Form 10Q Dated March 31, 2007
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 March 31, 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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File
Number
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Address;
and Telephone Number
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Identification
No.
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333-21011
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FIRSTENERGY
CORP.
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34-1843785
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(An
Ohio Corporation)
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-2578
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OHIO
EDISON COMPANY
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34-0437786
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-2323
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THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
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34-0150020
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3583
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THE
TOLEDO EDISON COMPANY
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34-4375005
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3141
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JERSEY
CENTRAL POWER & LIGHT COMPANY
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21-0485010
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(A
New
Jersey Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-446
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METROPOLITAN
EDISON COMPANY
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23-0870160
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3522
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PENNSYLVANIA
ELECTRIC COMPANY
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25-0718085
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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Indicate
by check
mark whether each of the registrants (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes
(X)
No ( )
Indicate
by check
mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of "accelerated filer and large
accelerated filer" in Rule 12b-2 of the Exchange Act.
Large
Accelerated Filer (X)
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FirstEnergy
Corp.
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Accelerated
Filer ( )
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N/A
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Non-accelerated
Filer (X)
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Ohio
Edison
Company, The Cleveland Electric Illuminating Company, The Toledo
Edison
Company, Jersey Central Power & Light Company, Metropolitan Edison
Company, and Pennsylvania Electric
Company
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Indicate
by check
mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the
Act).
Yes
(
)
No (X)
Indicate
the number
of shares outstanding of each of the issuer's classes of common stock, as of
the
latest practicable date:
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OUTSTANDING
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CLASS
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AS
OF MAY 9, 2007
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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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15,009,335
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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 and the various state public utility
commissions as disclosed in the registrants’ SEC filings, the timing and outcome
of various proceedings before the PUCO (including, but not limited to, the
distribution rate cases 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 the transition rate plan filings
for
Met-Ed and Penelec and Penn’s default service plan filing), 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, the successful structuring and completion of a potential sale and
leaseback transaction for Bruce Mansfield Unit 1 currently under consideration
by management, any purchase price adjustment 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-v
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Part
I. Financial
Information
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Items
1. and 2. - Financial Statements and Management’s Discussion and Analysis
of Financial
Condition and Results of Operations
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Notes
to
Consolidated Financial Statements
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1-21
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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22
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Consolidated
Statements of Comprehensive Income
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23
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Consolidated
Balance Sheets
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24
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Consolidated
Statements of Cash Flows
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25
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Report
of
Independent Registered Public Accounting Firm
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26
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Management's
Discussion and Analysis of Financial
Condition and Results of Operations
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27-59
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Ohio
Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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60
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Consolidated
Balance Sheets
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61
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Consolidated
Statements of Cash Flows
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62
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Report
of
Independent Registered Public Accounting Firm
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63
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Management's
Discussion and Analysis of Financial
Condition and Results of Operations
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64-67
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The
Cleveland Electric Illuminating Company
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Consolidated
Statements of Income and Comprehensive Income
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68
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Consolidated
Balance Sheets
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69
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Consolidated
Statements of Cash Flows
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70
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Report
of
Independent Registered Public Accounting Firm
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71
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Management's
Discussion and Analysis of Financial
Condition and Results of Operations
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72-75
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The
Toledo Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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76
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Consolidated
Balance Sheets
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77
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Consolidated
Statements of Cash Flows
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78
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Report
of
Independent Registered Public Accounting Firm
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79
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Management's
Discussion and Analysis of
Financial
Condition and Results of Operations
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80-82
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TABLE
OF
CONTENTS (Cont'd)
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Pages
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Jersey
Central Power & Light Company
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Consolidated
Statements of Income and Comprehensive Income
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83
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Consolidated
Balance Sheets
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84
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Consolidated
Statements of Cash Flows
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85
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Report
of
Independent Registered Public Accounting Firm
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86
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Management's
Discussion and Analysis of Financial
Condition and Results of Operations
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87-89
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Metropolitan
Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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90
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Consolidated
Balance Sheets
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91
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Consolidated
Statements of Cash Flows
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92
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Report
of
Independent Registered Public Accounting Firm
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93
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Management's
Discussion and Analysis of Financial
Condition and Results of Operations
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94-96
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Pennsylvania
Electric Company
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Consolidated
Statements of Income and Comprehensive Income
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97
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Consolidated
Balance Sheets
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98
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Consolidated
Statements of Cash Flows
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99
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Report
of
Independent Registered Public Accounting Firm
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100
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Management's
Discussion and Analysis of
Financial
Condition and Results of Operations
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101-103
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Combined
Management’s Discussion and Analysis of Registrant
Subsidiaries
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104-115
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk
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116
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Item
4. Controls
and Procedures
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116
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Part
II. Other
Information
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Item
1. Legal
Proceedings
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117
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Item
1A. Risk
Factors
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117
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Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds
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117
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Item
6. Exhibits
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117-118
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GLOSSARY
OF
TERMS
The
following abbreviations and acronyms are used in this report to identify
FirstEnergy Corp. and its current and former subsidiaries:
ATSI
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American
Transmission Systems, Inc., owns and operates transmission
facilities
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CEI
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The
Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
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Centerior
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Centerior
Energy Corporation, former parent of CEI and TE, which merged with
OE to
form
FirstEnergy
on
November 8, 1997
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Companies
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OE,
CEI, TE,
JCP&L, Met-Ed and Penelec
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FENOC
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FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
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FES
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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
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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
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Jersey
Central
Power & Light Company, a New Jersey electric utility operating
subsidiary
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JCP&L
Transition
Funding
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JCP&L
Transition Funding LLC, a Delaware limited liability company and
issuer of
transition bonds
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JCP&L
Transition
Funding
II
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JCP&L
Transition Funding II LLC, a Delaware limited liability company and
issuer
of transition
bonds
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Met-Ed
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Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
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MYR
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MYR
Group,
Inc., a utility infrastructure construction service
company
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NGC
|
FirstEnergy
Nuclear Generation Corp., owns nuclear generating
facilities
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OE
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Ohio
Edison
Company, an Ohio electric utility operating subsidiary
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Ohio
Companies
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CEI,
OE and
TE
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Penelec
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Pennsylvania
Electric Company, a Pennsylvania electric utility operating
subsidiary
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Penn
|
Pennsylvania
Power Company, a Pennsylvania electric utility operating subsidiary
of
OE
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PNBV
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PNBV
Capital
Trust, a special purpose entity created by OE in 1996
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Shippingport
|
Shippingport
Capital Trust, a special purpose entity created by CEI and TE in
1997
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TE
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The
Toledo
Edison Company, an Ohio electric utility operating
subsidiary
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TEBSA
|
Termobarranquilla
S.A., Empresa de Servicios Publicos
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The
following
abbreviations and acronyms are used to identify frequently used terms
in
this report:
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ALJ
|
Administrative
Law Judge
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AOCL
|
Accumulated
Other Comprehensive Loss
|
APB
|
Accounting
Principles Board
|
APB
12
|
APB
Opinion
No. 12, “Omnibus Opinion - 1967”
|
ARO
|
Asset
Retirement Obligation
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B&W
|
Babcock
&
Wilcox Company
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Bechtel
|
Bechtel
Power
Corporation
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BGS
|
Basic
Generation Service
|
CAIR
|
Clean
Air
Interstate Rule
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CAL
|
Confirmatory
Action Letter
|
CAMR
|
Clean
Air
Mercury Rule
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CBP
|
Competitive
Bid Process
|
CO2
|
Carbon
Dioxide
|
DOJ
|
United
States
Department of Justice
|
DRA
|
Division
of
Ratepayer Advocate
|
ECAR
|
East
Central
Area Reliability Coordination Agreement
|
EITF
|
Emerging
Issues Task Force
|
EITF
06-10
|
EITF
Issue No.
06-10, “Accounting for Deferred Compensation and Postretirement
Benefit
Aspects
of
Collateral Split-Dollar Life Insurance Arrangements”
|
EPA
|
Environmental
Protection Agency
|
EPACT
|
Energy
Policy
Act of 2005
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ERO
|
Electric
Reliability Organization
|
FASB
|
Financial
Accounting Standards Board
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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"
|
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
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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
|
NUG
|
Non-Utility
Generation
|
NUGC
|
Non-Utility
Generation Charge
|
OCA
|
Office
of
Consumer Advocate
|
OCC
|
Office
of the
Ohio Consumer’s Counsel
|
OVEC
|
Ohio
Valley
Electric Corporation
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PCAOB
|
Public
Company
Accounting Oversight Board
|
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
Agreements
|
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
106
|
SFAS
No. 106,
“Employers’ Accounting for Postretirement Benefits Other Than
Pensions”
|
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
|
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.
FirstEnergy's
and
the Companies' independent registered public accounting firm has performed
reviews of, and issued reports on, these consolidated interim financial
statements in accordance with standards established by the PCAOB. Pursuant
to
Rule 436(c) under the Securities Act of 1933, their reports of those reviews
should not be considered a report within the meaning of Section 7 and 11 of
that
Act, and the independent registered public accounting firm’s liability under
Section 11 does not extend to them.
2.
EARNINGS
PER SHARE
Basic
earnings per
share 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 first quarter 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. The effect of any potential settlement in shares
is
currently unknown.
Reconciliation
of Basic and Diluted
|
|
Three
Months Ended
March
31,
|
|
Earnings
per Share of Common Stock
|
|
2007
|
|
2006
|
|
|
(In millions, except per share amounts)
|
Income
from
continuing operations
|
|
$
|
290
|
|
$
|
219
|
|
Discontinued
operations
|
|
|
-
|
|
|
2
|
|
Net
income
available for common shareholders
|
|
$
|
290
|
|
$
|
221
|
|
|
|
|
|
|
|
|
|
Average
shares
of common stock outstanding - Basic
|
|
|
314
|
|
|
329
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
2
|
|
|
1
|
|
Average
shares
of common stock outstanding - Dilutive
|
|
|
316
|
|
|
330
|
|
|
|
|
|
|
|
|
|
Earnings
per
share:
|
|
|
|
|
|
|
|
|
Basic
earnings
per share:
|
|
|
|
|
|
|
|
|
|
Earnings
from
continuing operations
|
|
$
|
0.92
|
|
$
|
0.67
|
|
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
|
Net
earnings
per basic share
|
|
$
|
0.92
|
|
$
|
0.67
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share:
|
|
|
|
|
|
|
|
|
|
Earnings
from
continuing operations
|
|
$
|
0.92
|
|
$
|
0.67
|
|
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
|
Net
earnings
per diluted share
|
|
$
|
0.92
|
|
$
|
0.67
|
|
|
|
|
|
|
|
|
|
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 quarter
ended March 31, 2006; Roth Bros. does 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 in the first quarter of 2006 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 $140 million in first quarter of 2006.
The following table summarizes the net income (loss) included in "Discontinued
Operations" on the Consolidated Statements of Income for the three months ended
March 31, 2006 (in millions):
FSG
subsidiaries
|
|
$
|
(1
|
)
|
MYR
|
|
|
3
|
|
Income
from
discontinued operations
|
|
$
|
2
|
|
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 the Company. They are responsible for promoting the effective design
and implementation of sound risk management programs. They also oversee
compliance with corporate risk management policies and established risk
management practices.
FirstEnergy
accounts
for derivative instruments on its Consolidated Balance Sheet at their fair
value
unless they meet the normal purchase and normal sales criterion. Derivatives
that meet that criterion are accounted for on the accrual basis. The changes
in
the fair value of derivative instruments that do not meet the normal purchase
and sales criterion are recorded 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 March 31, 2007, for derivative
hedging activity, as compared to the December 31, 2006 balance of $58
million of net deferred losses, resulted from a net $9 million decrease
related to current hedging activity and a $4 million decrease due to net
hedge losses reclassified into earnings during the three months ended March
31,
2007. Based on current estimates, approximately $7 million (after tax) of
the net deferred losses on derivative instruments in AOCL as of March 31, 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. In prior years, FirstEnergy has
unwound swaps, the gains and losses are amortized in earnings over the remaining
maturity of each respective hedged security as adjustments to interest expense.
As of March 31, 2007, FirstEnergy had interest rate swaps with an aggregate
notional value of $750 million and a fair value of
$(24) million.
During
2006 and the
first three 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 -
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 three months
of
2007, FirstEnergy terminated swaps with a notional value of $250 million
for which it paid $3 million, all of which was deemed effective.
FirstEnergy will recognize the loss over the life of the associated future
debt.
As of March 31, 2007, FirstEnergy had forward swaps with an aggregate notional
amount of $475 million and a long-term debt securities fair value of
$(2) 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 March 31, 2007 is primarily related to the nuclear
decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear
generating facilities. The obligation to decommission these units was developed
based on site specific studies performed by an independent engineer. FirstEnergy
utilized an expected cash flow approach to measure the fair value of the nuclear
decommissioning ARO.
FirstEnergy
maintains nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of March 31, 2007,
the fair value of the decommissioning trust assets was
$2.0 billion.
The
following tables
analyze changes to the ARO balance during the first quarters of 2007 and 2006,
respectively.
ARO
Reconciliation
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance,
January 1, 2007
|
|
$
|
1,190
|
|
$
|
88
|
|
$
|
2
|
|
$
|
27
|
|
$
|
84
|
|
$
|
151
|
|
$
|
77
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated cash flows
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
March
31, 2007
|
|
$
|
1,208
|
|
$
|
89
|
|
$
|
2
|
|
$
|
27
|
|
$
|
86
|
|
$
|
153
|
|
$
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2006
|
|
$
|
1,126
|
|
$
|
83
|
|
$
|
8
|
|
$
|
25
|
|
$
|
80
|
|
$
|
142
|
|
$
|
72
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated cash flows
|
|
|
4
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
March
31, 2006
|
|
$
|
1,148
|
|
$
|
84
|
|
$
|
8
|
|
$
|
25
|
|
$
|
81
|
|
$
|
144
|
|
$
|
73
|
|
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. The Company’s funding policy is based on
actuarial computations using the projected unit credit method. 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 cost and other postretirement benefit cost
(including amounts capitalized) for the three months ended March 31, 2007 and
2006, consisted of the following:
|
|
Pension
Benefits
|
|
Other
Postretirement Benefits
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
(In
millions)
|
|
|
|
Service
cost
|
|
$
|
21
|
|
$
|
21
|
|
$
|
5
|
|
$
|
9
|
|
Interest
cost
|
|
|
71
|
|
|
66
|
|
|
17
|
|
|
26
|
|
Expected
return on plan assets
|
|
|
(112
|
)
|
|
(99
|
)
|
|
(13
|
)
|
|
(12
|
)
|
Amortization
of prior service cost
|
|
|
2
|
|
|
2
|
|
|
(37
|
)
|
|
(19
|
)
|
Recognized
net
actuarial loss
|
|
|
10
|
|
|
15
|
|
|
12
|
|
|
14
|
|
Net
periodic
cost (credit)
|
|
$
|
(8)
|
|
$
|
5
|
|
$
|
(16
|
)
|
$
|
18
|
|
Pension
and
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. The Companies capitalize employee benefits
related to construction projects. The net periodic pension costs and net
periodic postretirement benefit costs (including amounts capitalized) recognized
by each of the Companies for the three months ended March 31, 2007 and 2006
were as follows:
|
|
Pension
Benefit Cost (Credit)
|
|
Other
Postretirement
Benefit
Cost (Credit)
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
(In
millions)
|
|
|
|
OE
|
|
$
|
(4.0
|
)
|
$
|
(1.5
|
)
|
$
|
(2.7
|
)
|
$
|
4.2
|
|
CEI
|
|
|
0.3
|
|
|
1.0
|
|
|
1.0
|
|
|
2.8
|
|
TE
|
|
|
-
|
|
|
0.2
|
|
|
1.2
|
|
|
2.0
|
|
JCP&L
|
|
|
(2.1
|
)
|
|
(1.4
|
)
|
|
(4.0
|
)
|
|
0.6
|
|
Met-Ed
|
|
|
(1.7
|
)
|
|
(1.7
|
)
|
|
(2.5
|
)
|
|
0.7
|
|
Penelec
|
|
|
(2.6
|
)
|
|
(1.3
|
)
|
|
(3.2
|
)
|
|
1.8
|
|
Other
FirstEnergy subsidiaries
|
|
|
2.5
|
|
|
9.9
|
|
|
(5.7
|
)
|
|
6.1
|
|
|
|
$
|
(7.6
|
)
|
$
|
5.2
|
|
$
|
(15.9
|
)
|
$
|
18.2
|
|
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 $817 million,
$960 million and $960 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 $646 million,
$89 million
and
$500 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 March 31, 2007, the net projected above-market loss
liability recognized for these eight NUG agreements was $155 million.
Purchased power costs from these entities during the first quarters of 2007
and
2006 are shown in the table below:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
JCP&L
|
|
$
|
20
|
|
$
|
15
|
|
Met-Ed
|
|
|
15
|
|
|
16
|
|
Penelec
|
|
|
8
|
|
|
8
|
|
|
|
$
|
43
|
|
$
|
39
|
|
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 March 31, 2007, $420 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 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 quarter of 2007, there were no material changes
to
FirstEnergy’s unrecognized tax benefits. The entire balance is included in other
non-current liabilities.
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 quarter 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 quarter
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 between 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
March 31, 2007, outstanding guarantees and other assurances aggregated
approximately $4.3 billion, consisting of contract guarantees -
$2.5 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 $0.9 billion
(included in the $2.5 billion discussed above) as of March 31, 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
March 31, 2007, FirstEnergy's maximum exposure under these collateral
provisions was $392 million.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of
$106 million provide additional assurance to outside parties that
contractual and statutory obligations will be met in a number of areas including
construction jobs, environmental commitments and various retail transactions.
The
Companies, with
the exception of TE and JCP&L, each have a wholly owned subsidiary whose
borrowings are secured by customer accounts receivable purchased from its
respective parent company. The CEI subsidiary's borrowings are also secured
by
customer accounts receivable purchased from TE. Each subsidiary company has
its
own receivables financing arrangement and, as a separate legal entity with
separate creditors, would have to satisfy its obligations to creditors before
any of its remaining assets could be available to its parent
company.
|
|
|
|
Borrowing
|
|
Subsidiary
Company
|
|
Parent
Company
|
|
Capacity
|
|
|
|
|
|
(In
millions)
|
|
OES
Capital,
Incorporated
|
|
|
OE
|
|
$
|
170
|
|
Centerior
Funding Corp.
|
|
|
CEI
|
|
|
200
|
|
Penn
Power
Funding LLC
|
|
|
Penn
|
|
|
25
|
|
Met-Ed
Funding
LLC
|
|
|
Met-Ed
|
|
|
80
|
|
Penelec
Funding LLC
|
|
|
Penelec
|
|
|
75
|
|
|
|
|
|
|
$
|
550
|
|
FirstEnergy
has also
guaranteed the obligations of the operators of the TEBSA project, up to a
maximum of $6 million (subject to escalation) under the project's
operations and maintenance agreement. In connection with the sale of TEBSA
in
January 2004, the purchaser indemnified FirstEnergy against any loss under
this
guarantee. FirstEnergy has also provided an LOC ($27 million as of
March 31, 2007), which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA.
(B) ENVIRONMENTAL
MATTERS
Various
federal,
state and local authorities regulate FirstEnergy with regard to air and water
quality and other environmental matters. The effects of compliance on
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. Overall, FirstEnergy believes it is in compliance with
existing regulations but is unable to predict future changes in regulatory
policies and what, if any, the effects of such changes would be. FirstEnergy
estimates additional capital expenditures for environmental compliance of
approximately $1.8 billion for 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.
FirstEnergy
complies
with SO2
reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX
reductions required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX
reductions at
FirstEnergy's facilities. The EPA's NOX
Transport Rule
imposes uniform reductions of NOX
emissions (an
approximate 85% reduction in utility plant NOX
emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX
emissions are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX
budgets established
under SIPs through combustion controls and post-combustion controls, including
Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems,
and/or using emission allowances.
National
Ambient
Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and fine particulate matter.
In
March 2005, the EPA finalized the CAIR covering a total of 28 states
(including Michigan, New Jersey, Ohio and Pennsylvania) and the District of
Columbia based on proposed findings that air emissions from 28 eastern states
and the District of Columbia significantly contribute to non-attainment of
the
NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR
provided 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 Mansfield, FirstEnergy’s
only 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.
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 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 New Source Review 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 W.
H. Sammis Plant and other FES 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 are currently estimated to be $1.5 billion ($400 million of which
is
expected to be spent during 2007, with the largest portion of the remaining
$1.1
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.
On
August 26, 2005,
FGCO entered into an agreement with Bechtel Power Corporation under which
Bechtel will engineer, procure, and construct air quality control systems for
the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement with
B&W.
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.
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. FirstEnergy is conducting
comprehensive demonstration studies, due in 2008, to determine the operational
measures or equipment, if any, necessary for compliance by its facilities with
the performance standards. FirstEnergy is unable to predict the outcome of
such
studies or changes in these requirements from the remand to EPA. Depending
on
the outcome of such studies and EPA’s further rulemaking, 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 March 31, 2007, FirstEnergy had
approximately $1.4 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
March 31, 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 $87 million (JCP&L - $59 million, TE -
$3 million, CEI - $1 million, and other subsidiaries -
$24 million) have been accrued through March 31, 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, New
Jersey. In 2005, JCP&L renewed its motion to decertify the class based on a
very limited number of class members who incurred damages and also filed a
motion for summary judgment on the remaining plaintiffs’ claims for negligence,
breach of contract and punitive damages. In July 2006, the New Jersey Superior
Court dismissed the punitive damage claim and again decertified the class based
on the fact that a vast majority of the class members did not suffer damages
and
those that did would be more appropriately addressed in individual actions.
Plaintiffs appealed this ruling to the New Jersey Appellate Division 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. In late March 2007,
JCP&L filed a petition for allowance of an appeal of the Appellate Division
ruling to the New Jersey Supreme Court. FirstEnergy is unable to predict the
outcome of these matters and no liability has been accrued as of March 31,
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. It is unknown whether or not
the matter will be further appealed. 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 will continue
and that the plant must improve performance to be removed from the
Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Nuclear Power Plant
and
stated that the CAL would remain open until substantial improvement was
demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight
Process. By two letters dated March 2, 2007, the NRC closed the Confirmatory
Action Letter 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 (routine agency oversight).
On
April 30, 2007,
the Union of Concerned Scientists (UCS) filed a petition with the NRC under
Section 2.206 of the NRC’s regulations based on an expert witness report that
FENOC developed for an unrelated insurance arbitration. In December 2006,
the
expert witness for FENOC prepared 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) that Davis-Besse’s operating
license be revoked.
In
a letter dated
May 4, 2007, the NRC stated that "the current inspection requirements are
sufficient to detect degradation of a reactor pressure vessel head penetration
nozzles prior to the development of significant head wastage even if the
assumptions and conclusions in the [expert witness] report relating to the
wastage of the head at Davis-Besse were applied to all pressurized water
reactors." The NRC also indicated that while they are developing a more complete
response to the UCS' petition, “the staff informed UCS that, as an initial
matter, it has determined that no immediate action with respect to Davis-Besse
or other nuclear plant is warranted.” 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. The Court has scheduled oral argument for
June 25, 2007 to hear the plaintiffs' request for reconsideration of its order
denying class certification and request to amend their complaint.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. JCP&L
intends to re-file an appeal again in federal district court once the damages
associated with this case are identified at an individual employee level.
JCP&L recognized a liability for the potential $16 million award in
2005.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters, it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
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 (Focused Audit).
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
NERC has been
preparing the implementation aspects of reorganizing its structure to meet
the
FERC’s certification requirements for the ERO. The NERC made a filing with the
FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
approval of pro forma delegation agreements with regional reliability
organizations (regional entities). A rule adopted by the FERC in 2006 provides
for reorganizing regional entities that would replace the current regional
councils and for rearranging their relationship with the ERO. The “regional
entity” may be delegated authority by the ERO, subject to FERC approval, for
compliance and enforcement of reliability standards adopted by the ERO and
approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments
and reply comments were filed in May, June and July 2006. On July 20, 2006,
the
FERC certified the NERC as the ERO to implement the provisions of Section 215
of
the Federal Power Act and directed the NERC to make compliance filings
addressing governance and non-governance issues and the regional delegation
agreements. On September 18, 2006 and October 18, 2006, NERC submitted
compliance filings addressing the governance and non-governance issues
identified in the FERC ERO Certification Order, dated July 20, 2006. On October
30, 2006, the FERC issued an order accepting most of NERC’s governance filings.
On January 18, 2007, the FERC issued an order largely accepting NERC’s
compliance filings addressing non-governance issues, subject to an additional
compliance filing, which NERC submitted on March 19, 2007.
On
November 29,
2006, NERC submitted an additional compliance filing with the FERC regarding
the
Compliance Monitoring and Enforcement Program (CMEP) along with the proposed
Delegation Agreements between the ERO and the regional reliability entities.
The
FERC provided opportunity for interested parties to comment on the CMEP by
January 10, 2007. FirstEnergy, as well as other parties, moved to intervene
and
submitted responsive comments on January 10, 2007. This filing, which
established the regulatory framework for NERC’s future enforcement program, was
approved by the FERC on April 19, 2007.
The
ECAR,
Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
councils completed the consolidation of these regions into a single new regional
reliability organization known as ReliabilityFirst
Corporation.
ReliabilityFirst
began operations as
a regional reliability council under NERC on January 1, 2006 and on
November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain
certification consistent with the final rule as a “regional entity” under the
ERO. This Delegation Agreement was also approved by the FERC on April 19,
2007. All of FirstEnergy’s facilities are located within the
ReliabilityFirst
region.
On
May 2, 2006, the
NERC Board of Trustees adopted eight new cyber security standards that replaced
interim standards put in place in the wake of the September 11, 2001 terrorist
attacks, and thirteen additional reliability standards. The security standards
became effective on June 1, 2006, and the remaining standards become effective
during 2007. NERC filed these proposed standards with the FERC and relevant
Canadian authorities for approval. The cyber security standards were not
included in the October 20, 2006 NOPR and are being addressed in a separate
FERC docket. On December 11, 2006, the FERC Staff provided its preliminary
assessment of these proposed mandatory reliability standards and again cited
various deficiencies in the proposed standards. Numerous parties, including
FirstEnergy, provided comments on the assessment by February 12, 2007. This
filing is pending before the FERC.
On
April 4, 2006,
NERC submitted a filing with the FERC seeking approval of mandatory reliability
standards. On October 20, 2006, the FERC in turn issued a Proposed Rule on
the
reliability standards. After a period of public review of the proposal, the
FERC
issued on March 16, 2007 its Final Rule on Mandatory Reliability Standards
for the Bulk-Power System. In this ruling, the FERC approved 83 of the 107
mandatory electric reliability standards proposed by NERC, making them
enforceable with penalties and sanctions for noncompliance when the rule becomes
effective, which is expected by the summer of 2007. The final rule will become
effective on June 4, 2007. The FERC also directed NERC to submit
improvements to 56 standards, endorsing NERC's process for developing
reliability standards and its associated work plan. The 24 standards that were
not approved remain pending at the FERC awaiting further information from NERC
and its regional entities.
FirstEnergy
believes
it is in compliance with all current NERC reliability standards. However,
based
upon a review of the March 16, 2007 Final Rule, it appears that the FERC
will
eventually adopt stricter NERC reliability standards than those just approved
as
NERC addresses the FERC's guidance in the Final Rule. 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.
(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. 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 will automatically become
effective on July 1, 2007. The revised riders represent an increase over the
amounts collected through the 2006 riders of approximately $64 million annually.
During
the period
between May 1, 2007 and June 1, 2007, any party may raise issues related to
the
revised tariffs through an informal resolution process. If not adequately
resolved through this process by June 30, 2007, any interested party may file
a
formal complaint with the PUCO which will be addressed by the PUCO after all
parties have been heard. If at the conclusion of either the informal or formal
process, adjustments are found to be necessary, such adjustments (with carrying
costs) will be included in the Ohio Companies’ next rider filing which must be
filed no later than May 1, 2008. No assurance can be given that such formal
or
informal proceedings will not be instituted.
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 intend to file the application
and rate request with the PUCO on or after June 7, 2007. The requested $334
million 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. The new rates, subject to evidentiary
hearings at the PUCO, would become effective January 1, 2009 for OE and TE,
and
May 2009 for CEI.
(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 allows Met-Ed and Penelec to sell the output of NUG
generation 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 have also 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.
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 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 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.
If Met-Ed
and
Penelec do not prevail on the issue of congestion, it could have a material
adverse effect on FirstEnergy’s and their financial condition and results of
operations.
As
of March 31,
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 $472 million and $124 million, respectively.
Penelec’s $124 million 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
may file exceptions to the initial decision by May 22, 2007 and parties may
reply to those exceptions 10 days thereafter. 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 Energy Independence Strategy (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 through a "Least Cost Portfolio", the
utilization of micro-grids and an optional three year phase-in of rate
increases. Since the EIS has only recently been proposed, the final form of
any
legislation 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 March 31, 2007, the accumulated deferred
cost balance totaled approximately $357 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 and 2) renewables have completed their assigned
tasks of data gathering and analysis. Both groups have provided a report to
the
EMP Committee. The working groups addressing reliability and pricing issues
continue their data gathering and analysis activities. Public stakeholder
meetings were held in the fall of 2006 and in early 2007, and further public
meetings are expected in the summer of 2007. A final draft of the EMP is
expected to be presented to the Governor in the fall of 2007 with further public
hearings anticipated in early 2008. 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 issued a draft proposal relating to changes to the
regulations addressing electric distribution service reliability and quality
standards. A meeting between the NJBPU Staff and interested stakeholders to
discuss the proposal was held on February 15, 2007. On February 22, 2007, the
NJBPU Staff circulated a revised proposal upon which discussions with interested
stakeholders were held on March 26, 2007. On April 18 and April 23, 2007 the
NJBPU staff circulated further revised draft proposals. A schedule for formal
proceedings has not yet been established. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, ultimate
regulations resulting from these draft proposals 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 second 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. On May 31, 2005, the FERC issued an order on these
cases. First, it set for hearing the existing rate design and indicated that
it
will issue a final order within six months. American Electric Power Company,
Inc. filed in opposition proposing to create a "postage stamp" rate for high
voltage transmission facilities across PJM. Second, the FERC approved the
proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
formula rate, subject to refund and hearing procedures. On June 30, 2005, the
settling PJM transmission owners filed a request for rehearing of the May 31,
2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
rate proceeding that generally accepts the companies' formula rate proposal.
The
FERC issued an order approving this settlement on April 19, 2006. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the 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. On April 19,
2007, the FERC issued an order rejecting the ALJ’s findings and recommendations
in nearly every respect. 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, 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, 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.
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
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 an implementation in the second
or
third 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 has requested FERC action on its filing by June 2007.
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 will become effective on
May 14, 2007. The final rule has not yet been fully evaluated to assess its
impact on FirstEnergy’s operations. MISO, PJM and ATSI will be filing revised
tariffs to comply with FERC’s order.
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. The Standard 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
06-10 -
“Accounting for Deferred Compensation and Postretirement Benefit Aspects of
Collateral
Split-Dollar
Life Insurance Arrangements”
In
March 2007, the
EITF reached a final consensus on Issue 06-10 concluding that an employer should
recognize a liability for the postretirement obligation associated with a
collateral assignment split-dollar life insurance arrangement if, based on
the
substantive arrangement with the employee, the employer has agreed to maintain
a
life insurance policy during the employee’s retirement or provide the employee
with a death benefit. The liability should be recognized in accordance with
SFAS
106 if,
in substance, a
postretirement plan exists or APB 12 if the arrangement is, in substance, an
individual deferred compensation contract. The EITF also reached a consensus
that the employer should recognize and measure the associated asset on the
basis
of the terms of the collateral assignment arrangement. This pronouncement is
effective for fiscal years beginning after December 15, 2007, including interim
periods within those years. FirstEnergy does not expect this pronouncement
to
have a material impact on its 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
reflected in the revised 2006 segment reporting primarily reflects the transfer
within FirstEnergy’s management and organization of the responsibility of
obtaining PLR generation for the utilities for their non-shopping customers
from
FES to business units within the regulated utilities. 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)
|
|
March
31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
2,040
|
|
$
|
328
|
|
$
|
619
|
|
$
|
12
|
|
$
|
(26
|
)
|
$
|
2,973
|
|
Internal
revenues
|
|
|
-
|
|
|
714
|
|
|
-
|
|
|
-
|
|
|
(714
|
)
|
|
-
|
|
Total
revenues
|
|
|
2,040
|
|
|
1,042
|
|
|
619
|
|
|
12
|
|
|
(740
|
)
|
|
2,973
|
|
Depreciation
and amortization
|
|
|
220
|
|
|
51
|
|
|
(15
|
)
|
|
1
|
|
|
6
|
|
|
263
|
|
Investment
income
|
|
|
70
|
|
|
3
|
|
|
1
|
|
|
-
|
|
|
(41
|
)
|
|
33
|
|
Net
interest
charges
|
|
|
107
|
|
|
49
|
|
|
1
|
|
|
2
|
|
|
21
|
|
|
180
|
|
Income
taxes
|
|
|
148
|
|
|
65
|
|
|
15
|
|
|
5
|
|
|
(33
|
)
|
|
200
|
|
Net
income
|
|
|
218
|
|
|
98
|
|
|
24
|
|
|
1
|
|
|
(51
|
)
|
|
290
|
|
Total
assets
|
|
|
23,526
|
|
|
7,089
|
|
|
246
|
|
|
254
|
|
|
675
|
|
|
31,790
|
|
Total
goodwill
|
|
|
5,874
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,898
|
|
Property
additions
|
|
|
155
|
|
|
124
|
|
|
-
|
|
|
1
|
|
|
16
|
|
|
296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,796
|
|
$
|
355
|
|
$
|
543
|
|
$
|
28
|
|
$
|
(17
|
)
|
$
|
2,705
|
|
Internal
revenues
|
|
|
9
|
|
|
611
|
|
|
-
|
|
|
-
|
|
|
(620
|
)
|
|
-
|
|
Total
revenues
|
|
|
1,805
|
|
|
966
|
|
|
543
|
|
|
28
|
|
|
(637
|
)
|
|
2,705
|
|
Depreciation
and amortization
|
|
|
258
|
|
|
46
|
|
|
(21
|
)
|
|
1
|
|
|
5
|
|
|
289
|
|
Investment
income
|
|
|
84
|
|
|
15
|
|
|
-
|
|
|
-
|
|
|
(56
|
)
|
|
43
|
|
Net
interest
charges
|
|
|
99
|
|
|
44
|
|
|
-
|
|
|
1
|
|
|
16
|
|
|
160
|
|
Income
taxes
|
|
|
126
|
|
|
21
|
|
|
20
|
|
|
(6
|
)
|
|
(26
|
)
|
|
135
|
|
Income
from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
continuing
operations
|
|
|
189
|
|
|
32
|
|
|
30
|
|
|
12
|
|
|
(44
|
)
|
|
219
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
-
|
|
|
2
|
|
Net
income
|
|
|
189
|
|
|
32
|
|
|
30
|
|
|
14
|
|
|
(44
|
)
|
|
221
|
|
Total
assets
|
|
|
23,633
|
|
|
6,759
|
|
|
215
|
|
|
367
|
|
|
823
|
|
|
31,797
|
|
Total
goodwill
|
|
|
5,916
|
|
|
24
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,940
|
|
Property
additions
|
|
|
193
|
|
|
244
|
|
|
-
|
|
|
-
|
|
|
10
|
|
|
447
|
|
Reconciling
adjustments to segment operating results from internal management reporting
to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses, fuel marketing revenues (which are reflected as reductions to expenses
for internal management reporting purposes) and elimination of intersegment
transactions.
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
Electric
utilities
|
|
$
|
2,681
|
|
$
|
2,340
|
|
Unregulated
businesses
|
|
|
292
|
|
|
365
|
|
Total
revenues*
|
|
|
2,973
|
|
|
2,705
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
1,121
|
|
|
998
|
|
Other
operating expenses
|
|
|
749
|
|
|
754
|
|
Provision
for
depreciation
|
|
|
156
|
|
|
148
|
|
Amortization
of regulatory assets
|
|
|
251
|
|
|
221
|
|
Deferral
of
new regulatory assets
|
|
|
(144
|
)
|
|
(80
|
)
|
General
taxes
|
|
|
203
|
|
|
193
|
|
Total
expenses
|
|
|
2,336
|
|
|
2,234
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
637
|
|
|
471
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Investment
income
|
|
|
33
|
|
|
43
|
|
Interest
expense
|
|
|
(185
|
)
|
|
(165
|
)
|
Capitalized
interest
|
|
|
5
|
|
|
7
|
|
Subsidiaries’
preferred stock dividends
|
|
|
-
|
|
|
(2
|
)
|
Total
other
expense
|
|
|
(147
|
)
|
|
(117
|
)
|
|
|
|
|
|
|
|
|
INCOME
FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
|
|
|
490
|
|
|
354
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
200
|
|
|
135
|
|
|
|
|
|
|
|
|
|
INCOME
FROM CONTINUING OPERATIONS
|
|
|
290
|
|
|
219
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income tax benefit of $1 million)
|
|
|
|
|
|
|
|
(Note
3)
|
|
|
-
|
|
|
2
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
290
|
|
$
|
221
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
0.92
|
|
$
|
0.67
|
|
Discontinued
operations (Note 3)
|
|
|
-
|
|
|
-
|
|
Net
income
|
|
$
|
0.92
|
|
$
|
0.67
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
314
|
|
|
329
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
Income
from
continuing operations
|
|
$
|
0.92
|
|
$
|
0.67
|
|
Discontinued
operations (Note 3)
|
|
|
-
|
|
|
-
|
|
Net
income
|
|
$
|
0.92
|
|
$
|
0.67
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
316
|
|
|
330
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$
|
0.50
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Includes
$104 million and $99 million of excise tax collections in the
first
quarter of 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
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
290
|
|
$
|
221
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(11
|
)
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
21
|
|
|
37
|
|
Unrealized
gain on available for sale securities
|
|
|
17
|
|
|
37
|
|
Other
comprehensive income
|
|
|
27
|
|
|
74
|
|
Income
tax
expense related to other comprehensive income
|
|
|
9
|
|
|
27
|
|
Other
comprehensive income, net of tax
|
|
|
18
|
|
|
47
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
$
|
308
|
|
$
|
268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
89
|
|
$
|
90
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $40 million and
|
|
|
|
|
|
|
|
$43
million,
respectively, for uncollectible accounts)
|
|
|
1,250
|
|
|
1,135
|
|
Other
(less
accumulated provisions of $23 million and
|
|
|
|
|
|
|
|
$24
million,
respectively, for uncollectible accounts)
|
|
|
184
|
|
|
132
|
|
Materials
and
supplies, at average cost
|
|
|
591
|
|
|
577
|
|
Prepayments
and other
|
|
|
233
|
|
|
149
|
|
|
|
|
2,347
|
|
|
2,083
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
In
service
|
|
|
24,223
|
|
|
24,105
|
|
Less
-
Accumulated provision for depreciation
|
|
|
10,191
|
|
|
10,055
|
|
|
|
|
14,032
|
|
|
14,050
|
|
Construction
work in progress
|
|
|
754
|
|
|
617
|
|
|
|
|
14,786
|
|
|
14,667
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
2,008
|
|
|
1,977
|
|
Investments
in
lease obligation bonds
|
|
|
775
|
|
|
811
|
|
Other
|
|
|
742
|
|
|
746
|
|
|
|
|
3,525
|
|
|
3,534
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
5,898
|
|
|
5,898
|
|
Regulatory
assets
|
|
|
4,371
|
|
|
4,441
|
|
Pension
assets
|
|
|
277
|
|
|
-
|
|
Other
|
|
|
586
|
|
|
573
|
|
|
|
|
11,132
|
|
|
10,912
|
|
|
|
$
|
31,790
|
|
$
|
31,196
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
2,093
|
|
$
|
1,867
|
|
Short-term
borrowings
|
|
|
2,247
|
|
|
1,108
|
|
Accounts
payable
|
|
|
625
|
|
|
726
|
|
Accrued
taxes
|
|
|
413
|
|
|
598
|
|
Other
|
|
|
1,020
|
|
|
956
|
|
|
|
|
6,398
|
|
|
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
|
|
|
5,574
|
|
|
6,466
|
|
Accumulated
other comprehensive loss
|
|
|
(241
|
)
|
|
(259
|
)
|
Retained
earnings
|
|
|
2,941
|
|
|
2,806
|
|
Unallocated
employee stock ownership plan common stock-
|
|
|
|
|
|
|
|
324,738
and
521,818 shares, respectively
|
|
|
(5
|
)
|
|
(10
|
)
|
Total
common
stockholders' equity
|
|
|
8,299
|
|
|
9,035
|
|
Long-term
debt
and other long-term obligations
|
|
|
8,546
|
|
|
8,535
|
|
|
|
|
16,845
|
|
|
17,570
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
2,826
|
|
|
2,740
|
|
Asset
retirement obligations
|
|
|
1,208
|
|
|
1,190
|
|
Power
purchase
contract loss liability
|
|
|
1,063
|
|
|
1,182
|
|
Retirement
benefits
|
|
|
920
|
|
|
944
|
|
Lease
market
valuation liability
|
|
|
745
|
|
|
767
|
|
Other
|
|
|
1,785
|
|
|
1,548
|
|
|
|
|
8,547
|
|
|
8,371
|
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
31,790
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
290
|
|
$
|
221
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
156
|
|
|
148
|
|
Amortization
of regulatory assets
|
|
|
251
|
|
|
222
|
|
Deferral
of
new regulatory assets
|
|
|
(144
|
)
|
|
(80
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
26
|
|
|
20
|
|
Deferred
purchased power and other costs
|
|
|
(116
|
)
|
|
(104
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
53
|
|
|
6
|
|
Investment
impairment
|
|
|
5
|
|
|
-
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(25
|
)
|
|
(38
|
)
|
Accrued
compensation and retirement benefits
|
|
|
(65
|
)
|
|
(19
|
)
|
Commodity
derivative transactions, net
|
|
|
1
|
|
|
26
|
|
Income
from
discontinued operations
|
|
|
-
|
|
|
(2
|
)
|
Cash
collateral
|
|
|
6
|
|
|
(106
|
)
|
Pension
trust
contribution
|
|
|
(300
|
)
|
|
-
|
|
Decrease
(Increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
(155
|
)
|
|
226
|
|
Materials
and
supplies
|
|
|
15
|
|
|
(52
|
)
|
Prepayments
and other current assets
|
|
|
(74
|
)
|
|
(93
|
)
|
Increase
(Decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(108
|
)
|
|
(114
|
)
|
Accrued
taxes
|
|
|
73
|
|
|
9
|
|
Accrued
interest
|
|
|
86
|
|
|
100
|
|
Electric
service prepayment programs
|
|
|
(17
|
)
|
|
(14
|
)
|
Other
|
|
|
(33
|
)
|
|
(32
|
)
|
Net
cash
provided from (used for) operating activities
|
|
|
(75
|
)
|
|
324
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
250
|
|
|
-
|
|
Short-term
borrowings, net
|
|
|
1,139
|
|
|
200
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(891
|
)
|
|
-
|
|
Preferred
stock
|
|
|
-
|
|
|
(30
|
)
|
Long-term
debt
|
|
|
(13
|
)
|
|
(64
|
)
|
Net
controlled
disbursement activity
|
|
|
12
|
|
|
(8
|
)
|
Stock-based
compensation tax benefit
|
|
|
8
|
|
|
-
|
|
Common
stock
dividend payments
|
|
|
(159
|
)
|
|
(148
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
346
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(296
|
)
|
|
(447
|
)
|
Proceeds
from
asset sales
|
|
|
-
|
|
|
57
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
266
|
|
|
481
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(269
|
)
|
|
(484
|
)
|
Cash
investments
|
|
|
25
|
|
|
103
|
|
Other
|
|
|
2
|
|
|
(20
|
)
|
Net
cash used
for investing activities
|
|
|
(272
|
)
|
|
(310
|
)
|
|
|
|
|
|
|
|
|
Net
decrease
in cash and cash equivalents
|
|
|
(1
|
)
|
|
(36
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
90
|
|
|
64
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
89
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 sheets of FirstEnergy Corp. and its
subsidiaries as of March 31, 2007 and the related consolidated
statements of income, comprehensive income and cash flows for each of the
three-month periods ended March 31, 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 stockholders’ equity, preferred stock and cash flows for the year
then ended, management’s assessment of the effectiveness of the Company’s
internal control over financial reporting as of December 31, 2006 and the
effectiveness of the Company’s internal control over financial reporting as of
December 31, 2006; 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 unqualified opinions thereon. The
consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above
are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet 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
May
8,
2007
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE
SUMMARY
Net
income in the
first quarter of 2007 was $290 million, or basic and diluted earnings of
$0.92 per share of common stock, compared with net income of $221 million,
or basic and diluted earnings of $0.67 per share in the first quarter of 2006.
The
increase in FirstEnergy’s earnings was driven primarily by increased electric
sales revenues, partially offset by higher fuel and purchase power
costs.
Change
in Basic Earnings Per Share From
Prior
Year First Quarter
|
|
|
|
|
|
|
|
Basic
Earnings
Per Share - First Quarter 2006
|
|
$
0.67
|
|
Revenues
|
|
0.51
|
|
Fuel
and
purchased power
|
|
(0.24)
|
|
Depreciation
and amortization
|
|
(0.08)
|
|
Deferral
of
new regulatory assets
|
|
0.07
|
|
Other
expenses
|
|
(0.05)
|
|
Saxton
decommissioning regulatory asset
|
|
0.05
|
|
Trust
securities impairment
|
|
(0.01)
|
|
Basic
Earnings
Per Share - First Quarter 2007
|
|
$
0.92
|
|
|
|
|
|
Financial
Matters
Share
Repurchase
Programs - On March 2, 2007, FirstEnergy repurchased approximately 14.4 million
shares, or 4.5%, of its outstanding common stock under an accelerated share
repurchase (ASR) agreement with an affiliate of Morgan Stanley & Co.
Incorporated. The initial purchase price was approximately $900 million, or
$62.63 per share. 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 ASR was completed under a January 30, 2007 Board of Directors authorization
to repurchase up to 16 million shares of outstanding common stock.
On
April 2, 2007, an
affiliate of J.P. Morgan Securities completed its acquisition of shares under
FirstEnergy’s prior ASR program of 10.6 million shares, which was executed in
August 2006. In settling the transaction, FirstEnergy remitted approximately
$27 million to J.P. Morgan as a final purchase price adjustment based on
the average of the daily volume-weighted average price over the purchase period,
as well as other purchase price adjustments.
Under
the two ASR
programs, FirstEnergy has repurchased approximately 25 million shares, or
8%, of the total shares outstanding as of July 2006.
Sale
and Leaseback
of Bruce Mansfield Unit 1 - On January 31, 2007, FirstEnergy announced its
intention to pursue a sale and leaseback transaction for its owned portion
(776
MW) of Bruce Mansfield Unit 1. FirstEnergy anticipates the after-tax proceeds
of
this proposed transaction to be approximately $1.2 billion. The proceeds
are expected to be used to repay short-term borrowings incurred to fund the
recently executed ASR program and the recent voluntary pension plan
contribution. FirstEnergy is targeting a second quarter of 2007 closing for
the
transaction including related lease debt financing.
New
Long-Term Debt
Issuance - On March 27, 2007, CEI issued $250 million of 5.70%
unsecured senior notes due 2017. The proceeds from the transaction were used
to
repay short-term borrowings and for general corporate purposes.
Credit
Rating Agency
Update - On March 26, 2007, S&P assigned its corporate credit rating of BBB
to FES. Moody’s also issued a rating of Baa2 on FES on March 27, 2007. FES is
the holding company of FirstEnergy Generation Corp. and FirstEnergy Nuclear
Generation Corp., the owners of FirstEnergy’s fossil and nuclear generation
assets, respectively. Both S&P and Moody’s cited the strength of
FirstEnergy’s generation portfolio as a key contributor to the investment grade
credit ratings.
Regulatory
Matters
Ohio
- 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 will automatically become
effective on July 1, 2007. The revised riders represent an increase over the
amounts collected through the 2006 riders of approximately $64 million annually.
During
the period
between May 1, 2007 and June 1, 2007, any party may raise issues related to
the
revised tariffs through an informal resolution process. If not adequately
resolved through this process by June 30, 2007, any interested party may file
a
formal complaint with the PUCO which will be addressed by the PUCO after all
parties have been heard. If at the conclusion of either the informal or formal
process, adjustments are found to be necessary, such adjustments (with carrying
costs) will be included in the Ohio Companies’ next rider filing which must be
filed no later than May 1, 2008. No assurance can be given that such formal
or
informal proceedings will not be instituted.
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 intend to file the application
and rate request with the PUCO on or after June 7, 2007. The requested $334
million 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. The new rates, subject to evidentiary
hearings at the PUCO, would become effective January 1, 2009 for OE and TE,
and
May 2009 for CEI.
Pennsylvania
- On
January 11, 2007, the PPUC issued its order in the Met-Ed and Penelec 2006
comprehensive transition rate cases (see Note 10). Several parties to the
proceeding, including Met-Ed and Penelec, have filed appeals with the
Pennsylvania Commonwealth Court, which are currently pending.
A
hearing was held
February 21, 2007 in the Met-Ed and Penelec NUG accounting case. In this case,
Met-Ed and Penelec are seeking to modify the NUG purchased power stranded costs
accounting methodology to eliminate improper reductions of the deferred cost
balance during periods in which market prices exceed NUG payments. 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
may file exceptions to the initial decision by May 22, 2007 and parties may
reply to those exceptions 10 days thereafter. It is not known when the PPUC
may
issue a final decision in this matter.
On
May 2, 2007, Penn
made a filing with the PPUC proposing how it will procure the power supply
needed for default service customers beginning June 1, 2008. Penn’s customers
transitioned to a fully competitive market on January 1, 2007, and the default
service plan that the PPUC previously approved covered a 17-month period through
May 31, 2008. The filing proposes that Penn procure a full requirements product,
by class, through multiple RFPs with staggered delivery periods extending
through May 2011. It also proposes a 3-year phase-out of promotional generation
rates. Penn expects the PPUC to address the filing later this year.
On
February 1, 2007,
the Governor of Pennsylvania proposed an Energy Independence Strategy (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 through a "Least Cost Portfolio", the
utilization of micro-grids and an optional three year phase-in of rate
increases. Since the EIS has only recently been proposed, the final form
of any
legislation is uncertain. Consequently, FirstEnergy is unable to predict
what
impact, if any, such legislation may have on its operations.
Generation
NRC
Oversight Update
- On March 2, 2007, the NRC returned FirstEnergy’s Perry Plant to routine agency
oversight as a result of sufficient corrective actions that have been taken
over
the last two-and-one-half years. The Perry Plant had been operating under
heightened NRC oversight since August 2004 (see Note 9).
Refueling
Outage -
FirstEnergy’s Perry Plant began its regularly scheduled refueling outage on
April 2, 2007. Major work activities to be completed on the 1,258 MW facility
include replacing approximately one-third of the fuel assemblies in the reactor
and two of the three low-pressure turbine rotors in the main generator.
Power
Uprates - In
March 2007, Beaver Valley Unit 1 completed the final phase of an extended power
uprate project to add additional capacity to FirstEnergy’s system. This is its
second power uprate in the past 12 months. Capacity testing will be conducted
later this year to verify the actual megawatts gained. This power uprate was
achieved in support of FirstEnergy’s strategy to maximize the full potential of
its existing generation assets.
Environmental
Update
- In March 2007, an SNCR system was placed in-service at FirstEnergy’s 597 MW
Eastlake Unit 5, upon completion of a scheduled maintenance outage. The SNCR
installation is part of FirstEnergy’s overall Air Quality Compliance Strategy
and was required under the New Source Review consent decree. The SNCR is
expected to reduce NOx emissions and help achieve reductions required by
the
EPA’s NOx Transport Rule.
FIRSTENERGY’S
BUSINESS
FirstEnergy
is a
public utility holding 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 to non-shopping retail customers under
the PLR
obligations in its Pennsylvania and New Jersey franchise areas.
Its
results
reflect the commodity costs of securing electric generation from
the
Competitive Energy Services Segment under partial requirements purchased
power agreements with FES and non-affiliated power suppliers as well
as
the net PJM transmission expenses related to the delivery of that
generation load.
|
· |
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
and operates FirstEnergy's generating facilities and also purchases
electricity to meet 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 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 and net transmission
(including congestion) and ancillary costs charged by MISO to deliver
energy to its 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
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
Net
Income
|
|
(In
millions, except per share data)
|
|
By
Business Segment
|
|
|
|
|
|
|
|
Energy
delivery services
|
|
$
|
218
|
|
$
|
189
|
|
$
|
29
|
|
Competitive
energy services
|
|
|
98
|
|
|
32
|
|
|
66
|
|
Ohio
transitional generation services
|
|
|
24
|
|
|
30
|
|
|
(6
|
)
|
Other
and
reconciling adjustments*
|
|
|
(50
|
)
|
|
(30
|
)
|
|
(20
|
)
|
Total
|
|
$
|
290
|
|
$
|
221
|
|
$
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted Earnings Per Share
|
|
$
|
0.92
|
|
$
|
0.67
|
|
$
|
0.25
|
|
*Represents
other
operating segments and reconciling items including interest expense on holding
company debt and
corporate
support services revenues and expenses.
Net
income in the first quarter of 2006 included after-tax earnings from
discontinued operations of $2 million resulting from FirstEnergy’s
disposition of non-core assets and operations (see Note 3).
Financial
results
for FirstEnergy's major business segments in the first quarter of 2007 and
2006
were as follows:
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
Energy
|
|
Competitive
|
|
Transitional
|
|
Other
and
|
|
|
|
|
|
Delivery
|
|
Energy
|
|
Generation
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Quarter 2007 Financial Results
|
|
Services
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
External |
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
1,875 |
|
$
|
276
|
|
$
|
613
|
|
$
|
-
|
|
$
|
2,764
|
|
Other
|
|
|
165 |
|
|
52
|
|
|
6
|
|
|
(14
|
)
|
|
209
|
|
Internal
|
|
|
- |
|
|
714
|
|
|
-
|
|
|
(714
|
)
|
|
-
|
|
Total
Revenues
|
|
|
2,040
|
|
|
1,042
|
|
|
619
|
|
|
(728
|
)
|
|
2,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
844 |
|
|
447
|
|
|
544
|
|
|
(714
|
)
|
|
1,121
|
|
Other
operating expenses
|
|
|
408 |
|
|
307
|
|
|
49
|
|
|
(15
|
)
|
|
749
|
|
Provision
for
depreciation
|
|
|
98 |
|
|
51
|
|
|
-
|
|
|
7
|
|
|
156
|
|
Amortization
of regulatory assets
|
|
|
246 |
|
|
-
|
|
|
5
|
|
|
-
|
|
|
251
|
|
Deferral
of
new regulatory assets
|
|
|
(124
|
) |
|
-
|
|
|
(20
|
)
|
|
-
|
|
|
(144
|
)
|
General
taxes
|
|
|
165 |
|
|
28
|
|
|
2
|
|
|
8
|
|
|
203
|
|
Total
Expenses
|
|
|
1,637
|
|
|
833
|
|
|
580
|
|
|
(714
|
)
|
|
2,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
403
|
|
|
209
|
|
|
39
|
|
|
(14
|
)
|
|
637
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
70 |
|
|
3
|
|
|
1
|
|
|
(41
|
)
|
|
33
|
|
Interest
expense
|
|
|
(109 |
) |
|
(52
|
)
|
|
(1
|
)
|
|
(23
|
)
|
|
(185
|
)
|
Capitalized
interest
|
|
|
2 |
|
|
3
|
|
|
-
|
|
|
-
|
|
|
5
|
|
Total
Other
Expense
|
|
|
(37
|
)
|
|
(46
|
)
|
|
-
|
|
|
(64
|
)
|
|
(147
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations Before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
366 |
|
|
163
|
|
|
39
|
|
|
(78
|
)
|
|
490
|
|
Income
taxes
|
|
|
148
|
|
|
65
|
|
|
15
|
|
|
(28
|
)
|
|
200
|
|
Net
Income
|
|
$
|
218
|
|
$
|
98
|
|
$
|
24
|
|
$
|
(50
|
)
|
$
|
290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
Energy
|
|
Competitive
|
|
Transitional
|
|
Other
and
|
|
|
|
|
|
Delivery
|
|
Energy
|
|
Generation
|
|
Reconciling
|
|
FirstEnergy
|
|
First
Quarter 2006 Financial Results
|
|
Services
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,668 |
|
$
|
304
|
|
$
|
539
|
|
$
|
-
|
|
$
|
2,511
|
|
Other
|
|
|
128 |
|
|
51
|
|
|
4
|
|
|
11
|
|
|
194
|
|
Internal
|
|
|
9 |
|
|
611
|
|
|
-
|
|
|
(620
|
)
|
|
-
|
|
Total
Revenues
|
|
|
1,805
|
|
|
966
|
|
|
543
|
|
|
(609
|
)
|
|
2,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
693 |
|
|
468
|
|
|
457
|
|
|
(620
|
)
|
|
998
|
|
Other
operating expenses
|
|
|
366 |
|
|
344
|
|
|
56
|
|
|
(12
|
)
|
|
754
|
|
Provision
for
depreciation
|
|
|
96 |
|
|
46
|
|
|
-
|
|
|
6
|
|
|
148
|
|
Amortization
of regulatory assets
|
|
|
217 |
|
|
-
|
|
|
4
|
|
|
-
|
|
|
221
|
|
Deferral
of
new regulatory assets
|
|
|
(55 |
) |
|
-
|
|
|
(25
|
)
|
|
-
|
|
|
(80
|
)
|
General
taxes
|
|
|
158 |
|
|
26
|
|
|
1
|
|
|
8
|
|
|
193
|
|
Total
Expenses
|
|
|
1,475
|
|
|
884
|
|
|
493
|
|
|
(618
|
)
|
|
2,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
330
|
|
|
82
|
|
|
50
|
|
|
9
|
|
|
471
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
84 |
|
|
15
|
|
|
-
|
|
|
(56
|
)
|
|
43
|
|
Interest
expense
|
|
|
(100 |
) |
|
(47
|
)
|
|
-
|
|
|
(18
|
)
|
|
(165
|
)
|
Capitalized
interest
|
|
|
3 |
|
|
3
|
|
|
-
|
|
|
1
|
|
|
7
|
|
Subsidiaries'
preferred stock dividends
|
|
|
(2 |
) |
|
-
|
|
|
-
|
|
|
-
|
|
|
(2
|
)
|
Total
Other
Expense
|
|
|
(15
|
)
|
|
(29
|
)
|
|
-
|
|
|
(73
|
)
|
|
(117
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations Before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
315 |
|
|
53
|
|
|
50
|
|
|
(64
|
)
|
|
354
|
|
Income
taxes
|
|
|
126
|
|
|
21
|
|
|
20
|
|
|
(32
|
)
|
|
135
|
|
Income
from
continuing operations
|
|
|
189
|
|
|
32
|
|
|
30
|
|
|
(32
|
)
|
|
219
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
2
|
|
Net
Income
|
|
$
|
189
|
|
$
|
32
|
|
$
|
30
|
|
$
|
(30
|
)
|
$
|
221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between First Quarter 2007 and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter 2006 Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
207 |
|
$
|
(28
|
)
|
$
|
74
|
|
$
|
-
|
|
$
|
253
|
|
Other
|
|
|
37 |
|
|
1
|
|
|
2
|
|
|
(25
|
)
|
|
15
|
|
Internal
|
|
|
(9 |
) |
|
103
|
|
|
-
|
|
|
(94
|
)
|
|
-
|
|
Total
Revenues
|
|
|
235
|
|
|
76
|
|
|
76
|
|
|
(119
|
)
|
|
268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
151 |
|
|
(21
|
)
|
|
87
|
|
|
(94
|
)
|
|
123
|
|
Other
operating expenses
|
|
|
42 |
|
|
(37
|
)
|
|
(7
|
)
|
|
(3
|
)
|
|
(5
|
)
|
Provision
for
depreciation
|
|
|
2 |
|
|
5
|
|
|
-
|
|
|
1
|
|
|
8
|
|
Amortization
of regulatory asset
|
|
|
29 |
|
|
-
|
|
|
1
|
|
|
-
|
|
|
30
|
|
Deferral
of
new regulatory assets
|
|
|
(69 |
) |
|
-
|
|
|
5
|
|
|
-
|
|
|
(64
|
)
|
General
taxes
|
|
|
7 |
|
|
2
|
|
|
1
|
|
|
-
|
|
|
10
|
|
Total
Expenses
|
|
|
162
|
|
|
(51
|
)
|
|
87
|
|
|
(96
|
)
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
73
|
|
|
127
|
|
|
(11
|
)
|
|
(23
|
)
|
|
166
|
|
Other
Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(14 |
) |
|
(12
|
)
|
|
1
|
|
|
15
|
|
|
(10
|
)
|
Interest
expense
|
|
|
(9 |
) |
|
(5
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|
(20
|
)
|
Capitalized
interest
|
|
|
(1 |
) |
|
-
|
|
|
-
|
|
|
(1
|
)
|
|
(2
|
)
|
Subsidiaries'
preferred stock dividends
|
|
|
2 |
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
Total
Other
Income (Expense)
|
|
|
(22
|
)
|
|
(17
|
)
|
|
-
|
|
|
9
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
From
Continuing Operations Before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
51 |
|
|
110
|
|
|
(11
|
)
|
|
(14
|
)
|
|
136
|
|
Income
taxes
|
|
|
22
|
|
|
44
|
|
|
(5
|
)
|
|
4
|
|
|
65
|
|
Income
from
continuing operations
|
|
|
29
|
|
|
66
|
|
|
(6
|
)
|
|
(18
|
)
|
|
71
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(2
|
)
|
|
(2
|
)
|
Net
Income
|
|
$
|
29
|
|
$
|
66
|
|
$
|
(6
|
)
|
$
|
(20
|
)
|
$
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Delivery Services - First Quarter 2007 Compared to First Quarter
2006
Net
income increased
$29 million (or 15%) to $218 million in the first quarter of 2007
compared to $189 million in the first quarter 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:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Distribution
services
|
|
$
|
944
|
|
$
|
935
|
|
$
|
9
|
|
Generation
sales:
|
|
|
|
|
|
|
|
|
|
|
Retail
|
|
|
720
|
|
|
637
|
|
|
83
|
|
Wholesale
|
|
|
132
|
|
|
55
|
|
|
77
|
|
Total
generation sales
|
|
|
852
|
|
|
692
|
|
|
160
|
|
Transmission
|
|
|
183
|
|
|
124
|
|
|
59
|
|
Other
|
|
|
61
|
|
|
54
|
|
|
7
|
|
Total
Revenues
|
|
$
|
2,040
|
|
$
|
1,805
|
|
$
|
235
|
|
The
increases in distribution deliveries by customer class are summarized in the
following table:
Electric
Distribution Deliveries
|
|
|
|
Residential
|
|
|
7.1
|
%
|
Commercial
|
|
|
4.3
|
%
|
Industrial
|
|
|
0.1
|
%
|
Total
Distribution Deliveries
|
|
|
3.9
|
%
|
The
increase in electric distribution deliveries to customers was primarily due
to
colder than average weather during the first quarter of 2007 compared to
unseasonably mild weather during the same period of 2006, offset by an
unfavorable rate mix and 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 $160 million
increase in non-affiliated generation sales in 2007 compared to
2006:
Sources
of Change in Generation Sales
|
|
Increase
|
|
|
|
|
(In
millions)
|
|
|
Retail:
|
|
|
|
|
|
Effect
of 0.3%
increase in volume
|
|
$
|
2
|
|
|
Change
in
prices
|
|
|
81
|
|
|
|
|
|
83
|
|
|
Wholesale:
|
|
|
|
|
|
Effect
of 139%
increase in volume
|
|
|
77
|
|
|
Change
in
prices
|
|
|
-
|
|
|
|
|
|
77
|
|
|
Net
Increase
in Generation Sales
|
|
$
|
160
|
|
|
|
|
|
|
|
|
The
increase in
retail generation prices during the first quarter of 2007 compared to 2006
was
primarily due to increased generation and NUGC rates for JCP&L resulting
from the New Jersey BGS auction. 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.
The
$59 million
increase in transmission revenue was primarily due to approximately
$42 million of Met-Ed and Penelec transmission revenues in 2007 resulting
from a January 2007 PPUC authorization for transmission costs recovery. Met-Ed
and Penelec defer the difference between revenues accrued under the transmission
rider and transmission costs incurred, with no material effect to current period
earnings.
Expenses
-
The
net increases in revenues discussed above were partially offset by a
$162 million increase in expenses due to the following:
|
·
|
Purchased
power costs were $151 million higher in the first quarter of 2007
due to
higher unit prices and volumes purchased. The increased unit prices
reflected the effect of higher JCP&L purchased power unit prices
resulting from the BGS auction. 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
|
|
Increase
(Decrease)
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
Purchased
Power:
|
|
|
|
|
|
Change
due to
increased unit costs
|
|
$
|
74
|
|
|
Change
due to
increased volume
|
|
|
79
|
|
|
Decrease
in
NUG costs deferred
|
|
|
(2
|
)
|
|
Net
Increase
in Purchased Power Costs
|
|
$
|
151
|
|
|
|
·
|
Other
operating expenses increased $42 million due to the net effects of:
|
- |
An
increase of
$52 million in MISO and PJM transmission expenses, resulting
primarily from higher congestion
costs;
|
- |
Miscellaneous
operating expenses decreased $8 million primarily due to reduced
support services billings from FESC; and
|
- |
Operation
and
maintenance expenses decreased $2 million primarily due to lower
employee
benefit and storm-related costs.
|
|
·
|
Amortization
of regulatory assets increased $29 million compared to 2006 due primarily
to recovery of deferred BGS costs through higher NUGC revenues for
JCP&L as discussed above;
|
|
·
|
The
deferral
of new regulatory assets during the first quarter of 2007 was
$69 million higher in 2007 primarily due to the deferral of
previously expensed decommissioning expenses of $27 million related
to the
Saxton nuclear research facility (see Outlook - State Regulatory
Matters -
Pennsylvania) and the absence in the first quarter of 2006 of PJM
transmission costs and interest deferrals of $33 million that began
during
the second quarter of 2006.
|
Other
Income and
Expense -
Other
income
decreased $22 million in 2007 compared to the first quarter of 2006
primarily due to lower interest income of $14 million from repayment of
associated company notes receivable since the first quarter of 2006 related
to
the generation asset transfers and increased interest expense of $9 million
related in part to new debt issuances by CEI and JCP&L.
Ohio
Transitional Generation Services - First Quarter 2007 Compared to First Quarter
2006
Net
income for this segment decreased to $24 million in the first quarter of
2007 from $30 million in the same period last year. Higher generation
revenues were more than offset by higher operating expenses, primarily for
purchased power.
Revenues
-
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Generation
sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
545
|
|
$
|
472
|
|
$
|
73
|
|
Wholesale
|
|
|
2
|
|
|
7
|
|
|
(5
|
)
|
Total
generation sales
|
|
|
547
|
|
|
479
|
|
|
68
|
|
Transmission
|
|
|
71
|
|
|
63
|
|
|
8
|
|
Other
|
|
|
1
|
|
|
1
|
|
|
-
|
|
Total
Revenues
|
|
$
|
619
|
|
$
|
543
|
|
$
|
76
|
|
The
following table
summarizes the price and volume factors contributing to the increase in sales
revenues from retail customers:
Source
of Change in Electric Generation Sales
|
|
Increase
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 6.6%
increase in customer usage
|
|
$
|
31
|
|
Change
in
prices
|
|
|
42
|
|
Total Increase
in Retail Generation Sales
|
|
$
|
73
|
|
|
|
|
|
|
The
customer usage
increase was due to colder weather in the first quarter of 2007 compared to
the
same period of 2006 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 in the Ohio Companies’ service areas decreased by a weighted
average of 2.1 percentage points.
Expenses
-
Purchased
power
costs were $87 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
|
|
$
|
10
|
|
Change
due to
volume purchased
|
|
|
-
|
|
|
|
|
10
|
|
Purchases
from
FES:
|
|
|
|
|
Change
due to
increased unit costs
|
|
|
55
|
|
Change
due to
volume purchased
|
|
|
22
|
|
|
|
|
77
|
|
Total
Increase
in Purchased Power Costs
|
|
$
|
87
|
|
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.
Competitive
Energy Services - First Quarter 2007 Compared to First Quarter
2006
Net
income for this
segment was $98 million in the first quarter of 2007 compared to
$32 million in the same period last year. An improvement in gross
generation margin and lower other operating expenses was partially offset by
higher general taxes and reduced investment income.
Revenues
-
Total
revenues
increased $76 million in the first quarter of 2007 compared to the same
period in 2006. This increase primarily resulted from higher unit prices under
affiliated power 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 requirements 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 decreased sales
to
Penn as a result of the implementation of its competitive solicitation process
in the first quarter of 2007.
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31,
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
173
|
|
$
|
131
|
|
$
|
42
|
|
Wholesale
|
|
|
103
|
|
|
173
|
|
|
(70
|
)
|
Total
Non-Affiliated Generation Sales
|
|
|
276
|
|
|
304
|
|
|
(28
|
)
|
Affiliated
Power Sales
|
|
|
714
|
|
|
611
|
|
|
103
|
|
Transmission
|
|
|
23
|
|
|
20
|
|
|
3
|
|
Other
|
|
|
29
|
|
|
31
|
|
|
(2
|
)
|
Total
Revenues
|
|
$
|
1,042
|
|
$
|
966
|
|
$
|
76
|
|
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
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of
17.9% increase in customer usage
|
|
$
|
23
|
|
Change
in
prices
|
|
|
19
|
|
|
|
|
42
|
|
Wholesale:
|
|
|
|
|
Effect
of
35.9% decrease in KWH sales
|
|
|
(62
|
)
|
Change
in
prices
|
|
|
(8
|
)
|
|
|
|
(70
|
)
|
Net
Decrease
in Non-Affiliated Generation Sales
|
|
$
|
(28
|
)
|
|
|
|
|
|
|
|
|
Source
of Change in Affiliated Generation Sales
|
|
Increase
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect
of 4.9%
increase in KWH sales
|
|
$
|
22
|
|
Change
in
prices
|
|
|
55
|
|
|
|
|
77
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect
of
10.0% increase in KWH sales
|
|
|
16
|
|
Change
in
prices
|
|
|
10
|
|
|
|
|
26
|
|
Net
Increase
in Affiliated Generation Sales
|
|
$
|
103
|
|
Expenses
-
Total
operating
expenses were $51 million lower in the first quarter of 2007 due to the
following factors:
|
|
Increase
|
|
Source
of Change in Fuel and Purchased Power
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Fuel:
|
|
|
|
|
Change
due to
decreased composite unit costs
|
|
$
|
(11
|
)
|
Change
due to
volume consumed
|
|
|
(9
|
)
|
|
|
|
(20
|
)
|
Purchased
Power:
|
|
|
|
|
Change
due to
decreased unit costs
|
|
|
(30
|
)
|
Change
due to
volume purchased
|
|
|
29
|
|
|
|
|
(1
|
)
|
Net
Decrease
in Fuel and Purchased Power Costs
|
|
$
|
(21
|
)
|
|
·
|
Fuel
costs
were $20 million lower primarily due to reduced coal costs ($19 million)
and lower emission allowance costs ($6 million) reflecting decreased
fossil KWH production, partially offset by a $7 million increase
in
nuclear fuel costs resulting from higher nuclear KWH
production;
|
|
·
|
Purchased
power costs decreased by $1 million due primarily to lower unit costs
for
power in MISO and lower KWH purchases in PJM, partially offset by
higher
unit prices in PJM; and
|
|
·
|
Other
operating expenses were $37 million lower in 2007 primarily due to
the
absence of contractor service costs related to the 2006 refueling
outages
at Beaver Valley Unit 1 and Davis-Besse with no refueling outages
in the
first quarter of 2007.
|
Partially
offsetting
the lower costs were the following:
|
·
|
Higher
fossil
plant operating costs principally due to planned maintenance outages
at
Sammis Units 6 and 7 and Eastlake Unit 5;
and
|
|
·
|
Increased
depreciation expense of $5 million resulting principally from fossil
and nuclear property additions since the first quarter of
2006.
|
Other
Income -
Investment
income in
the first quarter of 2007 was $17 million lower than the 2006 period
primarily due to decreased earnings on nuclear decommissioning trust
investments.
Other
-
First Quarter 2007 Compared to First Quarter 2006
FirstEnergy’s
financial results from other operating segments and reconciling items, including
interest expense on holding company debt and corporate support services revenues
and expenses, resulted in a $20 million decrease in FirstEnergy’s net
income in the first quarter of 2007 compared to the same quarter of 2006. The
decrease was due to higher short-term disability costs ($8 million), the absence
of $2 million included in 2006 results from discontinued operations (see
Note 3) and a $3 million gain in 2006 related to interest rate swap
financing arrangements. In addition, there was a $3 million decrease in life
insurance investment income and increased interest expense in 2007 compared
to
2006 due to higher revolving credit facility borrowings and a new
$250 million bridge loan in March 2007.
CAPITAL
RESOURCES AND LIQUIDITY
FirstEnergy’s
business is capital intensive and requires considerable capital resources to
fund operating expenses, construction expenditures, scheduled debt maturities
and interest and dividend payments. In 2007 and subsequent years, FirstEnergy
expects to meet its contractual obligations and other cash 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 also has access
to
$2.75 billion of short-term financing under a revolving credit facility
which expires in 2011, subject to short-term debt limitations under current
regulatory approvals of $1.5 billion and to outstanding borrowings by its
subsidiaries that are also parties to such facility. In the first quarter of
2007, FirstEnergy received $160 million of cash dividends and return of
capital contributions from its subsidiaries and paid $159 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. FirstEnergy acquired
these
shares under its previously announced authorization to repurchase up to 16
million shares of its common stock. Under a prior authorized program,
FirstEnergy repurchased approximately 10.6 million of its outstanding
common stock on August 10, 2006, under an accelerated share repurchase
agreement, dated August 9, 2006. The latest share repurchase was funded with
short-term borrowings, including $500 million from bridge loan
facilities.
As
of March 31,
2007, FirstEnergy had $89 million of cash and cash equivalents compared
with $90 million as of December 31, 2006. The major sources of changes
in these balances are summarized below.
Cash
Flows
From Operating Activities
FirstEnergy's
consolidated net cash from operating activities is provided primarily by its
energy delivery and competitive energy businesses (see Results of Operations
above). Net cash used for operating activities was $75 million in the first
quarter of 2007 compared to $324 million provided from operating activities
in the first quarter of 2006, as summarized in the following table:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
290
|
|
$
|
221
|
|
Non-cash
charges
|
|
|
125
|
|
|
165
|
|
Pension
trust
contribution
|
|
|
(300
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(190
|
)
|
|
(62
|
)
|
Net
cash
provided from (used for) operating activities
|
|
$
|
(75
|
)
|
$
|
324
|
|
Net
cash provided
from operating activities decreased by $399 million in the first quarter of
2007 compared to the first quarter of 2006 primarily due to a $300 million
pension trust contribution in 2007 and $168 million from decreases in
working capital and non-cash charges, partially offset by a $69 million
increase in net income described under “Results of Operations.” The decrease
from working capital and other changes primarily resulted from a
$381 million decrease in cash provided from the collection of receivables,
partially offset by increased cash collateral of $112 million returned from
suppliers and $66 million from income tax refunds received during the 2007
period.
Cash
Flows
From Financing Activities
In
the first quarter
of 2007, net cash provided from financing activities was $346 million
compared to $50 million used for financing activities in the first quarter
of 2006. The change was primarily due to a long-term debt issuance in 2007
and
higher short-term borrowings, partially offset by the repurchase of common
stock
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Securities
Issued or Redeemed
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
New
Issues:
|
|
|
|
|
|
|
|
Unsecured
notes
|
|
$
|
250
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
Redemptions:
|
|
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
-
|
|
$
|
54
|
|
Senior
secured
notes
|
|
|
13
|
|
|
10
|
|
Common
stock
|
|
|
891
|
|
|
-
|
|
Preferred
stock
|
|
|
-
|
|
|
30
|
|
|
|
$
|
904
|
|
$
|
94
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
1,139
|
|
$
|
200
|
|
FirstEnergy
had
approximately $2.2 billion of short-term indebtedness as of March 31, 2007
compared to approximately $1.1 billion as of December 31, 2006. The
increase was primarily due to the voluntary pension fund contribution and the
common share repurchase program in the first quarter of 2007. Available bank
borrowing capability as of March 31, 2007 included the
following:
Borrowing
Capability (In millions)
|
|
|
|
Short-term
credit facilities(1)
|
|
$
|
3,370
|
|
Accounts
receivable financing facilities
|
|
|
550
|
|
Utilized
|
|
|
(2,244
|
)
|
LOCs
|
|
|
(473
|
)
|
Net
|
|
$
|
1,203
|
|
|
|
|
|
|
(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 two $250 million bridge
loan
facilities.
|
As
of March 31,
2007, the Ohio Companies and Penn had the aggregate capability to issue
approximately $2.8 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 $600 million,
$517 million and $130 million, respectively, as of March 31,
2007. Under the provisions of its senior note indenture, JCP&L may issue
additional FMB only as collateral for senior notes. As of March 31, 2007,
JCP&L had the capability to issue $937 million of additional senior
notes upon the basis of FMB collateral.
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 March 31,
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
March 31, 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.
On
August 24, 2006,
FirstEnergy and certain of its subsidiaries entered into a $2.75 billion
five-year revolving credit facility (included in the borrowing capability table
above), which replaced FirstEnergy’s prior $2 billion credit facility.
FirstEnergy may request an increase in the total commitments available under
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
|
|
Borrower
|
|
Sub-Limit
|
|
Debt
Limitations(1)
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
|
$
|
2,750
|
|
|
$
|
1,500
|
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
39
|
|
CEI
|
|
|
250
|
(2)
|
|
500
|
|
TE
|
|
|
250
|
(2)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
412
|
|
Met-Ed
|
|
|
250
|
|
|
250
|
(3)
|
Penelec
|
|
|
250
|
|
|
250
|
(3)
|
FES
|
|
|
250
|
|
|
n/a
|
|
ATSI
|
|
|
-
|
(4)
|
|
50
|
|
|
(1)
|
As
of
March 31, 2007.
|
|
(2)
|
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.
|
|
(3)
|
Excluding
amounts which may be borrowed under the regulated money
pool.
|
|
(4)
|
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 ($229 million unused as of
March 31, 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 March 31, 2007, FirstEnergy and its
subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy
|
|
61
|
%
|
OE
|
|
49
|
%
|
Penn
|
|
28
|
%
|
CEI
|
|
57
|
%
|
TE
|
|
49
|
%
|
JCP&L
|
|
25
|
%
|
Met-Ed
|
|
46
|
%
|
Penelec
|
|
36
|
%
|
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 quarter of 2007 was approximately 5.61% for
both the regulated and the unregulated companies' money pools.
FirstEnergy’s
access
to debt capital markets and costs of financing are impacted by its credit
ratings. The following table displays FirstEnergy’s and the Companies’
securities ratings as of March 31, 2007. The ratings outlook from S&P
on all securities is Stable. The ratings outlook from Moody’s on all securities
is Positive. The ratings outlook from Fitch is Positive for CEI and TE and
Stable for all other companies.
Issuer
|
|
Securities
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB
|
|
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
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
|
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 in proceeds to repurchase shares of its
common stock from FirstEnergy.
On
March 2, 2007,
FirstEnergy and FES entered into substantially similar $250 million bridge
loan facilities with Morgan Stanley Senior Funding, Inc., proceeds of which
were
used to fund the March 2, 2007 accelerated share repurchase. FirstEnergy
provided a guaranty of FES' loan obligations until such time that FES’ senior
unsecured debt was rated at least BBB- by S&P or Baa3 by Moody's. On March
26, 2007, S&P assigned FES a corporate credit rating of BBB. On March 27,
2007, Moody's assigned FES an issuer rating of Baa2. Accordingly, FirstEnergy
currently has no liability under the guaranty.
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 $62.63 per share, or
a
total price of approximately $900 million. This new program supplements the
prior repurchase program dated August 10, 2006. Under the prior program,
approximately 10.6 million shares were repurchased at an initial purchase price
of $600 million, or $56.44 per share. A final purchase price adjustment of
$27 million related to the August 2006 agreement was paid in cash by
FirstEnergy on April 2, 2007.
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.
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
first quarter of 2007 and 2006 by segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
Three
Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
Energy
delivery services
|
|
$
|
(155
|
)
|
$
|
53
|
|
$
|
9
|
|
$
|
(93
|
)
|
Competitive
energy services
|
|
|
(124
|
)
|
|
(4
|
)
|
|
1
|
|
|
(127
|
)
|
Other
|
|
|
(17
|
)
|
|
(16
|
)
|
|
(4
|
)
|
|
(37
|
)
|
Inter-Segment
reconciling items
|
|
|
-
|
|
|
(15
|
)
|
|
-
|
|
|
(15
|
)
|
Total
|
|
$
|
(296
|
)
|
$
|
18
|
|
$
|
6
|
|
$
|
(272
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
delivery services
|
|
$
|
(193
|
)
|
$
|
136
|
|
$
|
(7
|
)
|
$
|
(64
|
)
|
Competitive
energy services
|
|
|
(244
|
)
|
|
(20
|
)
|
|
(1
|
)
|
|
(265
|
)
|
Other
|
|
|
(10
|
)
|
|
41
|
|
|
(3
|
)
|
|
28
|
|
Inter-Segment
reconciling items
|
|
|
-
|
|
|
(9
|
)
|
|
-
|
|
|
(9
|
)
|
Total
|
|
$
|
(447
|
)
|
$
|
148
|
|
$
|
(11
|
)
|
$
|
(310
|
)
|
Net
cash used for
investing activities in the first quarter of 2007 decreased by $38 million
compared to the first quarter of 2006. The decrease was principally due to
a
$151 million decrease in property additions which reflects the replacement
of the steam generators and reactor head at Beaver Valley Unit 1 in 2006.
Partially offsetting the decrease in property additions was a $78 million
decrease in cash investments, primarily from the use of restricted cash
investments to repay debt.
During
the remaining
three quarters of 2007, capital requirements for property additions and capital
leases are expected to be $1.2 billion. FirstEnergy and the Companies have
additional requirements of approximately $231 million for maturing
long-term debt during the remainder of 2007. These cash requirements are
expected to be satisfied from a combination of internal cash, short-term credit
arrangements, and funds raised in the capital markets.
FirstEnergy's
capital spending for the period 2007-2011 is expected to be nearly
$8 billion (excluding nuclear fuel), of which approximately
$1.4 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 $99 million applies to 2007. During the same period,
FirstEnergy's nuclear fuel investments are expected to be reduced by
approximately $810 million and $104 million, respectively, as the
nuclear fuel is consumed.
GUARANTEES
AND OTHER ASSURANCES
As
part of normal
business activities, FirstEnergy enters into various agreements on behalf of
its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds, and LOCs. Some
of
the guaranteed contracts contain collateral provisions that are contingent
upon
FirstEnergy’s credit ratings.
As
of March 31,
2007, FirstEnergy’s maximum exposure to potential future payments under
outstanding guarantees and other assurances totaled approximately
$4.3 billion, as summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
Exposure
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees of Subsidiaries
|
|
|
|
Energy
and
Energy-Related Contracts (1)
|
|
$
|
910
|
|
LOC
(2)
|
|
|
994
|
|
Other
(3)
|
|
|
592
|
|
|
|
|
2,496
|
|
Surety
Bonds
|
|
|
106
|
|
LOC
(4)(5)
|
|
|
1,737
|
|
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
$
|
4,339
|
|
|
(1)
|
Issued
for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
LOC’s
issued
by FGCO and NGC in support of pollution control
revenue
bonds
with various maturities.
|
|
(3)
|
Includes
guarantees of $300 million for OVEC obligations and
$80 million
for nuclear decommissioning funding
assurances.
|
|
(4)
|
Includes
$470 million issued for various terms under LOC capacity
available
in
FirstEnergy’s revolving credit agreement and an additional
$648 million
outstanding in support of pollution control revenue bonds
issued
with
various maturities.
|
|
(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 March 31,
2007, FirstEnergy’s maximum exposure under these collateral provisions was
$392 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
March 31, 2007), which is renewable and declines yearly based upon the
senior outstanding debt of TEBSA.
OFF-BALANCE
SHEET ARRANGEMENTS
FirstEnergy
has
obligations that are not included on its Consolidated Balance Sheets related
to
the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley
Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating
lease payments. As of March 31, 2007, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total
$1.2 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 first quarter of 2007 is summarized in the
following table:
Increase
(Decrease) in the Fair Value of Commodity Derivative
Contracts
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Change
in the Fair Value of Commodity Derivative
Contracts:
|
|
|
|
|
|
|
|
Outstanding
net liability as of January 1, 2007
|
|
$
|
(1,140
|
)
|
$
|
(17
|
)
|
$
|
(1,157
|
)
|
Additions/change
in value of existing contracts
|
|
|
16
|
|
|
6
|
|
|
22
|
|
Settled
contracts
|
|
|
96
|
|
|
12
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net liability as of March 31, 2007(1)
|
|
$
|
(1,028
|
)
|
$
|
1
|
|
$
|
(1,027
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Assets as of March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
Interest
Rate
Swaps(2)
|
|
|
-
|
|
|
(26
|
)
|
|
(26
|
)
|
Net
Liabilities - Derivatives Contracts as of March 31,
2007
|
|
$
|
(1,028
|
)
|
$
|
(25
|
)
|
$
|
(1,053
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of First Quarter Changes in Commodity Derivative
Contracts:(3)
|
|
|
|
|
|
|
|
|
|
|
Income
Statement Effects (Pre-Tax)
|
|
$
|
2
|
|
$
|
-
|
|
$
|
2
|
|
Balance
Sheet
Effects:
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income (Pre-Tax)
|
|
$
|
-
|
|
$
|
18
|
|
$
|
18
|
|
Regulatory
Asset (net)
|
|
$
|
(110
|
)
|
$
|
-
|
|
$
|
(110
|
)
|
(1) Includes
$1.026 billion in non-hedge commodity derivative contracts (primarily with
NUGs), which are offset by a regulatory asset.
(2) Interest
rate swaps
are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements
below).
(3) Represents
the
change in value of existing contracts, settled contracts and changes in
techniques/assumptions.
Derivatives
are
included on the Consolidated Balance Sheet as of March 31, 2007 as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Current-
|
|
|
|
|
|
|
|
Other
assets
|
|
$
|
-
|
|
$
|
35
|
|
$
|
35
|
|
Other
liabilities
|
|
|
(2
|
)
|
|
(34
|
)
|
|
(36
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred
charges
|
|
|
37
|
|
|
20
|
|
|
57
|
|
Other
non-current liabilities
|
|
|
(1,063
|
)
|
|
(46
|
)
|
|
(1,109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
liabilities
|
|
$
|
(1,028
|
)
|
$
|
(25
|
)
|
$
|
(1,053
|
)
|
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 March 31, 2007 are summarized by year in the following
table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Fair
Value by Contract Year
|
|
2007(1)
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Prices
actively quoted(2)
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Other
external
sources(3)
|
|
|
(198
|
)
|
|
(257
|
)
|
|
(202
|
)
|
|
(168
|
)
|
|
-
|
|
|
-
|
|
|
(825
|
)
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(101
|
)
|
|
(101
|
)
|
|
(202
|
)
|
Total(4)
|
|
$
|
(198
|
)
|
$
|
(257
|
)
|
$
|
(202
|
)
|
$
|
(168
|
)
|
$
|
(101
|
)
|
$
|
(101
|
)
|
$
|
(1,027
|
)
|
(1) For
the last three
quarters of 2007.
(2) Exchange
traded.
(3) Broker
quote
sheets.
|
(4)
|
Includes
$1.026 billion in non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
FirstEnergy
performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of March 31, 2007. Based on derivative contracts held as of
March 31, 2007, an adverse 10% change in commodity prices would decrease
net income by approximately $2 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. As of March 31, 2007, the debt underlying the
$750 million outstanding notional amount of interest rate swaps had a
weighted average fixed interest rate of 5.74%, which the swaps have converted
to
a current weighted average variable rate of 6.40%.
|
|
March
31, 2007
|
|
December
31, 2006
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Interest
Rate Swaps
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
Fair
value
hedges
|
|
$
|
100
|
|
|
2008
|
|
$
|
(2
|
)
|
$
|
100
|
|
|
2008
|
|
$
|
(2)
|
|
|
|
|
50
|
|
|
2010
|
|
|
-
|
|
|
50
|
|
|
2010
|
|
|
(1)
|
|
|
|
|
300
|
|
|
2013
|
|
|
(5
|
)
|
|
300
|
|
|
2013
|
|
|
(6)
|
|
|
|
|
150
|
|
|
2015
|
|
|
(10
|
)
|
|
150
|
|
|
2015
|
|
|
(10)
|
|
|
|
|
50
|
|
|
2025
|
|
|
(1
|
)
|
|
50
|
|
|
2025
|
|
|
(2)
|
|
|
|
|
100
|
|
|
2031
|
|
|
(6
|
)
|
|
100
|
|
|
2031
|
|
|
(6)
|
|
|
|
$
|
750
|
|
|
|
|
$
|
(24
|
)
|
$
|
750
|
|
|
|
|
$
|
(27)
|
|
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
quarter of 2007, FirstEnergy terminated forward swaps with an aggregate notional
value of $250 million. FirstEnergy paid $3 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
March 31, 2007, FirstEnergy had outstanding forward swaps with an aggregate
notional amount of $475 million and an aggregate fair value of
$(2) million.
|
|
March
31, 2007
|
|
December
31, 2006
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Forward
Starting Swaps
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
Cash
flow
hedges
|
|
$
|
25
|
|
|
2015
|
|
$
|
-
|
|
$
|
25
|
|
|
2015
|
|
$
|
-
|
|
|
|
|
375
|
|
|
2017
|
|
|
(2
|
)
|
|
200
|
|
|
2017
|
|
|
(4
|
)
|
|
|
|
25
|
|
|
2018
|
|
|
(1
|
)
|
|
25
|
|
|
2018
|
|
|
(1
|
)
|
|
|
|
50
|
|
|
2020
|
|
|
1
|
|
|
50
|
|
|
2020
|
|
|
1
|
|
|
|
$
|
475
|
|
|
|
|
$
|
(2
|
)
|
$
|
300
|
|
|
|
|
$
|
(4
|
)
|
Equity
Price
Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their market
value of approximately $1.3 billion as of March 31, 2007 and
December 31, 2006. A hypothetical 10% decrease in prices quoted by stock
exchanges would result in a $128 million reduction in fair value as of
March 31, 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 March 31, 2007, the largest credit concentration with one
party (currently rated investment grade) represented 11.6% of FirstEnergy‘s
total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of
credit exposures, net of collateral and reserves, were with investment-grade
counterparties as of March 31, 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 $213 million as of March 31, 2007. The following table
discloses regulatory assets by company:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
729
|
|
$
|
741
|
|
$
|
(12
|
)
|
CEI
|
|
|
854
|
|
|
855
|
|
|
(1
|
)
|
TE
|
|
|
237
|
|
|
248
|
|
|
(11
|
)
|
JCP&L
|
|
|
2,059
|
|
|
2,152
|
|
|
(93
|
)
|
Met-Ed
|
|
|
455
|
|
|
409
|
|
|
46
|
|
ATSI
|
|
|
37
|
|
|
36
|
|
|
1
|
|
Total
|
|
$
|
4,371
|
|
$
|
4,441
|
|
$
|
(70
|
)
|
*
|
Penelec
had
net regulatory liabilities of approximately $70 million
and
$96 million as of March 31, 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:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
3,040
|
|
$
|
3,266
|
|
$
|
(226
|
)
|
Customer
shopping incentives
|
|
|
583
|
|
|
603
|
|
|
(20
|
)
|
Customer
receivables for future income taxes
|
|
|
270
|
|
|
217
|
|
|
53
|
|
Societal
benefits charge
|
|
|
4
|
|
|
11
|
|
|
(7
|
)
|
Loss
on
reacquired debt
|
|
|
42
|
|
|
43
|
|
|
(1
|
)
|
Employee
postretirement benefits
|
|
|
45
|
|
|
47
|
|
|
(2
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and
spent fuel
disposal costs
|
|
|
(108
|
)
|
|
(145
|
)
|
|
37
|
|
Asset
removal
costs
|
|
|
(169
|
)
|
|
(168
|
)
|
|
(1
|
)
|
Property
losses and unrecovered plant costs
|
|
|
16
|
|
|
19
|
|
|
(3
|
)
|
MISO/PJM
transmission costs
|
|
|
238
|
|
|
213
|
|
|
25
|
|
Fuel
costs -
RCP
|
|
|
127
|
|
|
113
|
|
|
14
|
|
Distribution
costs - RCP
|
|
|
202
|
|
|
155
|
|
|
47
|
|
Other
|
|
|
81
|
|
|
67
|
|
|
14
|
|
Total
|
|
$
|
4,371
|
|
$
|
4,441
|
|
$
|
(70
|
)
|
Reliability
Initiatives
FirstEnergy
is
proceeding with the implementation of the recommendations that were issued
from
various entities, including governmental, industry and ad hoc reliability
entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force)
in late 2003 and early 2004, regarding enhancements to regional reliability
that
were to be completed subsequent to 2004. FirstEnergy will continue to
periodically assess the FERC-ordered Reliability Study recommendations for
forecasted 2009 system conditions, recognizing revised load forecasts and other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new, or material upgrades to existing,
equipment. The FERC or other applicable government agencies and reliability
entities, however, may take a different view as to recommended enhancements
or
may recommend additional enhancements in the future that could require
additional, material expenditures.
As
a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU
adopted an MOU that set out specific tasks related to service reliability to
be
performed by JCP&L and a timetable for completion and endorsed JCP&L’s
ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a
Stipulation that incorporates the final report of an SRM who made
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The Stipulation also incorporates the Executive Summary and
Recommendation portions of the final report of a focused audit of JCP&L’s
Planning and Operations and Maintenance programs and practices (Focused Audit).
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
NERC has been
preparing the implementation aspects of reorganizing its structure to meet
the
FERC’s certification requirements for the ERO. The NERC made a filing with the
FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC
approval of pro forma delegation agreements with regional reliability
organizations (regional entities). A rule adopted by the FERC in 2006 provides
for reorganizing regional entities that would replace the current regional
councils and for rearranging their relationship with the ERO. The “regional
entity” may be delegated authority by the ERO, subject to FERC approval, for
compliance and enforcement of reliability standards adopted by the ERO and
approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments
and reply comments were filed in May, June and July 2006. On July 20, 2006,
the
FERC certified the NERC as the ERO to implement the provisions of Section 215
of
the Federal Power Act and directed the NERC to make compliance filings
addressing governance and non-governance issues and the regional delegation
agreements. On September 18, 2006 and October 18, 2006, NERC submitted
compliance filings addressing the governance and non-governance issues
identified in the FERC ERO Certification Order, dated July 20, 2006. On October
30, 2006, the FERC issued an order accepting most of NERC’s governance filings.
On January 18, 2007, the FERC issued an order largely accepting NERC’s
compliance filings addressing non-governance issues, subject to an additional
compliance filing, which NERC submitted on March 19, 2007.
On
November 29,
2006, NERC submitted an additional compliance filing with the FERC regarding
the
Compliance Monitoring and Enforcement Program (CMEP) along with the proposed
Delegation Agreements between the ERO and the regional reliability entities.
The
FERC provided opportunity for interested parties to comment on the CMEP by
January 10, 2007. FirstEnergy, as well as other parties, moved to intervene
and
submitted responsive comments on January 10, 2007. This filing, which
established the regulatory framework for NERC’s future enforcement program, was
approved by the FERC on April 19, 2007.
The
ECAR,
Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability
councils completed the consolidation of these regions into a single new regional
reliability organization known as ReliabilityFirst
Corporation.
ReliabilityFirst
began operations as
a regional reliability council under NERC on January 1, 2006 and on
November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain
certification consistent with the final rule as a “regional entity” under the
ERO. This Delegation Agreement was also approved by the FERC on April 19,
2007. All of FirstEnergy’s facilities are located within the
ReliabilityFirst
region.
On
May 2, 2006, the
NERC Board of Trustees adopted eight new cyber security standards that replaced
interim standards put in place in the wake of the September 11, 2001 terrorist
attacks, and thirteen additional reliability standards. The security standards
became effective on June 1, 2006, and the remaining standards become effective
during 2007. NERC filed these proposed standards with the FERC and relevant
Canadian authorities for approval. The cyber security standards were not
included in the October 20, 2006 NOPR and are being addressed in a separate
FERC docket. On December 11, 2006, the FERC Staff provided its preliminary
assessment of these proposed mandatory reliability standards and again cited
various deficiencies in the proposed standards. Numerous parties, including
FirstEnergy, provided comments on the assessment by February 12, 2007. This
filing is pending before the FERC.
On
April 4, 2006,
NERC submitted a filing with the FERC seeking approval of mandatory reliability
standards. On October 20, 2006, the FERC in turn issued a Proposed Rule on
the
reliability standards. After a period of public review of the proposal, the
FERC
issued on March 16, 2007 its Final Rule on Mandatory Reliability Standards
for the Bulk-Power System. In this ruling, the FERC approved 83 of the 107
mandatory electric reliability standards proposed by NERC, making them
enforceable with penalties and sanctions for noncompliance when the rule becomes
effective, which is expected by the summer of 2007. The final rule becomes
effective on June 4, 2007. The FERC also directed NERC to submit
improvements to 56 standards, endorsing NERC's process for developing
reliability standards and its associated work plan. The 24 standards that were
not approved remain pending at the FERC awaiting further information from NERC
and its regional entities.
FirstEnergy
believes
it is in compliance with all current NERC reliability standards. However, based
upon a review of the March 16, 2007 Final Rule, it appears that the FERC will
eventually adopt stricter NERC reliability standards than those just approved
as
NERC addresses the FERC's guidance in the Final Rule. 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.
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. 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
|
|
Period
|
|
OE
|
|
CEI
|
|
TE
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
$
|
179
|
|
$
|
108
|
|
$
|
93
|
|
$
|
380
|
|
2008
|
|
|
208
|
|
|
124
|
|
|
119
|
|
|
451
|
|
2009
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
216
|
|
2010
|
|
|
-
|
|
|
273
|
|
|
-
|
|
|
273
|
|
Total
Amortization
|
|
$
|
387
|
|
$
|
721
|
|
$
|
212
|
|
$
|
1,320
|
|
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 will automatically become
effective on July 1, 2007. The revised riders represent an increase over the
amounts collected through the 2006 riders of approximately $64 million annually.
During
the period
between May 1, 2007 and June 1, 2007, any party may raise issues related to
the
revised tariffs through an informal resolution process. If not adequately
resolved through this process by June 30, 2007, any interested party may file
a
formal complaint with the PUCO which will be addressed by the PUCO after all
parties have been heard. If at the conclusion of either the informal or formal
process, adjustments are found to be necessary, such adjustments (with carrying
costs) will be included in the Ohio Companies’ next rider filing which must be
filed no later than May 1, 2008. No assurance can be given that such formal
or
informal proceedings will not be instituted.
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 intend to file the application
and rate request with the PUCO on or after June 7, 2007. The requested $334
million 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. The new rates, subject to evidentiary
hearings at the PUCO, would become effective January 1, 2009 for OE and TE,
and
May 2009 for CEI.
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 allows Met-Ed and Penelec to sell the output of NUG
generation 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 have also 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.
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 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 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. If Met-Ed
and
Penelec do not prevail on the issue of congestion, it could have a material
adverse effect on FirstEnergy’s and their financial condition and results of
operations.
As
of March 31,
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 $472 million and $124 million, respectively.
Penelec’s $124 million 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
may file exceptions to the initial decision by May 22, 2007 and parties may
reply to those exceptions 10 days thereafter. 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 Energy Independence Strategy (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 through a "Least Cost Portfolio", the
utilization of micro-grids and an optional three year phase-in of rate
increases. Since the EIS has only recently been proposed, the final form of
any
legislation 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 March 31, 2007, the accumulated deferred
cost balance totaled approximately $357 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 and 2) renewables have completed their assigned
tasks of data gathering and analysis. Both groups have provided a report to
the
EMP Committee. The working groups addressing reliability and pricing issues
continue their data gathering and analysis activities. Public stakeholder
meetings were held in the fall of 2006 and in early 2007, and further public
meetings are expected in the summer of 2007. A final draft of the EMP is
expected to be presented to the Governor in the fall of 2007 with further public
hearings anticipated in early 2008. 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 issued a draft proposal relating to changes to the
regulations addressing electric distribution service reliability and quality
standards. A meeting between the NJBPU Staff and interested stakeholders to
discuss the proposal was held on February 15, 2007. On February 22, 2007, the
NJBPU Staff circulated a revised proposal upon which discussions with interested
stakeholders were held on March 26, 2007. On April 18 and April 23, 2007 the
NJBPU staff circulated further revised draft proposals. A schedule for formal
proceedings has not yet been established. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, ultimate
regulations resulting from these draft proposals 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 second 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. On May 31, 2005, the FERC issued an order on these
cases. First, it set for hearing the existing rate design and indicated that
it
will issue a final order within six months. American Electric Power Company,
Inc. filed in opposition proposing to create a "postage stamp" rate for high
voltage transmission facilities across PJM. Second, the FERC approved the
proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
formula rate, subject to refund and hearing procedures. On June 30, 2005, the
settling PJM transmission owners filed a request for rehearing of the May 31,
2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
rate proceeding that generally accepts the companies' formula rate proposal.
The
FERC issued an order approving this settlement on April 19, 2006. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the 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. On April 19,
2007, the FERC issued an order rejecting the ALJ’s findings and recommendations
in nearly every respect. 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, 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, 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.
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 JCPL, Met-Ed, and Penelec zones.
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. MISO is targeting implementation for
the second or third 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 has requested FERC action on its filing by
June, 2007.
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 will become effective on
May 14, 2007. The final rule has not yet been fully evaluated to assess its
impact on First Energy’s operations. MISO, PJM and ATSI will all have to file
revised tariffs to comply with FERC’s order.
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.
FirstEnergy
complies
with SO2
reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX
reductions required
by the 1990 Amendments are being achieved through combustion controls and the
generation of more electricity at lower-emitting plants. In September 1998,
the
EPA finalized regulations requiring additional NOX
reductions at
FirstEnergy's facilities. The EPA's NOX
Transport Rule
imposes uniform reductions of NOX
emissions (an
approximate 85% reduction in utility plant NOX
emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX
emissions are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX
budgets established
under SIPs through combustion controls and post-combustion controls, including
Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems,
and/or using emission allowances.
National
Ambient
Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and fine particulate matter.
In
March 2005, the EPA finalized the CAIR covering a total of 28 states
(including Michigan, New Jersey, Ohio and Pennsylvania) and the District of
Columbia based on proposed findings that air emissions from 28 eastern states
and the District of Columbia significantly contribute to non-attainment of
the
NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR
provided 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 Mansfield, FirstEnergy’s
only 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.
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 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 New Source Review 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 W.
H. Sammis Plant and other FES 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 are currently estimated to be $1.5 billion ($400 million of which
is
expected to be spent during 2007, with the largest portion of the remaining
$1.1
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.
On
August 26, 2005,
FGCO entered into an agreement with Bechtel Power Corporation under which
Bechtel will engineer, procure, and construct air quality control systems for
the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement with
B&W.
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.
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. FirstEnergy is conducting
comprehensive demonstration studies, due in 2008, to determine the operational
measures or equipment, if any, necessary for compliance by its facilities with
the performance standards. FirstEnergy is unable to predict the outcome of
such
studies or changes in these requirements from the remand to EPA. Depending
on
the outcome of such studies and EPA’s further rulemaking, 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 March 31, 2007, FirstEnergy had
approximately $1.4 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
March 31, 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 $87 million have been accrued through March 31, 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, New
Jersey. In 2005, JCP&L renewed its motion to decertify the class based on a
very limited number of class members who incurred damages and also filed a
motion for summary judgment on the remaining plaintiffs’ claims for negligence,
breach of contract and punitive damages. In July 2006, the New Jersey Superior
Court dismissed the punitive damage claim and again decertified the class based
on the fact that a vast majority of the class members did not suffer damages
and
those that did would be more appropriately addressed in individual actions.
Plaintiffs appealed this ruling to the New Jersey Appellate Division 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. In late March 2007,
JCP&L filed a petition for allowance of an appeal of the Appellate Division
ruling to the New Jersey Supreme Court. FirstEnergy is unable to predict the
outcome of these matters and no liability has been accrued as of March 31,
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. It is unknown whether or not
the matter will be further appealed. 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 will continue
and that the plant must improve performance to be removed from the
Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments that
FENOC had made to improve the performance at the Perry Nuclear Power Plant
and
stated that the CAL would remain open until substantial improvement was
demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight
Process. By two letters dated March 2, 2007, the NRC closed the Confirmatory
Action Letter 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 (routine agency oversight).
On
April 30, 2007,
the Union of Concerned Scientists (UCS) filed a petition with the NRC under
Section 2.206 of the NRC’s regulations based on an expert witness report that
FENOC developed for an unrelated insurance arbitration. In December 2006,
the
expert witness for FENOC prepared 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) that Davis-Besse’s operating
license be revoked.
In
a letter dated
May 4, 2007, the NRC stated that "the current inspection requirements are
sufficient to detect degradation of a reactor pressure vessel head penetration
nozzles prior to the development of significant head wastage even if the
assumptions and conclusions in the [expert witness] report relating to the
wastage of the head at Davis-Besse were applied to all pressurized water
reactors." The NRC also indicated that while they are developing a more complete
response to the UCS' petition, “the staff informed UCS that, as an initial
matter, it has determined that no immediate action with respect to Davis-Besse
or other nuclear plant is warranted.” 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. The Court has scheduled oral argument for
June 25, 2007 to hear the plaintiffs' request for reconsideration of its order
denying class certification and request to amend their complaint.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. 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.
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. The Standard 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
06-10 -
“Accounting for Deferred Compensation and Postretirement Benefit Aspects of
Collateral
Split-Dollar
Life Insurance Arrangements”
In
March 2007, the
EITF reached a final consensus on Issue 06-10 concluding that an employer should
recognize a liability for the postretirement obligation associated with a
collateral assignment split-dollar life insurance arrangement if, based on
the
substantive arrangement with the employee, the employer has agreed to maintain
a
life insurance policy during the employee’s retirement or provide the employee
with a death benefit. The liability should be recognized in accordance with
SFAS
106 if,
in substance, a
postretirement plan exists or APB 12 if the arrangement is, in substance, an
individual deferred compensation contract. The EITF also reached a consensus
that the employer should recognize and measure the associated asset on the
basis
of the terms of the collateral assignment arrangement. This pronouncement is
effective for fiscal years beginning after December 15, 2007, including interim
periods within those years. FirstEnergy does not expect this pronouncement
to
have a material impact on its financial statements.
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE
INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
|
|
2006
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$
|
594,344
|
|
|
$
|
557,229
|
|
Excise
tax
collections
|
|
|
31,254
|
|
|
|
28,974
|
|
Total
revenues
|
|
|
625,598
|
|
|
|
586,203
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
3,015
|
|
|
|
2,951
|
|
Purchased
power
|
|
|
349,852
|
|
|
|
283,020
|
|
Nuclear
operating costs
|
|
|
41,514
|
|
|
|
41,084
|
|
Other
operating costs
|
|
|
88,486
|
|
|
|
90,810
|
|
Provision
for
depreciation
|
|
|
18,848
|
|
|
|
18,016
|
|
Amortization
of regulatory assets
|
|
|
45,417
|
|
|
|
53,861
|
|
Deferral
of
new regulatory assets
|
|
|
(36,649
|
)
|
|
|
(36,240
|
)
|
General
taxes
|
|
|
49,745
|
|
|
|
45,895
|
|
Total
expenses
|
|
|
560,228
|
|
|
|
499,397
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
65,370
|
|
|
|
86,806
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
26,630
|
|
|
|
33,042
|
|
Miscellaneous
income
|
|
|
373
|
|
|
|
197
|
|
Interest
expense
|
|
|
(21,022
|
)
|
|
|
(18,232
|
)
|
Capitalized
interest
|
|
|
110
|
|
|
|
491
|
|
Subsidiary's
preferred stock dividend requirements
|
|
|
-
|
|
|
|
(156
|
)
|
Total
other
income
|
|
|
6,091
|
|
|
|
15,342
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
71,461
|
|
|
|
102,148
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
17,426
|
|
|
|
38,318
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
54,035
|
|
|
|
63,830
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
|
659
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
54,035
|
|
|
$
|
63,171
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
54,035
|
|
|
$
|
63,830
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(3,423
|
)
|
|
|
-
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
(126
|
)
|
|
|
5,735
|
|
Other
comprehensive income (loss)
|
|
|
(3,549
|
)
|
|
|
5,735
|
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
|
(1,503
|
)
|
|
|
2,069
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(2,046
|
)
|
|
|
3,666
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
51,989
|
|
|
$
|
67,496
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Ohio Edison
Company are an integral part of
these
statements.
|
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
694
|
|
$
|
712
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $15,242,000 and $15,033,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
266,347
|
|
|
234,781
|
|
Associated
companies
|
|
|
207,377
|
|
|
141,084
|
|
Other
(less
accumulated provisions of $5,409,000 and $1,985,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
18,106
|
|
|
13,496
|
|
Notes
receivable from associated companies
|
|
|
527,232
|
|
|
458,647
|
|
Prepayments
and other
|
|
|
23,657
|
|
|
13,606
|
|
|
|
|
1,043,413
|
|
|
862,326
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
2,649,190
|
|
|
2,632,207
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,029,438
|
|
|
1,021,918
|
|
|
|
|
1,619,752
|
|
|
1,610,289
|
|
Construction
work in progress
|
|
|
44,405
|
|
|
42,016
|
|
|
|
|
1,664,157
|
|
|
1,652,305
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
639,658
|
|
|
1,219,325
|
|
Investment
in
lease obligation bonds
|
|
|
291,225
|
|
|
291,393
|
|
Nuclear
plant
decommissioning trusts
|
|
|
118,636
|
|
|
118,209
|
|
Other
|
|
|
37,418
|
|
|
38,160
|
|
|
|
|
1,086,937
|
|
|
1,667,087
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
729,500
|
|
|
741,564
|
|
Pension
assets
|
|
|
94,682
|
|
|
68,420
|
|
Property
taxes
|
|
|
60,080
|
|
|
60,080
|
|
Unamortized
sale and leaseback costs
|
|
|
48,885
|
|
|
50,136
|
|
Other
|
|
|
55,011
|
|
|
18,696
|
|
|
|
|
988,158
|
|
|
938,896
|
|
|
|
$
|
4,782,665
|
|
$
|
5,120,614
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
161,424
|
|
$
|
159,852
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
16,460
|
|
|
113,987
|
|
Other
|
|
|
178,097
|
|
|
3,097
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
150,368
|
|
|
115,252
|
|
Other
|
|
|
20,047
|
|
|
13,068
|
|
Accrued
taxes
|
|
|
135,793
|
|
|
187,306
|
|
Accrued
interest
|
|
|
17,900
|
|
|
24,712
|
|
Other
|
|
|
93,484
|
|
|
64,519
|
|
|
|
|
773,573
|
|
|
681,793
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares -
|
|
|
|
|
|
|
|
60
and 80
shares outstanding, respectively
|
|
|
1,208,467
|
|
|
1,708,441
|
|
Accumulated
other comprehensive income
|
|
|
1,162
|
|
|
3,208
|
|
Retained
earnings
|
|
|
314,043
|
|
|
260,736
|
|
Total
common
stockholder's equity
|
|
|
1,523,672
|
|
|
1,972,385
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,117,635
|
|
|
1,118,576
|
|
|
|
|
2,641,307
|
|
|
3,090,961
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
712,023
|
|
|
674,288
|
|
Accumulated
deferred investment tax credits
|
|
|
19,640
|
|
|
20,532
|
|
Asset
retirement obligations
|
|
|
89,428
|
|
|
88,223
|
|
Retirement
benefits
|
|
|
165,031
|
|
|
167,379
|
|
Deferred
revenues - electric service programs
|
|
|
77,657
|
|
|
86,710
|
|
Other
|
|
|
304,006
|
|
|
310,728
|
|
|
|
|
1,367,785
|
|
|
1,347,860
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
4,782,665
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
54,035
|
|
$
|
63,830
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
18,848
|
|
|
18,016
|
|
Amortization
of regulatory assets
|
|
|
45,417
|
|
|
53,861
|
|
Deferral
of
new regulatory assets
|
|
|
(36,649
|
)
|
|
(36,240
|
)
|
Amortization
of lease costs
|
|
|
32,934
|
|
|
32,934
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(3,992
|
)
|
|
(3,945
|
)
|
Accrued
compensation and retirement benefits
|
|
|
(16,794
|
)
|
|
(1,494
|
)
|
Pension
trust
contribution
|
|
|
(20,261
|
)
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
(102,469
|
)
|
|
116,271
|
|
Prepayments
and other current assets
|
|
|
(6,339
|
)
|
|
(12,136
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
42,095
|
|
|
9,668
|
|
Accrued
taxes
|
|
|
(46,791
|
)
|
|
27,505
|
|
Accrued
interest
|
|
|
(6,812
|
)
|
|
3,721
|
|
Electric
service prepayment programs
|
|
|
(9,053
|
)
|
|
(7,763
|
)
|
Other
|
|
|
(4,137
|
)
|
|
4,454
|
|
Net
cash
provided from (used for) operating activities
|
|
|
(59,968
|
)
|
|
268,682
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
77,473
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(500,000
|
)
|
|
-
|
|
Long-term
debt
|
|
|
(72
|
)
|
|
(59,506
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
(178,716
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
(35,000
|
)
|
Preferred
stock
|
|
|
-
|
|
|
(659
|
)
|
Net
cash used
for financing activities
|
|
|
(422,599
|
)
|
|
(273,881
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(29,888
|
)
|
|
(28,793
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
12,951
|
|
|
19,054
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(12,951
|
)
|
|
(19,054
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
511,082
|
|
|
(45,224
|
)
|
Cash
investments
|
|
|
168
|
|
|
78,458
|
|
Other
|
|
|
1,187
|
|
|
877
|
|
Net
cash
provided from investing activities
|
|
|
482,549
|
|
|
5,318
|
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
(18
|
)
|
|
119
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
712
|
|
|
929
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
694
|
|
$
|
1,048
|
|
|
|
|
|
|
|
|
|
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 sheets of Ohio Edison Company and its
subsidiaries as of March 31, 2007 and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 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 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
May
8,
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 first quarter of 2007 decreased to $54 million from $63 million
in
the first quarter of 2006. This decrease primarily resulted from higher
purchased power costs and reduced other income, partially offset by higher
revenues.
Revenues
Revenues
increased
by $39 million or 6.7% in the first quarter of 2007 compared with the same
period in 2006, primarily due to higher retail generation revenues of $48
million, partially offset by decreases in revenues from distribution throughput
and wholesale generation sales of $13 million and $3 million,
respectively.
Higher
retail
generation revenues from residential and commercial customers reflected
increased sales volume and the impact of higher average unit prices. Average
prices increased in part due to the higher composite unit prices that were
effective in January 2007 under Penn’s competitive RFP process. Colder weather
in the first quarter of 2007 compared to the same period in 2006 contributed
to
the higher KWH sales to residential and commercial customers (heating
degree days
increased 15.6% and 11.2% in OE’s and Penn’s service territories,
respectively).
Retail generation
revenues from the industrial sector decreased primarily due to a 9.7 percentage
point increase in customer shopping in the first quarter of 2007 as compared
to
the same period in 2006.
Changes
in retail
electric generation KWH sales and revenues
in the
first
quarter of 2007 from the same quarter of 2006 are summarized in the following
tables:
Retail
Generation KWH Sales |
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
12.1
|
%
|
Commercial
|
|
|
2.7
|
%
|
Industrial
|
|
|
(12.9
|
)%
|
Net
Increase in Generation Sales
|
|
|
0.8
|
%
|
Retail
Generation Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
Residential
|
|
$
|
37
|
|
Commercial
|
|
|
16
|
|
Industrial
|
|
|
(5
|
)
|
Net
Increase in Generation
Revenues
|
|
$
|
48
|
|
Decreased
revenues
from distribution throughput to residential and commercial customers reflected
the impact of lower composite unit prices, partially offset by higher KWH
deliveries due to colder weather in the first quarter of 2007 as compared to
the
same period in 2006. Decreased revenues from distribution throughput to
industrial customers resulted from lower unit prices and reduced KWH
deliveries.
Changes
in
distribution KWH deliveries and revenues
in the
first quarter 2007 from the same quarter of 2006 are summarized in the following
tables.
Changes
in Distribution KWH Deliveries
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
9.7
|
%
|
Commercial
|
|
|
4.5
|
%
|
Industrial
|
|
|
(1.5
|
)%
|
Net
Increase in Distribution Deliveries
|
|
|
4.3
|
%
|
Decreases
in Distribution Revenues
|
|
(In
millions)
|
|
|
|
|
|
|
Residential
|
|
$
|
(1
|
) |
Commercial
|
|
|
(4
|
) |
Industrial
|
|
|
(8
|
) |
Decrease
in Distribution Revenues
|
|
$
|
(13
|
) |
Expenses
Total
expenses
increased by $61 million in the first quarter of 2007 from the same period
of
2006. The following table presents changes from the prior year by expense
category.
Expenses
- Changes
|
|
Increase
(Decrease)
|
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
67
|
|
Other
operating costs
|
|
|
(2
|
) |
Provision
for
depreciation
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
(8
|
) |
Deferral
of
new regulatory assets
|
|
|
(1
|
) |
General
taxes
|
|
|
4
|
|
Net
Increase in Expenses
|
|
$
|
61
|
|
|
|
|
|
|
Increased
purchased
power costs in the first quarter of 2007 primarily reflected higher unit prices
associated with Penn’s competitive RFP process and OE’s power supply agreement
with FES. The decrease in other operating costs during the first quarter of
2007
was primarily due to lower employee benefit expenses. Lower amortization of
regulatory assets was due to the completion of the generation-related transition
cost amortization under the OE Companies' respective transition plans by the
end
of January 2006. General taxes were higher in the first quarter 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 $9 million in the first quarter of 2007 compared with the same period
of 2006 primarily due to reductions in interest income on notes receivable
resulting from principal payments received from associated companies. Higher
interest expense in the first quarter of 2007 also contributed to the decrease
in other income 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
first quarter of 2006.
Income
Taxes
In
the first quarter
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 between FirstEnergy and its subsidiaries.
Capital
Resources and Liquidity
During
2007, OE
expects to meet its contractual obligations primarily with cash from operations.
Borrowing capacity under OE’s credit facilities is available to manage its
working capital requirements.
Changes
in Cash
Position
OE
had $694,000 of
cash and cash equivalents as of March 31, 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 quarter of 2007 and 2006
were as follows:
|
|
Three
Months Ended
March
31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
54
|
|
$
|
64
|
|
Non-cash
charges
|
|
|
31
|
|
|
56
|
|
Pension
trust
contribution
|
|
|
(20
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(125
|
)
|
|
149
|
|
Net
cash
provided from (used for) operating activities
|
|
$
|
(60
|
)
|
$
|
269
|
|
Net
cash used for
operating activities was $60 million for the first quarter of 2007 compared
to
$269 million provided from operating activities for the same period of 2006.
The
$329 million change was due to a $10 million decrease in net income, a $25
million decrease in non-cash charges, a $274 million decrease from changes
in
working capital and other, and a $20 million pension trust contribution in
the
first quarter of 2007. 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 $219 million and
accrued taxes of $74 million, partially offset by changes in accounts payable
of
$32 million.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities increased by $149 million in the first quarter of 2007
from
the same period last year. This increase primarily resulted from a $500 million
repurchase of common stock from FirstEnergy, partially offset by a $316 million
decrease in net debt redemptions and the absence in 2007 of a $35 million common
stock dividend to FirstEnergy in the first quarter of 2006.
OE
had approximately
$528 million of cash and temporary cash investments (which include short-term
notes receivable from associated companies) and $195 million of short-term
indebtedness as of March 31, 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 March 31, 2007, and also
has
access to bank facilities and the utility money pool.
On
February 21,
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 $477 million in the first quarter of 2007
from the same period in 2006. The change resulted primarily from a $556 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 remaining
three quarters of 2007, OE’s capital spending is expected to be approximately
$114 million. OE has additional requirements of approximately $4 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 $776 million, of which
approximately $146 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
March 31, 2007, the present value of these operating lease commitments, net
of
trust investments, was $646 million.
Equity
Price Risk
Included
in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $78 million and $80 million
as of
March 31, 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 March 31, 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
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
Electric
sales
|
|
$
|
422,805
|
|
$
|
390,499
|
|
Excise
tax
collections
|
|
|
18,027
|
|
|
17,311
|
|
Total
revenues
|
|
|
440,832
|
|
|
407,810
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Fuel
|
|
|
13,191
|
|
|
13,563
|
|
Purchased
power
|
|
|
180,657
|
|
|
143,770
|
|
Other
operating costs
|
|
|
74,951
|
|
|
72,895
|
|
Provision
for
depreciation
|
|
|
18,468
|
|
|
17,201
|
|
Amortization
of regulatory assets
|
|
|
33,129
|
|
|
31,530
|
|
Deferral
of
new regulatory assets
|
|
|
(33,957
|
)
|
|
(30,526
|
)
|
General
taxes
|
|
|
38,894
|
|
|
35,070
|
|
Total
expenses
|
|
|
325,333
|
|
|
283,503
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
115,499
|
|
|
124,307
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Investment
income
|
|
|
17,687
|
|
|
26,936
|
|
Miscellaneous
income (expense)
|
|
|
731
|
|
|
(246
|
)
|
Interest
expense
|
|
|
(35,740
|
)
|
|
(34,732
|
)
|
Capitalized
interest
|
|
|
205
|
|
|
673
|
|
Total
other
expense
|
|
|
(17,117
|
)
|
|
(7,369
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
98,382
|
|
|
116,938
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
34,833
|
|
|
44,525
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
63,549
|
|
|
72,413
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
1,202
|
|
|
-
|
|
Income
tax
expense related to other comprehensive income
|
|
|
355
|
|
|
-
|
|
Other
comprehensive income, net of tax
|
|
|
847
|
|
|
-
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
64,396
|
|
$
|
72,413
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
775
|
|
$
|
221
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $6,578,000 and $6,783,000,
|
|
|
264,634
|
|
|
245,193
|
|
respectively,
for uncollectible accounts)
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
16,705
|
|
|
249,735
|
|
Other
|
|
|
3,818
|
|
|
14,240
|
|
Notes
receivable from associated companies
|
|
|
259,098
|
|
|
27,191
|
|
Prepayments
and other
|
|
|
1,675
|
|
|
2,314
|
|
|
|
|
546,705
|
|
|
538,894
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
2,140,603
|
|
|
2,136,766
|
|
Less
-
Accumulated provision for depreciation
|
|
|
830,385
|
|
|
819,633
|
|
|
|
|
1,310,218
|
|
|
1,317,133
|
|
Construction
work in progress
|
|
|
63,588
|
|
|
46,385
|
|
|
|
|
1,373,806
|
|
|
1,363,518
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
353,293
|
|
|
486,634
|
|
Investment
in
lessor notes
|
|
|
483,996
|
|
|
519,611
|
|
Other
|
|
|
13,418
|
|
|
13,426
|
|
|
|
|
850,707
|
|
|
1,019,671
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521
|
|
|
1,688,521
|
|
Regulatory
assets
|
|
|
853,733
|
|
|
854,588
|
|
Pension
assets
|
|
|
13,456
|
|
|
-
|
|
Property
taxes
|
|
|
65,000
|
|
|
65,000
|
|
Other
|
|
|
65,134
|
|
|
33,306
|
|
|
|
|
2,685,844
|
|
|
2,641,415
|
|
|
|
$
|
5,457,062
|
|
$
|
5,563,498
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
223,676
|
|
$
|
120,569
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
102,201
|
|
|
218,134
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
109,744
|
|
|
365,678
|
|
Other
|
|
|
6,320
|
|
|
7,194
|
|
Accrued
taxes
|
|
|
142,355
|
|
|
128,829
|
|
Accrued
interest
|
|
|
37,155
|
|
|
19,033
|
|
Lease
market
valuation liability
|
|
|
60,200
|
|
|
60,200
|
|
Other
|
|
|
29,883
|
|
|
52,101
|
|
|
|
|
711,534
|
|
|
971,738
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 105,000,000 shares -
|
|
|
860,165
|
|
|
860,133
|
|
67,930,743
shares outstanding
|
|
|
|
|
|
|
|
Accumulated
other comprehensive loss
|
|
|
(103,584
|
)
|
|
(104,431
|
)
|
Retained
earnings
|
|
|
752,491
|
|
|
713,201
|
|
Total
common
stockholder's equity
|
|
|
1,509,072
|
|
|
1,468,903
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,937,294
|
|
|
1,805,871
|
|
|
|
|
3,446,366
|
|
|
3,274,774
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
488,325
|
|
|
470,707
|
|
Accumulated
deferred investment tax credits
|
|
|
19,850
|
|
|
20,277
|
|
Lease
market
valuation liability
|
|
|
532,800
|
|
|
547,800
|
|
Retirement
benefits
|
|
|
110,039
|
|
|
122,862
|
|
Deferred
revenues - electric service programs
|
|
|
46,275
|
|
|
51,588
|
|
Other
|
|
|
101,873
|
|
|
103,752
|
|
|
|
|
1,299,162
|
|
|
1,316,986
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
5,457,062
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
63,549
|
|
$
|
72,413
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
18,468
|
|
|
17,201
|
|
Amortization
of regulatory assets
|
|
|
33,129
|
|
|
31,530
|
|
Deferral
of
new regulatory assets
|
|
|
(33,957
|
)
|
|
(30,526
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
56
|
|
|
60
|
|
Deferred
rents
and lease market valuation liability
|
|
|
(46,528
|
)
|
|
(54,821
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(5,453
|
)
|
|
(402
|
)
|
Accrued
compensation and retirement benefits
|
|
|
(890
|
)
|
|
(172
|
)
|
Pension
trust
contribution
|
|
|
(24,800
|
)
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
224,011
|
|
|
74,518
|
|
Prepayments
and other current assets
|
|
|
592
|
|
|
515
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(256,808
|
)
|
|
(9,424
|
)
|
Accrued
taxes
|
|
|
13,959
|
|
|
15,691
|
|
Accrued
interest
|
|
|
18,122
|
|
|
12,802
|
|
Electric
service prepayment programs
|
|
|
(5,313
|
)
|
|
(4,056
|
)
|
Other
|
|
|
(223
|
)
|
|
81
|
|
Net
cash
provided from (used for) operating activities
|
|
|
(2,086
|
)
|
|
125,410
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
247,715
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(150
|
)
|
|
(172
|
)
|
Short-term
borrowings, net
|
|
|
(130,585
|
)
|
|
(57,760
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(24,000
|
)
|
|
(63,000
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
92,980
|
|
|
(120,932
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(36,682
|
)
|
|
(34,410
|
)
|
Loans
to
associated companies, net
|
|
|
(231,907
|
)
|
|
(9,158
|
)
|
Collection
of
principal on long-term notes receivable
|
|
|
133,341
|
|
|
-
|
|
Investments
in
lessor notes
|
|
|
35,614
|
|
|
44,548
|
|
Other
|
|
|
9,294
|
|
|
(5,448
|
)
|
Net
cash used
for investing activities
|
|
|
(90,340
|
)
|
|
(4,468
|
)
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
554
|
|
|
10
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
221
|
|
|
207
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
775
|
|
$
|
217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Cleveland
Electric Illuminating Company are
an
integral part of these statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of The
Cleveland Electric Illuminating Company:
We
have reviewed the
accompanying consolidated balance sheets of The Cleveland Electric Illuminating
Company and its subsidiaries as of March 31, 2007 and the related
consolidated statements of income, comprehensive income and cash flows for
each
of the three-month periods ended March 31, 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
May
8,
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
first quarter of 2007 decreased to $64 million from $72 million in the same
period of 2006. This decrease resulted primarily from higher purchased power
costs and lower investment income, partially offset by higher revenues.
Revenues
Revenues
increased
by $33 million or 8% in the first quarter of 2007 from the first quarter of
2006
primarily due to higher retail
and wholesale
generation revenues. Retail generation revenues increased $22 million due to
increased KWH sales and higher composite unit prices. Colder weather in the
first quarter of 2007 compared to the same period in 2006 contributed to the
higher KWH sales to residential and commercial customers (heating degree days
increased 18.1%). KWH sales to industrial customers increased in part due to
a
reduction in customer shopping during the first quarter of 2007.
Wholesale
generation
revenues increased by $11 million primarily due to higher unit prices for PSA
sales to associated companies, 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 first quarter of 2007 from the
same period of 2006 are summarized in the following tables:
Retail
Generation KWH Sales
|
|
Increase
|
|
Residential
|
|
|
8.0
|
%
|
Commercial
|
|
|
7.1
|
%
|
Industrial
|
|
|
3.3
|
%
|
Total
Retail Electric Generation Sales
|
|
|
5.6
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
7
|
|
Commercial
|
|
|
7
|
|
Industrial
|
|
|
8
|
|
Total
Retail Generation Revenues
|
|
$
|
22
|
|
Revenues
from
distribution throughput decreased $2 million in the first quarter of 2007
compared to the same period of 2006. This decrease was primarily a
result of lower
composite unit prices in all customer classes, partially offset by increased
KWH
deliveries to residential and commercial customers due to colder
weather in
the first quarter of 2007 as compared to the same period in 2006. The lower
composite unit prices in part reflected the completion of the generation-related
transition cost recovery under CEI’s transition plan by the end of January
2006.
Changes
in
distribution KWH deliveries and revenues in the first quarter of 2007 compared
to the same period of 2006 are summarized in the following tables.
Distribution
KWH Deliveries
|
|
Increase
|
|
Residential
|
|
|
8.0
|
%
|
Commercial
|
|
|
4.9
|
%
|
Industrial
|
|
|
2.1
|
%
|
Total
Increase in Distribution Deliveries
|
|
|
4.6
|
%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
Commercial
|
|
|
1
|
|
Industrial
|
|
|
(5
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(2
|
)
|
Expenses
Total
expenses
increased by $42 million in the first quarter of 2007 compared to the same
period of 2006. The following table presents changes from the prior year by
expense category:
Expenses
- Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
37
|
|
Other
operating costs
|
|
|
2
|
|
Provision
for
depreciation
|
|
|
1
|
|
Amortization
of regulatory assets
|
|
|
2
|
|
Deferral
of
new regulatory assets
|
|
|
(4
|
)
|
General
taxes
|
|
|
4
|
|
Net
increase in expenses
|
|
$
|
42
|
|
Higher
purchased
power costs in the first quarter of 2007 compared to the first quarter of 2006
primarily reflected higher unit prices associated with the power supply
agreement with FES and an increase in KWH purchases to meet CEI’s higher retail
generation sales requirements. The change in the deferral of new regulatory
assets in the first quarter of 2007 reflects a higher level of MISO costs that
were deferred in excess of transmission revenue and increased distribution
cost
deferrals under CEI’s RCP. General
taxes were
higher in the first quarter 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
Expense
Other
expense
increased by $10 million in the first quarter of 2007 compared to the same
period of 2006 primarily due to lower investment income on associated company
notes receivable. CEI received principal repayments from FGCO and NGC subsequent
to the first quarter of 2006 on notes receivable related to the generation
asset
transfers.
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 March 31,
2007, CEI had $775,000 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
provided from
operating activities during the first quarter of 2007, compared with the first
quarter of 2006, were as follows:
|
|
Three
Months Ended
March
31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
Income
|
|
$
|
64
|
|
$
|
72
|
|
Non-cash
credits
|
|
|
(40
|
)
|
|
(41
|
)
|
Pension
trust
contribution
|
|
|
(25
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(1
|
)
|
|
94
|
|
Net
cash
provided from (used for) operating activities
|
|
$
|
(2
|
) |
$
|
125
|
|
Net
cash provided
from operating activities decreased by $127 million in the first quarter of
2007
compared to the same period of 2006 due primarily to a $25 million pension
trust
contribution in the first quarter of 2007 and a $95 million change in
working capital and other. The decrease from working capital changes was due
primarily to changes in accounts payable of $247 million, partially offset
by
changes in accounts receivable of $149 million. The decreases of $8 million
from
net income and $1 million from non-cash credits are described above under
“Results of Operations.”
Cash
Flows from
Financing Activities
Net
cash provided
from financing activities was $93 million in the first quarter of 2007 compared
to net cash used of $121 million in the first quarter of 2006. The change
reflects $248 million of new long-term debt financing and a $39 million decrease
in common stock dividend payments to FirstEnergy, partially offset by a $73
million increase in repayments of short-term borrowings.
CEI
had $260 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and approximately $102 million of short-term
indebtedness as of March 31, 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.
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 used for
investing activities increased by $86 million in the first quarter of 2007
compared to the same period of 2006. The change was primarily due to increased
loans to associated companies, partially offset by the collection of principal
on long-term notes receivable.
CEI’s
capital
spending for the last three quarters of 2007 is expected to be about
$130 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 $841 million, of
which
approximately $158 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 March 31,
2007, the present value of these operating lease commitments, net of trust
investments, total $89 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
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
Electric
sales
|
|
$
|
233,056
|
|
$
|
210,874
|
|
Excise
tax
collections
|
|
|
7,400
|
|
|
7,103
|
|
Total
revenues
|
|
|
240,456
|
|
|
217,977
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Fuel
|
|
|
10,147
|
|
|
9,762
|
|
Purchased
power
|
|
|
96,169
|
|
|
75,420
|
|
Nuclear
operating costs
|
|
|
17,721
|
|
|
17,332
|
|
Other
operating costs
|
|
|
42,921
|
|
|
40,425
|
|
Provision
for
depreciation
|
|
|
9,117
|
|
|
8,097
|
|
Amortization
of regulatory assets
|
|
|
23,876
|
|
|
24,456
|
|
Deferral
of
new regulatory assets
|
|
|
(13,481
|
)
|
|
(13,656
|
)
|
General
taxes
|
|
|
13,734
|
|
|
12,931
|
|
Total
expenses
|
|
|
200,204
|
|
|
174,767
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
40,252
|
|
|
43,210
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Investment
income
|
|
|
7,225
|
|
|
9,780
|
|
Miscellaneous
expense
|
|
|
(3,100
|
)
|
|
(2,684
|
)
|
Interest
expense
|
|
|
(7,503
|
)
|
|
(4,310
|
)
|
Capitalized
interest
|
|
|
83
|
|
|
214
|
|
Total
other
income (expense)
|
|
|
(3,295
|
)
|
|
3,000
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
36,957
|
|
|
46,210
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
11,097
|
|
|
17,204
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
25,860
|
|
|
29,006
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
1,275
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
25,860
|
|
$
|
27,731
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
25,860
|
|
$
|
29,006
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
573
|
|
|
-
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
379
|
|
|
(1,138
|
)
|
Other
comprehensive income (loss)
|
|
|
952
|
|
|
(1,138
|
)
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
334
|
|
|
(411
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
618
|
|
|
(727
|
)
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
26,478
|
|
$
|
28,279
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
201
|
|
$
|
22
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
|
|
|
557
|
|
|
772
|
|
Associated
companies
|
|
|
14,059
|
|
|
13,940
|
|
Other
(less
accumulated provisions of $433,000 and $430,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
3,769
|
|
|
3,831
|
|
Notes
receivable from associated companies
|
|
|
109,195
|
|
|
100,545
|
|
Prepayments
and other
|
|
|
539
|
|
|
851
|
|
|
|
|
128,320
|
|
|
119,961
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
897,270
|
|
|
894,888
|
|
Less
-
Accumulated provision for depreciation
|
|
|
398,461
|
|
|
394,225
|
|
|
|
|
498,809
|
|
|
500,663
|
|
Construction
work in progress
|
|
|
16,787
|
|
|
16,479
|
|
|
|
|
515,596
|
|
|
517,142
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Investment
in
lessor notes
|
|
|
154,689
|
|
|
169,493
|
|
Long-term
notes receivable from associated companies
|
|
|
96,589
|
|
|
128,858
|
|
Nuclear
plant
decommissioning trusts
|
|
|
62,075
|
|
|
61,094
|
|
Other
|
|
|
1,840
|
|
|
1,871
|
|
|
|
|
315,193
|
|
|
361,316
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576
|
|
|
500,576
|
|
Regulatory
assets
|
|
|
237,220
|
|
|
247,595
|
|
Pension
assets
|
|
|
4,796
|
|
|
-
|
|
Property
taxes
|
|
|
22,010
|
|
|
22,010
|
|
Other
|
|
|
50,514
|
|
|
30,042
|
|
|
|
|
815,116
|
|
|
800,223
|
|
|
|
$
|
1,774,225
|
|
$
|
1,798,642
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
30,000
|
|
$
|
30,000
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
67,253
|
|
|
84,884
|
|
Other
|
|
|
4,119
|
|
|
4,021
|
|
Notes
payable
to associated companies
|
|
|
107,049
|
|
|
153,567
|
|
Accrued
taxes
|
|
|
54,781
|
|
|
47,318
|
|
Lease
market
valuation liability
|
|
|
24,600
|
|
|
24,600
|
|
Other
|
|
|
49,916
|
|
|
37,551
|
|
|
|
|
337,718
|
|
|
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
|
|
|
166,799
|
|
|
166,786
|
|
Accumulated
other comprehensive loss
|
|
|
(36,186
|
)
|
|
(36,804
|
)
|
Retained
earnings
|
|
|
230,200
|
|
|
204,423
|
|
Total
common
stockholder's equity
|
|
|
507,823
|
|
|
481,415
|
|
Long-term
debt
|
|
|
358,254
|
|
|
358,281
|
|
|
|
|
866,077
|
|
|
839,696
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
165,004
|
|
|
161,024
|
|
Accumulated
deferred investment tax credits
|
|
|
10,806
|
|
|
11,014
|
|
Lease
market
valuation liability
|
|
|
212,650
|
|
|
218,800
|
|
Retirement
benefits
|
|
|
75,265
|
|
|
77,843
|
|
Asset
retirement obligations
|
|
|
26,987
|
|
|
26,543
|
|
Deferred
revenues - electric service programs
|
|
|
20,930
|
|
|
23,546
|
|
Other
|
|
|
58,788
|
|
|
58,235
|
|
|
|
|
570,430
|
|
|
577,005
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
1,774,225
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
25,860
|
|
$
|
29,006
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
9,117
|
|
|
8,097
|
|
Amortization
of regulatory assets
|
|
|
23,876
|
|
|
24,456
|
|
Deferral
of
new regulatory assets
|
|
|
(13,481
|
)
|
|
(13,656
|
)
|
Deferred
rents
and lease market valuation liability
|
|
|
(10,891
|
)
|
|
(16,084
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(3,639
|
)
|
|
(8,453
|
)
|
Accrued
compensation and retirement benefits
|
|
|
(756
|
)
|
|
(293
|
) |
Pension
trust
contribution
|
|
|
(7,659
|
)
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
158
|
|
|
(8,793
|
)
|
Prepayments
and other current assets
|
|
|
312
|
|
|
366
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(17,533
|
)
|
|
(15,969
|
)
|
Accrued
taxes
|
|
|
9,379
|
|
|
20,401
|
|
Accrued
interest
|
|
|
3,951
|
|
|
(668
|
)
|
Electric
service prepayment programs
|
|
|
(2,616
|
)
|
|
(2,231
|
)
|
Other
|
|
|
(1,320
|
)
|
|
1,282
|
|
Net
cash
provided from operating activities
|
|
|
14,758
|
|
|
17,461
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
55,539
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
(30,000
|
)
|
Short-term
borrowings, net
|
|
|
(46,518
|
)
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
(25,000
|
)
|
Preferred
stock
|
|
|
-
|
|
|
(1,275
|
)
|
Net
cash used
for financing activities
|
|
|
(46,518
|
)
|
|
(736
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(6,064
|
)
|
|
(15,044
|
)
|
Loans
to
associated companies
|
|
|
(8,583
|
)
|
|
(11,270
|
)
|
Collection
of
principal on long-term notes receivable
|
|
|
32,202
|
|
|
-
|
|
Investments
in
lessor notes
|
|
|
14,804
|
|
|
9,335
|
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
16,863
|
|
|
13,793
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(16,863
|
)
|
|
(13,793
|
)
|
Other
|
|
|
(420
|
)
|
|
254
|
|
Net
cash
provided from (used for) investing activities
|
|
|
31,939
|
|
|
(16,725
|
)
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
179
|
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
22
|
|
|
15
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
201
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Toledo
Edison Company are an integral part
of these
statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of The
Toledo Edison Company:
We
have reviewed the
accompanying consolidated balance sheets of The Toledo Edison Company and its
subsidiary as of March 31, 2007 and the related consolidated statements of
income, comprehensive income and cash flows for each of the three-month periods
ended March 31, 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
May
8,
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 first quarter of 2007 decreased to $26 million from $28 million in the
first quarter of 2006. This decrease resulted primarily from higher purchased
power and other operating costs, partially offset by higher revenues.
Revenues
Revenues
increased
$22 million or 10.3% in the first quarter of 2007 compared to the same period
of
2006 primarily due to higher retail generation revenues of $12 million and
higher wholesale generation revenues of $10 million. Retail
generation
revenues increased for all customer sectors in the first quarter of 2007
compared to the same period of 2006 due to higher average prices and increased
sales volume. 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 4.7 percentage points and
1.5
percentage points for residential and commercial customers,
respectively.
The increase in
sales volume also resulted from colder weather in the first quarter of 2007
compared to the same period in 2006 (heating degree days increased
17.5%).
The
increase in
wholesale revenues resulted from higher unit prices for PSA sales to associated
companies, partially offset by a decrease in generation available for sale
due
in part to a maintenance outage at Mansfield Unit 2 in the first quarter of
2007. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and
the
Bruce Mansfield Plant to CEI and FGCO, respectively.
Increases
in retail
electric generation KWH sales and revenues
in the
first quarter of 2007 from the first quarter of 2006 are summarized in the
following tables.
Retail
Generation KWH Sales
|
|
Increase
|
|
Residential
|
|
|
13.7
|
%
|
Commercial
|
|
|
5.3
|
%
|
Industrial
|
|
|
0.8
|
%
|
Total
Retail Electric Generation Sales
|
|
|
5.0
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
4
|
|
Commercial
|
|
|
3
|
|
Industrial
|
|
|
5
|
|
Total
Retail Generation Revenues
|
|
$
|
12
|
|
Revenues
from
distribution throughput decreased by $2 million in the first quarter in 2007
compared to the same period in 2006 primarily due to lower composite unit prices
in the industrial customer sector, partially offset by higher KWH deliveries
to
residential and commercial customers. The higher
KWH deliveries to
residential and commercial customers in the first quarter of 2007 reflected
the
impact of colder weather in the first quarter of 2007 compared to the same
period in 2006.
Changes
in
distribution KWH deliveries and revenues
in the
first quarter of 2007 from the first quarter of 2006 are summarized in the
following tables.
Distribution
KWH Deliveries
|
|
Increase
|
|
Residential
|
|
|
8.0
|
%
|
Commercial
|
|
|
2.8
|
%
|
Industrial
|
|
|
0.4
|
%
|
Total
Increase in Distribution Deliveries
|
|
|
3.0
|
%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
Commercial
|
|
|
-
|
|
Industrial
|
|
|
(4
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(2
|
)
|
Expenses
Total
expenses
increased $25 million in the first quarter of 2007 from the same quarter of
2006. The following table presents changes from the prior year by expense
category:
Expenses
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
21
|
|
Other
operating costs
|
|
|
2
|
|
Provision
for
depreciation
|
|
|
1
|
|
General
taxes
|
|
|
1
|
|
Increase
in expenses
|
|
$
|
25
|
|
Higher
purchased
power costs in the first quarter of 2007 compared to the first quarter of 2006
reflected
higher
unit prices associated with the power supply agreement with FES and an increase
in KWH purchases to meet the higher retail generation sales requirements. Other
operating costs were higher due to a $2 million increase in MISO network
transmission expenses in the first quarter of 2007 compared to the same period
in 2006.
Other
Expense
Other
expense
increased
$6
million in the
first quarter of 2007
compared to the
same period of 2006
primarily due to
lower investment income and higher interest expense. A $3 million decrease
in
investment income resulted primarily from the principal repayments in 2006
on
notes receivable from associated companies. Higher interest expense of $3
million is largely associated with new long-term debt issuances in November
2006.
Capital
Resources and Liquidity
During
2007, TE
expects to meet its contractual obligations primarily with cash from operations.
Borrowing capacity under TE’s credit facilities is available to manage its
working capital requirements.
Changes
in Cash
Position
As
of March 31,
2007, TE had $201,000 of cash and cash equivalents, compared with $22,000 as
of
December 31, 2006. The major changes in these balances are summarized below.
Cash
Flows From
Operating Activities
Net
cash provided
from operating activities in the first quarter of 2007 and 2006 were as follows:
|
|
Three
Months Ended
March
31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
26
|
|
$
|
29
|
|
Non-cash
charges (credits)
|
|
|
2
|
|
|
(8
|
)
|
Pension
trust
contribution
|
|
|
(8
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(5
|
)
|
|
(3
|
)
|
Net
cash
provided from operating activities
|
|
$
|
15
|
|
$
|
18
|
|
Net
cash provided
from operating activities decreased $3 million in the first quarter of 2007
compared to the same period of 2006 as a result of a $3 million decrease in
net
income, an $8 million pension trust contribution in the first quarter of 2007
and a $2 million decrease from changes in working capital and other, partially
offset by a $10 million increase in net non-cash charges. The increase in
non-cash charges reflects changes in deferred lease costs and deferred income
taxes. The changes in net income are described above under “Results of
Operations.”
Cash
Flows From
Financing Activities
Net
cash used for
financing activities increased by $46 million in the first quarter of 2007
compared to the same period of 2006. The increase resulted from a $102 million
decrease in net short-term borrowings, partially offset by a $30 million
decrease in preferred stock redemptions and the absence in 2007 of a $25 million
common stock dividend to FirstEnergy in the first quarter of 2006.
TE
had $109 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and $107 million of short-term indebtedness as
of March 31, 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 was $32 million in the first quarter of 2007 compared
to net cash used for investing activities of $17 million in the first quarter
of
2006. The change was primarily due to a net increase of $35 million from
loan activity with associated companies, a $9 million decrease in property
additions and a $5 million increase from investments in lessor notes.
TE’s
capital
spending for the last three quarters of 2007 is expected to be about
$55 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 $325 million, of which approximately $64 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 March 31, 2007, the present value of these operating lease
commitments, net of trust investments, total $500 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
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
STATEMENTS
OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
Electric
sales
|
|
$
|
670,907
|
|
$
|
563,550
|
|
Excise
tax
collections
|
|
|
12,836
|
|
|
12,242
|
|
Total
revenues
|
|
|
683,743
|
|
|
575,792
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
386,497
|
|
|
315,710
|
|
Other
operating costs
|
|
|
74,651
|
|
|
83,028
|
|
Provision
for
depreciation
|
|
|
20,516
|
|
|
20,628
|
|
Amortization
of regulatory assets
|
|
|
95,228
|
|
|
66,745
|
|
General
taxes
|
|
|
16,999
|
|
|
16,232
|
|
Total
expenses
|
|
|
593,891
|
|
|
502,343
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
89,852
|
|
|
73,449
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
3,061
|
|
|
3,543
|
|
Interest
expense
|
|
|
(22,416
|
)
|
|
(20,616
|
)
|
Capitalized
interest
|
|
|
513
|
|
|
892
|
|
Total
other expense
|
|
|
(18,842
|
)
|
|
(16,181
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
71,010
|
|
|
57,268
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
32,664
|
|
|
23,558
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
38,346
|
|
|
33,710
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
125
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
38,346
|
|
$
|
33,585
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
38,346
|
|
$
|
33,710
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(2,115
|
)
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
97
|
|
|
69
|
|
Other
comprehensive income (loss)
|
|
|
(2,018
|
)
|
|
69
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
comprehensive income
|
|
|
(984
|
)
|
|
28
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(1,034
|
)
|
|
41
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
37,312
|
|
$
|
33,751
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
46
|
|
$
|
41
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,005,000 and $3,524,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
270,534
|
|
|
254,046
|
|
Associated
companies
|
|
|
863
|
|
|
11,574
|
|
Other
(less
accumulated provisions of $716,000
|
|
|
|
|
|
|
|
in
2007 for
uncollectible accounts)
|
|
|
57,628
|
|
|
40,023
|
|
Notes
receivable - associated companies
|
|
|
23,924
|
|
|
24,456
|
|
Materials
and
supplies, at average cost
|
|
|
2,044
|
|
|
2,043
|
|
Prepaid
taxes
|
|
|
1,127
|
|
|
13,333
|
|
Other
|
|
|
12,834
|
|
|
18,076
|
|
|
|
|
369,000
|
|
|
363,592
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
4,030,132
|
|
|
4,029,070
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,468,470
|
|
|
1,473,159
|
|
|
|
|
2,561,662
|
|
|
2,555,911
|
|
Construction
work in progress
|
|
|
92,008
|
|
|
78,728
|
|
|
|
|
2,653,670
|
|
|
2,634,639
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
fuel
disposal trust
|
|
|
171,007
|
|
|
171,045
|
|
Nuclear
plant
decommissioning trusts
|
|
|
166,342
|
|
|
164,108
|
|
Other
|
|
|
2,056
|
|
|
2,047
|
|
|
|
|
339,405
|
|
|
337,200
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
2,058,636
|
|
|
2,152,332
|
|
Goodwill
|
|
|
1,962,361
|
|
|
1,962,361
|
|
Pension
assets
|
|
|
36,034
|
|
|
14,660
|
|
Other
|
|
|
15,499
|
|
|
17,781
|
|
|
|
|
4,072,530
|
|
|
4,147,134
|
|
|
|
$
|
7,434,605
|
|
$
|
7,482,565
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
153,986
|
|
$
|
32,683
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
223,611
|
|
|
186,540
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
26,970
|
|
|
80,426
|
|
Other
|
|
|
151,777
|
|
|
160,359
|
|
Accrued
taxes
|
|
|
23,573
|
|
|
1,451
|
|
Accrued
interest
|
|
|
24,252
|
|
|
14,458
|
|
Cash
collateral from suppliers
|
|
|
32,446
|
|
|
32,300
|
|
Other
|
|
|
94,036
|
|
|
96,150
|
|
|
|
|
730,651
|
|
|
604,367
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
$10 par value, authorized 16,000,000 shares-
|
|
|
|
|
|
|
|
15,371,270
shares outstanding
|
|
|
150,093
|
|
|
150,093
|
|
Other
paid-in
capital
|
|
|
2,908,315
|
|
|
2,908,279
|
|
Accumulated
other comprehensive loss
|
|
|
(45,288
|
)
|
|
(44,254
|
)
|
Retained
earnings
|
|
|
168,732
|
|
|
145,480
|
|
Total
common
stockholder's equity
|
|
|
3,181,852
|
|
|
3,159,598
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,189,664
|
|
|
1,320,341
|
|
|
|
|
4,371,516
|
|
|
4,479,939
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
1,062,658
|
|
|
1,182,108
|
|
Accumulated
deferred income taxes
|
|
|
796,940
|
|
|
803,944
|
|
Nuclear
fuel
disposal costs
|
|
|
185,856
|
|
|
183,533
|
|
Asset
retirement obligations
|
|
|
85,722
|
|
|
84,446
|
|
Other
|
|
|
201,262
|
|
|
144,228
|
|
|
|
|
2,332,438
|
|
|
2,398,259
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
7,434,605
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
38,346
|
|
$
|
33,710
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
20,516
|
|
|
20,628
|
|
Amortization
of regulatory assets
|
|
|
95,228
|
|
|
66,745
|
|
Deferred
purchased power and other costs
|
|
|
(78,303
|
)
|
|
(61,868
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
8,076
|
|
|
3,826
|
|
Accrued
compensation and retirement benefits
|
|
|
(8,374
|
)
|
|
(2,736
|
)
|
Cash
collateral from (returned to) suppliers
|
|
|
1
|
|
|
(108,657
|
)
|
Pension
trust
contribution
|
|
|
(17,800
|
)
|
|
-
|
|
Decrease
(increase) in operating assets:
|
|
|
|
|
|
|
|
Receivables
|
|
|
(23,381
|
)
|
|
48,005
|
|
Materials
and
supplies
|
|
|
(1
|
)
|
|
255
|
|
Prepaid
taxes
|
|
|
11,946
|
|
|
8,992
|
|
Other
current
assets
|
|
|
454
|
|
|
(929
|
)
|
Increase
(decrease) in operating liabilities:
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(62,038
|
)
|
|
(68,993
|
)
|
Accrued
taxes
|
|
|
31,599
|
|
|
32,106
|
|
Accrued
interest
|
|
|
9,794
|
|
|
13,769
|
|
Other
|
|
|
(3,832
|
)
|
|
(5,773
|
)
|
Net
cash
provided from (used for) operating activities
|
|
|
22,231
|
|
|
(20,920
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
37,071
|
|
|
96,812
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(9,569
|
)
|
|
(3,731
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(15,000
|
)
|
|
(25,000
|
)
|
Preferred
stock
|
|
|
-
|
|
|
(125
|
)
|
Net
cash
provided from financing activities
|
|
|
12,502
|
|
|
67,956
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(40,015
|
)
|
|
(45,361
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
532
|
|
|
(3,132
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
22,407
|
|
|
45,865
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(23,131
|
)
|
|
(46,588
|
)
|
Other
|
|
|
5,479
|
|
|
2,181
|
|
Net
cash used
for investing activities
|
|
|
(34,728
|
)
|
|
(47,035
|
)
|
|
|
|
|
|
|
|
|
Net
increase
in cash and cash equivalents
|
|
|
5
|
|
|
1
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
41
|
|
|
102
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
46
|
|
$
|
103
|
|
|
|
|
|
|
|
|
|
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 sheets of Jersey Central Power & Light
Company and its subsidiaries as of March 31, 2007 and the related
consolidated statements of income, comprehensive income and cash flows for
each
of the three-month periods ended March 31, 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
May
8,
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 first quarter of 2007 increased to $38 million from
$34 million in the same period in 2006 primarily due to higher revenues and
lower other operating costs, partially offset by higher purchased power costs
and increased amortization of regulatory assets.
Revenues
Revenues
increased
$108 million or 18.7% in the first quarter of 2007 compared with the same period
of 2006 due to higher retail and wholesale generation revenues. Retail
generation revenues increased by $62 million in the first quarter of 2007 as
compared to the previous year in all customer classes (residential -
$36 million,
commercial - $24 million and industrial - $2 million). The increases
were due to higher unit prices resulting from the BGS auction effective in
May
2006 and increased sales volume (residential - 4.4% and commercial - 1.2%)
as a
result of colder weather in the first quarter of 2007 (heating degree days
were
12.9% greater than the first quarter of 2006).
Industrial
generation KWH sales declined by 1.4% from the same period of 2006, reflecting
a
slight increase in the level of customer shopping. Wholesale sales revenues
increased $8 million primarily due to higher market prices and a 1.0%
increase in sales volume as compared to the first quarter of 2006.
Revenues
from
distribution throughput increased by $28 million in the first quarter of 2007
compared to the same period of 2006 due to higher composite unit prices and
a
3.9% increase in KWH volume, reflecting the colder weather in JCP&L’s
service territory. The higher unit prices resulted from a NUGC rate increase
effective in December 2006 as approved by the NJBPU.
Increases
in KWH
sales by customer class in the first quarter of 2007 compared to the same period
of 2006 are summarized in the following table:
Increases
in KWH Sales
|
|
|
|
|
|
Electric
Generation:
|
|
|
Retail
|
|
2.8
|
%
|
Wholesale
|
|
1.0
|
%
|
Total
Electric Generation Sales
|
|
2.4
|
%
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
Residential
|
|
4.4
|
%
|
Commercial
|
|
4.2
|
%
|
Industrial
|
|
1.7
|
%
|
Total
Distribution Deliveries
|
|
3.9
|
%
|
The
higher revenues
in the first quarter of 2007 also reflect a $2 million increase in property
rents and higher transition funding revenues of $8 million. The increased
transition funding revenues resulted from the securitization of deferred costs
associated with JCP&L’s supply of BGS in August 2006.
Expenses
Total
expenses
increased by $92 million in the first quarter of 2007 compared to the first
quarter of 2006. The following table presents changes from the prior year by
expense category:
Expenses
- Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
71
|
|
Other
operating costs
|
|
|
(8
|
)
|
Amortization
of regulatory assets
|
|
|
28
|
|
General
taxes
|
|
|
1
|
|
Net
increase in expenses
|
|
$
|
92
|
|
Purchased
power
costs increased $71 million in the first quarter of 2007 compared to the same
period of 2006, reflecting higher prices from the BGS auction effective in
May
2006 and a 8.9% increase in KWH purchases to meet higher customer demand as
described above. The decrease of $8 million in other operating costs in the
first quarter of 2007 was due in part to lower postretirement benefits costs
and
a reduction in associated company service billings. Amortization of regulatory
assets increased $28 million in the first quarter of 2007 as a result of higher
transition cost recovery primarily associated with the December 2006 NUGC rate
increase.
Capital
Resources and Liquidity
During
2007,
JCP&L expects to meet its contractual obligations
with a combination
of cash from operations and funds from the capital markets. Borrowing
capacity
under JCP&L’s credit facilities is available to manage its working capital
requirements.
Changes
in Cash
Position
As
of March 31,
2007, JCP&L had $46,000 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
Net
cash provided
from operating activities was $22 million in the first quarter of 2007
compared to net cash used for operating activities of $21 million in the
first quarter of 2006, as summarized in the following table:
|
|
Three
Months Ended March 31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
38
|
|
$
|
34
|
|
Net
non-cash
charges
|
|
|
37
|
|
|
27
|
|
Pension
trust
contribution
|
|
|
(18
|
)
|
|
-
|
|
Cash
collateral from (returned to) suppliers
|
|
|
1
|
|
|
(109
|
)
|
Working
capital and other
|
|
|
(36
|
)
|
|
27
|
|
Net
cash
provided from (used for) operating activities
|
|
$
|
22
|
|
$
|
(21
|
)
|
Net
cash provided
from operating activities increased $43 million in the first quarter of 2007
from the same period in 2006. This increase was primarily due to the absence
in
2007 of $109 million of cash collateral payments made to suppliers in the first
quarter of 2006, partially offset by a $63 million decrease from working
capital (primarily due to changes in receivables) 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 under “Results of Operations.”
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities was $13 million in the first quarter of 2007 as
compared to $68 million in the same period of 2006. The $55 million
decrease resulted from a $59 million reduction in short-term borrowings and
a
$6 million increase in debt redemptions in the first quarter of 2007,
partially offset by a $10 million decrease in common stock dividend
payments to FirstEnergy.
JCP&L
had
approximately $24 million of cash and temporary investments (which includes
short-term notes receivable from associated companies) and approximately
$224 million of short-term indebtedness as of March 31, 2007.
JCP&L has authorization from the FERC to incur short-term debt up to its
charter limit of $412 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 JCP&L’s financing
capabilities.
Cash
Flows From
Investing Activities
Net
cash used in
investing activities was $35 million in the first quarter of 2007 compared
to
$47 million in the same period of 2006. The $12 million change
primarily resulted from a $5 million reduction in property additions and an
increase in loans from associated companies.
During
the last
three quarters of 2007,
capital
requirements for property additions and improvements are expected to be about
$152 million. JCP&L has cash requirements of $23 million for maturing
long-term debt during the remainder of 2007. These cash requirements are
expected to be satisfied from a combination of cash from operations, short-term
credit arrangements and funds from the capital markets. JCP&L’s
capital
spending for the period 2007-2011 is expected to be about $1.3 billion, of
which approximately $192 million applies to 2007.
Market
Risk Information
During
the first
quarter of 2007, net liabilities for commodity derivative contracts decreased
by
$117 million as a result of settled contracts ($104 million) and changes in
the
value of existing contracts ($13 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. Outstanding net liabilities for commodity derivative
contracts were $1.1 billion and $1.2 billion as of March 31, 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 $98 million and $97 million as of March 31,
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 March 31, 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
|
|
|
|
March
31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
Electric
sales
|
|
$
|
352,136
|
|
$
|
294,037
|
|
Gross
receipts
tax collections
|
|
|
18,120
|
|
|
17,176
|
|
Total
revenues
|
|
|
370,256
|
|
|
311,213
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
191,589
|
|
|
159,887
|
|
Other
operating costs
|
|
|
98,018
|
|
|
61,079
|
|
Provision
for
depreciation
|
|
|
10,284
|
|
|
10,905
|
|
Amortization
of regulatory assets
|
|
|
34,140
|
|
|
30,048
|
|
Deferral
of
new regulatory assets
|
|
|
(42,726
|
)
|
|
-
|
|
General
taxes
|
|
|
21,052
|
|
|
20,621
|
|
Total
expenses
|
|
|
312,357
|
|
|
282,540
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
57,899
|
|
|
28,673
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Interest
income
|
|
|
7,726
|
|
|
8,750
|
|
Miscellaneous
income
|
|
|
1,109
|
|
|
2,612
|
|
Interest
expense
|
|
|
(11,756
|
)
|
|
(11,184
|
)
|
Capitalized
interest
|
|
|
260
|
|
|
267
|
|
Total
other
income (expense)
|
|
|
(2,661
|
)
|
|
445
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
55,238
|
|
|
29,118
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
23,599
|
|
|
11,204
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
31,639
|
|
|
17,914
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(1,452
|
)
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
84
|
|
|
84
|
|
Other
comprehensive income (loss)
|
|
|
(1,368
|
)
|
|
84
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(692
|
)
|
|
35
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(676
|
)
|
|
49
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
30,963
|
|
$
|
17,963
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
129
|
|
$
|
130
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,063,000 and $4,153,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
154,261
|
|
|
127,084
|
|
Associated
companies
|
|
|
10,909
|
|
|
3,604
|
|
Other
|
|
|
27,337
|
|
|
8,107
|
|
Notes
receivable from associated companies
|
|
|
33,931
|
|
|
31,109
|
|
Prepaid
gross
receipts taxes
|
|
|
41,100 |
|
|
- |
|
Prepayments
and other
|
|
|
988
|
|
|
14,957
|
|
|
|
|
268,655
|
|
|
184,991
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
1,927,244
|
|
|
1,920,563
|
|
Less
-
Accumulated provision for depreciation
|
|
|
742,774
|
|
|
739,719
|
|
|
|
|
1,184,470
|
|
|
1,180,844
|
|
Construction
work in progress
|
|
|
23,290
|
|
|
18,466
|
|
|
|
|
1,207,760
|
|
|
1,199,310
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
273,627
|
|
|
269,777
|
|
Other
|
|
|
1,361
|
|
|
1,362
|
|
|
|
|
274,988
|
|
|
271,139
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
496,129
|
|
|
496,129
|
|
Regulatory
assets
|
|
|
454,997
|
|
|
409,095
|
|
Pension
assets
|
|
|
20,928
|
|
|
7,261
|
|
Other
|
|
|
41,073
|
|
|
46,354
|
|
|
|
|
1,013,127
|
|
|
958,839
|
|
|
|
$
|
2,764,530
|
|
$
|
2,614,279
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
50,000
|
|
$
|
50,000
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
70,120
|
|
|
141,501
|
|
Other
|
|
|
222,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
32,895
|
|
|
100,232
|
|
Other
|
|
|
67,427
|
|
|
59,077
|
|
Accrued
taxes
|
|
|
1,466
|
|
|
11,300
|
|
Accrued
interest
|
|
|
8,739
|
|
|
7,496
|
|
Other
|
|
|
20,415
|
|
|
22,825
|
|
|
|
|
473,062
|
|
|
392,431
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
859,000
shares
outstanding
|
|
|
1,276,094
|
|
|
1,276,075
|
|
Accumulated
other comprehensive loss
|
|
|
(27,192
|
)
|
|
(26,516
|
)
|
Accumulated
deficit
|
|
|
(203,029
|
)
|
|
(234,620
|
)
|
Total
common
stockholder's equity
|
|
|
1,045,873
|
|
|
1,014,939
|
|
Long-term
debt
and other long-term obligations
|
|
|
542,039
|
|
|
542,009
|
|
|
|
|
1,587,912
|
|
|
1,556,948
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
398,561
|
|
|
387,456
|
|
Accumulated
deferred investment tax credits
|
|
|
9,037
|
|
|
9,244
|
|
Nuclear
fuel
disposal costs
|
|
|
41,983
|
|
|
41,459
|
|
Asset
retirement obligations
|
|
|
153,469
|
|
|
151,107
|
|
Retirement
benefits
|
|
|
18,425
|
|
|
19,522
|
|
Other
|
|
|
82,081
|
|
|
56,112
|
|
|
|
|
703,556
|
|
|
664,900
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
2,764,530
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
31,639
|
|
$
|
17,914
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
10,284
|
|
|
10,905
|
|
Amortization
of regulatory assets
|
|
|
34,140
|
|
|
30,048
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(19,160
|
)
|
|
(22,818
|
)
|
Deferral
of
new regulatory assets
|
|
|
(42,726
|
)
|
|
-
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
16,178
|
|
|
1,704
|
|
Accrued
compensation and retirement benefits
|
|
|
(7,683
|
)
|
|
(3,912
|
)
|
Commodity
derivative transactions, net
|
|
|
-
|
|
|
(2,148
|
)
|
Cash
collateral
|
|
|
3,050
|
|
|
-
|
|
Pension
trust
contribution
|
|
|
(11,012
|
)
|
|
-
|
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
(49,818
|
)
|
|
27,829
|
|
Prepayments
and other current assets
|
|
|
(27,131
|
)
|
|
(37,665
|
)
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(58,986
|
)
|
|
1,160
|
|
Accrued
taxes
|
|
|
(9,835
|
)
|
|
(6,080
|
)
|
Accrued
interest
|
|
|
1,243
|
|
|
(109
|
)
|
Other
|
|
|
1,999
|
|
|
(4,649
|
)
|
Net
cash
provided from (used for) operating activities
|
|
|
(127,818
|
)
|
|
12,179
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
150,619
|
|
|
17,065
|
|
Net
cash
provided from financing activities
|
|
|
150,619
|
|
|
17,065
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(18,803
|
)
|
|
(25,277
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
25,323
|
|
|
42,061
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(26,579
|
)
|
|
(44,432
|
)
|
Loans
to
associated companies, net
|
|
|
(2,822
|
)
|
|
(2,145
|
)
|
Other
|
|
|
79
|
|
|
549
|
|
Net
cash used
for investing activities
|
|
|
(22,802
|
)
|
|
(29,244
|
)
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
(1
|
)
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
130
|
|
|
120
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
129
|
|
$
|
120
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Metropolitan
Edison Company are an integral
part
of these statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Metropolitan Edison Company:
We
have reviewed the
accompanying consolidated balance sheets of Metropolitan Edison Company and
its
subsidiaries as of March 31, 2007 and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 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
May
8,
2007
METROPOLITAN
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND
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
first quarter of 2007 increased to $32 million from $18 million in the first
quarter of 2006. This increase was primarily due to higher revenues and deferral
of new regulatory assets, partially offset by higher purchased power costs,
other operating costs, and amortization of regulatory assets.
Revenues
Revenues
increased
by $59 million, or 19.0% in the first quarter of 2007 compared with the same
period in 2006, reflecting higher retail and wholesale generation revenues.
Retail generation revenues increased by $5 million primarily due to higher
KWH
sales in all customer classes, partially offset by lower composite unit prices
in the industrial sector. Residential and commercial revenues increased by
$3
million and $2 million, respectively, in the first quarter of 2007 due to higher
KWH sales as a result of colder than normal weather compared to unseasonably
mild weather during the first quarter of 2006 (heating degree days increased
by
15.4% in 2007).
Wholesale
revenues
increased by $26 million in the first quarter of 2007 compared with the first
quarter of 2006 due to Met-Ed selling additional available power into the PJM
market beginning in January 2007.
Revenues
from
distribution throughput increased by $21 million in the first quarter of 2007
due to a 4.0% increase in KWH deliveries reflecting the effect of colder
temperatures compared to the same period of 2006, and an increase in composite
unit prices resulting from a January 2007 PPUC authorization to recover
increased transmission costs.
PJM
transmission
revenues increased by $7 million in the first quarter of 2007 primarily due
to
higher transmission volumes and additional PJM auction revenue rights in 2007.
Met-Ed defers the difference between revenue accrued under its transmission
rider and transmission costs incurred, resulting in no material effect to
current period earnings.
Increases
in
electric generation sales and distribution deliveries in the first quarter
of
2007 compared to the same period of 2006 are summarized in the following
table:
Changes
in KWH Sales
|
|
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
Residential
|
|
|
6.4
|
%
|
Commercial
|
|
|
3.7
|
%
|
Industrial
|
|
|
2.9
|
%
|
Total
Retail Electric Generation Sales
|
|
|
4.6
|
%
|
Distribution
Deliveries:
|
|
|
|
|
Residential
|
|
|
6.4
|
%
|
Commercial
|
|
|
3.5
|
%
|
Industrial
|
|
|
1.0
|
%
|
Total
Distribution Deliveries
|
|
|
4.0
|
%
|
Expenses
Total
expenses
increased by $30 million, or 10.6% in the first quarter of 2007 compared to
the
first quarter of 2006. The following table presents changes from the prior
year
by expense category:
Expenses
- Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
32
|
|
Other
operating costs
|
|
|
37
|
|
Provision
for
depreciation
|
|
|
(1
|
)
|
Amortization
of regulatory assets
|
|
|
4
|
|
Deferral
of
new regulatory assets
|
|
|
(43
|
)
|
General
taxes
|
|
|
1
|
|
Net
increase in expenses
|
|
$
|
30
|
|
Purchased
power
costs increased by $32 million in the first quarter of 2007 as compared with
the
same period of 2006. The increase was mainly attributable to a 15.8% increase
in
KWH purchases to meet higher retail and wholesale generation sales. Other
operating costs increased by $37 million in the first quarter of 2007 primarily
due to higher congestion costs associated with the increased transmission
volumes discussed above.
Met-Ed’s
revenue in
the first quarter of 2007 includes the authorized recovery of transmission
costs
that were deferred in 2006. As a result, amortization of regulatory assets
increased the first quarter of 2007 compared to the prior year. The deferral
of
new regulatory assets increased in the first quarter of 2007 due to the absence
in the first quarter of 2006 of PJM transmission costs and interest deferrals
that began in the second quarter of 2006, and 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.
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 March 31,
2007, Met-Ed had cash and cash equivalents of $129,000 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 $128 million in the first quarter of 2007 compared
to net cash provided from operating activities of $12 million in the first
quarter of 2006, as summarized in the following table:
|
|
Three
Months Ended
March
31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
32
|
|
$
|
18
|
|
Net
non-cash
charges (credits)
|
|
|
(9
|
)
|
|
13
|
|
Pension
trust
contribution
|
|
|
(11
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(140
|
)
|
|
(19
|
)
|
Net
cash
provided from (used for) operating activities
|
|
$
|
(128
|
)
|
$
|
12
|
|
Net
cash provided
from operating activities decreased by $140 million in the first quarter
2007 compared to the same period in 2006. The change was primarily due to a
$121
million decrease from changes in working capital and other, a $22 million
decrease in non-cash charges and an $11 million pension trust contribution
in
the first quarter of 2007, partially offset by a $14 million increase in net
income. The decrease from working capital primarily resulted from a $78 million
change in receivables and a $60 million change in accounts payable, partially
offset by an $11 million decrease in prepayments and a $3 million increase
in
cash collateral received from suppliers. 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 $151 million in the first quarter of 2007 compared
to $17 million in the first quarter of 2006. The increase reflects a $134
million increase in short-term borrowings in the first quarter of
2007.
As
of March 31,
2007, Met-Ed had approximately $34 million of cash and temporary investments
(which included short-term notes receivable from associated companies) and
$292
million of short-term borrowings (including $72 million from its
receivables financing arrangement). Met-Ed has authorization from the FERC
to
incur short-term debt up to $250 million (excluding receivables financing)
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 quarter
of 2007, Met-Ed's cash used for investing activities totaled $23 million,
compared to $29 million in the first quarter of 2006. The decrease resulted
from a $6 million reduction in property additions.
During
the remaining
three quarters of 2007, capital requirements for property additions and
improvements are expected to be approximately $64 million. Met-Ed has cash
requirements of approximately $50 million for maturing long-term debt
during the remainder of 2007. These cash requirements are 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 $511 million, of which
approximately $83 million applies to 2007.
Market
Risk Information
During
the first
quarter of 2007, net assets for 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. Outstanding
net
assets for commodity derivative contracts were $18 million and $23 million
as of
March 31, 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 $165 million and $164 million as of March 31,
2007 and December 31, 2006, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $16 million reduction in
fair
value as of March 31, 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
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
Electric
sales
|
|
$
|
339,226
|
|
$
|
275,827
|
|
Gross
receipts
tax collections
|
|
|
16,680
|
|
|
15,925
|
|
Total
revenues
|
|
|
355,906
|
|
|
291,752
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
200,842
|
|
|
161,641
|
|
Other
operating costs
|
|
|
59,461
|
|
|
38,342
|
|
Provision
for
depreciation
|
|
|
11,777
|
|
|
12,643
|
|
Amortization
of regulatory assets
|
|
|
15,394
|
|
|
14,815
|
|
Deferral
of
new regulatory assets
|
|
|
(17,088
|
)
|
|
-
|
|
General
taxes
|
|
|
19,851
|
|
|
19,389
|
|
Total
expenses
|
|
|
290,237
|
|
|
246,830
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
65,669
|
|
|
44,922
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
1,417
|
|
|
2,370
|
|
Interest
expense
|
|
|
(11,337
|
)
|
|
(10,536
|
)
|
Capitalized
interest
|
|
|
258
|
|
|
347
|
|
Total
other
expense
|
|
|
(9,662
|
)
|
|
(7,819
|
)
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
56,007
|
|
|
37,103
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
24,263
|
|
|
13,954
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
31,744
|
|
|
23,149
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Pension
and
other postretirement benefits
|
|
|
(2,825
|
)
|
|
-
|
|
Unrealized
gain on derivative hedges
|
|
|
16
|
|
|
16
|
|
Unrealized
loss on available for sale securities
|
|
|
(3
|
)
|
|
(4
|
)
|
Other
comprehensive income (loss)
|
|
|
(2,812
|
)
|
|
12
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(1,298
|
)
|
|
6
|
|
Other
comprehensive income (loss), net of tax
|
|
|
(1,514
|
)
|
|
6
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
30,230
|
|
$
|
23,155
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
March
31,
|
|
December
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
42
|
|
$
|
44
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,845,000 and $3,814,000
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
147,874
|
|
|
126,639
|
|
Associated
companies
|
|
|
47,552
|
|
|
49,728
|
|
Other
|
|
|
32,057
|
|
|
16,367
|
|
Notes
receivable from associated companies
|
|
|
18,840
|
|
|
19,548
|
|
Prepaid
gross
receipts taxes
|
|
|
39,502
|
|
|
1,917
|
|
Prepayments
and other
|
|
|
959 |
|
|
2,319 |
|
|
|
|
286,826
|
|
|
216,562
|
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
In
service
|
|
|
2,149,976
|
|
|
2,141,324
|
|
Less
-
Accumulated provision for depreciation
|
|
|
813,112
|
|
|
809,028
|
|
|
|
|
1,336,864
|
|
|
1,332,296
|
|
Construction
work in progress
|
|
|
26,964
|
|
|
22,124
|
|
|
|
|
1,363,828
|
|
|
1,354,420
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
127,014
|
|
|
125,216
|
|
Non-utility
generation trusts
|
|
|
100,514
|
|
|
99,814
|
|
Other
|
|
|
531
|
|
|
531
|
|
|
|
|
228,059
|
|
|
225,561
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
860,716
|
|
|
860,716
|
|
Pension
assets
|
|
|
28,101
|
|
|
11,474
|
|
Other
|
|
|
33,129
|
|
|
36,059
|
|
|
|
|
921,946
|
|
|
908,249
|
|
|
|
$
|
2,800,659
|
|
$
|
2,704,792
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
$
|
94,592
|
|
$
|
199,231
|
|
Other
|
|
|
224,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
40,112
|
|
|
92,020
|
|
Other
|
|
|
53,369
|
|
|
47,629
|
|
Accrued
taxes
|
|
|
2,518
|
|
|
11,670
|
|
Accrued
interest
|
|
|
12,742
|
|
|
7,224
|
|
Other
|
|
|
19,522
|
|
|
21,178
|
|
|
|
|
446,855
|
|
|
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
|
|
|
1,189,453
|
|
|
1,189,434
|
|
Accumulated
other comprehensive loss
|
|
|
(8,707
|
)
|
|
(7,193
|
)
|
Retained
earnings
|
|
|
121,702
|
|
|
90,005
|
|
Total
common
stockholder's equity
|
|
|
1,408,260
|
|
|
1,378,058
|
|
Long-term
debt
and other long-term obligations
|
|
|
477,504
|
|
|
477,304
|
|
|
|
|
1,885,764
|
|
|
1,855,362
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
69,668
|
|
|
96,151
|
|
Asset
retirement obligations
|
|
|
78,126
|
|
|
76,924
|
|
Accumulated
deferred income taxes
|
|
|
190,513
|
|
|
193,662
|
|
Retirement
benefits
|
|
|
50,662
|
|
|
50,328
|
|
Other
|
|
|
79,071
|
|
|
53,413
|
|
|
|
|
468,040
|
|
|
470,478
|
|
COMMITMENTS
AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
$
|
2,800,659
|
|
$
|
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)
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$
|
31,744
|
|
$
|
23,149
|
|
Adjustments
to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
11,777
|
|
|
12,643
|
|
Amortization
of regulatory assets
|
|
|
15,394
|
|
|
14,815
|
|
Deferral
of
new regulatory assets
|
|
|
(17,088
|
)
|
|
-
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(18,433
|
)
|
|
(19,211
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
13,366
|
|
|
5,361
|
|
Accrued
compensation and retirement benefits
|
|
|
(8,786
|
)
|
|
(472
|
)
|
Cash
collateral
|
|
|
1,450
|
|
|
-
|
|
Commodity
derivative transactions, net
|
|
|
-
|
|
|
(4,206
|
)
|
Pension
trust
contribution
|
|
|
(13,436
|
)
|
|
-
|
|
Decrease
(Increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
|
(30,050
|
)
|
|
16,729
|
|
Prepayments
and other current assets
|
|
|
(36,225
|
)
|
|
(36,540
|
)
|
Increase
(Decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(46,168
|
)
|
|
(9,623
|
)
|
Accrued
taxes
|
|
|
(9,152
|
)
|
|
(4,904
|
)
|
Accrued
interest
|
|
|
5,518
|
|
|
5,401
|
|
Other
|
|
|
1,943
|
|
|
(6,745
|
)
|
Net
cash used
for operating activities
|
|
|
(98,146
|
)
|
|
(3,603
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
119,361
|
|
|
39,315
|
|
Net
cash
provided from financing activities
|
|
|
119,361
|
|
|
39,315
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(20,404
|
)
|
|
(35,610
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
708
|
|
|
(1,134
|
)
|
Proceeds
from
nuclear decommissioning trust fund sales
|
|
|
9,758
|
|
|
14,942
|
|
Investments
in
nuclear decommissioning trust funds
|
|
|
(10,532
|
)
|
|
(14,942
|
)
|
Other,
net
|
|
|
(747
|
)
|
|
1,032
|
|
Net
cash used
for investing activities
|
|
|
(21,217
|
)
|
|
(35,712
|
)
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
(2
|
)
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
44
|
|
|
35
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
42
|
|
$
|
35
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Electric Company are an integral
part
of these statements.
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholder
and Board of
Directors
of
Pennsylvania Electric Company:
We
have reviewed the
accompanying consolidated balance sheets of Pennsylvania Electric Company and
its subsidiaries as of March 31, 2007 and the related consolidated
statements of income, comprehensive income and cash flows for each of the
three-month periods ended March 31, 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
May
8,
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, western and south central Pennsylvania, providing regulated
transmission and distribution services. Penelec also provides generation
services to those customers electing to retain Penelec as their power supplier.
Results
of Operations
Net
income in the
first quarter of 2007 increased to $32 million, compared to $23 million in
the first quarter of 2006. This increase resulted from higher revenues and
the
deferral of new regulatory assets, partially offset by higher purchased power
costs and other operating costs.
Revenues
Revenues
increased
by $64 million in the first quarter of 2007 compared to the same period of
2006,
reflecting higher retail and wholesale generation revenues. Retail generation
revenues increased by $6 million in the first quarter of 2007 primarily due
to
higher KWH sales in all customer classes,
partially offset
by lower composite unit prices in the industrial sector. Residential and
commercial sales both increased by $3 million for the first quarter of 2007
due
to increases in KWH sales as a result of colder than normal weather compared
to
unseasonably mild weather during the first quarter of 2006 (heating degree
days
increased by 14.2% in 2007).
Wholesale
revenues
increased $36 million in the first quarter of 2007 compared with the first
quarter of 2006 due to Penelec selling additional available power into the
PJM
market beginning in January 2007.
Revenues
from
distribution throughput increased $16 million in the first quarter of 2007
due
to a 3.0% increase in KWH deliveries reflecting the effect of colder
temperatures compared to the same period of 2006, and an increase in composite
unit prices resulting from a January 2007 PPUC authorization to recover
increased transmission costs.
PJM
transmission
revenues increased by $6 million in the first quarter 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 accrued under its transmission rider and transmission
costs incurred, with no material effect to current period earnings.
Changes
in electric
generation sales and distribution deliveries in the first quarter of 2007
compared to the same period of 2006 are summarized in the following
table:
|
|
|
|
Changes
in KWH Sales
|
|
|
|
Increase
(Decrease)
|
|
|
|
Retail
Electric Generation:
|
|
|
|
Residential
|
|
|
5.7
|
%
|
Commercial
|
|
|
5.0
|
%
|
Industrial
|
|
|
0.1
|
%
|
Total
Retail Electric Generation Sales
|
|
|
3.8
|
%
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
Residential
|
|
|
5.7
|
%
|
Commercial
|
|
|
5.0
|
%
|
Industrial
|
|
|
(1.8
|
)%
|
Total
Distribution Deliveries
|
|
|
3.0
|
%
|
Expenses
Total
expenses
increased by $44 million or 17.6% in the first quarter of 2007 compared to
the
first quarter of 2006. The
following table
presents changes from the prior year by expense category:
|
|
Increase
|
|
Expenses
- Changes
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
Purchased
power costs
|
|
$
|
39
|
|
Other
operating costs
|
|
|
21
|
|
Provision
for
depreciation
|
|
|
(1
|
)
|
Amortization
of regulatory assets
|
|
|
1
|
|
Deferral
of
new regulatory assets
|
|
|
(17
|
)
|
General
taxes
|
|
|
1
|
|
Net
increase in expenses
|
|
$
|
44
|
|
|
|
|
|
|
Purchased
power
costs increased by $39 million or 24.3% in the first quarter of 2007, compared
to the same period of 2006. The increase was due primarily to an increase in
KWH
purchases to meet the increased retail and wholesale generation sales and a
2.4%
increase in composite unit prices. Other operating costs increased by $21
million in the first quarter of 2007 principally due to higher congestion costs
associated with the increased transmission volumes discussed above.
Penelec’s
revenue in
the first quarter of 2007 includes the authorized recovery of transmission
costs
that were deferred in 2006. As a result, amortization of regulatory assets
increased in the first quarter of 2007 compared to the prior year. The deferral
of new regulatory assets increased in the first quarter of 2007 due to the
absence in the first quarter of 2006 of PJM transmission costs and interest
deferrals that began in the second quarter of 2006 and 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.
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 March 31,
2007, Penelec had $42,000 of cash and cash equivalents compared with $44,000
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 in the first quarter of 2007 and 2006 were as follows:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Operating
Cash Flows
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
32
|
|
$
|
23
|
|
Net
non-cash
charges (credits)
|
|
|
(4
|
)
|
|
9
|
|
Pension
trust
contribution
|
|
|
(13
|
)
|
|
-
|
|
Working
capital and other
|
|
|
(113
|
)
|
|
(36
|
)
|
Net
cash used
for operating activities
|
|
$
|
(98
|
)
|
$
|
(4
|
)
|
Net
cash used for
operating activities increased $94 million in the first quarter of 2007 compared
to the first quarter of 2006 as a result of a $77 million change in working
capital and other, a $13 million pension trust contribution in the first quarter
of 2007 and a $13 million decrease in net non-cash charges, partially offset
by
a $9 million increase in net income. The $77 million decrease from working
capital was principally due to changes in receivables of $47 million and changes
in accounts payable of $37 million. Changes in net income and non-cash charges
are described above under “Results of Operations.”
Cash
Flows From
Financing Activities
Net
cash provided
from financing activities increased $80 million in the first quarter of 2007
compared to the first quarter of 2006. The change reflects an increase in
short-term borrowings.
Penelec
had
approximately $19 million of cash and temporary investments (which includes
short-term notes receivable from associated companies) and approximately $319
million of short-term indebtedness
(including
$74 million from its receivables financing arrangement) as of
March 31, 2007. Penelec has authorization from the FERC to incur short-term
debt of up to $250 million (excluding receivables financing) 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 quarter
of 2007, net cash used for investing activities totaled $21 million compared
to
$36 million in the first quarter of 2006. The decrease primarily resulted from
a
$15 million reduction
in
property additions.
During
the remaining
three quarters of 2007, capital requirements for property additions are expected
to be approximately $71 million. These cash requirements are expected to be
satisfied from a combination of cash from operations, short-term credit
arrangements and funds from the capital markets. Penelec’s capital spending for
the period 2007-2011 is expected to be approximately $614 million, of which
approximately $92 million applies to 2007.
Market
Risk Information
During
the first
quarter of 2007, net assets for 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.
Outstanding net assets for commodity derivative contracts were $10 million
and
$12 million as of March 31, 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 $73 million and $72 million as of March 31,
2007 and December 31, 2006, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $7 million reduction in
fair
value as of March 31, 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 March 31,
2007, OE, CEI and TE had the capability to issue approximately
$1.5 billion, $536 million and $789 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
$600 million, $517 million and $130 million, respectively, as of
March 31, 2007. Under the provisions of its senior note indenture,
JCP&L may issue additional FMB only as collateral for senior notes. As of
March 31, 2007, JCP&L had the capability to issue $937 million of
additional senior notes upon the basis of FMB collateral.
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 March 31,
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.
On
August 24, 2006,
FirstEnergy and certain of its subsidiaries entered into a $2.75 billion
five-year revolving credit facility, which replaced FirstEnergy’s prior $2
billion credit facility. 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
|
|
Borrower
|
|
Sub-Limit
|
|
Debt
Limitations(1)
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
|
$
|
2,750
|
|
|
$
|
1,500
|
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
39
|
|
CEI
|
|
|
250
|
(2)
|
|
500
|
|
TE
|
|
|
250
|
(2)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
412
|
|
Met-Ed
|
|
|
250
|
|
|
250
|
(3)
|
Penelec
|
|
|
250
|
|
|
250
|
(3)
|
(1) As
of March 31,
2007.
|
(2)
|
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.
|
(3) 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 March 31, 2007, FirstEnergy and its
subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy
|
|
61
|
%
|
OE
|
|
49
|
%
|
Penn
|
|
28
|
%
|
CEI
|
|
57
|
%
|
TE
|
|
49
|
%
|
JCP&L
|
|
25
|
%
|
Met-Ed
|
|
46
|
%
|
Penelec
|
|
36
|
%
|
The
revolving credit
facility does not contain provisions that either restrict the ability to borrow
or accelerate repayment of outstanding advances as a result of any change in
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to the credit ratings of the company
borrowing the funds.
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 regulated money
pool and tracks surplus funds of FirstEnergy and the respective Companies,
as
well as proceeds available from bank borrowings. Companies receiving a loan
under the money pool agreement 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 and is based on the average cost of funds available
through the pool. The average interest rate for borrowings in the first quarter
of 2007 was approximately 5.61%.
FirstEnergy’s
access
to debt capital markets and costs of financing are impacted by its credit
ratings. The following table displays FirstEnergy’s and the Companies’
securities ratings as of March 31, 2007. The ratings outlook from S&P
on all securities is Stable. The ratings outlook from Moody’s on all securities
is Positive. The ratings outlook from Fitch is Positive for CEI and TE and
Stable for all other companies.
Issuer
|
|
Securities
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB
|
|
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
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 March 31,
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
|
|
$
|
156
|
|
0.15%
|
Centerior
Funding Corp.
|
|
CEI
|
|
|
200
|
|
|
-
|
|
0.15
|
Penn
Power
Funding LLC
|
|
Penn
|
|
|
25
|
|
|
19
|
|
0.125
|
Met-Ed
Funding
LLC
|
|
Met-Ed
|
|
|
80
|
|
|
72
|
|
0.125
|
Penelec
Funding LLC
|
|
Penelec
|
|
|
75
|
|
|
74
|
|
0.125
|
|
|
|
|
$
|
550
|
|
$
|
321
|
|
|
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. The following table discloses regulatory assets by
company:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2007
|
|
2006
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
729
|
|
$
|
741
|
|
$
|
(12
|
)
|
CEI
|
|
|
854
|
|
|
855
|
|
|
(1
|
)
|
TE
|
|
|
237
|
|
|
248
|
|
|
(11
|
)
|
JCP&L
|
|
|
2,059
|
|
|
2,152
|
|
|
(93
|
)
|
Met-Ed
|
|
|
455
|
|
|
409
|
|
|
46
|
|
Total
|
|
$
|
4,334
|
|
$
|
4,405
|
|
$
|
(71
|
)
|
*
|
Penelec
had
net regulatory liabilities of approximately $70 million
and
$96 million as of March 31, 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. 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
|
|
Period
|
|
OE
|
|
CEI
|
|
TE
|
|
Ohio
|
|
|
|
(In
millions)
|
|
2007
|
|
$
|
179
|
|
$
|
108
|
|
$
|
93
|
|
$
|
380
|
|
2008
|
|
|
208
|
|
|
124
|
|
|
119
|
|
|
451
|
|
2009
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
216
|
|
2010
|
|
|
-
|
|
|
273
|
|
|
-
|
|
|
273
|
|
Total
Amortization
|
|
$
|
387
|
|
$
|
721
|
|
$
|
212
|
|
$
|
1,320
|
|
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 will automatically become
effective on July 1, 2007. The revised riders represent an increase over the
amounts collected through the 2006 riders of approximately $64 million annually.
During
the period
between May 1, 2007 and June 1, 2007, any party may raise issues related to
the
revised tariffs through an informal resolution process. If not adequately
resolved through this process by June 30, 2007, any interested party may file
a
formal complaint with the PUCO which will be addressed by the PUCO after all
parties have been heard. If at the conclusion of either the informal or formal
process, adjustments are found to be necessary, such adjustments (with carrying
costs) will be included in the Ohio Companies’ next rider filing which must be
filed no later than May 1, 2008. No assurance can be given that such formal
or
informal proceedings will not be instituted.
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 intend to file the application
and rate request with the PUCO on or after June 7, 2007. The requested $334
million 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. The new rates, subject to evidentiary
hearings at the PUCO, would become effective January 1, 2009 for OE and TE,
and
May 2009 for CEI.
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 allows Met-Ed and Penelec to sell the output of NUG
generation 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 have also 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.
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.
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 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 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. If Met-Ed
and
Penelec do not prevail on the issue of congestion, it could have a material
adverse effect on FirstEnergy’s and their financial condition and results of
operations.
As
of March 31,
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 $472 million and $124 million, respectively.
Penelec’s $124 million 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
may file exceptions to the initial decision by May 22, 2007 and parties may
reply to those exceptions 10 days thereafter. 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 Energy Independence Strategy (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 through a "Least Cost Portfolio", the
utilization of micro-grids and an optional three year phase-in of rate
increases. Since the EIS has only recently been proposed, the final form of
any
legislation 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)
As
a result of
outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU
adopted an MOU that set out specific tasks related to service reliability to
be
performed by JCP&L and a timetable for completion and endorsed JCP&L’s
ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a
Stipulation that incorporates the final report of an SRM who made
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The Stipulation also incorporates the Executive Summary and
Recommendation portions of the final report of a focused audit of JCP&L’s
Planning and Operations and Maintenance programs and practices (Focused Audit).
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.
JCP&L
is
permitted to defer for future collection from customers the amounts by which
its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and NUGC rates and market sales
of NUG energy and capacity. As of March 31, 2007, the accumulated deferred
cost balance totaled approximately $357 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 and 2) renewables have completed their assigned
tasks of data gathering and analysis. Both groups have provided a report to
the
EMP Committee. The working groups addressing reliability and pricing issues
continue their data gathering and analysis activities. Public stakeholder
meetings were held in the fall of 2006 and in early 2007, and further public
meetings are expected in the summer of 2007. A final draft of the EMP is
expected to be presented to the Governor in the fall of 2007 with further public
hearings anticipated in early 2008. 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 issued a draft proposal relating to changes to the
regulations addressing electric distribution service reliability and quality
standards. A meeting between the NJBPU Staff and interested stakeholders to
discuss the proposal was held on February 15, 2007. On February 22, 2007, the
NJBPU Staff circulated a revised proposal upon which discussions with interested
stakeholders were held on March 26, 2007. On April 18 and April 23, 2007 the
NJBPU staff circulated further revised draft proposals. A schedule for formal
proceedings has not yet been established. At this time, FirstEnergy cannot
predict the outcome of this process nor determine the impact, if any, ultimate
regulations resulting from these draft proposals 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. JCP&L, Met-Ed and Penelec 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 second 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. On May 31, 2005, the FERC issued an order on these
cases. First, it set for hearing the existing rate design and indicated that
it
will issue a final order within six months. American Electric Power Company,
Inc. filed in opposition proposing to create a "postage stamp" rate for high
voltage transmission facilities across PJM. Second, the FERC approved the
proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed
formula rate, subject to refund and hearing procedures. On June 30, 2005, the
settling PJM transmission owners filed a request for rehearing of the May 31,
2005 order. On March 20, 2006, a settlement was filed with FERC in the formula
rate proceeding that generally accepts the companies' formula rate proposal.
The
FERC issued an order approving this settlement on April 19, 2006. Hearings
in
the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial
Decision was issued by the ALJ. The ALJ adopted the 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. On April 19,
2007, the FERC issued an order rejecting the ALJ’s findings and recommendations
in nearly every respect. 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, 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, 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.
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
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 an implementation in the second
or
third 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 has requested FERC action on its filing by June 2007.
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 will become effective on
May 14, 2007. The final rule has not yet been fully evaluated to assess its
impact on FirstEnergy’s operations. MISO and PJM will be filing revised tariffs
to comply with FERC’s order.
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
March 31, 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 $87 million (JCP&L - $59 million, TE -
$3 million, CEI - $1 million, and other subsidiaries -
$24 million) have been accrued through March 31, 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 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 New Source Review 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 W.
H. Sammis Plant and other FES 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 are currently estimated to be $1.5 billion for FGCO ($400 million
of
which is expected to be spent during 2007, with the largest portion of the
remaining $1.1 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.
On
August 26, 2005,
FGCO entered into an agreement with Bechtel Power Corporation under which
Bechtel will engineer, procure, and construct air quality control systems for
the reduction of SO2
emissions. FGCO
also entered into an agreement with B&W on August 25, 2006 to supply flue
gas desulfurization systems for the reduction of SO2
emissions.
Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions
also are being installed at the W.H. Sammis Plant under a 1999 agreement with
B&W.
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, New
Jersey. In 2005, JCP&L renewed its motion to decertify the class based on a
very limited number of class members who incurred damages and also filed a
motion for summary judgment on the remaining plaintiffs’ claims for negligence,
breach of contract and punitive damages. In July 2006, the New Jersey Superior
Court dismissed the punitive damage claim and again decertified the class based
on the fact that a vast majority of the class members did not suffer damages
and
those that did would be more appropriately addressed in individual actions.
Plaintiffs appealed this ruling to the New Jersey Appellate Division 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. In late March 2007,
JCP&L filed a petition for allowance of an appeal of the Appellate Division
ruling to the New Jersey Supreme Court. FirstEnergy is unable to predict the
outcome of these matters and no liability has been accrued as of March 31,
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. It is unknown whether or not
the matter will be further appealed. 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. The Court has scheduled oral argument for
June 25, 2007 to hear the plaintiffs' request for reconsideration of its order
denying class certification and request to amend their complaint.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the arbitration
panel decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. On February 6,
2006, a federal district court granted a union motion to dismiss, as premature,
a JCP&L appeal of the award filed on October 18, 2005. 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.
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. The Standard 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 respective
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
respective financial statements.
EITF
06-10 -
“Accounting for Deferred Compensation and Postretirement Benefit Aspects of
Collateral
Split-Dollar
Life Insurance Arrangements”
In
March 2007, the
EITF reached a final consensus on Issue 06-10 concluding that an employer should
recognize a liability for the postretirement obligation associated with a
collateral assignment split-dollar life insurance arrangement if, based on
the
substantive arrangement with the employee, the employer has agreed to maintain
a
life insurance policy during the employee’s retirement or provide the employee
with a death benefit. The liability should be recognized in accordance with
SFAS
106 if,
in substance, a
postretirement plan exists or APB 12 if the arrangement is, in substance, an
individual deferred compensation contract. The EITF also reached a consensus
that the employer should recognize and measure the associated asset on the
basis
of the terms of the collateral assignment arrangement. This pronouncement is
effective for fiscal years beginning after December 15, 2007, including interim
periods within those years. The Companies do not expect this pronouncement
to
have a material impact on their respective 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 March 31, 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 March 31, 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.
|
|
Period
|
|
|
|
January
1-31,
|
|
February
1-28,
|
|
March
1-31,
|
|
First
|
|
|
|
2007
|
|
2007
|
|
2007
|
|
Quarter
|
|
Total
Number
of Shares Purchased (a)
|
|
62,469
|
|
226,418
|
|
15,272,836
|
|
15,561,723
|
|
Average
Price
Paid per Share
|
|
$59.61
|
|
$63.78
|
|
$62.69
|
|
$62.69
|
|
Total
Number
of Shares Purchased
|
|
|
|
|
|
|
|
|
|
As
Part of
Publicly Announced Plans
|
|
|
|
|
|
|
|
|
|
or
Programs
(b)
|
|
-
|
|
-
|
|
14,370,110
|
|
14,370,110
|
|
Maximum
Number
(or Approximate Dollar
|
|
|
|
|
|
|
|
|
|
Value)
of
Shares that May Yet Be
|
|
|
|
|
|
|
|
|
|
Purchased
Under the Plans or Programs
|
|
16,000,000
|
|
16,000,000
|
|
1,629,890
|
|
1,629,890
|
|
(a)
|
Share
amounts
reflect purchases on the open market to satisfy FirstEnergy's obligations
to deliver common stock under its
Executive
and
Director Incentive Compensation Plan, Deferred Compensation Plan
for
Outside Directors, Executive Deferred
Compensation
Plan, Savings Plan and Stock Investment Plan. In addition, such amounts
reflect shares tendered by employees
to
pay the
exercise price or withholding taxes upon exercise of stock options
granted
under the Executive and Director Incentive
Compensation
Plan and shares purchased as part of publicly announced
plans.
|
|
|
(b)
|
FirstEnergy
publicly announced, on January 30, 2007, a plan to repurchase up to
16 million shares of its common stock through
June 30,
2008. On March 2, 2007, FirstEnergy repurchased approximately
14.4 million shares, or 4.5%, of its outstanding
common
stock
under this plan through an accelerated share repurchase program with
an
affiliate of Morgan Stanley and Co.,
Incorporated
at an initial price of $62.63 per
share.
|
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
FirstEnergy
|
|
|
|
|
|
10.1
|
Confirmation
dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and
Co.,
International
Limited (1)
|
|
10.2 |
Form
of U.S.
$250,000,000 Credit Agreement, dated as of March 2, 2007, between
FirstEnergy
Corp.,
as
Borrower, and Morgan Stanley Senior Funding, Inc., as Lender. (2)
|
|
10.3 |
Form
of
Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as
Guarantor, and
Morgan
Stanley
Senior Funding, Inc., as Lender under a U.S. $250,000,000 Credit
Agreement,
dated
as of
March 2, 2007, with FirstEnergy Solutions Corp., as
Borrower.
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
OE
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
CEI
|
|
|
|
|
|
4 |
Officer’s
Certificate (including the form of 5.70% Senior Notes due 2017),
dated as
of March 27,
2007(Form
8-K
dated March 28, 2007, Exhibit 4).
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
TE
|
|
|
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
JCP&L
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
Met-Ed
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
Penelec
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-(e).
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
(1) |
Confidential
treatment has been requested for certain portions of the Exhibit.
Omitted
portions have been filed
separately
with the SEC.
|
(2) |
A
substantially similar agreement, dated as of the same date and in
the same
amount, was executed and delivered by
the
registrant’s subsidiary, FirstEnergy Solutions Corp., for which the
registrant provided its guaranty in the form filed as
Exhibit
10.2
above, all as described in the registrant’s Form 8-K filed March 5,
2007.
|
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.
SIGNATURE
Pursuant
to the
requirements of the Securities Exchange Act of 1934, each Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto
duly
authorized.
May
9,
2007
|
FIRSTENERGY
CORP.
|
|
Registrant
|
|
|
|
OHIO
EDISON COMPANY
|
|
Registrant
|
|
|
|
THE
CLEVELAND ELECTRIC
|
|
ILLUMINATING
COMPANY
|
|
Registrant
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
Registrant
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
Registrant
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
Registrant
|
|
/s/ Harvey
L.
Wagner
|
|
Harvey
L.
Wagner
|
|
Vice
President, Controller
|
|
and
Chief
Accounting Officer
|