,028
|
|
|
|
33,306
|
|
|
|
|
2,682,431
|
|
|
|
2,641,415
|
|
|
|
$ |
5,290,798
|
|
|
$ |
5,563,498
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
120,597
|
|
|
$ |
120,569
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
179,892
|
|
|
|
218,134
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
71,407
|
|
|
|
365,678
|
|
Other
|
|
|
6,517
|
|
|
|
7,194
|
|
Accrued
taxes
|
|
|
88,277
|
|
|
|
128,829
|
|
Accrued
interest
|
|
|
22,150
|
|
|
|
19,033
|
|
Lease
market
valuation liability
|
|
|
58,750
|
|
|
|
60,200
|
|
Other
|
|
|
37,473
|
|
|
|
52,101
|
|
|
|
|
585,063
|
|
|
|
971,738
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
|
67,930,743
shares outstanding
|
|
|
860,206
|
|
|
|
860,133
|
|
Accumulated
other comprehensive loss
|
|
|
(102,738 |
) |
|
|
(104,431 |
) |
Retained
earnings
|
|
|
741,439
|
|
|
|
713,201
|
|
Total
common
stockholder's equity
|
|
|
1,498,907
|
|
|
|
1,468,903
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,936,862
|
|
|
|
1,805,871
|
|
|
|
|
3,435,769
|
|
|
|
3,274,774
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
492,203
|
|
|
|
470,707
|
|
Accumulated
deferred investment tax credits
|
|
|
19,422
|
|
|
|
20,277
|
|
Lease
market
valuation liability
|
|
|
505,725
|
|
|
|
547,800
|
|
Retirement
benefits
|
|
|
110,329
|
|
|
|
122,862
|
|
Deferred
revenues - electric service programs
|
|
|
40,459
|
|
|
|
51,588
|
|
Other
|
|
|
101,828
|
|
|
|
103,752
|
|
|
|
|
1,269,966
|
|
|
|
1,316,986
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
5,290,798
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
132,498
|
|
|
$ |
163,465
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
37,181
|
|
|
|
28,251
|
|
Amortization
of regulatory assets
|
|
|
68,176
|
|
|
|
61,006
|
|
Deferral
of
new regulatory assets
|
|
|
(77,016 |
) |
|
|
(62,223 |
) |
Nuclear
fuel
and capital lease amortization
|
|
|
116
|
|
|
|
120
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(45,858 |
) |
|
|
(55,043 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(7,103 |
) |
|
|
(4,745 |
) |
Accrued
compensation and retirement benefits
|
|
|
1,594
|
|
|
|
1,584
|
|
Pension
trust
contribution
|
|
|
(24,800 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
156,526
|
|
|
|
46,262
|
|
Prepayments
and other current assets
|
|
|
163
|
|
|
|
399
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(308,551 |
) |
|
|
(6,388 |
) |
Accrued
taxes
|
|
|
(40,119 |
) |
|
|
(1,932 |
) |
Accrued
interest
|
|
|
3,117
|
|
|
|
(76 |
) |
Electric
service prepayment programs
|
|
|
(11,129 |
) |
|
|
(7,695 |
) |
Other
|
|
|
573
|
|
|
|
(4,162 |
) |
Net
cash
provided from (used for) operating activities
|
|
|
(114,632 |
) |
|
|
158,823
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
247,426
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(103,397 |
) |
|
|
(118,152 |
) |
Short-term
borrowings, net
|
|
|
(52,894 |
) |
|
|
(57,675 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(104,000 |
) |
|
|
(63,000 |
) |
Net
cash used
for financing activities
|
|
|
(12,865 |
) |
|
|
(238,827 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(64,366 |
) |
|
|
(65,551 |
) |
Loan
repayments from associated companies, net
|
|
|
2,292
|
|
|
|
108,169
|
|
Collection
of
principal on long-term notes receivable
|
|
|
133,341
|
|
|
|
-
|
|
Redemption
of
lessor notes
|
|
|
56,175
|
|
|
|
44,551
|
|
Other
|
|
|
70
|
|
|
|
(7,155 |
) |
Net
cash
provided from investing activities
|
|
|
127,512
|
|
|
|
80,014
|
|
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
15
|
|
|
|
10
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
221
|
|
|
|
207
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
236
|
|
|
$ |
217
|
|
|
|
|
|
|
|
|
|
|
The
preceeding
Notes to Consolidated Financial Statements as they relate to
The Cleveland
Electric Illuminating Company |
|
are
an
integral part of these statements. |
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of The
Cleveland Electric Illuminating Company:
We
have reviewed the
accompanying consolidated balance sheet of The Cleveland Electric
Illuminating
Company and its subsidiaries as of June 30, 2007 and the related
consolidated
statements of income and comprehensive income for each of the three-month
and
six-month periods ended June 30, 2007 and 2006 and the consolidated
statement of
cash flows for the six-month periods ended June 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
August
6,
2007
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND 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
second quarter of 2007 decreased to $69 million from $91 million in the
same period of 2006. In the first six months of 2007, net income
decreased to $132 million from $163 million in the same period of
2006. The
decrease in both periods resulted primarily from higher purchased
power costs
and other operating costs, partially offset by higher revenues and
the deferral
of new regulatory assets.
Revenues
Revenues
increased
by $17 million or 4% in the second quarter of 2007 from the same
period of 2006
primarily due to higher retail generation and distribution revenues. Retail
generation revenues increased $11 million due to increased KWH sales
in the
residential and commercial sectors and higher composite unit prices
in the
commercial and industrial sectors. More extreme weather in the second
quarter of
2007 compared to the unseasonably mild weather in the same period
in 2006
contributed to the higher KWH sales for both residential and commercial
customers (cooling degree days increased 82% and heating degree days
were 10%
higher in 2007).
In
the first six
months of 2007, revenues increased by $50 million or 6% compared
to the same
period of 2006 primarily due to higher retail generation and wholesale
revenues. Retail generation revenues increased by $33 million due to
increased KWH sales and higher composite unit prices in all
classes. The weather contributed to the increased KWH sales in the
residential and commercial sectors (cooling degree days increased
84% and
heating degree days increased 16% from the same period in
2006). Increased industrial KWH sales reflected a slight decrease in
customer shopping.
Wholesale
generation
revenues increased by $1 million in the second quarter and $12 million
in the
first six months of 2007 compared to the corresponding periods of
2006. The increases in both periods were primarily due to higher unit
prices for PSA sales to associated companies. In the first six months
of 2007 higher unit prices were partially offset by a decrease in
sales volume
due in part to maintenance outages at the Bruce Mansfield Plant in
the first
quarter of 2007. CEI sells KWH from its leasehold interests in the
Bruce
Mansfield Plant to FGCO.
Increases
in retail
electric generation sales and revenues in the second quarter and
the first six
months of 2007 compared to the corresponding periods of 2006 are
summarized in
the following tables:
Retail
Generation KWH Sales |
|
Three
Months
|
|
Six
Months
|
|
Residential
|
|
|
5.3
|
%
|
|
6.8
|
%
|
Commercial
|
|
|
6.6
|
%
|
|
6.9
|
%
|
Industrial
|
|
|
0.8
|
%
|
|
2.0
|
%
|
Increase
in Retail Generation Sales
|
|
|
3.3
|
%
|
|
4.5
|
%
|
Retail
Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
$
|
9
|
|
Commercial
|
|
|
5
|
|
|
12
|
|
Industrial
|
|
|
4
|
|
|
12
|
|
Increase
in Generation Revenues
|
|
$
|
11
|
|
$
|
33
|
|
Revenues
from
distribution throughput increased by $3 million in the second quarter
and $1
million in the first six months of 2007 compared to the same periods
of 2006
primarily due to increased residential and commercial KWH deliveries,
offset by
lower composite unit prices in all classes. Increased KWH deliveries
were
primarily a result of the more extreme weather in 2007 as described
above.
Changes
in
distribution KWH deliveries and revenues in the second quarter and
first six
months of 2007 compared to the corresponding periods of 2006 are
summarized in
the following tables.
Increase
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Residential
|
|
|
5.4
|
%
|
|
6.9
|
%
|
Commercial
|
|
|
4.6
|
%
|
|
4.8
|
%
|
Industrial
|
|
|
0.9
|
%
|
|
1.5
|
%
|
Total
Increase in Distribution Deliveries
|
|
|
3.0
|
%
|
|
3.8
|
%
|
Change
in Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Residential
|
|
$
|
3
|
|
$
|
5
|
|
Commercial
|
|
|
2
|
|
|
3
|
|
Industrial
|
|
|
(2
|
)
|
|
(7
|
)
|
Net
Increase
in Distribution Revenues
|
|
$
|
3
|
|
$
|
1
|
|
Expenses
Total
expenses
increased by $41 million in the second quarter and $83 million in
the first six
months of 2007 compared to the corresponding periods of 2006. The
following
table presents changes in each period from the prior year by expense
category:
Expenses -
Changes
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
costs
|
|
$
|
1
|
|
$
|
1
|
|
Purchased
power costs
|
|
|
21
|
|
|
58
|
|
Other
operating costs
|
|
|
15
|
|
|
17
|
|
Provision
for
depreciation
|
|
|
8
|
|
|
9
|
|
Amortization
of regulatory assets
|
|
|
5
|
|
|
7
|
|
Deferral
of
new regulatory assets
|
|
|
(11
|
)
|
|
(15
|
)
|
General
taxes
|
|
|
2
|
|
|
6
|
|
Net
Increase in Expenses
|
|
$
|
41
|
|
$
|
83
|
|
Higher
purchased
power costs in the second quarter and the first six months of 2007
compared to
the corresponding periods of 2006 primarily reflect higher unit prices
associated with the PSA with FES and an increase in KWH purchases
to meet CEI’s
higher retail generation sales requirements. The higher other operating
costs in
the second quarter and the first six months of 2007 compared to the
same periods
of 2006 reflect an increase in MISO transmission related expenses. The
difference between transmission revenues accrued and transmission
costs incurred
is deferred, resulting in no material impact to current period earnings.
The
increased depreciation in the second quarter of 2007 and the first
six months of
2007 is primarily due to the absence of credit adjustments in the
second quarter
of 2006 related to prior periods ($6.5 million pre-tax, $4 million
net of
tax).
The
increased
amortization of regulatory assets in the second quarter and the first
six months
of 2007 compared to the corresponding periods of 2006 was due to
increased
transition cost amortization reflecting the higher KWH sales discussed
above. The increases in the deferral of new regulatory assets in the
second quarter and the first six months of 2007 compared to the same
periods of
2006 reflect a higher level of MISO costs that were deferred in excess
of
transmission revenues and increased distribution cost deferrals under
CEI’s
RCP. General taxes were higher in the second quarter and the first six
months of 2007 as a result of higher real and personal property taxes
and KWH
excise taxes.
Other
Expense
Other
expense
increased by $14 million in the second quarter and $24 million in
the first six
months of 2007 compared to the corresponding periods 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
second quarter
of 2006 on notes receivable related to the generation asset transfers. In
addition, there was a $6 million benefit recognized in the second
quarter of
2006 related to the sale of the Ashtabula C.
Capital
Resources and Liquidity
During
2007, CEI
expects to meet its contractual obligations with cash from operations
and
short-term credit arrangements.
Changes
in Cash Position
As
of June 30, 2007,
CEI had $236,000 of cash and cash equivalents, compared with $221,000
as of
December 31, 2006. The major sources of changes in these balances are
summarized below.
Cash
Flows from Operating
Activities
Cash
used for
operating activities during the first six months of 2007, compared
with cash
provided from operating activities for the first six months of 2006,
were as
follows:
|
|
Six
Months Ended
|
|
Operating
Cash Flows
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
|
|
$
|
|
|
Non-cash
credits
|
|
|
|
)
|
|
|
)
|
Pension
trust
contribution
|
|
|
|
)
|
|
|
|
Working
capital and other
|
|
|
|
)
|
|
|
|
Net
cash
provided from (used for) operating activities
|
|
$
|
|
)
|
$
|
|
|
Net
cash used for
operating activities was $115 million in the first six months of
2007 compared
to $159 million provided from operating activities for the same period
in
2006. The $274 million change was primarily due to a $25 million
pension trust contribution in the first quarter of 2007 and a
$222 million change in working capital and other. The change in
working capital was due to changes in accounts payable of $302 million
(primarily for the settlement of payables with associated companies)
and accrued
taxes of $38 million, partially offset by changes in accounts receivable
of
$110 million. The changes in net income and non–cash credits are described
above under “Results of Operations.”
Cash
Flows from Financing
Activities
Net
cash used for
financing activities was $13 million in the first six months of 2007
compared to
$239 million in the same period of 2006. The change reflects $248
million of new
long-term debt financing and a $14 million decrease in repayments
of long-term
debt, partially offset by a $41 million increase in common stock
dividend
payments to FirstEnergy.
CEI
had $25 million
of cash and temporary investments (which included short-term notes
receivable
from associated companies) and approximately $180 million of short-term
indebtedness as of June 30, 2007. CEI has obtained authorization
from the PUCO
to incur short-term debt of up to $500 million through bank facilities and
the utility money pool.
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 short-term borrowings
and for
general corporate purposes. On June 1, 2007 CEI redeemed $103 million
of Trust C
preferred securities.
See
the “Financing
Capability” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for additional discussion of CEI’s financing
capabilities.
Cash
Flows from Investing
Activities
Net
cash provided
from investing activities increased by $47 million in the first six
months of
2007 compared to the same period of 2006. The change was primarily
due to the
collection of principal on long-term notes receivable, partially
offset by a
decrease in loan repayments from associated companies.
CEI’s
capital
spending for the last two quarters of 2007 is expected to be about
$92 million. These cash requirements are expected to be satisfied with
cash
from operations and short-term credit arrangements. CEI’s capital spending for
the period 2007-2011 is expected to be about $843 million, of which
approximately $160 million applies to 2007.
Off-Balance
Sheet Arrangements
Obligations
not
included on CEI’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant. As of
June 30, 2007,
the present value of these operating lease commitments, net of trust
investments, total $82 million.
Regulatory
Matters
See
the “Regulatory
Matters” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of regulatory matters applicable
to
CEI.
Environmental
Matters
See
the
“Environmental Matters” section within the Combined Management’s Discussion and
Analysis of Registrant Subsidiaries for discussion of environmental
matters
applicable to CEI.
Other
Legal Proceedings
See
the “Other Legal
Proceedings” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of other 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
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
233,637
|
|
|
$ |
219,139
|
|
|
$ |
466,693
|
|
|
$ |
430,013
|
|
Excise
tax
collections
|
|
|
6,700
|
|
|
|
6,459
|
|
|
|
14,100
|
|
|
|
13,562
|
|
Total
revenues
|
|
|
240,337
|
|
|
|
225,598
|
|
|
|
480,793
|
|
|
|
443,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
10,461
|
|
|
|
9,638
|
|
|
|
20,608
|
|
|
|
19,400
|
|
Purchased
power
|
|
|
96,276
|
|
|
|
80,659
|
|
|
|
192,445
|
|
|
|
156,079
|
|
Nuclear
operating costs
|
|
|
17,846
|
|
|
|
17,866
|
|
|
|
35,567
|
|
|
|
35,198
|
|
Other
operating costs
|
|
|
46,164
|
|
|
|
39,718
|
|
|
|
89,085
|
|
|
|
80,143
|
|
Provision
for
depreciation
|
|
|
9,127
|
|
|
|
8,240
|
|
|
|
18,244
|
|
|
|
16,337
|
|
Amortization
of regulatory assets
|
|
|
24,948
|
|
|
|
22,117
|
|
|
|
48,824
|
|
|
|
46,573
|
|
Deferral
of
new regulatory assets
|
|
|
(18,247 |
) |
|
|
(14,190 |
) |
|
|
(31,728 |
) |
|
|
(27,846 |
) |
General
taxes
|
|
|
13,000
|
|
|
|
12,253
|
|
|
|
26,734
|
|
|
|
25,184
|
|
Total
expenses
|
|
|
199,575
|
|
|
|
176,301
|
|
|
|
399,779
|
|
|
|
351,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
40,762
|
|
|
|
49,297
|
|
|
|
81,014
|
|
|
|
92,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
7,309
|
|
|
|
8,945
|
|
|
|
14,534
|
|
|
|
18,725
|
|
Miscellaneous
expense
|
|
|
(2,056 |
) |
|
|
(1,926 |
) |
|
|
(5,156 |
) |
|
|
(4,610 |
) |
Interest
expense
|
|
|
(8,916 |
) |
|
|
(4,364 |
) |
|
|
(16,419 |
) |
|
|
(8,674 |
) |
Capitalized
interest
|
|
|
164
|
|
|
|
344
|
|
|
|
247
|
|
|
|
558
|
|
Total
other
income (expense)
|
|
|
(3,499 |
) |
|
|
2,999
|
|
|
|
(6,794 |
) |
|
|
5,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
37,263
|
|
|
|
52,296
|
|
|
|
74,220
|
|
|
|
98,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
15,392
|
|
|
|
19,924
|
|
|
|
26,489
|
|
|
|
37,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
21,871
|
|
|
|
32,372
|
|
|
|
47,731
|
|
|
|
61,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
|
1,161
|
|
|
|
-
|
|
|
|
2,436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$ |
21,871
|
|
|
$ |
31,211
|
|
|
$ |
47,731
|
|
|
$ |
58,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
21,871
|
|
|
$ |
32,372
|
|
|
$ |
47,731
|
|
|
$ |
61,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
573
|
|
|
|
-
|
|
|
|
1,146
|
|
|
|
-
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
(669 |
) |
|
|
191
|
|
|
|
(290 |
) |
|
|
(947 |
) |
Other
comprehensive income (loss)
|
|
|
(96 |
) |
|
|
191
|
|
|
|
856
|
|
|
|
(947 |
) |
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(43 |
) |
|
|
69
|
|
|
|
291
|
|
|
|
(342 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
(53 |
) |
|
|
122
|
|
|
|
565
|
|
|
|
(605 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
21,818
|
|
|
$ |
32,494
|
|
|
$ |
48,296
|
|
|
$ |
60,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to The Toledo
Edison Company are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
22
|
|
|
$ |
22
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
|
|
|
1,081
|
|
|
|
772
|
|
Associated
companies
|
|
|
37,927
|
|
|
|
13,940
|
|
Other
(less accumulated provisions of $408,000 and $430,000,
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
4,334
|
|
|
|
3,831
|
|
Notes
receivable from associated companies
|
|
|
120,101
|
|
|
|
100,545
|
|
Prepayments
and other
|
|
|
792
|
|
|
|
851
|
|
|
|
|
164,257
|
|
|
|
119,961
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
907,710
|
|
|
|
894,888
|
|
Less
-
Accumulated provision for depreciation
|
|
|
403,634
|
|
|
|
394,225
|
|
|
|
|
504,076
|
|
|
|
500,663
|
|
Construction
work in progress
|
|
|
14,573
|
|
|
|
16,479
|
|
|
|
|
518,649
|
|
|
|
517,142
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Investment
in
lessor notes
|
|
|
154,647
|
|
|
|
169,493
|
|
Long-term
notes receivable from associated companies
|
|
|
96,521
|
|
|
|
128,858
|
|
Nuclear
plant
decommissioning trusts
|
|
|
62,289
|
|
|
|
61,094
|
|
Other
|
|
|
1,808
|
|
|
|
1,871
|
|
|
|
|
315,265
|
|
|
|
361,316
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576
|
|
|
|
500,576
|
|
Regulatory
assets
|
|
|
230,002
|
|
|
|
247,595
|
|
Pension
assets
|
|
|
5,379
|
|
|
|
-
|
|
Property
taxes
|
|
|
22,010
|
|
|
|
22,010
|
|
Other
|
|
|
45,194
|
|
|
|
30,042
|
|
|
|
|
803,161
|
|
|
|
800,223
|
|
|
|
$ |
1,801,332
|
|
|
$ |
1,798,642
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
30,000
|
|
|
$ |
30,000
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
36,974
|
|
|
|
84,884
|
|
Other
|
|
|
4,020
|
|
|
|
4,021
|
|
Notes
payable
to associated companies
|
|
|
242,253
|
|
|
|
153,567
|
|
Accrued
taxes
|
|
|
46,153
|
|
|
|
47,318
|
|
Lease
market
valuation liability
|
|
|
23,655
|
|
|
|
24,600
|
|
Other
|
|
|
18,755
|
|
|
|
37,551
|
|
|
|
|
401,810
|
|
|
|
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
|
|
|
166,801
|
|
|
|
166,786
|
|
Accumulated
other comprehensive loss
|
|
|
(36,239 |
) |
|
|
(36,804 |
) |
Retained
earnings
|
|
|
212,071
|
|
|
|
204,423
|
|
Total
common
stockholder's equity
|
|
|
489,643
|
|
|
|
481,415
|
|
Long-term
debt
|
|
|
358,227
|
|
|
|
358,281
|
|
|
|
|
847,870
|
|
|
|
839,696
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
160,799
|
|
|
|
161,024
|
|
Accumulated
deferred investment tax credits
|
|
|
10,597
|
|
|
|
11,014
|
|
Lease
market
valuation liability
|
|
|
198,688
|
|
|
|
218,800
|
|
Retirement
benefits
|
|
|
76,270
|
|
|
|
77,843
|
|
Asset
retirement obligations
|
|
|
27,439
|
|
|
|
26,543
|
|
Deferred
revenues - electric service programs
|
|
|
18,212
|
|
|
|
23,546
|
|
Other
|
|
|
59,647
|
|
|
|
58,235
|
|
|
|
|
551,652
|
|
|
|
577,005
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
1,801,332
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
47,731
|
|
|
$ |
61,378
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
18,244
|
|
|
|
16,337
|
|
Amortization
of regulatory assets
|
|
|
48,824
|
|
|
|
46,573
|
|
Deferral
of
new regulatory assets
|
|
|
(31,728 |
) |
|
|
(27,846 |
) |
Deferred
rents
and lease market valuation liability
|
|
|
(41,981 |
) |
|
|
(45,843 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(11,924 |
) |
|
|
(13,322 |
) |
Accrued
compensation and retirement benefits
|
|
|
1,277
|
|
|
|
1,268
|
|
Pension
trust
contribution
|
|
|
(7,659 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(21,594 |
) |
|
|
(18,257 |
) |
Prepayments
and other current assets
|
|
|
59
|
|
|
|
(4,076 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(56,784 |
) |
|
|
(14,231 |
) |
Accrued
taxes
|
|
|
751
|
|
|
|
3,748
|
|
Accrued
interest
|
|
|
1
|
|
|
|
(222 |
) |
Electric
service prepayment programs
|
|
|
(5,334 |
) |
|
|
(4,454 |
) |
Other
|
|
|
1,093
|
|
|
|
3,326
|
|
Net
cash
provided from (used for) operating activities
|
|
|
(59,024 |
) |
|
|
4,379
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
88,686
|
|
|
|
71,882
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
|
(30,000 |
) |
Long-term
debt
|
|
|
-
|
|
|
|
(53,650 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(40,000 |
) |
|
|
(25,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(2,436 |
) |
Net
cash
provided from (used for) financing activities
|
|
|
48,686
|
|
|
|
(39,204 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(19,804 |
) |
|
|
(29,361 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(19,546 |
) |
|
|
2,611
|
|
Collection
of
principal on long-term notes receivable
|
|
|
32,327
|
|
|
|
53,766
|
|
Redemption
of
lessor notes
|
|
|
14,846
|
|
|
|
9,305
|
|
Sales
of
investment securities held in trusts
|
|
|
32,499
|
|
|
|
30,954
|
|
Purchases
of
investment securities held in trusts
|
|
|
(32,796 |
) |
|
|
(31,043 |
) |
Other
|
|
|
2,812
|
|
|
|
(1,399 |
) |
Net
cash
provided from investing activities
|
|
|
10,338
|
|
|
|
34,833
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
|
8
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
22
|
|
|
|
15
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
22
|
|
|
$ |
23
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2007 and the related consolidated statements
of income
and comprehensive income for each of the three-month and six-month
periods ended
June 30, 2007 and 2006 and the consolidated statement of cash flows
for the
six-month periods ended June 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
August
6,
2007
THE
TOLEDO
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND 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 second quarter of 2007 decreased to $22 million from
$31 million in
the second quarter of 2006. Earnings on common stock in the first
six months of
2007 decreased to $48 million from $59 million in the same period
of 2006. The
decreases in both periods resulted primarily from higher purchased
power and
other operating costs, partially offset by higher electric sales
revenues and
the deferral of new regulatory assets.
Revenues
Revenues
increased
$15 million or 6.5% in the second quarter of 2007 compared to the
same period of
2006 primarily due to higher retail and wholesale generation revenues.
Retail
generation revenues increased by $8 million in the second quarter
of 2007 due to
higher average prices and increased sales volume across all customer
classes.
Average prices increased primarily due to higher composite unit
prices for
retail generation shopping customers returning to TE. Generation
services
provided by alternative suppliers as a percentage of total sales
delivered in
TE’s franchise area decreased by 1 percentage point for residential customers
from the second quarter of 2006. The increase in sales volume also
resulted from changes in weather in the second quarter of 2007
(heating and
cooling degree days increased 14.3% and 38.4%, respectively, from
the second
quarter of 2006).
The
increase in
wholesale revenues ($2 million) resulted primarily from increased KWH sales
to associated companies, partially offset by lower unit prices.
TE sells KWH
from its leasehold interests in Beaver Valley Unit 2 and the Bruce
Mansfield
Plant to CEI and FGCO, respectively.
Revenues
increased
$37 million or 8.4% in the first six months of 2007 compared to
the same period
of 2006 primarily due to higher retail generation revenues of $20
million,
higher wholesale generation revenues of $12 million and higher
transmission
revenues from non-associated companies of $2 million. Retail generation
revenues
increased for all customer sectors in the first six months of 2007
due to higher
average prices and increased sales volume as 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. Generation
services
provided by alternative suppliers as a percentage of total sales
delivered in
TE’s franchise area decreased by 3 percentage points and 1 percentage
point for
residential and commercial customers, respectively. The increase in
sales volume also reflects weather impacts in the first six months
of 2007
(heating and cooling degree days increased 16.9% and 39.3%, 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. Wholesale revenues from
non-associated companies decreased $2 million primarily due to
lower sales to
municipal customers.
Increases
in
electric generation KWH sales and revenues in the second quarter
and first six
months of 2007 from the corresponding periods of 2006 are summarized
in the
following tables.
Increase
in Retail Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
9.7
|
%
|
|
11.9
|
%
|
Commercial
|
|
|
3.7
|
%
|
|
4.5
|
%
|
Industrial
|
|
|
0.4
|
%
|
|
0.6
|
%
|
Total
Retail Electric Generation Sales
|
|
|
2.9
|
%
|
|
3.9
|
%
|
Increase
in Retail Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
$
|
7
|
|
Commercial
|
|
|
2
|
|
|
4
|
|
Industrial
|
|
|
4
|
|
|
9
|
|
Total
Retail Generation Revenues
|
|
$
|
8
|
|
$
|
20
|
|
Revenues
from
distribution throughput increased by $4 million and $2 million
in the second
quarter and first six months of 2007, respectively, compared to
the respective
periods in 2006 due to higher KWH deliveries to all customer sectors,
partially
offset by lower composite unit prices. The higher KWH deliveries
to residential
and commercial customers in both the second quarter and first six
months of 2007
reflected the impact of weather variations described above in both
periods of
2007 compared to the respective periods in 2006.
Changes
in
distribution KWH deliveries and revenues in the second quarter
and first six
months of 2007 from the corresponding periods of 2006 are summarized
in the
following tables.
Increase
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
8.6
|
%
|
|
8.2
|
%
|
Commercial
|
|
|
4.3
|
%
|
|
3.5
|
%
|
Industrial
|
|
|
0.7
|
%
|
|
0.6
|
%
|
Total
Increase in Distribution Deliveries
|
|
|
3.2
|
%
|
|
3.1
|
%
|
Changes
in Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
$
|
4
|
|
Commercial
|
|
|
2
|
|
|
2
|
|
Industrial
|
|
|
-
|
|
|
(4
|
)
|
Net
Increase in Distribution Revenues
|
|
$
|
4
|
|
$
|
2
|
|
Expenses
Total
expenses
increased by $23 million and $49 million in the second quarter and the
first six months of 2007, respectively, from the same periods of
2006. The
following table presents changes from the prior year by expense
category:
Expenses
– Changes
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
|
|
$
|
1
|
|
$
|
1
|
|
Purchased
power costs
|
|
|
15
|
|
|
36
|
|
Other
operating costs
|
|
|
6
|
|
|
9
|
|
Provision
for
depreciation
|
|
|
1
|
|
|
2
|
|
Amortization
of regulatory assets
|
|
|
3
|
|
|
2
|
|
Deferral
of
new regulatory assets
|
|
|
(4
|
)
|
|
(3
|
)
|
General
taxes
|
|
|
|
|
|
|
|
Net
increase in expenses
|
|
$
|
23
|
|
$
|
49
|
|
Higher
purchased
power costs in the second quarter of 2007 compared to the second
quarter 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 a $7 million increase in MISO
network
transmission expense assessments in the second quarter of 2007.
Higher
amortization of regulatory assets reflected increased amortization
of transition
cost deferrals and MISO transmission deferrals. The change in the
deferral of
new regulatory assets was primarily due to $5 million of increased
deferrals for
MISO transmission expenses. The difference between transmission
revenues accrued and transmission costs incurred is deferred, resulting
in no
material impact to current period earnings.
Higher
purchased
power costs in the first six 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.
Higher
amortization of regulatory assets reflected increased amortization
of transition
cost deferrals and MISO transmission deferrals. The change in the
deferral of new regulatory assets was primarily due to increased
deferrals for
MISO transmission expenses and RCP reliability costs, partially
offset by lower
RCP fuel cost deferrals. Other operating costs were higher due
to an $8 million
increase in MISO network transmission expenses in the first six
months of 2007.
Depreciation expense was higher due to an increase in depreciable
property as a
result of plant additions. Higher general taxes primarily reflected
increased
property taxes and higher KWH excise taxes.
Other
Expense
Other
expense
increased $6 million in the second quarter of 2007 and $13 million
in the first
six months of 2007 compared to the same periods 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 second
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.
Capital
Resources and Liquidity
During
2007, TE
expects to meet its contractual obligations primarily with cash
from operations
and short-term credit arrangements. Borrowing capacity under TE’s credit
facilities is available to manage its working capital requirements.
Changes
in Cash Position
There
was no change
as of June 30, 2007 from December 31, 2006 in TE’s cash and cash equivalents of
$22,000.
Cash
Flows From Operating
Activities
Net
cash provided
from (used for) operating activities in the first six months of
2007 and 2006
were as follows:
|
|
Six Months
Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
Pension
trust
contribution
|
|
|
|
)
|
|
|
|
Working
capital and other
|
|
|
|
)
|
|
|
|
Net
cash
provided from (used for)
|
|
|
|
)
|
|
|
|
Net
cash used for
operating activities was $59 million in the first six months of
2007 compared to
net cash provided from operating activities of $4 million in the
same period of
2006. The change was the result of a $13 million decrease in net income, an
$8 million pension trust contribution in the first six months of
2007 and a $47
million decrease from changes in working capital and other, partially
offset by
a $5 million decrease in net non-cash credits. The change in net
income is
described above under “Results of Operations.” The changes in working
capital and other are primarily due to increased cash outflows
for accounts
payable of $43 million.
Cash
Flows From Financing
Activities
Net
cash provided
from financing activities increased by $88 million in the first
six months of
2007 compared to the same period of 2006. The increase resulted
primarily from a
$17 million increase in short-term borrowings, a $30 million decrease in
preferred stock redemptions and a $54 million decrease in long-term
debt
redemptions, partially offset by a $15 million increase in common
stock
dividends to FirstEnergy in the first six months of 2007.
TE
had $120 million
of cash and temporary investments (which included short-term notes
receivable
from associated companies) and $242 million of short-term indebtedness as
of June 30, 2007. TE has authorization from the PUCO to incur short-term
debt of
up to $500 million through bank facilities and the utility money
pool.
See
the “Financing
Capability” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for additional discussion of TE’s financing
capabilities.
Cash
Flows From Investing
Activities
Net
cash provided
from investing activities decreased by $24 million in the first
six months of
2007 compared to the same period of 2006. The change was primarily
due to a $44
million net decrease in loan repayments from associated companies,
partially
offset by a $10 million decrease in property additions and a $6 million
increase from the redemption of lessor notes.
TE’s
capital
spending for the last two quarters of 2007 is expected to be about
$38 million. TE has additional requirements of $30 million for maturing
long-term debt during the remainder of 2007. These cash requirements
are
expected to be satisfied primarily with cash from operations and
short-term
credit arrangements. TE’s capital spending for the period 2007-2011 is expected
to be nearly $322 million, of which approximately $61 million applies
to 2007.
Off-Balance
Sheet Arrangements
Obligations
not
included on TE’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant and
Beaver Valley
Unit 2. As of June 30, 2007, the present value of these operating
lease
commitments, net of trust investments, total $442 million.
Regulatory
Matters
See
the “Regulatory
Matters” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of regulatory matters applicable
to
TE.
Environmental
Matters
See
the
“Environmental Matters” section within the Combined Management’s Discussion and
Analysis of Registrant Subsidiaries for discussion of environmental
matters
applicable to TE.
Other
Legal Proceedings
See
the “Other Legal
Proceedings” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of other 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
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
768,190
|
|
|
$ |
600,560
|
|
|
$ |
1,439,097
|
|
|
$ |
1,164,110
|
|
Excise
tax
collections
|
|
|
11,845
|
|
|
|
10,924
|
|
|
|
24,681
|
|
|
|
23,166
|
|
Total
revenues
|
|
|
780,035
|
|
|
|
611,484
|
|
|
|
1,463,778
|
|
|
|
1,187,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
464,505
|
|
|
|
343,045
|
|
|
|
851,002
|
|
|
|
658,755
|
|
Other
operating costs
|
|
|
74,564
|
|
|
|
72,105
|
|
|
|
149,215
|
|
|
|
155,133
|
|
Provision
for
depreciation
|
|
|
21,319
|
|
|
|
20,826
|
|
|
|
41,835
|
|
|
|
41,454
|
|
Amortization
of regulatory assets
|
|
|
93,890
|
|
|
|
65,526
|
|
|
|
189,118
|
|
|
|
132,271
|
|
General
taxes
|
|
|
15,553
|
|
|
|
14,272
|
|
|
|
32,552
|
|
|
|
30,504
|
|
Total
expenses
|
|
|
669,831
|
|
|
|
515,774
|
|
|
|
1,263,722
|
|
|
|
1,018,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
110,204
|
|
|
|
95,710
|
|
|
|
200,056
|
|
|
|
169,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
3,238
|
|
|
|
2,528
|
|
|
|
6,299
|
|
|
|
6,071
|
|
Interest
expense
|
|
|
(24,494 |
) |
|
|
(20,367 |
) |
|
|
(46,910 |
) |
|
|
(40,983 |
) |
Capitalized
interest
|
|
|
563
|
|
|
|
1,037
|
|
|
|
1,076
|
|
|
|
1,929
|
|
Total
other
expense
|
|
|
(20,693 |
) |
|
|
(16,802 |
) |
|
|
(39,535 |
) |
|
|
(32,983 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
89,511
|
|
|
|
78,908
|
|
|
|
160,521
|
|
|
|
136,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
39,698
|
|
|
|
38,632
|
|
|
|
72,362
|
|
|
|
62,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
49,813
|
|
|
|
40,276
|
|
|
|
88,159
|
|
|
|
73,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
|
125
|
|
|
|
-
|
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$ |
49,813
|
|
|
$ |
40,151
|
|
|
$ |
88,159
|
|
|
$ |
73,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
49,813
|
|
|
$ |
40,276
|
|
|
$ |
88,159
|
|
|
$ |
73,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(2,115 |
) |
|
|
-
|
|
|
|
(4,230 |
) |
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
69
|
|
|
|
38
|
|
|
|
166
|
|
|
|
107
|
|
Other
comprehensive income (loss)
|
|
|
(2,046 |
) |
|
|
38
|
|
|
|
(4,064 |
) |
|
|
107
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(995 |
) |
|
|
15
|
|
|
|
(1,979 |
) |
|
|
43
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(1,051 |
) |
|
|
23
|
|
|
|
(2,085 |
) |
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
48,762
|
|
|
$ |
40,299
|
|
|
$ |
86,074
|
|
|
$ |
74,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to Jersey
Central Power & Light Company are an integral
|
|
part
of
these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
87
|
|
|
$ |
41
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,042,000 and $3,524,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
378,940
|
|
|
|
254,046
|
|
Associated
companies
|
|
|
186
|
|
|
|
11,574
|
|
Other
(less
accumulated provisions of $701,000 and $204,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
64,010
|
|
|
|
40,023
|
|
Notes
receivable - associated companies
|
|
|
23,691
|
|
|
|
24,456
|
|
Materials
and
supplies, at average cost
|
|
|
1,953
|
|
|
|
2,043
|
|
Prepaid
taxes
|
|
|
122,391
|
|
|
|
13,333
|
|
Other
|
|
|
10,480
|
|
|
|
18,076
|
|
|
|
|
601,738
|
|
|
|
363,592
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
4,074,918
|
|
|
|
4,029,070
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,484,602
|
|
|
|
1,473,159
|
|
|
|
|
2,590,316
|
|
|
|
2,555,911
|
|
Construction
work in progress
|
|
|
97,539
|
|
|
|
78,728
|
|
|
|
|
2,687,855
|
|
|
|
2,634,639
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
fuel
disposal trust
|
|
|
170,840
|
|
|
|
171,045
|
|
Nuclear
plant
decommissioning trusts
|
|
|
172,371
|
|
|
|
164,108
|
|
Other
|
|
|
2,065
|
|
|
|
2,047
|
|
|
|
|
345,276
|
|
|
|
337,200
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
1,824,873
|
|
|
|
2,152,332
|
|
Goodwill
|
|
|
1,962,361
|
|
|
|
1,962,361
|
|
Pension
Assets
|
|
|
39,609
|
|
|
|
14,660
|
|
Other
|
|
|
15,724
|
|
|
|
17,781
|
|
|
|
|
3,842,567
|
|
|
|
4,147,134
|
|
|
|
$ |
7,477,436
|
|
|
$ |
7,482,565
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
39,082
|
|
|
$ |
32,683
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
263,809
|
|
|
|
186,540
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
7,325
|
|
|
|
80,426
|
|
Other
|
|
|
229,023
|
|
|
|
160,359
|
|
Accrued
taxes
|
|
|
18,600
|
|
|
|
1,451
|
|
Accrued
interest
|
|
|
10,621
|
|
|
|
14,458
|
|
Cash
collateral from suppliers
|
|
|
8,505
|
|
|
|
32,300
|
|
Other
|
|
|
83,766
|
|
|
|
96,150
|
|
|
|
|
660,731
|
|
|
|
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
|
|
|
2,789,235
|
|
|
|
2,908,279
|
|
Accumulated
other comprehensive loss
|
|
|
(46,339 |
) |
|
|
(44,254 |
) |
Retained
earnings
|
|
|
218,545
|
|
|
|
145,480
|
|
Total
common
stockholder's equity
|
|
|
3,105,657
|
|
|
|
3,159,598
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,575,430
|
|
|
|
1,320,341
|
|
|
|
|
4,681,087
|
|
|
|
4,479,939
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
877,297
|
|
|
|
1,182,108
|
|
Accumulated
deferred income taxes
|
|
|
780,004
|
|
|
|
803,944
|
|
Nuclear
fuel
disposal costs
|
|
|
188,205
|
|
|
|
183,533
|
|
Asset
retirement obligations
|
|
|
87,018
|
|
|
|
84,446
|
|
Other
|
|
|
203,094
|
|
|
|
144,228
|
|
|
|
|
2,135,618
|
|
|
|
2,398,259
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
7,477,436
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
88,159
|
|
|
$ |
73,986
|
|
Adjustments
to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
41,835
|
|
|
|
41,454
|
|
Amortization
of regulatory assets
|
|
|
189,118
|
|
|
|
132,271
|
|
Deferred
purchased power and other costs
|
|
|
(111,517 |
) |
|
|
(134,759 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(3,116 |
) |
|
|
10,942
|
|
Accrued
compensation and retirement benefits
|
|
|
(11,467 |
) |
|
|
(3,436 |
) |
Cash
collateral returned to suppliers
|
|
|
(23,905 |
) |
|
|
(108,791 |
) |
Pension
trust
contribution
|
|
|
(17,800 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(137,492 |
) |
|
|
(24,074 |
) |
Materials
and
supplies
|
|
|
90
|
|
|
|
91
|
|
Prepaid
taxes
|
|
|
(109,058 |
) |
|
|
(100,650 |
) |
Other
current
assets
|
|
|
2,540
|
|
|
|
1,718
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(4,438 |
) |
|
|
23,589
|
|
Accrued
taxes
|
|
|
27,515
|
|
|
|
(9,062 |
) |
Accrued
interest
|
|
|
(3,837 |
) |
|
|
362
|
|
Tax
collections payable
|
|
|
(12,478 |
) |
|
|
(10,322 |
) |
Other
|
|
|
(6,114 |
) |
|
|
8,680
|
|
Net
cash used
for operating activities
|
|
|
(91,965 |
) |
|
|
(98,001 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
550,000
|
|
|
|
200,003
|
|
Short-term
borrowings, net
|
|
|
77,269
|
|
|
|
183,818
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(304,579 |
) |
|
|
(157,659 |
) |
Common
Stock
|
|
|
(125,000 |
) |
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(15,000 |
) |
|
|
(25,000 |
) |
Preferred
stock
|
|
|
-
|
|
|
|
(250 |
) |
Net
cash
provided from financing activities
|
|
|
182,690
|
|
|
|
200,912
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(95,310 |
) |
|
|
(91,101 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
765
|
|
|
|
(9,347 |
) |
Sales
of
investment securities held in trusts
|
|
|
77,941
|
|
|
|
131,079
|
|
Purchases
of
investment securities held in trusts
|
|
|
(79,388 |
) |
|
|
(132,526 |
) |
Other
|
|
|
5,313
|
|
|
|
(1,023 |
) |
Net
cash used
for investing activities
|
|
|
(90,679 |
) |
|
|
(102,918 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
46
|
|
|
|
(7 |
) |
Cash
and cash
equivalents at beginning of period
|
|
|
41
|
|
|
|
102
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
87
|
|
|
$ |
95
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they
relate to Jersey
Central Power & Light Company
|
|
are
an
integral part of these statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of Jersey
Central Power & Light Company:
We
have reviewed the
accompanying consolidated balance sheet of Jersey Central Power
& Light
Company and its subsidiaries as of June 30, 2007 and the related
consolidated
statements of income and comprehensive income for each of the
three-month and
six-month periods ended June 30, 2007 and 2006 and the consolidated
statement of
cash flows for the six-month periods ended June 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
August
6,
2007
JERSEY
CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND 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 in the second quarter of 2007 increased to $50 million
from
$40 million in 2006. The increase was primarily due to higher revenues,
partially offset by higher purchased power costs, increased amortization
of
regulatory assets, interest expense and other operating costs.
In the first six
months of 2007, earnings on common stock increased to $88 million
compared to
$74 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, increased amortization of regulatory assets
and interest
expense.
Revenues
Revenues
increased
$169 million or 27.6% in the second quarter of 2007 and $277
million or 23.3% in
the first six months of 2007 compared with the same periods of
2006, reflecting
higher retail and wholesale generation revenues. Retail generation
revenues
increased by $102 million and $164 million in the second quarter
and the first
six months of 2007, respectively. Wholesale revenues increased
$19 million in
the second quarter and $27 million in the first six months of
2007.
Generation
revenues
from all customer classes increased in the second quarter and
first six months
of 2007 as compared to 2006. The increases in both periods of
2007 were 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 second quarter of 2007 (heating
degree days
were 35% greater than the second quarter of 2006). Industrial
generation KWH
sales declined in the second quarter and first six months of
2007 from the same
period in 2006 due to an increase in customer shopping.
Wholesale
generation
revenues increased ($19 million in the second quarter and $27
million in the
first six months of 2007) due to higher market prices, partially
offset by sales
volume decreases of 3.9% and 1.4% from the second quarter and
first six months
of 2006, respectively.
Changes
in retail
generation KWH sales and revenues by customer class in the second
quarter and
the first six months of 2007 compared to the same periods of
2006 are summarized
in the following table:
Retail
Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
Residential
|
|
|
13.6
|
%
|
|
8.9
|
%
|
Commercial
|
|
|
5.3
|
%
|
|
3.2
|
%
|
Industrial
|
|
|
(8.4
|
)%
|
|
(4.9
|
)%
|
Net
Increase in Generation Sales
|
|
|
9.0
|
%
|
|
5.8
|
%
|
Retail
Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
64
|
|
$
|
100
|
|
Commercial
|
|
|
36
|
|
|
60
|
|
Industrial
|
|
|
2
|
|
|
4
|
|
Increase
in Generation Revenues
|
|
$
|
102
|
|
$
|
164
|
|
Distribution
revenues increased $39 million and $67 million in the second
quarter and first
six months of 2007, respectively, compared to the same periods
of 2006 due to
higher composite unit prices and increased KWH deliveries, reflecting
the
weather impacts described above. The higher unit prices resulted
from a NUGC
rate increase effective in December 2006 as approved by the
NJBPU.
Changes
in
distribution KWH deliveries and revenues in the second quarter
and first six
months of 2007 compared to the corresponding periods of 2006
are summarized in
the following tables.
Increase
in Distribution KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Residential
|
|
|
13.7
|
%
|
|
8.9
|
%
|
Commercial
|
|
|
5.4
|
%
|
|
4.8
|
%
|
Industrial
|
|
|
2.9
|
%
|
|
2.3
|
%
|
Total
Increase in Distribution Deliveries
|
|
|
8.5
|
%
|
|
6.2
|
%
|
Increase
in Distribution Revenues |
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
24
|
|
$
|
38
|
|
Commercial
|
|
|
13
|
|
|
25
|
|
Industrial
|
|
|
2
|
|
|
4
|
|
Total
Increase in Distribution Revenues
|
|
$
|
39
|
|
$
|
67
|
|
The
higher revenues
for the second quarter and first six months of 2007 also included
$8 million and
$16 million, respectively, of increased revenues resulting from
the August 2006
securitization of deferred costs associated with JCP&L’s BGS
supply.
Expenses
Total
expenses
increased by $154 million in the second quarter and $246 million
in the first
six months of 2007 as compared to the same periods of 2006. The
following table
presents changes from the prior year by expense category:
Expenses -
Changes
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
121
|
|
$
|
192
|
|
Other
operating costs
|
|
|
2
|
|
|
(6
|
)
|
Provision
for
depreciation
|
|
|
1
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
29
|
|
|
57
|
|
General
Taxes
|
|
|
1
|
|
|
2
|
|
Net
increase in expenses
|
|
$
|
154
|
|
$
|
246
|
|
The
increase in
purchased power costs (35.4% in the second quarter of 2007 and
29.2% in the
first six months) primarily reflected higher unit prices resulting
from the BGS
auctions. Other operating costs increased $2 million in the second
quarter of
2007 due to higher labor costs from storm damage repairs in 2007,
but decreased
$6 million in the first six months of 2007 primarily due to lower
employee benefit costs. Amortization of regulatory assets increased
$29 million
in the second quarter and $57 million in the first six months
of 2007 due to
higher transition cost recovery associated with the December
2006 NUGC rate
increase.
Capital
Resources and Liquidity
During
the remainder
of 2007, JCP&L expects to meet its contractual obligations with a
combination of cash from operations and short-term borrowings.
Borrowing
capacity under JCP&L’s credit facilities is available to manage its working
capital requirements.
Changes
in Cash Position
As
of June 30,
2007, JCP&L had $87,000 of cash and cash equivalents compared with $41,000
as of December 31, 2006. The major sources for changes in these balances
are summarized below.
Cash
Flows From Operating
Activities
Cash
provided from
operating activities in the first six months of 2007 compared
with the first six
months of 2006 were as follows:
|
|
Six
Months Ended
|
|
|
|
|
June
30,
|
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
|
(In
millions)
|
|
|
Net
income
|
|
$
|
88
|
|
$
|
74
|
|
|
Net
non-cash
charges
|
|
|
105
|
|
|
46
|
|
|
Pension
trust
contribution
|
|
|
(18
|
)
|
|
-
|
|
|
Cash
collateral returned to suppliers
|
|
|
(24
|
)
|
|
(109
|
)
|
|
Working
capital and other
|
|
|
(243
|
)
|
|
(109
|
)
|
|
Net
cash used
for operating activities
|
|
$
|
(92
|
)
|
$
|
(98
|
)
|
|
Net
cash used for
operating activities decreased $6 million in the first six months
of 2007 from
the same period of 2006. This decrease was primarily due to an
$85 million
reduction in cash collateral payments made to suppliers in the
first six months
of 2007 compared to the same period in 2006, an increase of $59
million in
non-cash charges and an increase in net income of $14 million.
These increases
were largely offset by a $134 million decrease from working capital
(due to
changes in the collection of receivables and tax payments) and
an $18 million
pension trust contribution in the first quarter of 2007. The
changes in net
income and non-cash charges are described above in “Results of
Operations.”
Cash
Flows From Financing
Activities
Net
cash provided
from financing activities was $183 million in the first six months
of 2007
compared to $201 million in same period of 2006. The decrease primarily
resulted from a $107 million reduction in short-term borrowings,
a $125 million
repurchase of common stock from FirstEnergy and $147 million
of additional
long-term debt redemptions, partially offset by a $350 million
increase in new
long-term debt financing and a $10 million reduction in common
stock dividend
payments to FirstEnergy.
JCP&L had
$24 million of cash and temporary investments (which includes
short-term notes
receivable from associated companies) and approximately $229 million of
short-term indebtedness as of June 30, 2007. JCP&L has authorization
from the FERC to incur short-term debt up to its charter limit
of $431 million
(including the utility money pool).
See
the “Financing
Capability” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for additional discussion of JCP&L’s financing
capabilities.
Cash
Flows From Investing
Activities
Net
cash used for
investing activities was $91 million in the first six months
of 2007 compared to
$103 million in the previous year. The $12 million decrease primarily
resulted from the absence of $10 million in loans to associated
companies in
2006.
During
the last half
of 2007, capital requirements for property additions and improvements
are
expected to be about $95 million. These cash requirements are expected to
be satisfied from a combination of internal cash and short-term
credit
arrangements.
JCP&L’s
capital
spending for the period 2007-2011 is expected to be about $1.3 billion for
property additions, of which approximately $192 million applies
to
2007.
Market
Risk Information
During
the first six
months of 2007, the value of commodity derivative contracts decreased
by $302
million as a result of settled contracts ($196 million) and changes
in the value
of existing contracts ($106 million). These non-trading contracts
(primarily
with NUG entities) are adjusted to fair value at the end of each
quarter with a
corresponding offset to regulatory assets, resulting in no impact
to current
period earnings. Commodity derivative contracts were valued at $869
million and $1.2 billion as of June 30, 2007 and December 31,
2006,
respectively. See the “Market Risk Information” section of
JCP&L’s 2006 Annual Report on Form 10-K for additional discussion of
market
risk.
Equity
Price Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried
at their current
fair value of approximately $104 million and $97 million as of
June 30,
2007 and December 31, 2006, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $10 million
reduction in fair
value as of June 30, 2007.
Regulatory
Matters
See
the “Regulatory
Matters” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of regulatory matters
applicable to
JCP&L.
Environmental
Matters
See
the
“Environmental Matters” section within the Combined Management’s Discussion and
Analysis of Registrant Subsidiaries for discussion of environmental
matters
applicable to JCP&L.
Other
Legal Proceedings
See
the “Other Legal
Proceedings” section 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
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
344,241
|
|
|
$ |
266,533
|
|
|
$ |
696,377
|
|
|
$ |
560,570
|
|
Gross
receipts
tax collections
|
|
|
17,502
|
|
|
|
15,686
|
|
|
|
35,622
|
|
|
|
32,862
|
|
Total
revenues
|
|
|
361,743
|
|
|
|
282,219
|
|
|
|
731,999
|
|
|
|
593,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
182,818
|
|
|
|
143,070
|
|
|
|
374,407
|
|
|
|
302,957
|
|
Other
operating costs
|
|
|
111,105
|
|
|
|
59,575
|
|
|
|
209,123
|
|
|
|
120,654
|
|
Provision
for
depreciation
|
|
|
10,531
|
|
|
|
10,288
|
|
|
|
20,815
|
|
|
|
21,193
|
|
Amortization
of regulatory assets
|
|
|
30,972
|
|
|
|
25,669
|
|
|
|
65,112
|
|
|
|
55,717
|
|
Deferral
of
new regulatory assets
|
|
|
(31,895 |
) |
|
|
(45,581 |
) |
|
|
(74,621 |
) |
|
|
(45,581 |
) |
General
taxes
|
|
|
20,170
|
|
|
|
18,595
|
|
|
|
41,222
|
|
|
|
39,216
|
|
Total
expenses
|
|
|
323,701
|
|
|
|
211,616
|
|
|
|
636,058
|
|
|
|
494,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
38,042
|
|
|
|
70,603
|
|
|
|
95,941
|
|
|
|
99,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
7,775
|
|
|
|
8,964
|
|
|
|
15,501
|
|
|
|
17,714
|
|
Miscellaneous
income
|
|
|
1,498
|
|
|
|
1,792
|
|
|
|
2,607
|
|
|
|
4,404
|
|
Interest
expense
|
|
|
(13,424 |
) |
|
|
(12,071 |
) |
|
|
(25,180 |
) |
|
|
(23,255 |
) |
Capitalized
interest
|
|
|
388
|
|
|
|
344
|
|
|
|
648
|
|
|
|
611
|
|
Total
other
expense
|
|
|
(3,763 |
) |
|
|
(971 |
) |
|
|
(6,424 |
) |
|
|
(526 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
34,279
|
|
|
|
69,632
|
|
|
|
89,517
|
|
|
|
98,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
14,809
|
|
|
|
29,555
|
|
|
|
38,408
|
|
|
|
40,759
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
19,470
|
|
|
|
40,077
|
|
|
|
51,109
|
|
|
|
57,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(1,453 |
) |
|
|
-
|
|
|
|
(2,905 |
) |
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
84
|
|
|
|
84
|
|
|
|
168
|
|
|
|
168
|
|
Other
comprehensive income (loss)
|
|
|
(1,369 |
) |
|
|
84
|
|
|
|
(2,737 |
) |
|
|
168
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(693 |
) |
|
|
35
|
|
|
|
(1,385 |
) |
|
|
70
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(676 |
) |
|
|
49
|
|
|
|
(1,352 |
) |
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
18,794
|
|
|
$ |
40,126
|
|
|
$ |
49,757
|
|
|
$ |
58,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they
relate to Metropolitan
Edison Company are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
127
|
|
|
$ |
130
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,480,000 and $4,153,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
160,147
|
|
|
|
127,084
|
|
Associated
companies
|
|
|
27,213
|
|
|
|
3,604
|
|
Other
|
|
|
20,163
|
|
|
|
8,107
|
|
Notes
receivable from associated companies
|
|
|
34,399
|
|
|
|
31,109
|
|
Prepaid
taxes
|
|
|
23,598
|
|
|
|
13,533
|
|
Other
|
|
|
353
|
|
|
|
1,424
|
|
|
|
|
266,000
|
|
|
|
184,991
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
1,945,821
|
|
|
|
1,920,563
|
|
Less
-
Accumulated provision for depreciation
|
|
|
750,937
|
|
|
|
739,719
|
|
|
|
|
1,194,884
|
|
|
|
1,180,844
|
|
Construction
work in progress
|
|
|
33,474
|
|
|
|
18,466
|
|
|
|
|
1,228,358
|
|
|
|
1,199,310
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
283,596
|
|
|
|
269,777
|
|
Other
|
|
|
1,361
|
|
|
|
1,362
|
|
|
|
|
284,957
|
|
|
|
271,139
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
496,129
|
|
|
|
496,129
|
|
Regulatory
assets
|
|
|
464,434
|
|
|
|
409,095
|
|
Pension
assets
|
|
|
23,583
|
|
|
|
7,261
|
|
Other
|
|
|
38,885
|
|
|
|
46,354
|
|
|
|
|
1,023,031
|
|
|
|
958,839
|
|
|
|
$ |
2,802,346
|
|
|
$ |
2,614,279
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
-
|
|
|
$ |
50,000
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
158,731
|
|
|
|
141,501
|
|
Other
|
|
|
197,000
|
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
26,435
|
|
|
|
100,232
|
|
Other
|
|
|
70,566
|
|
|
|
59,077
|
|
Accrued
taxes
|
|
|
513
|
|
|
|
11,300
|
|
Accrued
interest
|
|
|
7,050
|
|
|
|
7,496
|
|
Other
|
|
|
22,978
|
|
|
|
22,825
|
|
|
|
|
483,273
|
|
|
|
392,431
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
|
859,000
shares
outstanding
|
|
|
1,276,119
|
|
|
|
1,276,075
|
|
Accumulated
other comprehensive loss
|
|
|
(27,868 |
) |
|
|
(26,516 |
) |
Accumulated
deficit
|
|
|
(183,560 |
) |
|
|
(234,620 |
) |
Total
common
stockholder's equity
|
|
|
1,064,691
|
|
|
|
1,014,939
|
|
Long-term
debt
and other long-term obligations
|
|
|
542,070
|
|
|
|
542,009
|
|
|
|
|
1,606,761
|
|
|
|
1,556,948
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
405,170
|
|
|
|
387,456
|
|
Accumulated
deferred investment tax credits
|
|
|
8,830
|
|
|
|
9,244
|
|
Nuclear
fuel
disposal costs
|
|
|
42,514
|
|
|
|
41,459
|
|
Asset
retirement obligations
|
|
|
155,867
|
|
|
|
151,107
|
|
Retirement
benefits
|
|
|
17,187
|
|
|
|
19,522
|
|
Other
|
|
|
82,744
|
|
|
|
56,112
|
|
|
|
|
712,312
|
|
|
|
664,900
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
2,802,346
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
51,109
|
|
|
$ |
57,991
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
20,815
|
|
|
|
21,193
|
|
Amortization
of regulatory assets
|
|
|
65,112
|
|
|
|
55,717
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(38,540 |
) |
|
|
(50,570 |
) |
Deferral
of
new regulatory assets
|
|
|
(74,621 |
) |
|
|
(45,581 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
27,069
|
|
|
|
22,463
|
|
Accrued
compensation and retirement benefits
|
|
|
(11,150 |
) |
|
|
(4,712 |
) |
Cash
collateral
|
|
|
4,850
|
|
|
|
(2,250 |
) |
Pension
trust
contribution
|
|
|
(11,012 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(64,465 |
) |
|
|
38,182
|
|
Prepayments
and other current assets
|
|
|
(8,994 |
) |
|
|
(24,564 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(62,308 |
) |
|
|
6,161
|
|
Accrued
taxes
|
|
|
(10,788 |
) |
|
|
(12,045 |
) |
Accrued
interest
|
|
|
(446 |
) |
|
|
297
|
|
Other
|
|
|
4,238
|
|
|
|
(4,011 |
) |
Net
cash
provided from (used for) operating activities
|
|
|
(109,131 |
) |
|
|
58,271
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
214,229
|
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(50,000 |
) |
|
|
-
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
|
(1,707 |
) |
Net
cash
provided from (used for) financing activities
|
|
|
164,229
|
|
|
|
(1,707 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(49,852 |
) |
|
|
(47,301 |
) |
Sales
of
investment securities held in trusts
|
|
|
55,603
|
|
|
|
113,637
|
|
Purchases
of
investment securities held in trusts
|
|
|
(57,571 |
) |
|
|
(118,379 |
) |
Loans
to
associated companies, net
|
|
|
(3,290 |
) |
|
|
(4,054 |
) |
Other
|
|
|
9
|
|
|
|
(453 |
) |
Net
cash used
for investing activities
|
|
|
(55,101 |
) |
|
|
(56,550 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(3 |
) |
|
|
14
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
130
|
|
|
|
120
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
127
|
|
|
$ |
134
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they
relate to Metropolitan
Edison Company are an integral
|
part
of these
statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Metropolitan Edison Company:
We
have reviewed the
accompanying consolidated balance sheet of Metropolitan Edison
Company and its
subsidiaries as of June 30, 2007 and the related consolidated
statements of
income and comprehensive income for each of the three-month
and six-month
periods ended June 30, 2007 and 2006 and the consolidated statement
of cash
flows for the six-month periods ended June 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
August
6,
2007
METROPOLITAN
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITIONAND 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 in the
second quarter of 2007 decreased to $19 million from $40 million
in the second
quarter of 2006. The decrease was primarily due to higher purchased
power costs,
other operating costs and lower deferrals of new regulatory
assets due to the
May 2006 PPUC order as discussed below, partially offset by
higher revenues. For
the first six months of 2007, net income decreased to $51 million
from $58
million in the same period of 2006. The decrease in the six
month period
reflects higher purchased power costs and other operating costs,
partially
offset by higher revenues and increased deferrals of new regulatory
assets.
Revenues
Revenues
increased
by $80 million, or 28.2%, in the second quarter of 2007 and
$139 million, or
23.4%, in the first six months of 2007 compared with the same
periods of 2006.
The increases in both periods were primarily due to higher
retail and wholesale
generation revenues.
In
the second
quarter of 2007, retail generation revenues increased by $10
million primarily
due to higher KWH sales in the residential and commercial sectors,
partially
offset by slightly lower KWH sales in the industrial sector.
The increase in
retail generation revenues in the residential and commercial
sectors primarily
resulted from higher weather-related usage in the second quarter
of 2007 as
compared to the same period of 2006 (heating degree days increased
by 34.9% and
cooling degree days increased by 19.3%).
In
the first six
months of 2007, retail generation revenues increased by $15
million due to
higher KWH sales in all customer sectors. The increase in retail
generation
revenues in the residential and commercial sectors was primarily
due to weather
conditions during the first six months of 2007 (heating degree
days increased by
18.3% and cooling degree days increased by 19.3% as compared
to the same period
of 2006).
Increases
in retail
electric generation sales and revenues in the second quarter
and the first six
months of 2007 compared to the same periods of 2006 are summarized
in the
following tables:
Retail
Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
Residential
|
|
|
11.7
|
%
|
|
8.7
|
%
|
Commercial
|
|
|
4.7
|
%
|
|
4.2
|
%
|
Industrial
|
|
|
(0.2
|
)%
|
|
1.3
|
%
|
Total
Retail Electric Generation Sales
|
|
|
5.6
|
%
|
|
5.0
|
%
|
Retail
Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
7
|
|
$
|
10
|
|
Commercial
|
|
|
3
|
|
|
5
|
|
Industrial
|
|
|
-
|
|
|
-
|
|
Increase
in Generation Revenues
|
|
$
|
10
|
|
$
|
15
|
|
Wholesale
revenues
increased by $36 million in the second quarter of 2007 and
$62 million in the
first six months of 2007 compared with the same periods of
2006. The
increases in both periods were due to Met-Ed selling additional
available power
into the PJM market beginning in January 2007.
Revenues
from
distribution throughput increased by $22 million in the second
quarter and $43
million in the first six months of 2007 compared to the same
periods in 2006.
The increases are due to higher KWH deliveries, reflecting
the effect of the
weather discussed above, and an increase in composite unit
prices resulting from
a January 2007 PPUC authorization to increase transmission
rates, partially
offset by a 5% decrease in distribution rates.
Changes
in
distribution KWH deliveries and revenues in the second quarter
and first six
months of 2007 compared to the same periods of 2006 are summarized
in the
following tables:
Distribution
KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Residential
|
|
|
11.7
|
%
|
|
8.7
|
%
|
Commercial
|
|
|
4.7
|
%
|
|
4.1
|
%
|
Industrial
|
|
|
0.5
|
% |
|
0.7
|
%
|
Total
Increase in Distribution Deliveries
|
|
|
5.7
|
%
|
|
4.8
|
%
|
Distribution
Revenues
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
15
|
|
$
|
32
|
|
Commercial
|
|
|
2
|
|
|
1
|
|
Industrial
|
|
|
5
|
|
|
10
|
|
Increase
in Distribution Revenues
|
|
$
|
22
|
|
$
|
43
|
|
PJM
transmission
revenues increased by $13 million and $20 million in the second
quarter and
first six months of 2007, respectively, as a result of higher
transmission
volumes and additional PJM auction revenue rights, compared
to the prior year
periods. 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 $112 million and $142 million in the second quarter
and first six
months of 2007, respectively, compared to the same periods
of 2006. The
following table presents changes from the prior year by expense
category:
Expenses
– Changes
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
40
|
|
$
|
72
|
|
Other
operating costs
|
|
|
52
|
|
|
88
|
|
Amortization
of regulatory assets
|
|
|
5
|
|
|
9
|
|
Deferral
of
new regulatory assets
|
|
|
13
|
|
|
(29
|
)
|
General
taxes
|
|
|
2
|
|
|
2
|
|
Net
increase in expenses
|
|
$
|
112
|
|
$
|
142
|
|
Purchased
power
costs increased in the second quarter and first six months
of 2007 by $40
million and $72 million, respectively, due to increased KWH
purchases to source
higher generation sales, combined with higher composite unit
costs. In the
second quarter of 2007, other operating costs increased primarily
due to $47
million in higher congestion costs and other transmission expenses
associated
with the increased transmission volumes discussed above and $4
million of increased contractor service and labor costs for
increased work on
reliability-related projects. In the first six months of 2007,
other operating
costs increased primarily due to higher congestion costs and
other transmission
expenses ($84 million) and increased customer expenses ($3
million) related to
Met-Ed’s customer assistance programs.
Met-Ed’s
revenue in
the first six months of 2007 included the recovery of a portion
of the
transmission costs that were deferred in 2006. As a result,
amortization of
regulatory assets increased in the second quarter and first
six months of 2007
compared to the prior year. In the second quarter of 2007,
the deferral of new
regulatory assets decreased primarily due to higher PJM transmission
cost
deferrals recognized in the second quarter of 2006. The deferral
in the second
quarter of 2006 also included PJM Transmission costs incurred
in the first
quarter following authorization by the PPUC in May 2006. The
deferral of new
regulatory assets increased in the first six months of 2007
due to the deferral
of previously expensed decommissioning costs of $15 million
associated with the
Saxton nuclear research facility as approved by the PPUC in
January 2007 and
higher PJM transmission costs and associated interest deferrals.
For
both periods,
general taxes increased primarily due to higher gross receipts
taxes.
Capital
Resources and Liquidity
During
2007, Met-Ed
expects to meet its contractual obligations with a combination
of cash from
operations and funds from the capital markets. Borrowing capacity
under Met-Ed’s
credit facilities is available to manage its working capital
requirements.
Changes
in Cash Position
As
of June 30, 2007,
Met-Ed had cash and cash equivalents of $127,000 compared with
$130,000 as of
December 31, 2006. The major sources of changes in these balances are
summarized below.
Cash
Flows From Operating
Activities
Net
cash used for
operating activities was $109 million in the first six months of 2007
compared to net cash provided from operating activities of
$58 million in
the same period of 2006, as summarized in the following table:
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
Net
non-cash
charges (credits)
|
|
|
|
)
|
|
|
)
|
Pension
trust
contribution
|
|
|
|
|
|
|
|
Working
capital and other
|
|
|
|
|
|
|
|
Net
cash
provided from (used for) operating activities
|
|
|
|
)
|
|
|
|
The
decrease from
working capital primarily resulted from a $103 million change
in receivables,
due in part to increased billings associated with the January
2007 rate increase
that were delayed until the second quarter of 2007, and a $68
million change in
accounts payable, partially offset by a $16 million decrease
in prepayments, a
$7 million increase in cash collateral received from suppliers
and an $8 million
increase in cash flows from other operating activities. Changes
in net income
and non-cash charges (credits) are described above under “Results of
Operations.”
Cash
Flows From Financing
Activities
Net
cash provided
from financing activities was $164 million in the first six
months of 2007
compared to net cash used for financing of $2 million in the first six
months of 2006. The increase reflects a $216 million increase
in short-term
borrowings, offset by a $50 million increase in long-term debt
redemptions in
the first six months of 2007.
As
of June 30, 2007,
Met-Ed had approximately $34 million of cash and temporary
investments (which
included short-term notes receivable from associated companies)
and $356 million
of short-term borrowings (including $72 million from its receivables
financing arrangement and $138 million from money pool borrowings).
Met-Ed has
authorization from the FERC to incur short-term debt up to
$250 million
(excluding receivables financing and money pool borrowings)
and authorization
from the PPUC to incur money pool borrowings up to
$300 million.
See
the “Financing
Capability” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for additional discussion of Met-Ed’s financing
capabilities.
Cash
Flows From Investing
Activities
In
the first six
months of 2007, Met-Ed's cash used for investing activities
totaled
$55 million, compared to $56 million in the same period of 2006. The
decrease primarily resulted from a reduction in loan repayments
to associated
companies.
During
the last half
of 2007, capital requirements for property additions and improvements
are
expected to be approximately $42 million. This cash requirement is expected
to be satisfied from a combination of cash from operations,
short-term credit
arrangements and funds from the capital markets. Met-Ed's capital
spending for
the period 2007 through 2011 is expected to be about $520 million, of which
approximately $92 million applies to 2007.
In
June 2007, Met-Ed
entered into an agreement to sell 100% of its ownership interest
in York Haven
Power Company, pending approval from the PPUC. The sale is
subject to regulatory
accounting and is not expected to have a material impact on
Met-Ed’s
earnings.
Market
Risk Information
During
the first six
months of 2007, the value of commodity derivative contracts
decreased by $5
million as a result of settled contracts ($6 million) and changes
in the value
of existing contracts ($1 million). These non-trading contracts
are adjusted to
fair value at the end of each quarter with a corresponding
offset to regulatory
liabilities, resulting in no impact to current period
earnings. Commodity derivative contracts were valued at $18 million
and $23 million as of June 30, 2007 and December 31, 2006,
respectively. See the “Market Risk Information” section of Met-Ed’s
2006 Annual Report on Form 10-K for additional discussion of
market
risk.
Equity
Price Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried
at their current
fair value of approximately $175 million and $164 million as
of June 30, 2007
and December 31, 2006, respectively. A hypothetical 10% decrease in prices
quoted by stock exchanges would result in an $18 million reduction
in fair value
as of June 30, 2007.
Regulatory
Matters
See
the “Regulatory
Matters” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of regulatory matters
applicable to
Met-Ed.
Environmental
Matters
See
the
“Environmental Matters” section within the Combined Management’s Discussion and
Analysis of Registrant Subsidiaries for discussion of environmental
matters
applicable to Met-Ed.
Other
Legal Proceedings
See
the “Other Legal
Proceedings” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of other 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
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
315,745
|
|
|
$ |
250,400
|
|
|
$ |
654,971
|
|
|
$ |
526,227
|
|
Gross
receipts
tax collections
|
|
|
15,672
|
|
|
|
14,599
|
|
|
|
32,352
|
|
|
|
30,524
|
|
Total
revenues
|
|
|
331,417
|
|
|
|
264,999
|
|
|
|
687,323
|
|
|
|
556,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
184,494
|
|
|
|
146,875
|
|
|
|
385,336
|
|
|
|
308,516
|
|
Other
operating costs
|
|
|
58,267
|
|
|
|
48,133
|
|
|
|
117,728
|
|
|
|
86,475
|
|
Provision
for
depreciation
|
|
|
12,335
|
|
|
|
11,798
|
|
|
|
24,112
|
|
|
|
24,441
|
|
Amortization
of regulatory assets
|
|
|
13,845
|
|
|
|
12,979
|
|
|
|
29,239
|
|
|
|
27,794
|
|
Deferral
of
new regulatory assets
|
|
|
(364 |
) |
|
|
(11,815 |
) |
|
|
(17,452 |
) |
|
|
(11,815 |
) |
General
taxes
|
|
|
18,350
|
|
|
|
17,458
|
|
|
|
38,201
|
|
|
|
36,847
|
|
Total
expenses
|
|
|
286,927
|
|
|
|
225,428
|
|
|
|
577,164
|
|
|
|
472,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
44,490
|
|
|
|
39,571
|
|
|
|
110,159
|
|
|
|
84,493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
2,135
|
|
|
|
1,627
|
|
|
|
3,552
|
|
|
|
3,997
|
|
Interest
expense
|
|
|
(13,072 |
) |
|
|
(11,599 |
) |
|
|
(24,409 |
) |
|
|
(22,135 |
) |
Capitalized
interest
|
|
|
285
|
|
|
|
422
|
|
|
|
543
|
|
|
|
769
|
|
Total
other
expense
|
|
|
(10,652 |
) |
|
|
(9,550 |
) |
|
|
(20,314 |
) |
|
|
(17,369 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
33,838
|
|
|
|
30,021
|
|
|
|
89,845
|
|
|
|
67,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
14,375
|
|
|
|
14,564
|
|
|
|
38,638
|
|
|
|
28,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
19,463
|
|
|
|
15,457
|
|
|
|
51,207
|
|
|
|
38,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(2,825 |
) |
|
|
-
|
|
|
|
(5,650 |
) |
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
17
|
|
|
|
16
|
|
|
|
33
|
|
|
|
32
|
|
Change
in
unrealized gain on available for sale securities
|
|
|
(13 |
) |
|
|
(14 |
) |
|
|
(16 |
) |
|
|
(18 |
) |
Other
comprehensive income (loss)
|
|
|
(2,821 |
) |
|
|
2
|
|
|
|
(5,633 |
) |
|
|
14
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(1,302 |
) |
|
|
1
|
|
|
|
(2,600 |
) |
|
|
7
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(1,519 |
) |
|
|
1
|
|
|
|
(3,033 |
) |
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
17,944
|
|
|
$ |
15,458
|
|
|
$ |
48,174
|
|
|
$ |
38,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they
relate to Pennsylvania
Electric Company are an integral
|
|
|
|
|
|
part
of these
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$ |
40
|
|
|
$ |
44
|
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,216,000 and $3,814,000
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
143,874
|
|
|
|
126,639
|
|
Associated
companies
|
|
|
73,743
|
|
|
|
49,728
|
|
Other
|
|
|
19,809
|
|
|
|
16,367
|
|
Notes
receivable from associated companies
|
|
|
18,263
|
|
|
|
19,548
|
|
Prepaid
taxes
|
|
|
24,740
|
|
|
|
3,016
|
|
Other
|
|
|
314
|
|
|
|
1,220
|
|
|
|
|
280,783
|
|
|
|
216,562
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,169,653
|
|
|
|
2,141,324
|
|
Less
-
Accumulated provision for depreciation
|
|
|
822,098
|
|
|
|
809,028
|
|
|
|
|
1,347,555
|
|
|
|
1,332,296
|
|
Construction
work in progress
|
|
|
28,719
|
|
|
|
22,124
|
|
|
|
|
1,376,274
|
|
|
|
1,354,420
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
133,103
|
|
|
|
125,216
|
|
Non-utility
generation trusts
|
|
|
101,240
|
|
|
|
99,814
|
|
Other
|
|
|
531
|
|
|
|
531
|
|
|
|
|
234,874
|
|
|
|
225,561
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
860,716
|
|
|
|
860,716
|
|
Pension
assets
|
|
|
31,293
|
|
|
|
11,474
|
|
Other
|
|
|
32,785
|
|
|
|
36,059
|
|
|
|
|
924,794
|
|
|
|
908,249
|
|
|
|
$ |
2,816,725
|
|
|
$ |
2,704,792
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
$ |
166,534
|
|
|
$ |
199,231
|
|
Other
|
|
|
199,000
|
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
23,354
|
|
|
|
92,020
|
|
Other
|
|
|
46,225
|
|
|
|
47,629
|
|
Accrued
taxes
|
|
|
2,920
|
|
|
|
11,670
|
|
Accrued
interest
|
|
|
7,404
|
|
|
|
7,224
|
|
Other
|
|
|
21,703
|
|
|
|
21,178
|
|
|
|
|
467,140
|
|
|
|
378,952
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common
stock,
$20 par value, authorized 5,400,000 shares-
|
|
|
|
|
|
|
|
|
5,290,596
shares outstanding
|
|
|
105,812
|
|
|
|
105,812
|
|
Other
paid-in
capital
|
|
|
1,189,479
|
|
|
|
1,189,434
|
|
Accumulated
other comprehensive loss
|
|
|
(10,226 |
) |
|
|
(7,193 |
) |
Retained
earnings
|
|
|
116,165
|
|
|
|
90,005
|
|
Total
common
stockholder's equity
|
|
|
1,401,230
|
|
|
|
1,378,058
|
|
Long-term
debt
and other long-term obligations
|
|
|
477,704
|
|
|
|
477,304
|
|
|
|
|
1,878,934
|
|
|
|
1,855,362
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
73,990
|
|
|
|
96,151
|
|
Asset
retirement obligations
|
|
|
79,348
|
|
|
|
76,924
|
|
Accumulated
deferred income taxes
|
|
|
185,969
|
|
|
|
193,662
|
|
Retirement
benefits
|
|
|
50,974
|
|
|
|
50,328
|
|
Other
|
|
|
80,370
|
|
|
|
53,413
|
|
|
|
|
470,651
|
|
|
|
470,478
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
$ |
2,816,725
|
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
51,207
|
|
|
$ |
38,606
|
|
Adjustments
to
reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
24,112
|
|
|
|
24,441
|
|
Amortization
of regulatory assets
|
|
|
29,239
|
|
|
|
27,794
|
|
Deferral
of
new regulatory assets
|
|
|
(17,452 |
) |
|
|
(11,815 |
) |
Deferred
costs
recoverable as regulatory assets
|
|
|
(34,691 |
) |
|
|
(54,092 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
13,548
|
|
|
|
13,206
|
|
Accrued
compensation and retirement benefits
|
|
|
(12,130 |
) |
|
|
893
|
|
Cash
collateral
|
|
|
3,250
|
|
|
|
-
|
|
Pension
trust
contribution
|
|
|
(13,436 |
) |
|
|
-
|
|
Decrease
(increase) in operating assets
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(39,530 |
) |
|
|
30,485
|
|
Prepayments
and other current assets
|
|
|
(20,819 |
) |
|
|
(18,565 |
) |
Increase
(decrease) in operating liabilities
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(70,070 |
) |
|
|
(9,008 |
) |
Accrued
taxes
|
|
|
(8,750 |
) |
|
|
(10,756 |
) |
Accrued
interest
|
|
|
181
|
|
|
|
190
|
|
Other
|
|
|
1,377
|
|
|
|
8,817
|
|
Net
cash
provided from (used for) operating activities
|
|
|
(93,964 |
) |
|
|
40,196
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
166,303
|
|
|
|
26,642
|
|
Dividend
Payments
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(25,000 |
) |
|
|
-
|
|
Net
cash
provided from financing activities
|
|
|
141,303
|
|
|
|
26,642
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(43,904 |
) |
|
|
(60,747 |
) |
Loan
repayments from (loans to) associated companies,
net
|
|
|
1,285
|
|
|
|
(3,466 |
) |
Sales
of
investment securities held in trust
|
|
|
26,882
|
|
|
|
60,650
|
|
Purchases
of
investment securities held in trust
|
|
|
(29,610 |
) |
|
|
(60,650 |
) |
Other,
net
|
|
|
(1,996 |
) |
|
|
(2,611 |
) |
Net
cash used
for investing activities
|
|
|
(47,343 |
) |
|
|
(66,824 |
) |
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(4 |
) |
|
|
14
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
44
|
|
|
|
35
|
|
Cash
and cash
equivalents at end of period
|
|
$ |
40
|
|
|
$ |
49
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they
relate to Pennsylvania
Electric Company are an
|
|
integral
part
of these statements.
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Pennsylvania Electric Company:
We
have reviewed the
accompanying consolidated balance sheet of Pennsylvania Electric
Company and its
subsidiaries as of June 30, 2007 and the related consolidated
statements of
income and comprehensive income for each of the three-month
and six-month
periods ended June 30, 2007 and 2006 and the consolidated
statement of cash
flows for the six-month periods ended June 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
August
6,
2007
PENNSYLVANIA
ELECTRIC COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS
OF
FINANCIAL
CONDITION AND 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
Net
income in the
second quarter of 2007 increased to $19 million, compared
to $15 million in
the second quarter of 2006. This increase resulted from higher
revenues
partially offset by higher purchased power costs, other operating
costs and
lower deferrals of new regulatory assets due to the May 2006
PPUC order
discussed below. In the first six months of 2007, net income
increased to $51
million, compared to $39 million in the first six months
of 2006. This increase
in net income was due to higher revenues and deferrals of
new regulatory assets,
partially offset by increased purchased power costs and other
operating
costs.
Revenues
Revenues
increased
by $66 million, or 25.1%, in the second quarter of 2007 and
$131 million, or
23.5%, in the first six months of 2007. The increases in
both periods were
primarily due to higher retail and wholesale generation revenues.
Retail
generation
revenues increased by $6 million in the second quarter of
2007 primarily due to
higher KWH sales to residential and commercial customers.
The increase in retail
generation revenues in the residential and commercial classes
was primarily due
to higher weather-related usage in the second quarter of
2007 compared to the
second quarter of 2006 (heating degree days increased 6.2%
and cooling degree
days increased 58.5%).
Retail
generation
revenues increased $12 million for the first six 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
due to weather
conditions in the first six months of 2007 (heating degree
days increased 12.5%
and cooling degree days increased 58.5% as compared to the
same time period of
2006).
Increases
in retail
electric generation sales and revenues in the second quarter
and first six
months of 2007 compared to the corresponding periods of 2006
are summarized in
the following tables:
Retail
Generation KWH Sales
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
5.2
|
%
|
|
5.5
|
%
|
Commercial
|
|
|
4.9
|
%
|
|
5.0
|
%
|
Industrial
|
|
|
(0.1
|
)%
|
|
-
|
|
Total
Retail Electric Generation Sales
|
|
|
3.3
|
%
|
|
3.6
|
%
|
Retail
Generation Revenues
|
|
Three
Months
|
|
Six
Months
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
3
|
|
$
|
6
|
|
Commercial
|
|
|
3
|
|
|
6
|
|
Industrial
|
|
|
-
|
|
|
-
|
|
Increase
in Retail Generation Revenues
|
|
$
|
6
|
|
$
|
12
|
|
Wholesale
revenues
increased $39 million in the second quarter of 2007 and $74
million in the first
six months of 2007, compared with the same periods of 2006
due to Penelec
selling additional available power into the PJM market beginning
in January
2007.
Revenues
from
distribution throughput increased $13 million in the second
quarter and $29
million in the first six months of 2007 due to higher KWH
deliveries reflecting
the effect of the weather discussed above and an increase
in composite unit
prices resulting from a January 2007 PPUC authorization to
increase transmission
rates, partially offset by a 4.5% decrease in distribution
rates.
Changes
in
distribution KWH deliveries and revenues in the second quarter
and first six
months of 2007 compared to the same periods in 2006 are summarized
in the
following tables:
Distribution
KWH Deliveries
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
5.2
|
%
|
|
5.5
|
%
|
Commercial
|
|
|
4.9
|
%
|
|
5.0
|
%
|
Industrial
|
|
|
-
|
|
|
(0.9
|
)%
|
Total
Distribution Deliveries
|
|
|
3.2
|
%
|
|
3.1
|
%
|
Distribution Revenues
|
|
Three
Months
|
|
Six
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Residential
|
|
$
|
13
|
|
$
|
30
|
|
Commercial
|
|
|
(1
|
)
|
|
(3
|
)
|
Industrial
|
|
|
1
|
|
|
2
|
|
Total
Distribution Revenues
|
|
$
|
13
|
|
$
|
29
|
|
PJM
transmission
revenues increased by $9 million in the second quarter of
2007 and $15 million
in the first six 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 $62 million in the second quarter of 2007 and
$105 million in the
first six months of 2007 compared with the same periods in
2006. The following
table presents changes from the prior year by expense category:
|
|
Three
|
|
Six
|
|
Expenses
- Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
38
|
|
$
|
77
|
|
Other
operating costs
|
|
|
10
|
|
|
31
|
|
Provision
for
depreciation
|
|
|
1
|
|
|
-
|
|
Amortization
of regulatory assets
|
|
|
1
|
|
|
1
|
|
Deferral
of
new regulatory assets
|
|
|
11
|
|
|
(5
|
)
|
General
taxes
|
|
|
1
|
|
|
1
|
|
Net
increase in expenses
|
|
$
|
62
|
|
$
|
105
|
|
Purchased
power
costs increased by $38 million, or 25.6%, in the second quarter
of 2007 and $77
million, or 24.9%, in the first six months of 2007, compared
to the same period
of 2006. The increases were due primarily to higher KWH purchases
to source
higher retail and wholesale generation sales combined with
higher composite unit
costs. Other operating costs increased by $9 million in the second
quarter
of 2007 and $32 million in the first six months of 2007 principally
due to
higher congestion costs and other transmission expenses associated
with the
increased transmission volumes discussed above.
In
the second
quarter of 2007, the deferral of new regulatory assets decreased
primarily due
to higher PJM transmission cost deferrals recognized in the
second quarter of
2006. The deferral in the second quarter of 2006 also included
PJM transmission
costs incurred in the first quarter following authorization
by the PPUC in May
2006. The deferral of new regulatory assets increased in
the first six months of
2007 due to the deferral of previously expensed decommissioning
costs of $12
million associated with the Saxton nuclear research facility
as approved by the
PPUC in January 2007, partially
offset by lower PJM transmission cost deferrals.
Capital
Resources and Liquidity
During
2007, Penelec
expects to meet its contractual obligations with a combination
of cash from
operations and funds from the capital markets. Borrowing
capacity under
Penelec’s credit facilities is available to manage its working capital
requirements.
Changes
in Cash Position
As
of June 30,
2007, Penelec had $40,000 of cash and cash equivalents compared
with $44,000 as
of December 31, 2006. The major sources for changes in these
balances are
summarized below.
Cash
Flows From Operating
Activities
Net
cash provided
(used) for operating activities in the second quarter of
2007 and 2006 were as
follows:
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
51
|
|
$
|
39
|
|
Net
non-cash
charges
|
|
|
3
|
|
|
-
|
|
Pension
trust
contribution
|
|
|
(13
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(135
|
)
|
|
1
|
|
Net
cash
provided from (used for) operating activities
|
|
$
|
(94
|
)
|
$
|
40
|
|
The
$136 million change from working capital principally resulted
from a $70 million
change in accounts receivable due in part to increased billings
associated with
the January 2007 rate increase that were delayed until the
second quarter of
2007, increased cash payments of $61 million for accounts
payable and $8 million
in increased cash outflows from other operating activities
partially offset by a
$3 million increase in cash collateral received from suppliers.
Changes in
net income and non-cash charges are described under “Results of
Operations.”
Cash
Flows From Financing
Activities
Net
cash provided
from financing activities was $141 million in the first six
months of 2007
compared to $26 million in the first six months of 2006. The increase
reflects a $140 million increase in short-term borrowings,
partially offset by a
$25 million increase in common stock dividend payments to
FirstEnergy.
Penelec
had
approximately $18 million of cash and temporary investments
(which included
short-term notes receivable from associated companies) and
$366 million of
short-term indebtedness (including $74 million from its receivables
financing
arrangement and $167 million in money pool borrowings) as
of June 30,
2007. Penelec has authorization from the FERC to incur short-term
debt of
up to $250 million (excluding receivables financing and money
pool borrowings)
and authorization from the PPUC to incur money pool borrowings
of up to
$300 million.
See
the “Financing
Capability” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for additional discussion of Penelec’s financing
capabilities.
Cash
Flows From Investing
Activities
In
the first six
months of 2007, net cash used for investing activities totaled
$47 million
compared to $67 million in the first six months of 2006.
The decrease primarily
resulted from a $17 million decrease in property additions
and a $5 million
increase in loan repayments from associated companies, partially
offset by a $3
million increase in the investments in the nuclear decommissioning
trust
fund.
During
the last half
of 2007, capital requirements for property additions are
expected to be
about $46 million. Penelec’s capital spending for the period 2007-2011 is
expected to be about $614 million, of which approximately
$92 million applies to
2007.
Market
Risk Information
During
the first six
months of 2007, the value of commodity derivative contracts
decreased by $2
million as a result of settled contracts. These non-trading
contracts are
adjusted to fair value at the end of each quarter with a
corresponding offset to
regulatory liabilities, resulting in no impact to current
period earnings.
Commodity derivative contracts were valued at $10 million
and $12 million as of
June 30, 2007 and December 31, 2006, respectively. See the
“Market Risk
Information” section of Penelec’s 2006 Annual Report on Form 10-K for additional
discussion of market risk.
Equity
Price Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried
at their current
fair value of approximately $80 million and $72 million as of June 30, 2007
and December 31, 2006, respectively. A hypothetical 10% decrease in prices
quoted by stock exchanges would result in an $8 million reduction
in fair value
as of June 30, 2007.
Regulatory
Matters
See
the “Regulatory
Matters” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of regulatory matters
applicable to
Penelec.
Environmental
Matters
See
the
“Environmental Matters” section within the Combined Management’s Discussion and
Analysis of Registrant Subsidiaries for discussion of environmental
matters
applicable to Penelec.
Other
Legal Proceedings
See
the “Other Legal
Proceedings” section within the Combined Management’s Discussion and Analysis of
Registrant Subsidiaries for discussion of other 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
Discussion and Analysis of Financial Condition and Results
of Operations of the
Companies. This information should be read in conjunction
with (i) the
Companies’ respective Consolidated Financial Statements and Management’s
Discussion and Analysis of Financial Condition and Results
of Operations; (ii)
the Notes to Consolidated Financial Statements as they relate
to the Companies;
and (iii) the Companies’ respective 2006 Annual Reports on Form
10-K.
Financing
Capability (Applicable to each of the
Companies)
As
of June 30, 2007,
OE, CEI and TE had the capability to issue approximately
$1.5 billion, $557
million and $797 million, respectively, 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 $463 million,
$515 million and $127 million, respectively, as of June 30, 2007.
Because 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, it is no
longer required to issue FMBs as collateral for senior notes
and therefore is
not limited as to the amount of senior notes it may issue.
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 June 30, 2007,
OE had approximately $400 million of capacity remaining unused under its
existing 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
|
|
|
39
|
|
CEI
|
|
|
250
|
(3)
|
|
500
|
|
TE
|
|
|
250
|
(3)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
431
|
|
Met-Ed
|
|
|
250
|
|
|
250
|
(4)
|
Penelec
|
|
|
250
|
|
|
250
|
(4)
|
|
(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.
|
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 June 30, 2007, FirstEnergy and its
subsidiaries' debt to total capitalization ratios (as defined
under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy
|
|
61
|
%
|
OE*
|
|
48
|
%
|
Penn
|
|
24
|
%
|
CEI*
|
|
60
|
%
|
TE*
|
|
56
|
%
|
JCP&L
|
|
32
|
%
|
Met-Ed
|
|
46
|
%
|
Penelec*
|
|
38
|
%
|
*The
ratios of
June 30, 2007, as adjusted for common stock dividends declared
in
July 2007 would
be: OE – 50%, CEI – 63%, TE – 61% and Penelec – 39%.
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.
The
Companies also
have the ability to borrow from each other and the holding
company to meet their
short-term working capital requirements. FESC administers
the money pool and
tracks surplus funds of FirstEnergy and the Companies, 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 the pool and
is based on the average
cost of funds available through the pool. The average interest
rate for
borrowings in the first six months of 2007 was 5.64%.
Each
of the
Companies’ access to capital markets and costs of financing are influenced
by
the ratings of its securities and the securities of FirstEnergy. The
following table displays FirstEnergy’s and the Companies’ securities ratings as
of June 30, 2007. The ratings outlook from Moody’s is positive for all
securities. The ratings outlook from S&P on all securities is
stable. The ratings outlook from Fitch on CEI and TE is positive
and
stable on all other operating companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB
|
|
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
TE
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
Penn
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
JCP&L
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
A-
|
|
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
OE,
CEI, Penn,
Met-Ed and Penelec 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. The receivables
financing
borrowing capacity and outstanding balance by company, as
of June 30, 2007, are
shown in the following table.
Subsidiary
Company
|
|
Parent
Company
|
|
|
Borrowing
Capacity
|
|
|
Outstanding
Balance
|
|
Annual
Facility Fee
|
|
|
(In
millions)
|
OES
Capital,
Incorporated
|
|
OE
|
|
$
|
170
|
|
$
|
100
|
|
0.15%
|
Centerior
Funding Corp.
|
|
CEI
|
|
|
200
|
|
|
-
|
|
0.15
|
Penn
Power
Funding LLC
|
|
Penn
|
|
|
25
|
|
|
17
|
|
0.125
|
Met-Ed
Funding
LLC
|
|
Met-Ed
|
|
|
80
|
|
|
72
|
|
0.125
|
Penelec
Funding LLC
|
|
Penelec
|
|
|
75
|
|
|
74
|
|
0.125
|
|
|
|
|
$
|
550
|
|
$
|
263
|
|
|
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 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
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 $219 million as of June 30, 2007 (JCP&L -
$103 million, Met-Ed - $34 million and Penelec - $82 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:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
733
|
|
$
|
741
|
|
$
|
(8
|
)
|
CEI
|
|
|
863
|
|
|
855
|
|
|
8
|
|
TE
|
|
|
230
|
|
|
248
|
|
|
(18
|
)
|
JCP&L
|
|
|
1,825
|
|
|
2,152
|
|
|
(327
|
)
|
Met-Ed
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec
had
net regulatory liabilities of approximately $74 million
and
$96 million as of June 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)
On
October 21, 2003,
the Ohio Companies filed their RSP case with the PUCO. On
August 5, 2004, the
Ohio Companies accepted the RSP as modified and approved
by the PUCO in an
August 4, 2004 Entry on Rehearing, subject to a CBP. The
RSP was intended to
establish generation service rates beginning January 1, 2006,
in response to the
PUCO’s concerns about price and supply uncertainty following the
end of the Ohio
Companies' transition plan market development period. On
May 3, 2006, the
Supreme Court of Ohio issued an opinion affirming the PUCO's
order in all
respects, except it remanded back to the PUCO the matter
of ensuring the
availability of sufficient means for customer participation
in the marketplace.
The RSP contained a provision that permitted the Ohio Companies
to withdraw and
terminate the RSP in the event that the PUCO, or the Supreme
Court of Ohio,
rejected all or part of the RSP. In such event, the Ohio
Companies have 30 days
from the final order or decision to provide notice of termination.
On July 20,
2006 the Ohio Companies filed with the PUCO a Request to
Initiate a Proceeding
on Remand. In their Request, the Ohio Companies provided
notice of termination
to those provisions of the RSP subject to termination, subject
to being
withdrawn, and also set forth a framework for addressing
the Supreme Court of
Ohio’s findings on customer participation. If the PUCO approves
a resolution to
the issues raised by the Supreme Court of Ohio that is acceptable
to the Ohio
Companies, the Ohio Companies’ termination will be withdrawn and considered to
be null and void. On July 20, 2006, the OCC and NOAC also submitted to the
PUCO a conceptual proposal addressing the issue raised by
the Supreme Court of
Ohio. On July 26, 2006, the PUCO issued an Entry directing
the Ohio Companies to
file a plan in a new docket to address the Court’s concern. The Ohio Companies
filed their RSP Remand CBP on September 29, 2006. Initial comments were
filed on January 12, 2007 and reply comments were filed on January 29,
2007. In their reply comments the Ohio Companies described
the highlights of a
new tariff offering they would be willing to make available
to customers that
would allow customers to purchase renewable energy certificates
associated with
a renewable generation source, subject to PUCO approval.
On May 29, 2007,
the Ohio Companies, together with the PUCO Staff and the
OCC, filed a
stipulation with the PUCO agreeing to offer a standard bid
product and a green
resource tariff product. The stipulation is currently pending
before the PUCO.
No further proceedings are scheduled at this time.
The
Ohio Companies
filed an application and stipulation with the PUCO on September 9, 2005
seeking approval of the RCP, a supplement to the RSP. On
November 4, 2005, the
Ohio Companies filed a supplemental stipulation with the
PUCO, which constituted
an additional component of the RCP filed on September 9,
2005. 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
|
|
$
|
179
|
|
$
|
108
|
|
$
|
93
|
|
$
|
380
|
|
2008
|
|
|
208
|
|
|
124
|
|
|
119
|
|
|
451
|
|
2009
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
216
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
provided an update 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 late 2007. The PUCO order
is expected to be
issued by March 9, 2008. The new rates, subject to evidentiary hearings and
approval at the PUCO, 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 Ohio
Companies requested
that the PUCO issue an order by November 1, 2007, to provide
sufficient time to
conduct the bidding process. The PUCO has scheduled a technical
conference for
August 16, 2007.
Pennsylvania (Applicable
to 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 costs during the
term of these
agreements with FES.
On
April 7,
2006, the parties entered into a tolling agreement that arose
from FES’ notice
to Met-Ed and Penelec that FES elected to exercise its right
to terminate the
partial requirements agreement effective midnight December 31, 2006. On
November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April
7
tolling agreement pending resolution of the PPUC’s proceedings regarding the
Met-Ed and Penelec comprehensive transition rate cases filed
April 10, 2006,
described below. Separately, 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 substantially exceed
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
tolling, suspension and 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 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 in accordance with the April 7, 2006 tolling agreement described
above. Met-Ed and Penelec also requested approval of a January 12, 2005
petition for the deferral of transmission-related costs,
but only for those
costs incurred during 2006. In this rate filing, Met-Ed and
Penelec also
requested recovery of annual transmission and related costs
incurred on or after
January 1, 2007, plus the amortized portion of 2006 costs over a
ten-year
period, along with applicable carrying charges, through an
adjustable rider.
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 the merger savings,
with the comprehensive
transmission 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 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 by all
parties. Responsive briefs are due August 20, 2007, with
reply briefs due
September 4, 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 June 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 $493 million and $127 million, respectively. $82 million of
Penelec’s deferral is subject to final resolution of an IRS settlement
associated with NUG trust fund proceeds. 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
late 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
would 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. The PPUC is requested to act
on the proposal no
later than November 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 will be
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 June 30, 2007, the accumulated
deferred cost
balance totaled approximately $392 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
Energy Master Plan (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;
·
Unit
prices for electricity should remain 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 August 1,
2007, the NJBPU approved publication of a formal proposal
in the New Jersey
Register, which proposal will be subsequently considered
by the NJBPU following
a period for public comment. 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 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 third 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 and Electric Company
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 American Electric Power
Company, Inc., 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.
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 maintain
existing transmission rates between MISO and PJM. If accepted 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 transmission facilities
across the entire
MISO footprint be maintained. All of these filings were supported by
the majority of transmission owners in either MISO or PJM.
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
transmission facilities be spread throughout the entire MISO
footprint. If adopted by the FERC, this proposal would shift a
greater portion of the cost of new 345 kV transmission facilities
to the
FirstEnergy footprint, and increase the transmission rates
paid by load-serving
FirstEnergy affiliates.
American
Electric
Power (AEP) filed a letter with the FERC Commissioners stating
its intent to
file a complaint under Section 206 of the Federal Power Act
challenging the
justness and reasonableness of the rate designs underlying
the MISO and PJM
transmission tariffs. AEP will propose the adoption of a regional
rate design that is expected to reallocate the cost of both
existing and new
high voltage transmission facilities across the combined
MISO and PJM
footprint. Based upon the position advocated by AEP in a related
proceeding, the AEP proposal is expected to result in a greater
allocation of
costs to FirstEnergy transmission zones in MISO and PJM. If approved
by the FERC, AEP’s proposal would increase the transmission rates paid by
load-serving FirstEnergy affiliates.
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.
On
February 15,
2007, MISO filed documents with the FERC to establish a market-based,
competitive ancillary services market. MISO contends that the filing
will integrate operating reserves into MISO’s existing day-ahead and real-time
settlements process, incorporate opportunity costs into these
markets, address
scarcity pricing through the implementation of a demand curve
methodology,
foster demand response in the provision of operating reserves,
and provide for
various efficiencies and optimization with regard to generation
dispatch. The filing also proposes amendments to existing documents
to provide for the transfer of balancing functions from existing
local balancing
authorities to MISO. MISO will then carry out this reliability
function as the NERC-certified balancing authority for the
MISO region with
implementation in the third or fourth quarter of 2008. FirstEnergy
filed comments on March 23, 2007, supporting the ancillary
service market in
concept, but proposing certain changes in MISO’s proposal. MISO requested FERC
action on its filing by June 2007 and the FERC issued its
Order June 22,
2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO
has not submitted a market power analysis in support of its
proposed Ancillary
Services Market and (2) MISO has not submitted a readiness
plan to ensure
reliability during the transition from the current reserve
and regulation system
managed by the individual Balancing Authorities to a centralized
Ancillary
Services Market managed by MISO. MISO was ordered to remedy
these deficiencies
and the FERC provided more guidance on other issues brought
up in filings by
stakeholders to assist MISO to re-file a complete proposal.
This Order should
facilitate MISO’s timetable to incorporate final revisions to ensure a market
start in Spring 2008. FirstEnergy will be participating in
working groups and
task forces to ensure the Spring 2008 implementation of the
Ancillary Services
Market.
On
February 16,
2007, the FERC issued a final rule 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. As market participants in both MISO and
PJM, the Companies will conform their business practices
to each respective
revised tariff.
Environmental
Matters (Applicable to each of the
Companies)
The
Companies accrue
environmental liabilities only when they conclude that it
is probable that they
have an obligation for such costs and can reasonably estimate
the amount of such
costs. Unasserted claims are reflected in the Companies’ determination of
environmental liabilities and are accrued in the period that
they become both
probable and reasonably estimable.
Regulation
of Hazardous Waste
The
Companies have
been named as PRPs at waste disposal sites, which may require
cleanup under the
Comprehensive Environmental Response, Compensation, and Liability
Act of 1980.
Allegations of disposal of hazardous substances at historical
sites and the
liability involved are often unsubstantiated and subject
to dispute; however,
federal law provides that all PRPs for a particular site
are liable on a joint
and several basis. Therefore, environmental liabilities that
are considered
probable have been recognized on the Consolidated Balance
Sheet as of June 30,
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 $88 million (JCP&L - $60 million, TE
- $3 million, CEI - $1 million, and other subsidiaries - $24 million)
have
been accrued through June 30, 2007.
W.
H. Sammis
Plant (Applicable to 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 FGCO 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.
Other
Legal Proceedings (Applicable to each of the
Companies)
There
are various
lawsuits, claims (including claims for asbestos exposure)
and proceedings
related to the Companies’ normal business operations pending against FirstEnergy
and the Companies. 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 on
July 8, 2004, affirming the decertification of the originally
certified class,
but remanding for certification of a class limited to those
customers directly
impacted by the outages of JCP&L transformers in Red Bank, 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, on March 7, 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 on
May 9, 2007. Proceedings are continuing in the Superior
Court. FirstEnergy is vigorously defending this class action but
is
unable to predict the outcome of this matter. No liability has been
accrued as of June 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., 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 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.
On
October 10, 2006,
various insurance carriers refiled a complaint in Cuyahoga
County Common Pleas
Court seeking reimbursement for claims paid to numerous insureds
who allegedly
suffered losses as a result of the August 14, 2003 outages.
All of the insureds
appear to be non-customers. The plaintiff insurance companies
are the same
claimants in one of the pending PUCO cases. FirstEnergy,
the Ohio Companies and
Penn were served on October 27, 2006. On January 18, 2007, the Court
granted the Companies’ motion to dismiss the case and they have not been
appealed. However, on April 25, 2007, one of the insurance carriers
refiled the complaint naming only FirstEnergy as the defendant. On
July 30, 2007, the case was voluntarily dismissed. No estimate of
potential liability is available for any of these cases.
FirstEnergy
was also
named, along with several other entities, in a complaint
in New Jersey State
Court. The allegations against FirstEnergy were based, in
part, on an alleged
failure to protect the citizens of Jersey City from an electrical
power outage.
None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive
pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's
motion to dismiss. The plaintiff has not appealed.
FirstEnergy
is
vigorously defending these actions, but cannot predict the
outcome of any of
these proceedings or whether any further regulatory proceedings
or legal actions
may be initiated against the Companies. Although FirstEnergy
is unable to
predict the impact of these proceedings, if FirstEnergy or
the Companies were
ultimately determined to have legal liability in connection
with these
proceedings, it could have a material adverse effect on FirstEnergy's
or the
Companies' financial condition, results of operations and
cash
flows.
Other
Legal Matters
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 plaintiff’s motion to amend their complaint which OE
has opposed.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees
to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective
bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed
the proceedings. On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees.
On February 6,
2006, a federal district court granted a union motion to
dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. JCP&L
intends to re-file an appeal in federal district court once
the damages
associated with this case are identified at an individual
employee level.
JCP&L recognized a liability for the potential $16 million award in
2005. The parties met on June 27, 2007 before an arbitrator to assert their
positions regarding the finality of damages. A hearing before
the arbitrator is
set for September 7, 2007.
If
it were
ultimately determined that FirstEnergy or the Companies 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 the Companies’ financial
condition, results of operations and cash flows.
New
Accounting Standards and
Interpretations (Applicable to each of the
Companies)
|
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. The Companies are currently evaluating
the impact of this
Statement on their financial statements.
SFAS
157 – “Fair Value
Measurements”
In
September 2006,
the FASB issued SFAS 157 that establishes how companies should
measure fair
value when they are required to use a fair value measure
for recognition or
disclosure purposes under GAAP. This Statement addresses
the need for increased
consistency and comparability in fair value measurements
and for expanded
disclosures about fair value measurements. The key changes
to current practice
are: (1) the definition of fair value which focuses on an
exit price rather than
entry price; (2) the methods used to measure fair value such
as emphasis that
fair value is a market-based measurement, not an entity-specific
measurement, as
well as the inclusion of an adjustment for risk, restrictions
and credit
standing; and (3) the expanded disclosures about fair value
measurements. This
Statement is effective for financial statements issued for
fiscal years
beginning after November 15, 2007, and interim periods within those years.
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 the Companies’ financial statements.
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 June 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 9 and 10 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 June 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.
|
|
|
|
|
|
April
1-30,
|
|
May
1-31,
|
|
June
1-30,
|
|
Second
|
|
|
|
|
|
|
|
|
|
|
|
Total
Number
of Shares Purchased (a)
|
|
194,553
|
|
304,287
|
|
219,445
|
|
718,285
|
|
Average
Price
Paid per Share
|
|
$68.41
|
|
$71.09
|
|
$68.12
|
|
$69.46
|
|
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
Comp ensation 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
4. SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a)
|
The
annual
meeting of FirstEnergy shareholders was held on
May 15,
2007.
|
(b)
|
At
this
meeting, the following persons were elected to
FirstEnergy's Board of
Directors for one-year terms:
|
|
|
Number
of Votes
|
|
|
|
For
|
|
Withheld
|
|
|
|
|
|
|
|
Paul
T.
Addison
|
|
|
188,720,311
|
|
|
74,174,290
|
|
Anthony
J.
Alexander
|
|
|
188,700,783
|
|
|
74,193,818
|
|
Michael
J.
Anderson
|
|
|
249,806,449
|
|
|
13,088,152
|
|
Dr.
Carol A.
Cartwright
|
|
|
159,733,696
|
|
|
103,160,905
|
|
William
T.
Cottle
|
|
|
166,930,916
|
|
|
95,963,685
|
|
Robert
B.
Heisler, Jr.
|
|
|
190,762,159
|
|
|
72,132,442
|
|
Ernest
J.
Novak, Jr.
|
|
|
188,312,120
|
|
|
74,582,481
|
|
Catherine
A.
Rein
|
|
|
188,486,982
|
|
|
74,407,619
|
|
George
M.
Smart
|
|
|
166,422,193
|
|
|
96,472,408
|
|
Wes
M.
Taylor
|
|
|
188,651,197
|
|
|
74,243,404
|
|
Jesse
T.
Williams, Sr.
|
|
|
166,684,440
|
|
|
96,210,161
|
|
The
following
Directors retired from the Board effective May 15, 2007:
Russell W. Maier and
Robert C. Savage.
(c)
|
(i)
|
At
this
meeting, the appointment of PricewaterhouseCoopers
LLP, an independent
registered public accounting firm, as auditor for
the year 2007 was
ratified:
|
Number
of Votes
|
|
|
|
For
|
|
Against
|
|
Abstentions
|
|
|
|
|
|
|
|
258,877,611
|
|
|
1,368,549
|
|
|
2,648,441
|
|
|
(ii)
|
At
this
meeting, the FirstEnergy Corp. 2007 Incentive Plan
was
approved:
|
Number
of Votes
|
|
|
|
|
|
|
|
Broker
|
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
|
|
207,313,123
|
|
|
23,286,182
|
|
|
3,901,643
|
|
|
28,393,653
|
|
|
(iii)
|
At
this
meeting, a shareholder proposal recommending that
the Board of Directors
change the company’s jurisdiction from Ohio to Delaware was not approved
(approval required a favorable vote of a majority
of the votes
cast):
|
Number
of Votes
|
|
|
|
|
|
|
|
Broker
|
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
|
|
80,014,916
|
|
|
149,489,965
|
|
|
5,026,051
|
|
|
28,363,669
|
|
|
(iv)
|
At
this
meeting, a shareholder proposal recommending that
the Board of Directors
adopt a policy establishing an engagement process
with proponents of
shareholder proposals that are supported by a majority
of the votes cast
was not approved (approval required a favorable
vote of a majority of the
votes cast):
|
Number
of Votes
|
|
|
|
|
|
|
|
Broker
|
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
|
|
91,938,193
|
|
|
137,204,324
|
|
|
5,358,416
|
|
|
28,393,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(v)
|
At
this
meeting, a shareholder proposal recommending that
the Board of Directors
adopt simple majority shareholder voting was approved
(approval required a
favorable vote of a majority of the votes
cast):
|
Number
of Votes
|
|
|
|
|
|
|
|
Broker
|
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
|
|
175,884,412
|
|
|
53,721,749
|
|
|
4,893,976
|
|
|
28,394,464
|
|
Based
on this
result, the Board of directors will further review this proposal
and
consider the
appropriate steps to take in response.
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
FirstEnergy
|
|
|
|
|
|
10-1
|
Participation
Agreement, dated as of June 26, 2007, among FirstEnergy
Generation Corp.,
as Lessee, FirstEnergy Solutions Corp., as Guarantor, the
applicable Lessor, U.S. Bank Trust National Association,
as Trust Company,
the applicable Owner Participant, The Bank of New
York Trust Company,
N.A., as Indenture Trustee, and The Bank of New
York Trust Company, N.A.,
as Pass Through Trustee(1)(2)
|
|
10-2
|
Trust
Agreement, dated as of June 26, 2007 between the
applicable Owner
Participant and U.S. Bank Trust National Association,
as Owner
Trustee(1)(2)
|
|
10-3
|
Indenture
of
Trust, Open-End Mortgage and Security Agreement,
dated as of July 1, 2007,
between the applicable Lessor and The Bank of New
York Trust Company,
N.A., as Indenture Trustee(1)(2)
|
|
10-4
|
6.85%
Lessor
Note due 2034(1)(2)
(included in Exhibit 10-3)
|
|
10-5
|
Bill
of Sale
and Transfer, dated as of July 1, 2007, between
FirstEnergy Generation
Corp. and the applicable Lessor(1)(2)
|
|
10-6
|
Facility
Lease
Agreement, dated as of July 1, 2007, between FirstEnergy
Generation Corp.
and the applicable Lessor(1)(2)
|
|
10-7
|
Site
Lease,
dated as of July 1, 2007, between FirstEnergy Generation
Corp. and the
applicable Lessor(1)(2)
|
|
10-8
|
Site
Sublease,
dated as of July 1, 2007, between FirstEnergy Generation
Corp. and the
applicable Lessor(1)(2)
|
|
10-9
|
Guaranty
of
FirstEnergy Solutions Corp., dated as of July 1,
2007(1)(2)
|
|
10-10
|
Support
Agreement, dated as of July 1, 2007, between FirstEnergy
Generation Corp.
and the applicable Lessor(1)(2)
|
|
10-11
|
Second
Amendment to the Bruce Mansfield Units 1, 2, and
3 Operating Agreement,
dated as of July 1, 2007, between FirstEnergy Generation
Corp., The
Cleveland Electric Illuminating Company, and The
Toledo Edison
Company(1)
|
|
10-12
|
Pass
Through
Trust Agreement, dated as of June 26, 2007, among
FirstEnergy Generation
Corp., FirstEnergy Solutions Corp., and The Bank
of New York Trust
Company, N.A., as Pass Through Trustee(1)
|
|
10-13
|
6.85%
Pass
Through Trust Certificate due 2034(1)(2)
(included
in Exhibit 10-12)
|
|
10-14
|
Registration
Rights Agreement, dated as of July 13, 2007, among
FirstEnergy Generation
Corp., FirstEnergy Solutions Corp., The Bank of
New York Trust Company,
N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and
Credit Suisse Securities (USA) LLC, as representatives
of the several
initial purchasers(1)
|
|
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.
|
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
|
|
|
|
|
|
3
|
Jersey
Central
Power & Light Company By-Laws, as amended July 11,
2007
|
|
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
|
|
|
|
|
|
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.
|
(1)
Incorporated by
reference to the Registrant’s Form 8-K/A filed on August 2, 2007.
|
(2)
Pursuant to
the Instructions to Item 601(a), the Registrant
has omitted the
indentures, contracts and other documents required
to be filed as exhibits
since they are substantially identical in all material
respects except as
to the parties thereto and certain other details
as noted in the schedule
filed as Exhibit 99-1 to the Registrant’s Form 8-K/A file on August 2,
2007. The Registrant agrees to furnish these items
at the request of the
SEC.
|
Pursuant
to
reporting requirements of respective financings, FirstEnergy,
OE, JCP&L,
Met-Ed and Penelec are required to file fixed charge ratios
as an exhibit to
this Form 10-Q.
Pursuant
to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither
FirstEnergy, 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.
August
7,
2007
|
FIRSTENERGY
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)
|