Form 10-Q dated November 1, 2005
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D. C. 20549
FORM
10-Q
(Mark
One)
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the
quarterly period ended September 30, 2005
OR
[
]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the transition period from
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to
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Commission
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Registrant;
State of Incorporation;
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I.R.S.
Employer
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File
Number
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Address;
and Telephone Number
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Identification
No.
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333-21011
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FIRSTENERGY
CORP.
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34-1843785
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(An
Ohio Corporation)
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-2578
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OHIO
EDISON COMPANY
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34-0437786
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-2323
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THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
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34-0150020
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3583
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THE
TOLEDO EDISON COMPANY
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34-4375005
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3491
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PENNSYLVANIA
POWER COMPANY
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25-0718810
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3141
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JERSEY
CENTRAL POWER & LIGHT COMPANY
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21-0485010
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(A
New Jersey Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-446
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METROPOLITAN
EDISON COMPANY
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23-0870160
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-3522
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PENNSYLVANIA
ELECTRIC COMPANY
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25-0718085
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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Indicate
by check
mark whether each of the registrants (1) has filed all reports required
to
be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject
to
such filing requirements for the past 90 days.
Yes
X
No
Indicate
by check
mark whether each registrant is an accelerated filer (as defined in Rule
12b-2
of the Act):
YesX
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No
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FirstEnergy
Corp.
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Yes
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NoX
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Ohio
Edison
Company, Pennsylvania Power Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light
Company, Metropolitan Edison Company, and Pennsylvania Electric
Company
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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
NOVEMBER 2,
2005
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FirstEnergy
Corp., $.10 par value
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329,836,276
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Ohio
Edison
Company, no par value
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100
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The
Cleveland
Electric Illuminating Company, no par value
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79,590,689
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The
Toledo
Edison Company, $5 par value
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39,133,887
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Pennsylvania
Power Company, $30 par value
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6,290,000
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Jersey
Central Power & Light Company, $10 par value
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15,371,270
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Metropolitan
Edison Company, no par value
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859,500
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Pennsylvania
Electric Company, $20 par value
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5,290,596
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FirstEnergy
Corp.
is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company common stock.
Ohio
Edison Company is the sole holder of Pennsylvania Power Company common stock.
This
combined Form
10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania
Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison
Company, Jersey Central Power & Light Company, Metropolitan Edison Company
and Pennsylvania Electric Company. Information contained herein relating
to any
individual registrant is filed by such registrant on its own behalf. No
registrant makes any representation as to information relating to any other
registrant, except that information relating to any of the FirstEnergy
subsidiary registrants is also attributed to FirstEnergy Corp.
This
Form 10-Q
includes forward-looking statements based on information currently available
to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
"anticipate", "potential", "expect", "believe", "estimate" and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets
for
energy services, changing energy and commodity market prices, replacement
power
costs being higher than anticipated or inadequately hedged, the continued
ability of our regulated utilities to collect transition and other charges,
maintenance costs being higher than anticipated, legislative and regulatory
changes (including revised environmental requirements), the uncertainty of
the
timing and amounts of the capital expenditures (including that such amounts
could be higher than anticipated) or levels of emission reductions related
to
the settlement agreement resolving the New Source Review litigation, adverse
regulatory or legal decisions and outcomes (including, but not limited to,
the
revocation of necessary licenses or operating permits, fines or other
enforcement actions and remedies) of government investigations and oversight,
including by the Securities and Exchange Commission, the United States
Attorney’s Office and the Nuclear Regulatory Commission as disclosed in the
registrants’ Securities and Exchange Commission filings, generally, and with
respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny
at the Perry Nuclear Power Plant in particular, the availability and cost
of
capital, rising interest rates and other inflationary trends, 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 of strategic goals (including the proposed transfer
of nuclear generation assets), the ability to improve electric commodity
margins
and to experience growth in the distribution business, any decision of the
Pennsylvania Public Utility Commission regarding the plan filed by Penn on
October 11, 2005 to secure electricity supply for its customers at a set
rate,
the ability to access the public securities and other capital markets, 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 final outcome in the proceeding related to
FirstEnergy's Application for a Rate Stabilization Plan (RSP) in Ohio,
specifically, the PUCO's acceptance of the September 9, 2005 proposed
supplement to the RSP, the risks and other factors discussed from time to
time
in the registrants' Securities and Exchange Commission filings, including
their
annual report on Form 10-K for the year ended December 31, 2004, and
other
similar factors. A security rating is not a recommendation to buy, sell or
hold
securities and it may be subject to revision or withdrawal. Dividends declared
from time to time on FirstEnergy's common stock during any annual period
may in
aggregate vary from the indicated amounts due to circumstances considered
by
FirstEnergy's Board of Directors at the time of the actual declarations.
The
registrants expressly disclaim any current intention to update any
forward-looking statements contained in this document 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
Results of Operation and Financial Condition
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Notes
to
Consolidated Financial Statements
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1-25
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FirstEnergy
Corp.
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Consolidated
Statements of Income
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26
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Consolidated
Statements of Comprehensive Income
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27
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Consolidated
Balance Sheets
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28
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Consolidated
Statements of Cash Flows
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29
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Report
of
Independent Registered Public Accounting Firm
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30
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Management's
Discussion and Analysis of Results of Operations and
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31-65
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Financial
Condition
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Ohio
Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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66
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Consolidated
Balance Sheets
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67
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Consolidated
Statements of Cash Flows
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68
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Report
of
Independent Registered Public Accounting Firm
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69
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Management's
Discussion and Analysis of Results of Operations and
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70-82
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Financial
Condition
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The
Cleveland Electric Illuminating Company
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Consolidated
Statements of Income and Comprehensive Income
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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 Results of Operations and
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87-98
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Financial
Condition
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The
Toledo Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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99
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Consolidated
Balance Sheets
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100
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Consolidated
Statements of Cash Flows
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101
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Report
of
Independent Registered Public Accounting Firm
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102
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Management's
Discussion and Analysis of Results of Operations and
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103-114
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Financial
Condition
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Pennsylvania
Power Company
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Consolidated
Statements
of Income and Comprehensive Income
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115
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Consolidated
Balance
Sheets
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116
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Consolidated
Statements
of Cash Flows
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117
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Report
of
Independent Registered Public Accounting Firm
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118
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Management's
Discussion and Analysis of Results of Operations and
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119-127
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Financial
Condition
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TABLE
OF
CONTENTS (Cont'd)
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Pages
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Jersey
Central Power & Light Company
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Consolidated
Statements of Income and Comprehensive Income
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128
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Consolidated
Balance Sheets
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129
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Consolidated
Statements of Cash Flows
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130
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Report
of
Independent Registered Public Accounting Firm
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131
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Management's
Discussion and Analysis of Results of Operations and
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132-140
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Financial
Condition
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Metropolitan
Edison Company
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Consolidated
Statements of Income and Comprehensive Income
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141
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Consolidated
Balance Sheets
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142
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Consolidated
Statements of Cash Flows
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143
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Report
of
Independent Registered Public Accounting Firm
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144
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Management's
Discussion and Analysis of Results of Operations and
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145-153
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Financial
Condition
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Pennsylvania
Electric Company
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Consolidated
Statements of Income and Comprehensive Income
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154
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Consolidated
Balance Sheets
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155
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Consolidated
Statements of Cash Flows
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156
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Report
of
Independent Registered Public Accounting Firm
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157
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Management's
Discussion and Analysis of Results of Operations and
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158-166
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Financial
Condition
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk
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167
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Item
4. Controls
and Procedures
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167
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Part
II. Other
Information
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Item
1. Legal
Proceedings
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168
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168
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Item
2. Changes
in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
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Item
5. Other
Information |
168
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Item 6. Exhibits
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169-184
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GLOSSARY
OF
TERMS
The
following
abbreviations and acronyms are used in this report to identify FirstEnergy
Corp.
and its current and former subsidiaries:
ATSI
|
American
Transmission Systems, Incorporated, owns and operates transmission
facilities
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CEI
|
The
Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
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CFC
|
Centerior
Funding Corporation, a wholly owned finance subsidiary of
CEI
|
Companies
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OE,
CEI, TE,
Penn, JCP&L, Met-Ed and Penelec
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EUOC
|
Electric
Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed,
Penelec, and ATSI)
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FENOC
|
FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
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FES
|
FirstEnergy
Solutions Corp., provides energy-related products and
services
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FESC
|
FirstEnergy
Service Company, provides legal, financial, and other corporate
support
services
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FGCO
|
FirstEnergy
Generation Corp., owns and operates non-nuclear generating
facilities
|
FirstCom
|
First
Communications, LLC, provides local and long-distance telephone
service
|
FirstEnergy
|
FirstEnergy
Corp., a registered public utility holding company
|
FSG
|
FirstEnergy
Facilities Services Group, LLC, the parent company of several
heating,
ventilation,
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|
air
conditioning and energy management companies
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GPU
|
GPU,
Inc.,
former parent of JCP&L, Met-Ed and Penelec, which merged with
FirstEnergy on
|
|
November 7,
2001
|
JCP&L
|
Jersey
Central Power & Light Company, a New Jersey electric utility operating
subsidiary
|
JCP&L
Transition
|
JCP&L
Transition Funding LLC, a Delaware limited liability company
and issuer of
transition bonds
|
Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
|
MYR
|
MYR
Group,
Inc., a utility infrastructure construction service
company
|
NGC
|
FirstEnergy
Nuclear Generation Corp. established to acquire FirstEnergy's
nuclear
generating facilities
|
OE
|
Ohio
Edison
Company, an Ohio electric utility operating subsidiary
|
OE
Companies
|
OE
and Penn
|
Ohio
Companies
|
CEI,
OE and
TE
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Penelec
|
Pennsylvania
Electric Company, a Pennsylvania electric utility operating
subsidiary
|
Penn
|
Pennsylvania
Power Company, a Pennsylvania electric utility operating subsidiary
of
OE
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PNBV
|
PNBV
Capital
Trust, a special purpose entity created by OE in 1996
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Shippingport
|
Shippingport
Capital Trust, a special purpose entity created by CEI and
TE in
1997
|
TE
|
The
Toledo
Edison Company, an Ohio electric utility operating
subsidiary
|
TEBSA
|
Termobarranquilla
S. A., Empresa de Servicios
Publicos
|
The
following
abbreviations and acronyms are used to identify frequently used terms in
this
report:
AOCL
|
Accumulated
Other Comprehensive Loss
|
APB
|
Accounting
Principles Board
|
APB
25
|
APB
Opinion
No. 25, "Accounting for Stock Issued to Employees"
|
APB
29
|
APB
Opinion
No. 29, “Accounting for Nonmonetary Transactions”
|
ARO
|
Asset
Retirement Obligation
|
BGS
|
Basic
Generation Service
|
CAIR
|
Clean
Air
Interstate Rule
|
CAL
|
Confirmatory
Action Letter
|
CAT
|
Commercial
Activity Tax
|
CO2
|
Carbon
Dioxide |
CTC
|
Competitive
Transition Charge
|
DOJ
|
United
States
Department of Justice
|
ECAR
|
East
Central
Area Reliability Coordination Agreement
|
EITF
|
Emerging
Issues Task Force
|
EITF
03-1
|
EITF
Issue
No. 03-1, "The Meaning of Other-Than-Temporary and Its Application
to
Certain
|
|
Investments”
|
EITF
04-13
|
EITF
Issue
No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same
Counterparty”
|
EITF
99-19
|
EITF
Issue
No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an
Agent”
|
EPA
|
Environmental
Protection Agency
|
ERO
|
Electric
Reliability Organization
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy Regulatory Commission
|
FIN
|
FASB
Interpretation
|
FIN
46R
|
FIN
46
(revised December 2003), "Consolidation of Variable Interest
Entities"
|
FIN
47
|
FASB
Interpretation 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation
of FASB Statement No. 143”
|
FMBs
|
First
Mortgage Bonds
|
FSP
|
FASB
Staff
Position
|
FSP
EITF
03-1-1
|
FASB
Staff
Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs
10-20 of
EITF Issue
|
|
No.
03-1,
The
Meaning of Other-Than-Temporary Impairment and Its Application
to Certain
|
|
Investments"
|
FSP
109-1
|
FASB
Staff
Position No. 109-1, “Application of FASB Statement No. 109,
Accounting for Income
Taxes,
to the Tax
Deduction on Qualified Production Activities Provided by the
American
Jobs
Creation
Act
of 2004”
|
GCAF
|
Generation
Charge Adjustment Factor
|
GAAP
|
Accounting
Principles Generally Accepted in the United States
|
GHG
|
Greenhouse
Gases
|
HVAC
|
Heating,
Ventilation and Air-conditioning
|
IBEW
|
International
Brotherhood of Electrical Workers
|
KWH
|
Kilowatt-hours
|
LOC
|
Letter
of
Credit
|
MEIUG
|
Met-Ed
Industrial Users Group
|
MISO
|
Midwest
Independent Transmission System Operator, Inc.
|
MOU
|
Memorandum
of
Understanding
|
MSG
|
Market
Support Generation
|
MTC
|
Market
Transition Charge
|
MW
|
Megawatts
|
NAAQS
|
National
Ambient Air Quality Standards
|
NERC
|
North
American Electric Reliability Council
|
NJBPU
|
New
Jersey
Board of Public Utilities
|
NOAC
|
Northwest
Ohio Aggregation Coalition
|
NOV
|
Notices
of
Violation
|
NOx
|
Nitrogen
Oxide
|
NRC
|
Nuclear
Regulatory Commission
|
NUG
|
Non-Utility
Generation
|
OCA
|
Office
of
Consumer Advocate
|
OCC
|
Ohio
Consumers' Counsel
|
OCI
|
Other
Comprehensive Income
|
OPAE
|
Ohio
Partners
for Affordable Energy
|
OPEB
|
Other
Post-Employment Benefits
|
OSBA
|
Office
of
Small Business Advocate
|
OTS
|
Office
of
Trial Staff
|
PCAOB
|
Public
Company Accounting Oversight Board (United States)
|
PCRBs
|
Pollution
Control Revenue Bonds
|
PICA
|
Penelec
Industrial Customer Association
|
PJM
|
PJM
Interconnection, L.L.C.
|
PLR
|
Provider
of
Last Resort
|
PPUC
|
Pennsylvania
Public Utility Commission
|
PRP
|
Potentially
Responsible Party
|
PSA
|
Purchase
and
Sale Agreement
|
PUCO
|
Public
Utilities Commission of Ohio
|
PUHCA
|
Public
Utility Holding Company Act of 1935
|
RCP
|
Rate
Certainty Plan
|
RSP
|
Rate
Stabilization Plan
|
RTC
|
Regulatory
Transition Charge
|
S&P
|
Standard
& Poor’s Ratings Service
|
SBC
|
Societal
Benefits Charge
|
SEC
|
United
States
Securities and Exchange Commission
|
SFAS
|
Statement
of
Financial Accounting Standards
|
SFAS
71
|
SFAS
No. 71,
"Accounting for the Effects of Certain Types of
Regulation"
|
SFAS
123
|
SFAS
No. 123,
"Accounting for Stock-Based Compensation"
|
SFAS
123(R)
|
SFAS
No. 123
(revised 2004), “Share-Based Payment”
|
SFAS
131
|
SFAS
No. 131,
“Disclosures about Segments of an Enterprise and Related
Information”
|
SFAS
133
|
SFAS
No. 133,
“Accounting for Derivative Instruments and Hedging
Activities”
|
SFAS
140
|
SFAS
No. 140,
“Accounting for Transfers and Servicing of Financial Assets
and
|
|
Extinguishment
of Liabilities”
|
SFAS
144
|
SFAS
No. 144,
"Accounting for the Impairment or Disposal of Long-Lived
Assets"
|
SFAS
153
|
SFAS
No. 153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion
No.
29”
|
|
|
SFAS
154
|
SFAS
No. 154,
“Accounting Changes and Error Corrections - a replacement of APB
Opinion
No.
20
and FASB
Statement No. 3”
|
SO2
|
Sulfur
Dioxide
|
TBC
|
Transition
Bond Charge
|
TMI-2
|
Three
Mile
Island Unit 2
|
UWUA
|
Utility
Workers Union of America
|
VIE
|
Variable
Interest Entity
|
PART
I.
FINANCIAL INFORMATION
FIRSTENERGY
CORP. AND SUBSIDIARIES
OHIO
EDISON
COMPANY AND SUBSIDIARIES
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE
TOLEDO
EDISON COMPANY AND SUBSIDIARY
PENNSYLVANIA
POWER COMPANY AND SUBSIDIARY
JERSEY
CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN
EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA
ELECTRIC COMPANY AND SUBSIDIARIES
NOTES
TO
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1
-
ORGANIZATION AND BASIS OF PRESENTATION:
FirstEnergy’s
principal business is the holding, directly or indirectly, of all of the
outstanding common stock of its eight principal electric utility operating
subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a
wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements
also include its other principal subsidiaries: FENOC, FES and its subsidiary
FGCO, FESC, FSG and MYR.
FirstEnergy
and its
subsidiaries follow GAAP and comply with the regulations, orders, policies
and
practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and
NJBPU.
The preparation of financial statements in conformity with GAAP requires
management to make periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates. The reported results of operations are not indicative of results
of
operations for any future period.
These
statements
should be read in conjunction with the financial statements and notes included
in the combined Annual Report on Form 10-K for the year ended December 31,
2004 for FirstEnergy and the Companies. The consolidated unaudited financial
statements of FirstEnergy and each of the Companies reflect all normal recurring
adjustments that, in the opinion of management, are necessary to fairly present
results of operations for the interim periods. Certain businesses divested
in
the nine months ended September 30, 2005 have been classified as discontinued
operations on the Consolidated Statements of Income (see Note 6). As discussed
in Note 16, interim period segment reporting in 2004 was reclassified to
conform
with the current year business segment organizations and operations.
FirstEnergy
and its
subsidiaries consolidate all majority-owned subsidiaries over which they
exercise control and, when applicable, entities for which they have a
controlling financial interest. Intercompany transactions and balances are
eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 11)
when
it is determined to be the VIE's primary beneficiary. Investments in
nonconsolidated affiliates over which FirstEnergy and its subsidiaries have
the
ability to exercise significant influence, but not control, (20-50 percent
owned
companies, joint ventures and partnerships) are accounted for under the equity
method. Under the equity method, the interest in the entity is reported as
an
investment in the Consolidated Balance Sheet and the percentage share of
the
entity’s earnings is reported in the Consolidated Statement of Income.
Certain
prior year
amounts have been reclassified to conform to the current
presentation.
FirstEnergy's
and
the Companies' independent registered public accounting firm has performed
reviews of, and issued reports on, these consolidated interim financial
statements in accordance with standards established by the PCAOB. Pursuant
to
Rule 436(c) under the Securities Act of 1933, their reports of those reviews
should not be considered a report within the meaning of Section 7 and 11
of that
Act, and the independent registered public accounting firm’s liability under
Section 11 does not extend to them.
2
-
ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS
FES
engages in
purchase and sale transactions in the PJM Market to support the supply of
end-use customers, including PLR requirements in Pennsylvania. In conjunction
with FirstEnergy's dedication of its Beaver Valley Plant to PJM on
January 1, 2005, FES
began
accounting for purchase and sale transactions in the PJM Market based on
its net
hourly position -- recording each hour as either an energy purchase in Fuel
and
purchased power expense or an energy sale, respectively, in the Consolidated
Statements of Income relating to the Power Supply Management Services segment.
Hourly energy positions are aggregated to recognize gross purchases and sales
for the month.
This
revised method
of accounting, which has no impact on net income, is consistent with the
practice of other energy companies that have dedicated generating capacity
to
PJM and correlates with PJM's scheduling and reporting of hourly energy
transactions. FES also applies the net hourly methodology to purchase and
sale
transactions in MISO's energy market, which became active on April 1,
2005.
For
periods prior
to January 1, 2005, FirstEnergy did not have substantial generating
capacity in PJM and as such, FES recognized purchases and sales in the
PJM
Market by recording each discrete transaction. Under these transactions,
FES
would often buy a specific quantity of energy at a certain location in
PJM and
simultaneously sell a specific quantity of energy at a different location.
Physical delivery occurred and the risks and rewards of ownership transferred
with each transaction. FES
accounted for
those transactions on a gross basis in accordance with EITF 99-19.
At
its September
2005 meeting, the FASB's EITF reached a final consensus on EITF 04-13,
which
relates to the accounting for purchases and sales of inventory with the
same
counterparty. The Task Force concluded that two or more transactions with
the
same counterparty should be viewed as a single nonmonetary transaction
within
the scope of APB 29, when the transactions are entered into "in contemplation"
of one another. The consensus will be effective for new arrangements entered
into, or modifications of existing arrangements, in interim or annual periods
beginning after March 15, 2006. Retrospective application to prior
transactions and/or restatement of prior period financial statements is
not
permitted. Accordingly, EITF 04-13 is not applicable to FES' purchases
and sales
in the PJM Market made prior to January 1, 2005. The recognition
of these
transactions on a net basis in 2004 would have no impact on net income,
but
would have reduced both wholesale revenue and purchased power expense by
$264
million and $828 million for the three months and nine months ended
September 30, 2004, respectively.
3
-
DEPRECIATION
During
the second
half of 2004, FirstEnergy engaged an independent third party to assist
in
reviewing the service lives of its fossil generation units. This study
was
completed in the first quarter of 2005. As a result of the analysis, FirstEnergy
extended the estimated service lives of its fossil generation units for
periods
ranging from 11 to 33 years during the first quarter of 2005. Extension
of the
service lives will provide improved matching of depreciation expense with
the
expected economic lives of those generation units.
4
-
EARNINGS PER SHARE
Basic
earnings per
share are computed using the weighted average of actual common shares
outstanding during the respective period as the denominator. The denominator
for
diluted earnings per share reflects the weighted average of common shares
outstanding plus the potential additional common shares that could result
if
dilutive securities and other agreements to issue common stock were exercised.
Stock-based awards during the nine months ended September 30, 2004,
to
purchase 3.4 million shares of common stock were excluded from the calculation
of diluted earnings per share of common stock because their exercise prices
were
greater than the average market price of common shares during the period.
No
stock-based awards were excluded from the calculation in the three months
ended
September 30, 2005 and 2004, and the nine months ended September 30,
2005. The following table reconciles the denominators for basic and diluted
earnings per share from Income Before Discontinued Operations:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Basic and Diluted Earnings per Share
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before
Discontinued Operations
|
|
$
|
331,832
|
|
$
|
296,125
|
|
$
|
651,627
|
|
$
|
670,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Shares of Common Stock Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for basic earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(weighted
average shares outstanding)
|
|
|
328,119
|
|
|
327,499
|
|
|
328,030
|
|
|
327,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
2,074
|
|
|
1,600
|
|
|
1,896
|
|
|
1,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
for diluted earnings per share
|
|
|
330,193
|
|
|
329,099
|
|
|
329,926
|
|
|
328,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before
Discontinued Operations per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$1.01
|
|
|
$0.90
|
|
|
$1.99
|
|
|
$2.05
|
|
Diluted
|
|
|
$1.01
|
|
|
$0.90
|
|
|
$1.98
|
|
|
$2.04
|
|
5
-
GOODWILL
In
a business
combination, the excess of the purchase price over the estimated fair values
of
assets acquired and liabilities assumed is recognized as goodwill. Based
on the
guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment
at least annually and would make such an evaluation more frequently if
indicators of impairment should arise. In accordance with the accounting
standard, if the fair value of a reporting unit is less than its carrying
value
(including goodwill), the goodwill is tested for impairment. If impairment
is
indicated, FirstEnergy recognizes a loss - calculated as the difference
between
the implied fair value of a reporting unit's goodwill and the carrying
value of
the goodwill. FirstEnergy's 2005 annual review was completed in the third
quarter of 2005 with no impairment indicated.
FirstEnergy's
goodwill primarily relates to its regulated services segment. In the nine
months
ended September 30, 2005, FirstEnergy adjusted goodwill related
to the
divestiture of non-core operations (FES' retail natural gas business, MYR's
Power Piping Company subsidiary, and a portion of its interest in FirstCom)
as
further discussed in Note 6. In addition, adjustments to the former GPU
and
Centerior companies' goodwill were recorded to reverse pre-merger tax accruals
due to final resolution of these tax contingencies. FirstEnergy estimates
that
completion of transition cost recovery (see Note 14) will not result in
an
impairment of goodwill relating to its regulated business segment. A summary
of
the changes in goodwill for the three months and nine months ended
September 30, 2005 is shown below.
Three
Months Ended
|
|
FirstEnergy
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance
as of
July 1, 2005
|
|
$
|
6,033
|
|
$
|
1,694
|
|
$
|
505
|
|
$
|
1,984
|
|
$
|
868
|
|
$
|
887
|
|
Pre-merger
tax adjustments related to Centerior acquisition
|
|
|
(9
|
)
|
|
(5
|
)
|
|
(4
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance
as of
September 30, 2005
|
|
$
|
6,024
|
|
$
|
1,689
|
|
$
|
501
|
|
$
|
1,984
|
|
$
|
868
|
|
$
|
887
|
|
Nine
Months Ended
|
|
FirstEnergy
|
|
CEI
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance
as of
January 1, 2005
|
|
$
|
6,050
|
|
$
|
1,694
|
|
$
|
505
|
|
$
|
1,985
|
|
$
|
870
|
|
$
|
888
|
|
Non-core
asset sales
|
|
|
(13
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Pre-merger
tax adjustments related to Centerior acquisition
|
|
|
(9
|
)
|
|
(5
|
)
|
|
(4
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
Pre-merger
tax adjustments related to GPU acquisition
|
|
|
(4
|
)
|
|
-
|
|
|
-
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(1
|
)
|
Balance
as of
September 30, 2005
|
|
$
|
6,024
|
|
$
|
1,689
|
|
$
|
501
|
|
$
|
1,984
|
|
$
|
868
|
|
$
|
887
|
|
6
-
DIVESTITURES AND DISCONTINUED OPERATIONS
In
December 2004,
FES' retail natural gas business qualified as assets held for sale in accordance
with SFAS 144. On March 31, 2005, FES completed the sale for an
after-tax
gain of $5 million. In March 2005, FirstEnergy sold 51% of its interest
in
FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts
for
its remaining 31.85% interest in FirstCom on the equity basis.
During
the nine
months ended September 30, 2005, FirstEnergy sold certain of its
FSG
subsidiaries (Elliott-Lewis, Spectrum and Cranston), and MYR’s Power Piping
Company subsidiary, resulting in an after-tax gain of $12 million.
FSG's
remaining subsidiaries qualify as assets held for sale in accordance with
SFAS
144 and are expected to be recognized as completed sales within one year.
The
assets and liabilities of these remaining FSG subsidiaries are not material
to
FirstEnergy’s Consolidated Balance Sheet as of September 30, 2005, and
therefore have not been separately classified as assets held for
sale.
As
of
September 30, 2005, the remaining FSG businesses do not meet the
criteria
for discontinued operations; therefore, the net results from these subsidiaries
have been included in continuing operations. See Note 16 for FSG's segment
financial information.
Operating
results
from discontinued operations (including the gains on sales of assets discussed
above) for Elliott-Lewis, Cranston, Power Piping and FES' retail natural
gas
business are summarized as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
Revenues
|
|
$
|
1
|
|
$
|
151
|
|
$
|
214
|
|
$
|
508
|
|
Income
before
income taxes
|
|
$
|
1
|
|
$
|
4
|
|
$
|
10
|
|
$
|
10
|
|
Income
from
discontinued operations, net of tax
|
|
$
|
1
|
|
$
|
3
|
|
$
|
19
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following table
summarizes the sources of income from discontinued operations.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
Discontinued
operations (net of tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on
sale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
gas
business
|
|
$
|
-
|
|
$
|
-
|
|
$
|
5
|
|
$
|
-
|
|
FSG
and MYR
subsidiaries
|
|
|
-
|
|
|
-
|
|
|
12
|
|
|
-
|
|
Reclassification
of operating income, net of tax
|
|
|
1
|
|
|
3
|
|
|
2
|
|
|
6
|
|
Total
|
|
$
|
1
|
|
$
|
3
|
|
$
|
19
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
-
DERIVATIVE INSTRUMENTS
FirstEnergy
is
exposed to financial risks resulting from the fluctuation of interest rates
and
commodity prices, including prices for electricity, natural gas, coal and
energy
transmission. To manage the volatility relating to these exposures, FirstEnergy
uses a variety of non-derivative and derivative instruments, including
forward
contracts, options, futures contracts and swaps. The derivatives are used
principally for hedging purposes, and to a lesser extent, for trading purposes.
FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
provides general management oversight to risk management activities throughout
the Company.
FirstEnergy
accounts for derivative instruments on its Consolidated Balance Sheet at
their
fair value unless they meet the normal purchase and normal sales criteria.
Derivatives that meet that criteria are accounted for on the accrual basis.
The
changes in the fair value of a derivative instrument are recorded in current
earnings, in other comprehensive income, 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
has
entered into fair value hedges of fixed-rate, long-term debt issues to
protect
against the risk of changes in the fair value of fixed-rate debt instruments
due
to lower interest rates. Swap
maturities,
call options, fixed interest rates received, and interest payment dates
match
those of the underlying debt obligations. During
the third
quarter of 2005, FirstEnergy unwound swaps with a total notional amount
of $350
million from which it received immaterial net cash gains. The gains will
be
recognized in earnings over the remaining maturity of each respective hedged
security as reduced interest expense. As of September 30, 2005,
the
aggregate notional value of interest rate swap agreements outstanding was
$1.05
billion.
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 impact of ineffectiveness on earnings during the three months and nine
months ended September 30, 2005 was not material.
During
the third
quarter of 2005, 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 possible issuances of fixed-rate,
long-term debt securities for one or more of its consolidated entities
in the
second half of 2006 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. As of
September 30, 2005, FirstEnergy had entered into forward swaps with
an
aggregate notional amount of $500 million. As of September 30, 2005
the
forward swaps had a fair value of $2 million.
The
net deferred
losses of $79 million included in AOCL as of September 30, 2005,
for
derivative hedging activity, as compared to the December 31, 2004
balance
of $92 million of net deferred losses, resulted from a $6 million
decrease
related to current hedging activity, a $4 million increase due to the sale
of
gas business contracts and an $11 million decrease due to net hedge
losses
included in earnings during the nine months ended September 30,
2005.
Approximately $14 million of the net deferred losses on derivative instruments
in AOCL as of September 30, 2005 is expected to be reclassified
to earnings
during the next twelve months as hedged transactions occur. The fair value
of
these derivative instruments will fluctuate from period to period based
on
various market factors.
FirstEnergy
trades
commodity derivatives and periodically experiences net open positions.
FirstEnergy’s risk management policies limit the exposure to market risk from
open positions and require daily reporting to management of potential financial
exposures. During the three months and nine months ended September 30,
2005, the effect of trading on earnings was not material.
8
- STOCK
BASED COMPENSATION
FirstEnergy
applies
the recognition and measurement principles of APB 25 and related interpretations
in accounting for its stock-based compensation plans. No material stock-based
employee compensation expense is reflected in net income for options as
all
options granted under those plans have exercise prices equal to the market
value
of the underlying common stock on the respective grant dates, resulting
in
substantially no intrinsic value.
In
December 2004,
the FASB issued SFAS 123(R), a revision to SFAS 123 which requires expensing
the
fair value of stock options (see Note 15). In April 2005, the SEC delayed
the
effective date of SFAS 123(R) to annual, rather than interim, periods that
begin
after June 15, 2005. FirstEnergy will be required to adopt this
standard
beginning January 1, 2006. The table below summarizes the effects
on
FirstEnergy’s net income and earnings per share had FirstEnergy applied the fair
value recognition provisions of SFAS 123(R) to stock-based employee compensation
in the current reporting periods.
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
|
(In
thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income,
as reported
|
|
|
|
$
|
332,360
|
|
$
|
298,622
|
|
$
|
670,078
|
|
$
|
676,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add
back
compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
reported
in
net income, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(based
on APB
25)(1)
|
|
|
|
|
17,404
|
|
|
13,549
|
|
|
39,785
|
|
|
29,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deduct
compensation expense based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
upon
estimated fair value, net of tax(2)
|
|
|
|
|
(18,378
|
)
|
|
(16,981
|
)
|
|
(44,825
|
)
|
|
(40,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income,
as adjusted
|
|
|
|
$
|
331,386
|
|
$
|
295,190
|
|
$
|
665,038
|
|
$
|
665,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Per
Share of Common Stock -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
reported
|
|
|
|
|
$1.01
|
|
|
$0.91
|
|
|
$2.04
|
|
|
$2.07
|
|
As
adjusted
|
|
|
|
|
$1.01
|
|
|
$0.90
|
|
|
$2.03
|
|
|
$2.03
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
reported
|
|
|
|
|
$1.01
|
|
|
$0.91
|
|
|
$2.03
|
|
|
$2.06
|
|
As
adjusted
|
|
|
|
|
$1.00
|
|
|
$0.90
|
|
|
$2.02
|
|
|
$2.02
|
|
|
|
(1) Includes
restricted stock, restricted stock units, stock options, performance
shares, Employee Stock
Ownership
Plan, Executive
Deferred Compensation Plan and Deferred Compensation Plan for
outside Directors.
|
|
(2)
Assumes
vesting at age 65.
|
|
FirstEnergy
reduced
the use of stock options in 2005 and increased the use of performance-based,
restricted stock units. Therefore, the pro forma effects of applying SFAS
123(R)
may not be representative of its future effect. FirstEnergy does not expect
to
accelerate out-of-the-money options in anticipation of implementing SFAS
123(R)
on January 1, 2006.
9
- ASSET
RETIREMENT OBLIGATIONS
FirstEnergy
has
identified applicable legal obligations for nuclear power plant decommissioning,
reclamation of a sludge disposal pond related to the Bruce Mansfield Plant
and
closure of two coal ash disposal sites. The ARO liability of $1.130 billion
as
of September 30, 2005 included $1.115 billion for nuclear decommissioning
of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating
facilities. The Companies' share of 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.
In
the third
quarter of 2005, FirstEnergy revised the ARO associated with Beaver Valley
Units
1 and 2 as a result of an updated decommissioning study. The present value
of
revisions in the estimated cash flows associated with projected decommissioning
costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased
the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease
in
the ARO liability and corresponding plant asset of $1 million (OE
- ($2)
million, CEI - ($5) million, TE - ($5) million and Penn -
$11
million).
The
Companies
maintain trust funds that are legally restricted for purposes of settling
the
nuclear decommissioning ARO. As of September 30, 2005, the fair
value of
the decommissioning trust assets was $1.7 billion.
The
following
tables analyze changes to the ARO balance during the three months and nine
months ended September 30, 2005 and 2004, respectively.
Three
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
Penn
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance,
July
1, 2005
|
|
$
|
1,113
|
|
$
|
208
|
|
$
|
281
|
|
$
|
201
|
|
$
|
143
|
|
$
|
75
|
|
$
|
137
|
|
$
|
68
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
18
|
|
|
3
|
|
|
5
|
|
|
4
|
|
|
2
|
|
|
1
|
|
|
2
|
|
|
1
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
flows
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
11
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2005
|
|
$
|
1,130
|
|
$
|
209
|
|
$
|
281
|
|
$
|
200
|
|
$
|
156
|
|
$
|
76
|
|
$
|
139
|
|
$
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
July
1, 2004
|
|
$
|
1,217
|
|
$
|
194
|
|
$
|
263
|
|
$
|
188
|
|
$
|
134
|
|
$
|
113
|
|
$
|
216
|
|
$
|
108
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
19
|
|
|
4
|
|
|
5
|
|
|
3
|
|
|
2
|
|
|
2
|
|
|
3
|
|
|
1
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
flows
|
|
|
(176
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(43
|
)
|
|
(89
|
)
|
|
(44
|
)
|
Balance,
September 30, 2004
|
|
$
|
1,060
|
|
$
|
198
|
|
$
|
268
|
|
$
|
191
|
|
$
|
136
|
|
$
|
72
|
|
$
|
130
|
|
$
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
FirstEnergy
|
|
OE
|
|
CEI
|
|
TE
|
|
Penn
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
Balance,
January 1, 2005
|
|
$
|
1,078
|
|
$
|
201
|
|
$
|
272
|
|
$
|
195
|
|
$
|
138
|
|
$
|
72
|
|
$
|
133
|
|
$
|
67
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
53
|
|
|
10
|
|
|
14
|
|
|
10
|
|
|
7
|
|
|
4
|
|
|
6
|
|
|
2
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
flows
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
11
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance,
September 30, 2005
|
|
$
|
1,130
|
|
$
|
209
|
|
$
|
281
|
|
$
|
200
|
|
$
|
156
|
|
$
|
76
|
|
$
|
139
|
|
$
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2004
|
|
$
|
1,179
|
|
$
|
188
|
|
$
|
255
|
|
$
|
182
|
|
$
|
130
|
|
$
|
110
|
|
$
|
210
|
|
$
|
105
|
|
Liabilities
incurred
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Liabilities
settled
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Accretion
|
|
|
57
|
|
|
10
|
|
|
13
|
|
|
9
|
|
|
6
|
|
|
5
|
|
|
9
|
|
|
4
|
|
Revisions
in
estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
flows
|
|
|
(176
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(43
|
)
|
|
(89
|
)
|
|
(44
|
)
|
Balance,
September 30, 2004
|
|
$
|
1,060
|
|
$
|
198
|
|
$
|
268
|
|
$
|
191
|
|
$
|
136
|
|
$
|
72
|
|
$
|
130
|
|
$
|
65
|
|
10
-
PENSION AND OTHER POSTRETIREMENT BENEFITS:
The
components of
FirstEnergy's net periodic pension cost and other postretirement benefits
cost
(including amounts capitalized) for the three months and nine months ended
September 30, 2005 and 2004, consisted of the following:
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Pension
Benefits
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
19
|
|
$
|
19
|
|
$
|
58
|
|
$
|
58
|
|
Interest
cost
|
|
|
64
|
|
|
63
|
|
|
191
|
|
|
189
|
|
Expected
return on plan assets
|
|
|
(86
|
)
|
|
(71
|
)
|
|
(259
|
)
|
|
(215
|
)
|
Amortization
of prior service cost
|
|
|
2
|
|
|
2
|
|
|
6
|
|
|
7
|
|
Recognized
net actuarial loss
|
|
|
9
|
|
|
10
|
|
|
27
|
|
|
29
|
|
Net
periodic
cost
|
|
$
|
8
|
|
$
|
23
|
|
$
|
23
|
|
$
|
68
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Other
Postretirement Benefits
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
10
|
|
$
|
9
|
|
$
|
30
|
|
$
|
27
|
|
Interest
cost
|
|
|
27
|
|
|
26
|
|
|
83
|
|
|
83
|
|
Expected
return on plan assets
|
|
|
(11
|
)
|
|
(10
|
)
|
|
(34
|
)
|
|
(32
|
)
|
Amortization
of prior service cost
|
|
|
(11
|
)
|
|
(9
|
)
|
|
(33
|
)
|
|
(28
|
)
|
Recognized
net actuarial loss
|
|
|
10
|
|
|
9
|
|
|
30
|
|
|
29
|
|
Net
periodic
cost
|
|
$
|
25
|
|
$
|
25
|
|
$
|
76
|
|
$
|
79
|
|
Pension
and
postretirement benefit obligations are allocated to the FirstEnergy subsidiaries
employing the plan participants. The Companies capitalize employee benefits
related to construction projects. The net periodic pension benefits (credit)
and
net periodic postretirement benefits (including amounts capitalized) recognized
by each of the Companies in the three months and nine months ended
September 30, 2005 and 2004 were as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Pension
Benefits (Credit)
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
OE
|
|
$
|
0.2
|
|
$
|
1.7
|
|
$
|
0.7
|
|
$
|
5.2
|
|
Penn
|
|
|
(0.2
|
)
|
|
0.1
|
|
|
(0.7
|
)
|
|
0.4
|
|
CEI
|
|
|
0.3
|
|
|
1.6
|
|
|
1.0
|
|
|
4.8
|
|
TE
|
|
|
0.3
|
|
|
0.8
|
|
|
1.0
|
|
|
2.3
|
|
JCP&L
|
|
|
(0.3
|
)
|
|
1.9
|
|
|
(0.8
|
)
|
|
5.6
|
|
Met-Ed
|
|
|
(1.1
|
)
|
|
0.1
|
|
|
(3.2
|
)
|
|
0.2
|
|
Penelec
|
|
|
(1.3
|
)
|
|
0.1
|
|
|
(4.0
|
)
|
|
0.4
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Other
Postretirement Benefits
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
OE
|
|
$
|
5.8
|
|
$
|
5.7
|
|
$
|
17.3
|
|
$
|
17.7
|
|
Penn
|
|
|
1.2
|
|
|
1.2
|
|
|
3.5
|
|
|
3.7
|
|
CEI
|
|
|
3.8
|
|
|
4.4
|
|
|
11.4
|
|
|
13.7
|
|
TE
|
|
|
2.2
|
|
|
1.7
|
|
|
6.5
|
|
|
5.0
|
|
JCP&L
|
|
|
1.5
|
|
|
1.0
|
|
|
5.7
|
|
|
3.5
|
|
Met-Ed
|
|
|
0.4
|
|
|
0.7
|
|
|
1.2
|
|
|
2.5
|
|
Penelec
|
|
|
2.0
|
|
|
0.7
|
|
|
5.9
|
|
|
2.5
|
|
11
-
VARIABLE INTEREST ENTITIES
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 three-percent equity interest
by a
nonaffiliated third party and a three-percent equity interest held by OES
Ventures, a wholly owned subsidiary of OE. Shippingport was established
to
purchase all of the lease obligation bonds issued in connection with CEI’s and
TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and
TE
used debt and available funds to purchase the notes issued by
Shippingport.
OE,
CEI and TE are
exposed to losses under the applicable sale-leaseback agreements upon the
occurrence of certain contingent events that each company considers unlikely
to
occur. OE, CEI and TE each have a maximum exposure to loss under these
provisions of approximately $1 billion, which represents the net amount
of
casualty value payments upon the occurrence of specified casualty events
that
render the applicable plant worthless. Under the applicable sale and leaseback
agreements, OE, CEI and TE have net minimum discounted lease payments of
$678
million, $103 million and $541 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
structured 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. The maximum exposure to loss from these entities results
from
increases in the variable pricing component under the contract terms and
cannot
be determined without the requested data. Purchased power costs from these
entities during the three months and nine months ended September 30,
2005
and 2004 are shown in the table below:
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JCP&L
|
$
|
33
|
|
$
|
26
|
|
$
|
74
|
|
$
|
71
|
|
Met-Ed
|
|
10
|
|
|
13
|
|
|
40
|
|
|
38
|
|
Penelec
|
|
7
|
|
|
7
|
|
|
21
|
|
|
20
|
|
Total
|
$
|
50
|
|
$
|
46
|
|
$
|
135
|
|
$
|
129
|
|
Securitized
Transition Bonds
The
consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition, a wholly owned limited liability company of JCP&L. In
June 2002, JCP&L Transition sold $320 million of transition bonds to
securitize the recovery of JCP&L's bondable stranded costs associated with
the previously divested Oyster Creek Nuclear Generating Station.
JCP&L
did not
purchase and does not own any of the transition bonds, which are included
as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The
transition bonds are obligations of JCP&L Transition only and are
collateralized solely by the equity and assets of JCP&L Transition, which
consist primarily of bondable transition property. The bondable transition
property is solely the property of JCP&L Transition.
Bondable
transition
property represents the irrevocable right under New Jersey law of a utility
company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on the transition
bonds
and other fees and expenses associated with their issuance. JCP&L sold the
bondable transition property to JCP&L Transition and, as servicer, manages
and administers the bondable transition property, including the billing,
collection and remittance of the TBC, pursuant to a servicing agreement
with
JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $0.1
million that is payable from TBC collections.
12
- OHIO
TAX LEGISLATION
On
June 30,
2005, the State of Ohio enacted tax legislation that creates a new CAT
tax,
which is based on qualifying “taxable gross receipts” and will not consider any
expenses or costs incurred to generate such receipts, except for items
such as
cash discounts, returns and allowances, and bad debts. The CAT tax was
effective
July 1, 2005, and replaces the Ohio income-based franchise tax and
the Ohio
personal property tax. The CAT tax is phased-in while the current income-based
franchise tax is phased-out over a five-year period at a rate of 20% annually,
beginning with the year ended 2005, and the personal property tax is phased-out
over a four-year period at a rate of approximately 25% annually, beginning
with
the year ended 2005. For example, during the phase-out period the Ohio
income-based franchise tax will be computed consistently with the prior
tax law,
except that the tax liability as computed will be multiplied by 4/5 in
2005; 3/5
in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current
income-based franchise
tax over
a five-year period. As a result of the new tax structure, all net deferred
tax
benefits that were not expected to reverse during the five-year phase-in
period
were written-off as of June 30, 2005.
The
increase (in
millions) to income taxes associated with the adjustment to net deferred
taxes
for the nine months ended September 30, 2005 is summarized
below:
OE
|
|
$
|
36.0
|
CEI
|
|
|
7.5
|
TE
|
|
|
17.5
|
Other
FirstEnergy subsidiaries
|
|
|
10.7
|
Total
FirstEnergy
|
|
$
|
71.7
|
Income
tax expenses
were (increased) reduced during the three months and nine months ended
September 30, 2005 by the initial phase-out of the Ohio income-based
franchise tax and phase-in of the CAT tax as summarized below:
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2005
|
|
September
30, 2005
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
OE
|
|
$
|
1.6
|
|
$
|
6.5
|
|
CEI
|
|
|
(3.1
|
)
|
|
(1.7
|
)
|
TE
|
|
|
0.7
|
|
|
1.2
|
|
Other
FirstEnergy subsidiaries
|
|
|
0.7
|
|
|
1.5
|
|
Total
FirstEnergy
|
|
$
|
(0.1
|
)
|
$
|
7.5
|
|
13
-
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.
Such agreements include contract guarantees, surety bonds and ratings contingent
collateralization provisions. As of September 30, 2005, outstanding
guarantees and other assurances aggregated approximately $2.7 billion and
included contract guarantees ($1.3 billion), surety bonds ($0.3 billion)
and LOCs ($1.1 billion).
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved
in
energy commodity activities - principally to facilitate normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy to fulfill the obligations
of
those subsidiaries directly involved in energy and energy-related transactions
or financing where the law might otherwise limit the counterparties' claims.
If
demands of a counterparty were to exceed the ability of a subsidiary to
satisfy
existing obligations, FirstEnergy's guarantee enables the counterparty's
legal
claim to be satisfied by other FirstEnergy assets. Such parental guarantees
amount to $0.8 billion (included in the $1.3 billion discussed above) as
of
September 30, 2005 and the likelihood is remote that such guarantees
will
increase amounts otherwise to be paid by FirstEnergy to meet its obligations
incurred in connection with financings and ongoing energy and energy-related
contracts.
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. The
following table summarizes collateral provisions in effect as of
September 30, 2005:
|
|
|
Total
|
|
Collateral
Paid
|
|
Remaining
|
|
Collateral
Provisions
|
|
|
Exposure
|
|
Cash
|
|
LOC
|
|
Exposure
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit
rating
downgrade
|
|
|
|
$
|
445
|
|
$
|
213
|
|
$
|
18
|
|
$
|
214
|
|
Adverse
event
|
|
|
|
|
77
|
|
|
-
|
|
|
5
|
|
|
72
|
|
Total
|
|
|
|
$
|
522
|
|
$
|
213
|
|
$
|
23
|
|
$
|
286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On
October 3,
2005, S&P raised the senior unsecured ratings of FirstEnergy's holding
company to 'BBB-' from 'BB+'. As a result of the rating upgrade, $109 million
of
cash collateral was subsequently returned to FirstEnergy.
Most
of
FirstEnergy's surety bonds are backed by various indemnities common within
the
insurance industry. Surety bonds and related FirstEnergy guarantees of
$307
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.
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
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 ($47 million as of
September 30, 2005) which is renewable and declines yearly based
upon the
senior outstanding debt of TEBSA. The LOC was reduced to $36 million on
October
15, 2005.
(B) ENVIRONMENTAL
MATTERS
Various
federal,
state and local authorities regulate the Companies with regard to air and
water
quality and other environmental matters. The effects of compliance on the
Companies with regard to environmental matters could have a material adverse
effect on FirstEnergy's earnings and competitive position. These environmental
regulations affect 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 $670 million for 2005 through 2007.
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 are both probable and reasonably estimable.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
Clean
Air Act
Compliance
FirstEnergy
is
required to meet federally approved SO2
regulations.
Violations of such regulations can result in shutdown of the generating
unit
involved and/or civil or criminal penalties of up to $32,500 for each day
the
unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in
Ohio that allows for compliance based on a 30-day averaging period. The
Companies cannot predict what action the EPA may take in the future with
respect
to the interim enforcement policy.
FirstEnergy
believes it is complying with SO2
reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOx
reductions
required by the 1990 Amendments are being achieved through combustion controls
and the generation of more electricity at lower-emitting plants. In September
1998, the EPA finalized regulations requiring additional NOx
reductions from
FirstEnergy's facilities. The EPA's NOx
Transport Rule
imposes uniform reductions of NOx
emissions (an
approximate 85 percent reduction in utility plant NOx
emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia
based
on a conclusion that such NOx
emissions are
contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOx
budgets
established under State Implementation Plans through combustion controls
and
post-combustion controls, including Selective Catalytic Reduction and Selective
Non-Catalytic Reduction systems, and/or using emission
allowances.
National
Ambient Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
for fine
particulate matter. On March 10, 2005, the EPA finalized the "Clean
Air
Interstate Rule" 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 nonattainment of the NAAQS for fine particles
and/or
the "8-hour" ozone NAAQS in other states. CAIR provides each affected state
until 2006 to develop implementing regulations to achieve additional reductions
of NOx
and SO2
emissions in two
phases (Phase I in 2009 for NOx,
2010 for
SO2
and Phase II in
2015 for both NOx
and SO2)
in all cases from
the 2003 levels. FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired
generation facilities will be subject to the caps on SO2
and NOx
emissions, whereas
their New Jersey fossil-fired generation facilities will be subject to
a cap on
NOx
emissions only.
According to the EPA, SO2
emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by
the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2
emissions in
affected states to just 2.5 million tons annually. NOx
emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by
the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOx
cap of 1.3 million
tons annually. The future cost of compliance with these regulations may
be
substantial and will depend on how they are ultimately implemented by the
states
in which FirstEnergy operates affected facilities.
Mercury
Emissions
In
December 2000,
the EPA announced it would proceed with the development of regulations
regarding
hazardous air pollutants from electric power plants, identifying mercury
as the
hazardous air pollutant of greatest concern. On March 14, 2005,
the EPA
finalized the "Clean Air Mercury Rule," 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 Clean Air Mercury Rule 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.
W.
H. Sammis
Plant
In
1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities alleging violations
of
the Clean Air Act based on operation and maintenance of 44 power plants,
including the W. H. Sammis Plant, which was owned at that time by OE and
Penn.
In addition, the DOJ filed eight civil complaints against various investor-owned
utilities, including a complaint against OE and Penn in the U.S. District
Court
for the Southern District of Ohio. These cases are referred to as New Source
Review cases. On March 18, 2005, OE and Penn announced that they
had
reached a settlement with the EPA, the DOJ and three states (Connecticut,
New
Jersey, and New York) that resolved all issues related to the W. H. Sammis
Plant
New Source Review litigation. This settlement agreement, which is in the
form of
a Consent Decree, was approved by the Court on July 11, 2005, requires
OE
and Penn to reduce Nox
and SO2
emissions at the
W. H. Sammis Plant and other coal fired plants through the installation
of
pollution control devices. Capital expenditures necessary to meet those
requirements are currently estimated to be $1.5 billion (the primary portion
of
which is expected to be spent in the 2008 to 2011 time period). As disclosed
in
FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement
with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer,
procure, and construct air quality control systems for the reduction of
sulfur
dioxide emissions. The settlement agreement also requires OE and Penn to
spend
up to $25 million toward environmentally beneficial projects, which
include
wind energy purchased power agreements over a 20-year term. OE and Penn
agreed
to pay a civil penalty of $8.5 million. Results for the first quarter of
2005
included the penalties payable by OE and Penn of $7.8 million and $0.7
million,
respectively. OE and Penn also recognized liabilities of $9.2 million
and
$0.8 million, respectively, during the first quarter of 2005, for probable
future cash contributions toward environmentally beneficial projects.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (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 Protocol in 1998 but it failed
to
receive the two-thirds vote of the United States Senate required for
ratification. However, the Bush administration has committed the United
States
to a voluntary climate change strategy to reduce domestic GHG intensity
- the
ratio of emissions to economic output - by 18 percent through 2012. The
Energy
Policy Act of 2005 established a Committee on Climate Change Technology
to
coordinate federal climate change activities and promote the development
and
deployment of GHG reducing technologies.
FirstEnergy
cannot
currently estimate the financial impact of climate change policies, although
the
potential restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per
kilowatt-hour of electricity generated by FirstEnergy is lower than many
regional competitors due to its diversified generation sources, which include
low or non-CO2
emitting gas-fired
and nuclear generators.
Clean
Water
Act
Various
water
quality regulations, the majority of which are the result of the federal
Clean
Water Act and its amendments, apply to FirstEnergy's plants. In addition,
Ohio,
New Jersey and Pennsylvania have water quality standards applicable to
FirstEnergy's operations. As provided in the Clean Water Act, authority
to grant
federal National Pollutant Discharge Elimination System water discharge
permits
can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed
such
authority.
On
September 7, 2004, the EPA established new performance standards
under
Section 316(b) of the Clean Water Act for reducing impacts on fish and
shellfish
from cooling water intake structures at certain existing large electric
generating plants. The regulations call for reductions in impingement mortality,
when aquatic organisms are pinned against screens or other parts of a cooling
water intake system and entrainment, which occurs when aquatic species
are drawn
into a facility's cooling water system. FirstEnergy is conducting comprehensive
demonstration studies, due in 2008, to determine the operational measures,
equipment or restoration activities, if any, necessary for compliance by
its
facilities with the performance standards. FirstEnergy is unable to predict
the
outcome of such studies. Depending on the outcome of such studies, the
future
cost of compliance with these standards may require material capital
expenditures.
Regulation
of
Hazardous Waste
As
a result of the
Resource Conservation and Recovery Act of 1976, as amended, and the Toxic
Substances Control Act of 1976, federal and state hazardous waste regulations
have been promulgated. Certain fossil-fuel combustion waste products, such
as
coal ash, were exempted from hazardous waste disposal requirements pending
the
EPA's evaluation of the need for future regulation. The EPA subsequently
determined that regulation of coal ash as a hazardous waste is unnecessary.
In
April 2000, the EPA announced that it will develop national standards regulating
disposal of coal ash under its authority to regulate nonhazardous
waste.
The
Companies have
been named as PRPs at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation, and Liability Act of
1980.
Allegations of disposal of hazardous substances at historical sites and
the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on
a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
September 30, 2005, based on estimates of the total costs of cleanup,
the
Companies' proportionate responsibility for such costs and the financial
ability
of other nonaffiliated 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 $64 million (JCP&L
-
$46.8 million, CEI
-
$2.3 million, TE
-
$0.2 million,
Met-Ed -
$0.1 million and
other -
$14.6 million)
have been accrued through September 30, 2005.
(C) OTHER
LEGAL
PROCEEDINGS
Power
Outages
and Related Litigation
In
July 1999, the
Mid-Atlantic States experienced a severe heat wave, which resulted in power
outages throughout the service territories of many electric utilities,
including
JCP&L's territory. In an investigation into the causes of the outages and
the reliability of the transmission and distribution systems of all four
of New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior
Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.
In
August 2002, the
trial court granted partial summary judgment to JCP&L and dismissed the
plaintiffs' claims for consumer fraud, common law fraud, negligent
misrepresentation, and strict product liability. In November 2003, the
trial
court granted JCP&L's motion to decertify the class and denied plaintiffs'
motion to permit into evidence their class-wide damage model indicating
damages
in excess of $50 million. These class decertification and damage rulings
were
appealed to the Appellate Division. The Appellate Division issued a decision
on
July 8, 2004, affirming the decertification of the originally certified
class, but remanding for certification of a class limited to those customers
directly impacted by the outages of JCP&L transformers in Red Bank, New
Jersey. On September 8, 2004, the New Jersey Supreme Court denied
the
motions filed by plaintiffs and JCP&L for leave to appeal the decision of
the Appellate Division. JCP&L has filed a motion for summary judgment.
FirstEnergy is unable to predict the outcome of these matters and no liability
has been accrued as of September 30, 2005.
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 website (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 also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. 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. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the
proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two cases were originally
filed in Ohio State courts but were subsequently dismissed for lack of
subject
matter jurisdiction and further appeals were unsuccessful. In these cases
the
individual complainants—three in one case and four in the other—sought to
represent others as part of a class action. The PUCO dismissed the class
allegations, stating that its rules of practice do not provide for class
action
complaints. Of the four other pending PUCO complaint cases, three were
filed by
various insurance carriers either in their own name as subrogees or in
the name
of their insured. In each of the four cases, the carrier seeks reimbursement
from various FirstEnergy companies (and, in one case, from PJM, MISO and
American Electric Power Co. as well) for claims paid to insureds for claims
allegedly arising as a result of the loss of power on August 14,
2003. The
listed insureds in these cases, in many instances, are not customers of
any
FirstEnergy company. The fourth case involves the claim of a non-customer
seeking reimbursement for losses incurred when its store was burglarized
on
August 14, 2003. In addition to these six cases, the Ohio Companies
were
named as respondents in a regulatory proceeding that was initiated at the
PUCO
in response to complaints alleging failure to provide reasonable and adequate
service stemming primarily from the August 14, 2003 power outages.
No
estimate of potential liability has been undertaken for any of these cases.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005. Additionally, FirstEnergy Corp. was named in a complaint filed
in
Michigan State Court by an individual who is not a customer of any FirstEnergy
company. A responsive pleading to this matter is not due until on or about
December 1, 2005. No estimate of potential liability has been undertaken
in this
matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. In particular, if FirstEnergy or
its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition, results of operations and cash
flows.
Nuclear
Plant
Matters
FENOC
received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection
and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power
Station.
On December 10, 2004, FirstEnergy received a letter from the United
States
Attorney's Office stating that FENOC is a target of the federal grand jury
investigation into alleged false statements made to the NRC in the Fall
of 2001
in response to NRC Bulletin 2001-01. The letter also said that the designation
of FENOC as a target indicates that, in the view of the prosecutors assigned
to
the matter, it is likely that federal charges will be returned against
FENOC by
the grand jury. On February 10, 2005, FENOC received an additional
subpoena
for documents related to root cause reports regarding reactor head degradation
and the assessment of reactor head management issues at Davis-Besse.
On
May 11, 2005, FENOC received a subpoena for documents related to
outside
meetings attended by Davis-Besse personnel on corrosion and cracking of
control
rod drive mechanisms and additional root cause evaluations.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related
to
the degradation of the Davis-Besse reactor vessel head issue described
above.
FirstEnergy accrued $2.0 million for a potential fine prior to 2005 and
accrued
the remaining liability for the proposed fine during the first quarter
of 2005.
On September 14, 2005, FENOC filed its response to the NOV with
the NRC.
FENOC accepted full responsibility for the past failure to properly implement
its boric acid corrosion control and corrective action programs. The NRC
NOV
indicated that the violations do not represent current licensee performance.
FirstEnergy paid the penalty in the third quarter of 2005.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
based on the events surrounding Davis-Besse, it could have a material adverse
effect on FirstEnergy's or its subsidiaries' financial condition, results
of
operations and cash flows.
Effective
July 1, 2005, the NRC oversight panel for Davis-Besse was terminated
and
Davis-Besse returned to the standard NRC reactor oversight process. At
that
time, NRC inspections were augmented to include inspections to support
the NRC's
Confirmatory Order dated March 8, 2004 that was issued at the time
of
startup and to address an NRC White Finding related to the performance
of the
emergency sirens.
On
August 12,
2004, the NRC notified FENOC that it would increase its regulatory oversight
of
the Perry Nuclear Power Plant as a result of problems with safety system
equipment over the preceding two years and the licensee's failure to take
prompt
and corrective action. FENOC operates the Perry Nuclear Power Plant, which
is
currently owned and/or leased by OE, CEI, TE and Penn (however, see Note
17
regarding FirstEnergy’s pending intra-system generation asset transfers, which
will include owned portions of the plant).
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter
to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to
the NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During
the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to
be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the
Action
Matrix.
On
May 26,
2005, the NRC held a public meeting to discuss its oversight of the Perry
Plant.
While the NRC stated that the plant continued to operate safely, the NRC
also
stated that the overall performance had not substantially improved since
the
heightened inspection was initiated. The NRC reiterated this conclusion
in its
mid-year assessment letter dated August 30, 2005. On September 28,
2005, the NRC sent a CAL to FENOC describing commitments that FENOC had
made to
improve the performance of Perry 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. If performance does not improve, the NRC
has a
range of options under the Reactor Oversight Process, from increased oversight
to possible impact to the plant’s operating authority. As a result, these
matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
Other
Legal
Matters
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy's normal business operations pending against FirstEnergy
and its subsidiaries. The other potentially material items not otherwise
discussed above are described below.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
have
become the subject of a formal order of investigation. The SEC's formal order
of
investigation also encompasses issues raised during the SEC's examination
of
FirstEnergy and the Companies under the PUHCA. Concurrent with this
notification, FirstEnergy received a subpoena asking for background documents
and documents related to the restatements and Davis-Besse issues. On
December 30, 2004, FirstEnergy received a subpoena asking for documents
relating to issues raised during the SEC's PUHCA examination. On August 24,
2005 additional information was requested regarding Davis-Besse. FirstEnergy
has
cooperated fully with the informal inquiry and will continue to do so with
the
formal investigation.
On
August 22,
2005, a class action complaint was filed against OE in Jefferson County,
Ohio
Common Pleas Court seeking compensatory and punitive damages to be determined
at
trial based on claims of negligence and eight other tort counts alleging
damages
from the W.H. Sammis Plant air emissions. The two named plaintiffs are also
seeking injunctive relief to eliminate harmful emissions and repair property
damage and the institution of a medical monitoring program for class members.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties’ collective bargaining
agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16.1 million to the bargaining unit employees. JCP&L initiated an appeal of
this award by filing a motion to vacate in Federal Court in New Jersey on
October 18, 2005. JCP&L recognized a liability for the potential $16.1
million award during the three months ended September 30,
2005.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of a
newly-formed municipal electric utility. The complaint was filed on May 28,
2003, and OE timely filed its response on June 30, 2003. In a related
filing, the Ohio Companies filed for approval with the PUCO of a tariff that
would specifically allow the collection of transition charges from customers
of
municipal electric utilities formed after 1998. An
adverse ruling
could negatively affect full recovery of transition charges by the utility.
Hearings on the matter were held in August 2005. Initial briefs from all
parties
were filed on September 22, 2005 and reply briefs were filed on
October 14, 2005. It is unknown when the PUCO will rule on this case.
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.
14
-
REGULATORY MATTERS:
Reliability
Initiatives
In
late 2003 and
early 2004, a series of letters, reports and recommendations were issued
from
various entities, including governmental, industry and ad hoc reliability
entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task
Force)
regarding enhancements to regional reliability. In 2004, FirstEnergy completed
implementation of all actions and initiatives related to enhancing area
reliability, improving voltage and reactive management, operator readiness
and
training and emergency response preparedness recommended for completion in
2004.
On July 14, 2004, NERC independently verified that FirstEnergy had
implemented the various initiatives to be completed by June 30 or
summer
2004, with minor exceptions noted by FirstEnergy, which exceptions are now
essentially complete. FirstEnergy is proceeding with the implementation of
the
recommendations that were to be completed subsequent to 2004 and will continue
to periodically assess the FERC-ordered Reliability Study recommendations
for
forecasted 2009 system conditions, recognizing revised load forecasts and
other
changing system conditions which may impact the recommendations. Thus far,
implementation of the recommendations has not required, nor is expected to
require, substantial investment in new, or material upgrades to existing
equipment. The FERC or other applicable government agencies and reliability
coordinators may, however, take a different view as to recommended enhancements
or may recommend additional enhancements in the future as the result of adoption
of mandatory reliability standards pursuant to the Energy Policy Act of 2005
that could require additional, material expenditures. Finally, the PUCO is
continuing to review the FirstEnergy filing that addressed upgrades to control
room computer hardware and software and enhancements to the training of control
room operators, before determining the next steps, if any, in the proceeding.
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. On March 29,
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 a
Special
Reliability Master who made recommendations on appropriate courses of action
necessary to ensure system-wide reliability. The Stipulation also incorporates
the Executive Summary and Recommendation portions of the final report of
a
focused audit of JCP&L's Planning and Operations and Maintenance programs
and practices (Focused Audit). A final order in the Focused Audit docket
was
issued by the NJBPU on July 23, 2004. On February 11, 2005,
JCP&L
met with the Ratepayer Advocate to discuss reliability improvements. JCP&L
continues to file compliance reports reflecting activities associated with
the
MOU and Stipulation.
In
May 2004, the
PPUC issued an order approving revised reliability benchmarks and standards,
including revised benchmarks and standards for Met-Ed, Penelec and Penn.
Met-Ed,
Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC
on
May 26, 2004, due to their implementation of automated outage management
systems following restructuring. Evidentiary hearings have been scheduled
for
November 2005. FirstEnergy is unable to predict the outcome of this
proceeding.
The
Energy Policy
Act of 2005 provides for the creation of an ERO to establish and enforce
reliability standards for the bulk power system, subject to FERC review.
On
September 1, 2005, the FERC issued a Notice of Proposed Rulemaking
to
establish certification requirements for the ERO, as well as regional entities
envisioned to assume monitoring and compliance responsibility for the new
reliability standards. The FERC expects to adopt a final rule on or before
February 2006 regarding certification requirements for the ERO and regional
entities.
The
NERC is
expected to reorganize its structure to meet the FERC’s certification
requirements for the ERO. Following adoption of the final rule, the NERC
will be
required to make a filing with the FERC to obtain certification as the ERO.
The
proposed rule also provides for regional reliability organizations designed
to
replace the current regional councils. The “regional entity” may be delegated
authority by the ERO, subject to FERC approval, for enforcing reliability
standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic
Area Council, and Mid-American Interconnected Network
reliability
councils have signed an MOU designed to consolidate their regions into a
new
regional reliability organization known as ReliabilityFirst Corporation.
Their
intent is to file and obtain certification under the final rule as a “regional
entity”. All of FirstEnergy’s facilities would be located within the
ReliabilityFirst region.
On
a parallel path,
the NERC is establishing working groups to develop reliability standards
to be
filed for approval with the FERC following the NERC’s certification as an ERO.
These reliability standards are expected to build on the current NERC Version
0
reliability standards. It is expected that the proposed reliability standards
will be filed with the FERC in early 2006.
The
impact of this
effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance
with all current NERC reliability standards. However, it is expected that
the
FERC will adopt stricter reliability standards than those contained in the
current NERC Version 0 standards. The financial impact of complying with
the new
standards cannot be determined at this time. However, the Energy Policy Act
of
2005 requires that all prudent costs incurred to comply with the new reliability
standards be recovered in rates.
Ohio
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 competitive
bid
process. The RSP was filed by the Ohio Companies to establish generation
service
rates beginning January 1, 2006, in response to PUCO concerns about
price
and supply uncertainty following the end of the Ohio Companies' transition
plan
market development period. In October 2004, the OCC and NOAC filed appeals
with
the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO
order
in this proceeding as well as the associated entries on rehearing. On
September 28, 2005, the Ohio Supreme Court heard oral argument on
the
appeals.
On
May 27,
2005, the Ohio Companies filed an application with the PUCO to establish
a GCAF
rider under the RSP. The application seeks to implement recovery of increased
fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail
customers through a tariff rider to be implemented January 1, 2006.
The
application reflects projected increases in fuel costs in 2006 compared to
2002
baseline costs. The new rider, after adjustments made in testimony, is seeking
to recover all costs above the baseline (approximately $88 million in 2006).
Various parties including the OCC have intervened in this case and the case
has
been consolidated with the RCP application discussed below.
On
September 9,
2005, the Ohio Companies filed an application with the PUCO that, if approved,
would supplement their existing RSP with an RCP. On September 27,
2005, the
PUCO granted FirstEnergy's motion to consolidate the GCAF rider application
with
the RCP proceedings and set hearings for the consolidated cases to begin
November 29, 2005. The RCP is designed to provide customers with
more
certain rate levels than otherwise available under the RSP during the plan
period. Major provisions of the RCP include:
· Maintain
the
existing level of base distribution rates through December 31, 2008
for OE
and TE, and
April 30,
2009
for CEI;
· Defer
and
capitalize certain distribution costs to be incurred during the period
January 1, 2006
through
December 31, 2008, not to exceed $150 million in each of the three
years;
· Adjust
the RTC and
extended RTC recovery periods and rate levels so that full recovery of
authorized
costs
will occur as
of December 31, 2008 for OE and TE, and as of December 31,
2010 for
CEI;
· Reduce
the deferred
shopping incentive balances as of January 1, 2006 by up to $75 million
for
OE,
$45
million for TE,
and $85 million for CEI by accelerating the application of each
respective
company's
accumulated
cost of removal regulatory liability; and
· Recover
increased
fuel costs of up to $75 million, $77 million, and $79 million, in 2006,
2007,
and
2008,
respectively,
from all OE and TE distribution and transmission customers through a
fuel
recovery
mechanism
and OE, TE, and CEI may defer and capitalize increased fuel costs above
the
amount
collected
through the fuel recovery mechanism.
The
following table
provides a comparison of the estimated net amortization of regulatory transition
costs and deferred shopping incentives (including associated carrying charges)
under the proposed RCP and the current RSP for the period 2006 through
2010:
|
|
Estimated
Net Amortization
|
|
|
|
RCP
|
|
RSP
|
|
Amortization
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
Total
|
|
Period
|
|
OE
|
|
CEI
|
|
TE
|
|
Ohio
|
|
OE
|
|
CEI
|
|
TE
|
|
Ohio
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
$
|
169
|
|
$
|
100
|
|
$
|
80
|
|
$
|
349
|
|
$
|
175
|
|
$
|
94
|
|
$
|
73
|
|
$
|
342
|
|
2007
|
|
|
176
|
|
|
111
|
|
|
89
|
|
|
376
|
|
|
237
|
|
|
104
|
|
|
82
|
|
|
423
|
|
2008
|
|
|
198
|
|
|
129
|
|
|
100
|
|
|
427
|
|
|
206
|
|
|
122
|
|
|
159
|
|
|
487
|
|
2009
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
318
|
|
|
-
|
|
|
318
|
|
2010
|
|
|
-
|
|
|
268
|
|
|
-
|
|
|
268
|
|
|
-
|
|
|
271
|
|
|
-
|
|
|
271
|
|
Net
Amortization*
|
|
$
|
543
|
|
$
|
824
|
|
$
|
269
|
|
$
|
1,636
|
|
$
|
618
|
|
$
|
909
|
|
$
|
314
|
|
$
|
1,841
|
|
|
*
RCP
aggregate amortization is less than amortization under the RSP due
to the
accelerated application of regulatory liabilities
to reduce deferred shopping
incentives.
|
Under
provisions of
the RSP, the PUCO may require the Ohio Companies to undertake, no more often
than annually, a competitive bid process to secure generation for the years
2007
and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process
for
the period beginning in 2007 that is similar to the competitive bid process
approved by the PUCO for the Ohio Companies in 2004, which resulted in the
PUCO
accepting no bids. Any acceptance of future competitive bid results would
terminate the RSP pricing, with no accounting impacts to the RSP, and not
until
twelve months after the PUCO authorizes such termination. On September 28,
2005, the PUCO issued an Entry that essentially approved the Ohio Companies'
filing but delayed the proposed timing of the competitive bid process by
four
months, calling for the auction to be held on March 21, 2006.
Pennsylvania
A
February 2002
Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision
regarding approval of the FirstEnergy/GPU merger, remanded the issues of
quantification and allocation of merger savings to the PPUC and denied Met-Ed
and Penelec the rate relief initially approved in the PPUC decision. On
October 2, 2003, the PPUC issued an order concluding that the Commonwealth
Court reversed the PPUC’s June 2001 order in its entirety. In accordance
with the PPUC's direction, Met-Ed and Penelec filed supplements to their
tariffs
that became effective in October 2003 and that reflected the CTC rates and
shopping credits in effect prior to the June 2001 order.
In
accordance with
PPUC directives, Met-Ed and Penelec have been negotiating with interested
parties in an attempt to resolve the merger savings issues that are the subject
of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
of total merger savings is estimated to be approximately $31.5 million. On
April 13, 2005, the Commonwealth Court issued an interim order in
the
remand proceeding that the parties should report the status of the negotiations
to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals
in May and June 2005 and continue to have settlement discussions.
In
an
October 16, 2003 order, the PPUC approved September 30, 2004
as the
date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also
denied their accounting treatment request regarding the CTC rate/shopping
credit
swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that
were
in effect from January 1, 2002 on a retroactive basis. On October 22,
2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking
that the Court reverse this PPUC finding; a Commonwealth Court judge
subsequently denied their Objection on October 27, 2003 without
explanation. On October 31, 2003, Met-Ed and Penelec filed an Application
for Clarification of the Court order with the judge, a Petition for Review
of
the PPUC's October 2 and October 16, 2003 Orders, and an application
for reargument, if the judge, in his clarification order, indicates that
Met-Ed's and Penelec's Objection was intended to be denied on the merits.
The
Reargument Brief before the Commonwealth Court was filed on January 28,
2005.
Met-Ed
and Penelec
purchase a portion of their PLR requirements from FES through a wholesale
power
sales agreement. The PLR sale is automatically extended for each successive
calendar year unless any party elects to cancel the agreement by November 1
of the preceding year. Under the terms of the wholesale agreement, FES retains
the supply obligation, and the supply profit and loss risk for the portion
of
power supply requirements not self-supplied by Met-Ed and Penelec under their
NUG contracts and other power contracts with nonaffiliated third party
suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high
wholesale power prices by providing power at a fixed price for their uncommitted
PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec
are authorized to defer differences between NUG contract costs and current
market prices. On November
1,
2005, FES and the other parties to the wholesale power agreement amended
the
agreement to provide FES the right over the next year to terminate the agreement
at any time upon 60 days notice. If
the wholesale
power agreement were terminated, Met-Ed and Penelec would need to satisfy
the
applicable portion of their PLR obligations from other sources at prevailing
prices, which are likely to be higher than the current price charged by FES
under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
costs could materially increase.
In
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for its
customers at set rates following the end of its transition period on
December 31, 2006. Penn is recommending that the Request for Proposal
process cover the period of January 1, 2007 through May 31,
2008.
Under Pennsylvania's electric competition law, Penn is required to secure
generation supply for customers who do not choose alternative suppliers for
their electricity.
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 MTC rates. As of
September 30, 2005, the accumulated deferred cost balance totaled
approximately $508 million. New Jersey law allows for securitization of
JCP&L's deferred balance upon application by JCP&L and a determination
by the NJBPU that the conditions of the New Jersey restructuring legislation
are
met. On February 14, 2003, JCP&L filed for approval of the
securitization of the July 31, 2003 deferred balance. JCP&L is in
discussions with the NJBPU staff as a result of the stipulated settlement
agreements (as further discussed below) which recommended that the NJBPU
issue
an order regarding JCP&L's application. On July 20, 2005, JCP&L
requested the NJBPU to set a procedural schedule for this matter and is awaiting
NJBPU action.
The
2003 NJBPU
decision on JCP&L's base electric rate proceeding (the Phase I Order)
disallowed certain regulatory assets and provided for an interim return on
equity of 9.5% on JCP&L's rate base. The Phase I order also provided for a
Phase II proceeding in which the NJBPU would review whether JCP&L is in
compliance with current service reliability and quality standards and determine
whether the expenditures and projects undertaken by JCP&L to increase its
system's reliability are prudent and reasonable for rate recovery. Depending
on
its assessment of JCP&L's service reliability, the NJBPU could have
increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On
August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an
interim motion and a supplemental and amended motion for rehearing and
reconsideration of the Phase I Order, respectively. On July 7, 2004,
the
NJBPU granted limited reconsideration and rehearing on the following issues:
(1)
deferred cost disallowances; (2) the capital structure including the rate
of
return; (3) merger savings, including amortization of costs to achieve merger
savings; and (4) decommissioning costs.
On
July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for the recovery of system
reliability costs and a 9.75% return on equity. The filing also requested
an
increase to the MTC deferred balance recovery of approximately $20 million
annually.
On
May 25,
2005, the NJBPU approved two stipulated settlement agreements. The first
stipulation between JCP&L and the NJBPU staff resolves all of the issues
associated with JCP&L's motion for reconsideration of the Phase I Order. The
second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate
resolves all of the issues associated with JCP&L's Phase II proceeding.
The
stipulated settlements provide for, among other things, the
following:
|
·
|
An
annual
increase in distribution revenues of $23 million effective June 1,
2005, associated with the Phase I Order
reconsideration;
|
|
·
|
An
annual
increase in distribution revenues of $36 million effective June 1,
2005, related to JCP&L's Phase II
Petition;
|
|
·
|
An
annual
reduction in both rates and amortization expense of $8 million,
effective
June 1, 2005, in anticipation of an NJBPU order regarding
JCP&L's
request to securitize up to $277 million of its deferred cost
balance;
|
|
·
|
An
increase
in JCP&L's authorized return on common equity from 9.5% to 9.75%;
and
|
|
·
|
A
commitment
by JCP&L to maintain a target level of customer service reliability
with a reduction in JCP&L's authorized return on common equity from
9.75% to 9.5% if the target is not met for two consecutive quarters.
The
authorized return on common equity would then be restored to 9.75%
if the
target is met for two consecutive
quarters.
|
The
Phase II
stipulation included an agreement that the distribution revenue increase
also
reflects a three-year amortization of JCP&L's one-time service reliability
improvement costs incurred in 2003-2005. This resulted in the creation of
a
regulatory asset associated with accelerated tree trimming and other reliability
costs which were expensed in 2003 and 2004. The establishment of the new
regulatory asset of approximately $28 million resulted in an increase to
net
income of approximately $16 million ($0.05 per share of common stock) in
the
second quarter of 2005.
JCP&L
sells all
self-supplied energy (NUGs and owned generation) to the wholesale market
with
offsetting credits to its deferred energy balance with the exception of 300
MW
from JCP&L's NUG committed supply currently being used to serve BGS
customers pursuant to NJBPU order for the period June 1, 2005 through
May 31, 2006. New BGS tariffs reflecting the results of a February
2005
auction for the BGS supply became effective June 1, 2005. On July 1,
2005, JCP&L filed its BGS procurement proposals for post transition year
four. The auction is scheduled to take place in February 2006 for the annual
supply period beginning June 1, 2006.
In
accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting a continuation of the current level and duration of the funding
of TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The Ratepayer Advocate filed comments on
February 28, 2005. On March 18, 2005, JCP&L filed a response to
those comments. A schedule for further proceedings has not yet been
set.
Transmission
On
November 1,
2004, ATSI requested authority from the FERC to defer approximately $54 million
of vegetation management costs estimated to be incurred from 2004 through
2007.
On March 4, 2005, the FERC approved ATSI's request to defer those
costs
($21 million deferred as of September 30, 2005). ATSI expects to file
an
application with the FERC in the second quarter of 2006 that would include
recovery of the deferred costs.
On
December 30, 2004, the Ohio Companies filed with the PUCO two applications
related to the recovery of transmission and ancillary service related costs.
The
first application seeks recovery of these costs beginning January 1,
2006.
The Ohio Companies requested that these costs be recovered through a rider
that
would be effective on January 1, 2006 and adjusted each July 1
thereafter. The Ohio Companies reached a settlement with OCC, PUCO staff,
Industrial Energy Users - Ohio and OPAE. The only other party in this
proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This
settlement, which was filed with the PUCO on July 22, 2005, provides
for
the rider recovery requested by the Ohio Companies, with carrying charges
applied in the subsequent year’s rider for any over or under collection while
the then-current rider is in effect. The PUCO approved the settlement
stipulation on August 31, 2005. The incremental Transmission and Ancillary
service revenues expected to be recovered from January through June 2006
are
approximately $61.2 million. This amount includes the recovery of
the 2005
deferred MISO expenses as described below. In May 2006, the Companies will
file
a modification to the rider to determine revenues from July 2006 through
June
2007.
The
second
application sought authority to defer costs associated with transmission
and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On
May 18,
2005, the PUCO granted the accounting authority for the Ohio Companies to
defer
incremental transmission and ancillary service-related charges incurred as
a
participant in MISO, but only for those costs incurred during the period
December 30, 2004 through December 31, 2005. Permission to
defer costs
incurred prior to December 30, 2004 was denied. The PUCO also authorized
the Ohio Companies to accrue carrying charges on the deferred balances. An
application filed with the PUCO to recover these deferred charges over a
five-year period through the rider, beginning in 2006, was approved in the
PUCO
order issued on August 31, 2005 approving the stipulation referred
to
above. The OCC, OPAE and the Ohio Companies each filed applications for
rehearing. The Ohio Companies sought authority to defer the transmission
and
ancillary service-related costs incurred during the period October 1,
2003
through December 29, 2004, while both OCC and OPAE sought to have
the PUCO
deny deferral of all costs. On
July 6,
2005, the PUCO denied the Ohio Companies' and OCC’s applications and, at the
request of the Ohio Companies, struck as untimely OPAE’s application. The OCC
filed a notice of appeal with the Ohio Supreme Court on August 31,
2005. On
September 30, 2005, in accordance with appellate procedure, the PUCO filed
with
the Ohio Supreme Court the record in this case. The Companies' brief will
be due
thirty days after the OCC files its brief, which, absent any time extensions,
must be filed no later than November 9, 2005.
On
January 12,
2005, Met-Ed and Penelec filed a request with the PPUC for deferral of
transmission-related costs beginning January 1, 2005, estimated to
be
approximately $8 million per month. The
OCA, OSBA, OTS,
MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric
Association have all intervened in the case. To date no hearing schedule
has
been established, and neither company has yet implemented deferral accounting
for these costs.
On
January 31,
2005, certain PJM transmission owners made three filings 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. Second, the
FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to referral and hearing procedures. On
June 30, 2005, the PJM transmission owners filed a request for rehearing
of
the May 31, 2005 order. The rate design and formula rate proceedings
are
currently being litigated before the FERC. The outcome of these cases cannot
be
predicted.
Regulatory
Assets
The
EUOC recognize,
as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized
for recovery from customers in future periods. Without such authorization,
costs
currently recorded as regulatory assets would have been charged to income
as
incurred. All regulatory assets are expected to be recovered from customers
under the Companies' respective transition and regulatory plans. Based on
those
plans, the Companies continue to bill and collect cost-based rates for their
transmission and distribution services, which remain regulated; accordingly,
it
is appropriate that the Companies continue the application of SFAS 71 to
those
operations.
The
Ohio Companies
are deferring customer shopping incentives and interest costs as new regulatory
assets in accordance with the transition and rate stabilization plans. Under
the
RSP, recovery of these regulatory assets (OE - $302 million, CEI - $402 million,
TE - $122 million, as of September 30, 2005) would have begun through
a
surcharge rate equal to the RTC rate in effect only after the transition
costs
have been fully recovered. Under the proposed RCP, OE's and TE's recovery
of the
new regulatory assets would begin January 1, 2006 and expected to
be
completed by December 31, 2008. CEI's new regulatory asset recovery
would
still begin after full recovery of its transition costs (estimated as of
mid-2009) and expected to be completed by December 31, 2010. Amortization
of the new regulatory assets for each accounting period would equal the amount
of the surcharge revenue recognized during that period.
Regulatory
transition costs as of September 30, 2005 for JCP&L and Met-Ed are
approximately $2.4 billion and $0.6 billion, respectively. Deferral
of
above-market costs from power supplied by NUGs to JCP&L are approximately
$1.4 billion and are being recovered through BGS and MTC revenues. Met-Ed
has
deferred above-market NUG costs totaling approximately $200 million. These
costs
are being recovered through CTC revenues. The regulatory asset for above-market
NUG future obligations and the corresponding liability are adjusted to fair
value at the end of each quarter. Recovery of the remaining regulatory
transition costs is expected to continue under the provisions of the various
regulatory proceedings in New Jersey and Pennsylvania.
15
- NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP
No. FAS
13-1, "Accounting for Rental Costs Incurred during the Construction
Period"
Issued
in October 2005, FSP No.
FAS 13-1 requires rental costs associated with ground or building operating
leases that are incurred during a construction period to be recognized
as
rental expense. The effective date of the FSP guidance is the first reporting
period beginning after December 15, 2005. FirstEnergy is currently evaluating
this FSP and its impact on the financial statements.
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or
more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the EITF
reached a consensus that an exchange of inventory should be accounted for
at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, FirstEnergy will adopt this EITF
effective for new arrangements entered into, or modifications or renewals
of
existing arrangements, in interim or annual periods beginning after March
15,
2006. See Note 2 for an example of FirstEnergy's application of this
Issue.
|
EITF
Issue No. 05-6, "Determining the Amortization Period for Leasehold
Improvements Purchased after Lease Inception or Acquired in a Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6. EITF
05-6
addresses the amortization period for leasehold improvements that were either
acquired in a business combination or placed in service significantly after
and
not contemplated at or near the beginning of the initial lease term. For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that includes
required lease periods and renewals that are deemed to be reasonably assured
at
the date of acquisition. Leasehold improvements that are placed in service
significantly after and not contemplated at or near the beginning of the
lease
term should be amortized over the shorter of the useful life of the assets
or a
term that includes required lease periods and renewals that are deemed to
be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with FirstEnergy's current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective for FirstEnergy in the fourth quarter of
2005.
FirstEnergy and the Companies are currently evaluating the effect this
Interpretation will have on their financial statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement of APB
Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and reporting
a
change in accounting principle. It applies to all voluntary changes in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions. This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of
the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings (or other appropriate components of equity or net assets
in
the statement of financial position) for that period rather than being reported
in the Consolidated Statements of Income. This Statement also requires that
a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate affected
by a change in accounting principle. The provisions of this Statement are
effective for accounting changes and corrections of errors made in fiscal
years
beginning after December 15, 2005. FirstEnergy and the Companies will
adopt
this Statement effective January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows of
the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for FirstEnergy.
This FSP is not expected to have a material impact on FirstEnergy's financial
statements.
SFAS
123(R),
“Share-Based Payment”
In
December 2004,
the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing
stock options in the financial statements. Important to applying the new
standard is understanding how to (1) measure the fair value of stock-based
compensation awards and (2) recognize the related compensation cost for those
awards. For an award to qualify for equity classification, it must meet certain
criteria in SFAS 123(R). An award that does not meet those criteria will
be
classified as a liability and remeasured each period. SFAS 123(R) retains
SFAS
123's requirements on accounting for income tax effects of stock-based
compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R)
to annual, rather than interim, periods that begin after June 15,
2005. The
SEC’s new rule results in a six-month deferral for companies with a fiscal year
beginning January 1. Therefore, FirstEnergy will adopt this Statement
effective January 1, 2006. FirstEnergy expects to adopt modified
prospective application, without restatement of prior interim periods. Potential
cumulative adjustments, if any, have not yet been determined. FirstEnergy
uses
the Black-Scholes option-pricing model to value options for disclosure purposes
only and expects to apply this pricing model upon adoption of SFAS 123(R).
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be “so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective
for
inventory costs incurred by FirstEnergy beginning January 1, 2006.
FirstEnergy is currently evaluating this Standard and does not expect it
to have
a material impact on the financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application to Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security Whose
Cost
Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
loss no later than when the impairment is deemed other than temporary, even
if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP in the
fourth
quarter of 2005, which would require prospective application with an effective
date for reporting periods beginning after December 15, 2005. FirstEnergy
is
currently evaluating this FSP Issue and any impact on its
investments.
FSP
109-1,
“Application of FASB Statement No. 109, Accounting for Income Taxes, to the
Tax
Deduction and Qualified Production Activities Provided by the American Jobs
Creation Act of 2004”
Issued
in December
2004, FSP 109-1 provides guidance related to the provision within the American
Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified
production activities. The Act includes a tax deduction of up to nine percent
(when fully phased-in) of the lesser of (a) “qualified production activities
income,” as defined in the Act, or (b) taxable income (after the deduction for
the utilization of any net operating loss carryforwards). The FASB believes
that
the deduction should be accounted for as a special deduction in accordance
with
SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's
accounting.
16
-
SEGMENT INFORMATION:
FirstEnergy
has
three reportable segments: regulated services, power supply management services
and FSG. The aggregate “Other” segments do not individually meet the criteria to
be considered a reportable segment. FirstEnergy's primary segment is its
regulated services segment, whose operations include the regulated sale of
electricity and distribution and transmission services by its eight EUOCs
in
Ohio, Pennsylvania and New Jersey. The power supply management services segment
primarily consists of the subsidiaries (FES, FGCO, NGC and FENOC) that sell
electricity in deregulated markets and operate the generation facilities
of OE,
CEI, TE and Penn resulting from the deregulation of the Companies' electric
generation business. “Other” consists of MYR (a construction service company),
retail natural gas operations (recently sold - see Note 6) and
telecommunications services. The assets and revenues for the other business
operations are below the quantifiable threshold for operating segments for
separate disclosure as “reportable segments.”
The
regulated
services segment designs, constructs, operates and maintains FirstEnergy's
regulated transmission and distribution systems. Its revenues are primarily
derived from electricity delivery and transition cost recovery. Assets of
the
regulated services segment as of September 30, 2005 and 2004, included
generating units that were leased or whose output was sold to the power supply
management services segment. The regulated services segment’s internal revenues
represent the rental revenues for the generating unit leases.
The
power supply
management services segment has responsibility for FirstEnergy’s generation
operations. Its net income is primarily derived from all electric generation
sales revenues, which consist of generation services to regulated franchise
customers who have not chosen an alternative generation supplier, retail
sales
in deregulated markets and all domestic unregulated electricity sales in
the
retail and wholesale markets, less the related costs of electricity generation
and sourcing of commodity requirements. Its net income also reflects the
expense
of the intersegment generating unit leases and power sales agreements discussed
above and property taxes related to those generating units.
Segment
reporting
for interim periods in 2004 have been reclassified to conform with the current
year business segment organization and operations that were reported in the
2004
Form 10-K, emphasizing FirstEnergy's regulated electric businesses and power
supply management operations and the reclassification of discontinued operations
(see Note 6). FSG is being disclosed as a reporting segment due to its
subsidiaries qualifying as held for sale (see Note 6 for discussion of the
divestiture of three of those subsidiaries in 2005). Interest expense on
holding
company debt and corporate support services revenues and expenses are included
in "Reconciling Items."
Segment
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
Management
|
|
Facilities
|
|
|
|
Reconciling
|
|
|
|
|
|
Services
|
|
Services
|
|
Services
|
|
Other
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Three
Months Ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,676
|
|
$
|
1,712
|
|
$
|
59
|
|
$
|
138
|
|
$
|
2
|
|
$
|
3,587
|
|
Internal
revenues
|
|
|
79
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(79
|
)
|
|
-
|
|
Total
revenues
|
|
|
1,755
|
|
|
1,712
|
|
|
59
|
|
|
138
|
|
|
(77
|
)
|
|
3,587
|
|
Depreciation
and amortization
|
|
|
377
|
|
|
9
|
|
|
-
|
|
|
1
|
|
|
6
|
|
|
393
|
|
Net
interest
charges
|
|
|
88
|
|
|
11
|
|
|
-
|
|
|
2
|
|
|
57
|
|
|
158
|
|
Income
taxes
|
|
|
254
|
|
|
7
|
|
|
-
|
|
|
4
|
|
|
(28
|
)
|
|
237
|
|
Income
before
discontinued operations
|
|
|
366
|
|
|
10
|
|
|
(2
|
)
|
|
6
|
|
|
(49
|
)
|
|
331
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
Net
income
(loss)
|
|
|
366
|
|
|
10
|
|
|
(2
|
)
|
|
7
|
|
|
(49
|
)
|
|
332
|
|
Total
assets
|
|
|
28,385
|
|
|
1,741
|
|
|
82
|
|
|
522
|
|
|
644
|
|
|
31,374
|
|
Total
goodwill
|
|
|
5,938
|
|
|
24
|
|
|
-
|
|
|
62
|
|
|
-
|
|
|
6,024
|
|
Property
additions
|
|
|
207
|
|
|
79
|
|
|
-
|
|
|
1
|
|
|
7
|
|
|
294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
1,481
|
|
$
|
1,756
|
|
$
|
61
|
|
$
|
90
|
|
$
|
(3
|
)
|
$
|
3,385
|
|
Internal
revenues
|
|
|
80
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(80
|
)
|
|
-
|
|
Total
revenues
|
|
|
1,561
|
|
|
1,756
|
|
|
61
|
|
|
90
|
|
|
(83
|
)
|
|
3,385
|
|
Depreciation
and amortization
|
|
|
374
|
|
|
9
|
|
|
-
|
|
|
-
|
|
|
9
|
|
|
392
|
|
Net
interest
charges
|
|
|
82
|
|
|
9
|
|
|
-
|
|
|
-
|
|
|
60
|
|
|
151
|
|
Income
taxes
|
|
|
226
|
|
|
30
|
|
|
-
|
|
|
(1
|
)
|
|
(41
|
)
|
|
214
|
|
Income
before
discontinued operations
|
|
|
315
|
|
|
44
|
|
|
-
|
|
|
(2
|
)
|
|
(61
|
)
|
|
296
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
2
|
|
|
-
|
|
|
3
|
|
Net
income
(loss)
|
|
|
315
|
|
|
44
|
|
|
1
|
|
|
-
|
|
|
(61
|
)
|
|
299
|
|
Total
assets
|
|
|
28,416
|
|
|
1,467
|
|
|
182
|
|
|
596
|
|
|
564
|
|
|
31,225
|
|
Total
goodwill
|
|
|
5,965
|
|
|
24
|
|
|
37
|
|
|
75
|
|
|
-
|
|
|
6,101
|
|
Property
additions
|
|
|
157
|
|
|
46
|
|
|
-
|
|
|
1
|
|
|
7
|
|
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
4,366
|
|
$
|
4,346
|
|
$
|
161
|
|
$
|
385
|
|
$
|
19
|
|
$
|
9,277
|
|
Internal
revenues
|
|
|
237
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(237
|
)
|
|
-
|
|
Total
revenues
|
|
|
4,603
|
|
|
4,346
|
|
|
161
|
|
|
385
|
|
|
(218
|
)
|
|
9,277
|
|
Depreciation
and amortization
|
|
|
1,076
|
|
|
26
|
|
|
-
|
|
|
2
|
|
|
19
|
|
|
1,123
|
|
Net
interest
charges
|
|
|
285
|
|
|
29
|
|
|
1
|
|
|
4
|
|
|
170
|
|
|
489
|
|
Income
taxes
|
|
|
595
|
|
|
(10
|
)
|
|
3
|
|
|
13
|
|
|
(2
|
)
|
|
599
|
|
Income
before
discontinued operations
|
|
|
856
|
|
|
(15
|
)
|
|
(6
|
)
|
|
18
|
|
|
(201
|
)
|
|
652
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
13
|
|
|
5
|
|
|
-
|
|
|
18
|
|
Net
income
(loss)
|
|
|
856
|
|
|
(15
|
)
|
|
7
|
|
|
23
|
|
|
(201
|
)
|
|
670
|
|
Total
assets
|
|
|
28,385
|
|
|
1,741
|
|
|
82
|
|
|
522
|
|
|
644
|
|
|
31,374
|
|
Total
goodwill
|
|
|
5,938
|
|
|
24
|
|
|
-
|
|
|
62
|
|
|
-
|
|
|
6,024
|
|
Property
additions
|
|
|
506
|
|
|
226
|
|
|
1
|
|
|
5
|
|
|
18
|
|
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$
|
4,049
|
|
$
|
4,828
|
|
$
|
156
|
|
$
|
324
|
|
$
|
4
|
|
$
|
9,361
|
|
Internal
revenues
|
|
|
239
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(239
|
)
|
|
-
|
|
Total
revenues
|
|
|
4,288
|
|
|
4,828
|
|
|
156
|
|
|
324
|
|
|
(235
|
)
|
|
9,361
|
|
Depreciation
and amortization
|
|
|
1,098
|
|
|
26
|
|
|
1
|
|
|
-
|
|
|
28
|
|
|
1,153
|
|
Net
interest
charges
|
|
|
301
|
|
|
30
|
|
|
-
|
|
|
2
|
|
|
169
|
|
|
502
|
|
Income
taxes
|
|
|
541
|
|
|
55
|
|
|
(1
|
)
|
|
(19
|
)
|
|
(70
|
)
|
|
506
|
|
Income
before
discontinued operations
|
|
|
761
|
|
|
79
|
|
|
(1
|
)
|
|
39
|
|
|
(207
|
)
|
|
671
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
3
|
|
|
-
|
|
|
6
|
|
Net
income
(loss)
|
|
|
761
|
|
|
79
|
|
|
2
|
|
|
42
|
|
|
(207
|
)
|
|
677
|
|
Total
assets
|
|
|
28,416
|
|
|
1,467
|
|
|
182
|
|
|
596
|
|
|
564
|
|
|
31,225
|
|
Total
goodwill
|
|
|
5,965
|
|
|
24
|
|
|
37
|
|
|
75
|
|
|
-
|
|
|
6,101
|
|
Property
additions
|
|
|
377
|
|
|
149
|
|
|
2
|
|
|
1
|
|
|
17
|
|
|
546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
|
|
17
-
FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS
On
May 13,
2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain
agreements implementing a series of intra-system generation asset transfers.
When fully completed, the asset transfers will result in the respective
undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s
nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively.
The
generating plant interests that are being transferred do not include leasehold
interests of CEI, TE and OE in certain of the plants that are currently subject
to sale and leaseback arrangements with non-affiliates.
On
October 24,
2005, the Ohio Companies and Penn completed the intra-system transfer of
non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee
under a Master Facility Lease with the Ohio Companies and Penn, leased, operated
and maintained the non-nuclear generation assets that it now owns. The asset
transfers were consummated pursuant to the May 13, and May 18, 2005 agreements
and FGCO's purchase option under the Master Facility Lease.
As
contemplated by
the agreements entered into in May 2005, the Ohio Companies and Penn intend
to
transfer their respective interests in the nuclear generation assets to NGC
through, in the case of OE and Penn, a spin-off by way of dividend and, in
the
case of CEI and TE, a sale at net book value. FENOC currently operates and
maintains the nuclear generation assets to be transferred. FirstEnergy currently
expects to complete the nuclear asset transfers in the fourth quarter of
2005,
subject to the receipt of required regulatory approvals.
These
transactions
are pursuant to the Ohio Companies’ and Penn’s restructuring plans that were
approved by the PUCO and the PPUC, respectively, under applicable Ohio and
Pennsylvania electric utility restructuring legislation. Consistent with
the
restructuring plans, generation assets that had been owned by the Ohio Companies
and Penn were required to be separated from the regulated delivery business
of
those companies through transfer to a separate corporate entity. The
transactions will essentially complete the divestitures contemplated by the
restructuring plans by transferring the ownership interests to NGC and FGCO
without impacting the operation of the plants.
The
following table
provides the value of assets pending sale along with the related liabilities
as
of September 30, 2005:
|
|
OE
|
|
Penn
|
|
CEI
|
|
TE
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
Assets
Pending Sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
$
|
1,598
|
|
$
|
440
|
|
$
|
1,305
|
|
$
|
687
|
|
Other
property and investments
|
|
|
363
|
|
|
147
|
|
|
433
|
|
|
276
|
|
Current
assets
|
|
|
93
|
|
|
38
|
|
|
73
|
|
|
42
|
|
Deferred
charges
|
|
|
(60
|
)
|
|
2
|
|
|
-
|
|
|
-
|
|
Total
|
|
$
|
1,994
|
|
$
|
627
|
|
$
|
1,811
|
|
$
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
Related to Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pending
Sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$
|
238
|
|
$
|
53
|
|
$
|
-
|
|
$
|
-
|
|
Current
liabilities
|
|
|
40
|
|
|
31
|
|
|
434
|
|
|
253
|
|
Noncurrent
liabilities
|
|
|
280
|
|
|
226
|
|
|
362
|
|
|
202
|
|
Total
|
|
$
|
558
|
|
$
|
310
|
|
$
|
796
|
|
$
|
455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Assets Pending Sale
|
|
$
|
1,436
|
|
$
|
317
|
|
$
|
1,015
|
|
$
|
550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
Electric
utilities
|
|
$
|
2,935,547
|
|
$
|
2,526,971
|
|
$
|
7,573,858
|
|
$
|
6,874,574
|
|
Unregulated
businesses (Note 2)
|
|
|
651,240
|
|
|
858,497
|
|
|
1,703,281
|
|
|
2,485,959
|
|
Total
revenues
|
|
|
3,586,787
|
|
|
3,385,468
|
|
|
9,277,139
|
|
|
9,360,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power (Note 2)
|
|
|
1,287,225
|
|
|
1,285,355
|
|
|
3,115,153
|
|
|
3,514,816
|
|
Other
operating expenses
|
|
|
992,436
|
|
|
868,440
|
|
|
2,758,378
|
|
|
2,500,182
|
|
Provision
for
depreciation
|
|
|
152,786
|
|
|
147,052
|
|
|
444,443
|
|
|
439,017
|
|
Amortization
of regulatory assets
|
|
|
364,337
|
|
|
324,300
|
|
|
981,750
|
|
|
905,488
|
|
Deferral
of
new regulatory assets
|
|
|
(123,827
|
)
|
|
(78,767
|
)
|
|
(303,496
|
)
|
|
(191,487
|
)
|
General
taxes
|
|
|
187,562
|
|
|
177,452
|
|
|
540,606
|
|
|
514,174
|
|
Total
expenses
|
|
|
2,860,519
|
|
|
2,723,832
|
|
|
7,536,834
|
|
|
7,682,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INTEREST AND INCOME TAXES
|
|
|
726,268
|
|
|
661,636
|
|
|
1,740,305
|
|
|
1,678,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
162,104
|
|
|
152,348
|
|
|
488,462
|
|
|
504,396
|
|
Capitalized
interest
|
|
|
(7,005
|
)
|
|
(6,536
|
)
|
|
(11,957
|
)
|
|
(18,286
|
)
|
Subsidiaries’
preferred stock dividends
|
|
|
2,626
|
|
|
5,354
|
|
|
12,912
|
|
|
16,024
|
|
Net
interest
charges
|
|
|
157,725
|
|
|
151,166
|
|
|
489,417
|
|
|
502,134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
236,711
|
|
|
214,345
|
|
|
599,261
|
|
|
505,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE DISCONTINUED OPERATIONS
|
|
|
331,832
|
|
|
296,125
|
|
|
651,627
|
|
|
670,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations (net of income taxes (benefit) of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$367,000
and
$1,625,000 in the three months ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30,
and ($8,684,000) and $3,762,000 in the nine
|
|
|
|
|
|
|
|
|
|
|
|
|
|
months
ended
September 30, of 2005 and 2004, respectively)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note
6)
|
|
|
528
|
|
|
2,497
|
|
|
18,451
|
|
|
6,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
332,360
|
|
$
|
298,622
|
|
$
|
670,078
|
|
$
|
676,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
1.01
|
|
$
|
0.90
|
|
$
|
1.99
|
|
$
|
2.05
|
|
Discontinued
operations (Note 6)
|
|
|
-
|
|
|
0.01
|
|
|
0.05
|
|
|
0.02
|
|
Net
earnings
per basic share
|
|
$
|
1.01
|
|
$
|
0.91
|
|
$
|
2.04
|
|
$
|
2.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OUTSTANDING
|
|
|
328,119
|
|
|
327,499
|
|
|
328,030
|
|
|
327,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
1.01
|
|
$
|
0.90
|
|
$
|
1.98
|
|
$
|
2.04
|
|
Discontinued
operations (Note 6)
|
|
|
-
|
|
|
0.01
|
|
|
0.05
|
|
|
0.02
|
|
Net
earnings
per diluted share
|
|
$
|
1.01
|
|
$
|
0.91
|
|
$
|
2.03
|
|
$
|
2.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OUTSTANDING
|
|
|
330,193
|
|
|
329,099
|
|
|
329,926
|
|
|
328,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$
|
0.43
|
|
$
|
0.375
|
|
$
|
1.255
|
|
$
|
1.125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Corp. are an integral part of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
332,360
|
|
$
|
298,622
|
|
$
|
670,078
|
|
$
|
676,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
17,723
|
|
|
5,927
|
|
|
19,023
|
|
|
26,536
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
(13,093
|
)
|
|
8,715
|
|
|
(37,216
|
)
|
|
5,265
|
|
Other
comprehensive income (loss)
|
|
|
4,630
|
|
|
14,642
|
|
|
(18,193
|
)
|
|
31,801
|
|
Income
tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
(1,797
|
)
|
|
2,498
|
|
|
(7,704
|
)
|
|
11,026
|
|
Other
comprehensive income (loss), net of tax
|
|
|
6,427
|
|
|
12,144
|
|
|
(10,489
|
)
|
|
20,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
$
|
338,787
|
|
$
|
310,766
|
|
$
|
659,589
|
|
$
|
697,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Corp. are an integral part of these
|
|
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
139,812
|
|
$
|
52,941
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $37,429,000 and
|
|
|
|
|
|
|
|
$34,476,000,
respectively, for uncollectible accounts)
|
|
|
1,336,969
|
|
|
979,242
|
|
Other
(less
accumulated provisions of $26,416,000 and
|
|
|
|
|
|
|
|
$26,070,000,
respectively, for uncollectible accounts)
|
|
|
198,256
|
|
|
377,195
|
|
Materials
and
supplies, at average cost -
|
|
|
|
|
|
|
|
Owned
|
|
|
378,937
|
|
|
363,547
|
|
Under
consignment
|
|
|
117,265
|
|
|
94,226
|
|
Prepayments
and other
|
|
|
235,496
|
|
|
145,196
|
|
|
|
|
2,406,735
|
|
|
2,012,347
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
In
service
|
|
|
22,777,299
|
|
|
22,213,218
|
|
Less
-
Accumulated provision for depreciation
|
|
|
9,688,122
|
|
|
9,413,730
|
|
|
|
|
13,089,177
|
|
|
12,799,488
|
|
Construction
work in progress
|
|
|
684,042
|
|
|
678,868
|
|
|
|
|
13,773,219
|
|
|
13,478,356
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
1,711,112
|
|
|
1,582,588
|
|
Investments
in
lease obligation bonds
|
|
|
905,504
|
|
|
951,352
|
|
Other
|
|
|
773,994
|
|
|
740,026
|
|
|
|
|
3,390,610
|
|
|
3,273,966
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
6,024,376
|
|
|
6,050,277
|
|
Regulatory
assets
|
|
|
5,045,838
|
|
|
5,532,087
|
|
Other
|
|
|
733,164
|
|
|
720,911
|
|
|
|
|
11,803,378
|
|
|
12,303,275
|
|
|
|
$
|
31,373,942
|
|
$
|
31,067,944
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$
|
983,412
|
|
$
|
940,944
|
|
Short-term
borrowings
|
|
|
246,505
|
|
|
170,489
|
|
Accounts
payable
|
|
|
651,941
|
|
|
610,589
|
|
Accrued
taxes
|
|
|
852,477
|
|
|
657,219
|
|
Other
|
|
|
1,110,511
|
|
|
929,194
|
|
|
|
|
3,844,846
|
|
|
3,308,435
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholders’ equity -
|
|
|
|
|
|
|
|
Common
stock,
$0.10 par value, authorized 375,000,000 shares -
|
|
|
|
|
|
|
|
329,836,276
shares outstanding
|
|
|
32,984
|
|
|
32,984
|
|
Other
paid-in
capital
|
|
|
7,033,726
|
|
|
7,055,676
|
|
Accumulated
other comprehensive loss
|
|
|
(323,601
|
)
|
|
(313,112
|
)
|
Retained
earnings
|
|
|
2,115,434
|
|
|
1,856,863
|
|
Unallocated
employee stock ownership plan common stock -
|
|
|
|
|
|
|
|
1,642,223
and
2,032,800 shares, respectively
|
|
|
(30,584
|
)
|
|
(43,117
|
)
|
Total
common stockholders' equity
|
|
|
8,827,959
|
|
|
8,589,294
|
|
Preferred
stock of consolidated subsidiaries
|
|
|
183,719
|
|
|
335,123
|
|
Long-term
debt
and other long-term obligations
|
|
|
9,418,734
|
|
|
10,013,349
|
|
|
|
|
18,430,412
|
|
|
18,937,766
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
2,345,281
|
|
|
2,324,097
|
|
Asset
retirement obligations
|
|
|
1,130,194
|
|
|
1,077,557
|
|
Power
purchase
contract loss liability
|
|
|
1,920,358
|
|
|
2,001,006
|
|
Retirement
benefits
|
|
|
1,343,461
|
|
|
1,238,973
|
|
Lease
market
valuation liability
|
|
|
872,650
|
|
|
936,200
|
|
Other
|
|
|
1,486,740
|
|
|
1,243,910
|
|
|
|
|
9,098,684
|
|
|
8,821,743
|
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
31,373,942
|
|
$
|
31,067,944
|
|
|
|
|
|
|
|
|
|
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
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
332,360
|
|
$
|
298,622
|
|
$
|
670,078
|
|
$
|
676,666
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
152,786
|
|
|
147,052
|
|
|
444,443
|
|
|
439,017
|
|
Amortization
of regulatory assets
|
|
|
364,337
|
|
|
324,300
|
|
|
981,750
|
|
|
905,488
|
|
Deferral
of
new regulatory assets
|
|
|
(123,827
|
)
|
|
(78,767
|
)
|
|
(303,496
|
)
|
|
(191,487
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
25,785
|
|
|
26,776
|
|
|
63,363
|
|
|
71,782
|
|
Amortization
of electric service obligation
|
|
|
(8,630
|
)
|
|
(3,336
|
)
|
|
(24,135
|
)
|
|
(12,877
|
)
|
Deferred
purchased power and other costs
|
|
|
(39,215
|
)
|
|
(118,409
|
)
|
|
(231,438
|
)
|
|
(263,290
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(37,851
|
)
|
|
37,138
|
|
|
24,034
|
|
|
(56,995
|
)
|
Deferred
rents and lease market valuation liability
|
|
|
29,834
|
|
|
28,402
|
|
|
(71,275
|
)
|
|
(52,182
|
)
|
Accrued
retirement benefit obligations
|
|
|
56,116
|
|
|
42,397
|
|
|
104,488
|
|
|
106,897
|
|
Accrued
compensation, net
|
|
|
4,380
|
|
|
25,864
|
|
|
(32,895
|
)
|
|
48,186
|
|
Commodity
derivative transactions, net
|
|
|
(55,101
|
)
|
|
17,336
|
|
|
(40,993
|
)
|
|
(37,443
|
)
|
Cash
collateral from suppliers
|
|
|
76,978
|
|
|
-
|
|
|
76,978
|
|
|
-
|
|
Income
from
discontinued operations (Note 6)
|
|
|
(528
|
)
|
|
(2,497
|
)
|
|
(18,451
|
)
|
|
(6,332
|
)
|
Pension
trust
contribution
|
|
|
-
|
|
|
(500,000
|
)
|
|
-
|
|
|
(500,000
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(90,673
|
)
|
|
16,288
|
|
|
(225,982
|
)
|
|
187,730
|
|
Materials
and
supplies
|
|
|
11,976
|
|
|
6,210
|
|
|
(39,876
|
)
|
|
7,173
|
|
Prepayments
and other current assets
|
|
|
102,025
|
|
|
46,969
|
|
|
(57,192
|
)
|
|
(42,625
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(44,369
|
)
|
|
(37,049
|
)
|
|
59,662
|
|
|
(145,691
|
)
|
Accrued
taxes
|
|
|
167,851
|
|
|
152,009
|
|
|
207,006
|
|
|
296,668
|
|
Accrued
interest
|
|
|
95,721
|
|
|
82,221
|
|
|
91,934
|
|
|
75,158
|
|
Prepayment
for electric service - education programs
|
|
|
-
|
|
|
-
|
|
|
241,685
|
|
|
-
|
|
Other
|
|
|
(38,799
|
)
|
|
15,979
|
|
|
(7,416
|
)
|
|
32,370
|
|
Net
cash
provided from operating activities
|
|
|
981,156
|
|
|
527,505
|
|
|
1,912,272
|
|
|
1,538,213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
88,950
|
|
|
86,754
|
|
|
334,300
|
|
|
961,474
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
228,072
|
|
|
77,295
|
|
|
-
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
(30,000
|
)
|
|
(1,000
|
)
|
|
(169,650
|
)
|
|
(1,000
|
)
|
Long-term
debt
|
|
|
(162,939
|
)
|
|
(772,451
|
)
|
|
(851,687
|
)
|
|
(1,752,394
|
)
|
Short-term
borrowings, net
|
|
|
(308,319
|
)
|
|
-
|
|
|
-
|
|
|
(219,032
|
)
|
Net
controlled disbursement activity
|
|
|
(27,118
|
)
|
|
(19,129
|
)
|
|
(27,594
|
)
|
|
(36,400
|
)
|
Common
stock
dividend payments
|
|
|
(141,023
|
)
|
|
(123,965
|
)
|
|
(411,507
|
)
|
|
(367,751
|
)
|
Net
cash used
for financing activities
|
|
|
(580,449
|
)
|
|
(601,719
|
)
|
|
(1,048,843
|
)
|
|
(1,415,103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(294,443
|
)
|
|
(211,243
|
)
|
|
(756,118
|
)
|
|
(545,743
|
)
|
Proceeds
from
asset sales
|
|
|
-
|
|
|
1,662
|
|
|
61,207
|
|
|
213,109
|
|
Proceeds
from
certificates of deposit
|
|
|
-
|
|
|
277,763
|
|
|
-
|
|
|
277,763
|
|
Nonutility
generation trust contributions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(50,614
|
)
|
Contributions
to nuclear decommissioning trusts
|
|
|
(25,370
|
)
|
|
(25,370
|
)
|
|
(76,112
|
)
|
|
(76,112
|
)
|
Cash
investments
|
|
|
(13,950
|
)
|
|
(7,316
|
)
|
|
21,171
|
|
|
19,640
|
|
Other
|
|
|
23,120
|
|
|
7,072
|
|
|
(26,706
|
)
|
|
(7,236
|
)
|
Net
cash
provided from (used for) investing activities
|
|
|
(310,643
|
)
|
|
42,568
|
|
|
(776,558
|
)
|
|
(169,193
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
90,064
|
|
|
(31,646
|
)
|
|
86,871
|
|
|
(46,083
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
49,748
|
|
|
99,538
|
|
|
52,941
|
|
|
113,975
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
139,812
|
|
$
|
67,892
|
|
$
|
139,812
|
|
$
|
67,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to FirstEnergy
Corp. are an integral part of these
|
|
|
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholders
and Board of
Directors
of
FirstEnergy Corp.:
We
have reviewed
the accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of September 30, 2005, and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
and
nine-month periods ended September 30, 2005 and 2004. 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, 2004, and the related consolidated statements of income,
capitalization, common stockholders’ equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note
2(K) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 7 to those consolidated financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE
SUMMARY
Net
income in the
third quarter of 2005 was $332 million, or basic and diluted earnings of
$1.01
per share of common stock, compared to net income of $299 million, or basic
and
diluted earnings of $0.91 per share of common stock for the third quarter
of
2004. Net income in the first nine months of 2005 was $670 million, or basic
earnings of $2.04 per share of common stock ($2.03 diluted) compared to $677
million in the first nine months of 2004, or basic earnings of $2.07 per
share
of common stock ($2.06 diluted). The following Non-GAAP Reconciliation displays
the unusual items resulting in the difference between GAAP and non-GAAP
earnings.
Reconciliation
of non-GAAP to GAAP
|
|
2005
|
|
2004
|
|
|
|
After-tax
|
|
Basic
|
|
After-tax
|
|
Basic
|
|
|
|
Amount
|
|
Earnings
|
|
Amount
|
|
Earnings
|
|
Three
Months Ended September 30,
|
|
(Millions)
|
|
Per
Share
|
|
(Millions)
|
|
Per
Share
|
|
Earnings
Before Unusual Items (Non-GAAP)
|
|
$
|
342
|
|
$
|
1.04
|
|
$
|
319
|
|
$
|
0.97
|
|
Unusual
Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-core
asset sales gains/losses, net
|
|
|
-
|
|
|
-
|
|
|
(16
|
)
|
|
(0.05
|
)
|
JCP&L
arbitration decision
|
|
|
(10
|
)
|
|
(0.03
|
)
|
|
-
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
-
|
|
|
(4
|
)
|
|
(0.01
|
)
|
Net
Income
(GAAP)
|
|
$
|
332
|
|
$
|
1.01
|
|
$
|
299
|
|
$
|
0.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Before Unusual Items (Non-GAAP)
|
|
$
|
730
|
|
$
|
2.22
|
|
$
|
753
|
|
$
|
2.30
|
|
Unusual
Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-core
asset sales gains/losses, net
|
|
|
22
|
|
|
0.07
|
|
|
(23
|
)
|
|
(0.07
|
)
|
Davis-Besse
impacts
|
|
|
-
|
|
|
-
|
|
|
(38
|
)
|
|
(0.12
|
)
|
EPA
settlement
|
|
|
(14
|
)
|
|
(0.04
|
)
|
|
-
|
|
|
-
|
|
NRC
fine
|
|
|
(3
|
)
|
|
(0.01
|
)
|
|
-
|
|
|
-
|
|
JCP&L
rate settlement
|
|
|
16
|
|
|
0.05
|
|
|
-
|
|
|
-
|
|
JCP&L
arbitration decision
|
|
|
(10
|
)
|
|
(0.03
|
)
|
|
-
|
|
|
-
|
|
Ohio
tax write-off
|
|
|
(71
|
)
|
|
(0.22
|
)
|
|
-
|
|
|
-
|
|
Class-action
lawsuit settlement
|
|
|
-
|
|
|
-
|
|
|
(11
|
)
|
|
(0.03
|
)
|
Other
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
(0.01
|
)
|
Net
Income
(GAAP)
|
|
$
|
670
|
|
$
|
2.04
|
|
$
|
677
|
|
$
|
2.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Non-GAAP
measure above, earnings before unusual items, is not calculated in accordance
with GAAP because it excludes the impact of "unusual items." Unusual items
reflect the impact on earnings of events that are not routine or for which
management believes the financial impact will disappear or become immaterial
within a near-term finite period. By removing the earnings effect of such
issues
that have been resolved or are expected to be resolved over the near term,
management and investors can better measure FirstEnergy’s business and earnings
potential. In particular, the non-core asset sales item refers to a finite
set
of energy-related assets that have been previously disclosed as held for
sale, a
substantial portion of which has already been sold. In addition, as Davis-Besse
restarted in 2004, further impacts from its extended outage are not expected.
Similarly, further litigation settlements similar to the class action
settlements in 2004 are not reasonably expected over the near term. Furthermore,
FirstEnergy believes presenting normalized earnings calculated in this
manner
provides useful information to investors in evaluating the ongoing results
of
its businesses, over the longer term and assists investors in comparing
FirstEnergy’s operating performance to the operating performance of others in
the energy sector.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the nuclear
fleet through the third quarter of 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base load
generation fleet, low-risk transmission and distribution operations and
rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also noted
as
strengths.
On
September 20,
2005, FirstEnergy raised its quarterly dividend to $0.43 per share of
outstanding common stock - 4.2% higher than the previous quarterly rate of
$0.4125 per share. This action represents the second dividend payment increase
this year. The dividend payment was last increased by 10% for the dividend
paid
on March 1, 2005. The new dividend is payable December 1, 2005
to
shareholders of record on November 7, 2005. The Company’s dividend policy,
established on November 30, 2004, targets sustainable annual dividend
increases after 2005, generally reflecting an annual growth rate of 4% to
5%,
and an earnings payout ratio generally within the range of 50% to 60%. The
Board
of Directors will continue to review the Company's dividend policy regularly.
The amount and timing of all dividend payments are subject to the Board's
consideration of business conditions, results of operations, financial condition
and other factors.
On
September 9,
2005, FirstEnergy filed on behalf of the Ohio Companies an RCP that, if approved
by the PUCO, would essentially maintain current electricity prices through
2008.
The RCP was developed as a result of concerns about potential impacts to
customer rates due to rising fuel prices and other factors. A stipulated
agreement in support of the plan has been signed by the cities of Cleveland
and
Akron, along with the Industrial Energy Users - Ohio and the Ohio Energy
Group.
Also, the Mayor of the City of Parma has agreed to support the stipulation.
The
Parma City Council passed a resolution in support of the RCP plan on September
19, 2005.
During
the third
quarter of 2005, several FirstEnergy operating companies reached employment
agreements with various local unions. On July 13, 2005, UWUA 118
and 126 -
representing 445 workers - ratified an agreement with OE. On August 17,
2005, UWUA Local 180 - representing 170 workers - ratified an agreement
with
Penelec. On August 25, 2005, IBEW Local 1194 - representing 240
employees -
ratified an agreement with OE. The collective bargaining agreement with
IBEW
Local 29 representing approximately 450 workers at the Beaver Valley Nuclear
Power Station expired pursuant to its terms on September 30, 2005. The
parties
are currently negotiating a new agreement.
On
September 14, 2005, FENOC announced that it would pay the $5.45 million
fine proposed in April 2005 by the NRC related to the reactor head issue
at the
Davis-Besse Nuclear Power Station. FirstEnergy accrued $2.0 million of the
fine
in 2004 and the remaining amount in the first quarter of 2005. In a letter
to
the NRC, the Company noted that paying the fine brings regulatory closure
to
this issue and enables it to continue focusing on safe, reliable plant
operations. The letter also reiterated that FENOC acknowledges full
responsibility for the significant performance deficiencies that led to the
reactor head issue, and that the NRC has indicated that the cited violations
regarding the past plant operations do not represent current
performance.
FirstEnergy
announced on September 22, 2005, that FGCO plans to install an
Electro-Catalytic Oxidation (ECO) system on the 215-megawatt Unit 4 of its
Bay
Shore Plant in Oregon, Ohio. ECO is a multipollutant-control technology for
coal-based electric utility plants that was developed by Powerspan Corp.,
a
clean energy technology company in which FirstEnergy has a minority ownership
interest.
ECO
is currently
being demonstrated at FGCO's R. E. Burger Plant, and has proven effective
in
reducing NOx, SO2,
mercury, acid
gases, and fine particulates (soot). The ECO process also produces a highly
marketable ammonium sulfate fertilizer co-product, currently being sold to
the
fertilizer market.
FGCO
expects design
engineering of the Bay Shore ECO system to commence in the first quarter
of
2006, and estimates the overall cost of the system, including a fertilizer
processing plant, to be approximately $100 million.
FIRSTENERGY’S
BUSINESS
FirstEnergy
is a
registered public utility holding company headquartered in Akron, Ohio that
operates primarily through two core business segments.
·
|
Regulated
Services
transmits,
distributes and sells electricity through eight utility operating
companies that collectively comprise the nation’s fifth largest
investor-owned electric system, serving 4.5 million customers within
36,100 square miles of Ohio, Pennsylvania and New Jersey. This
business
segment primarily derives its revenue from the delivery of electricity,
including transition cost recovery.
|
·
|
Power
Supply Management Services
supplies the
electric power needs of end-use customers (principally in Ohio,
Pennsylvania and New Jersey) through retail and wholesale arrangements,
including sales to meet the PLR requirements of FirstEnergy’s Ohio
Companies and Penn. This business segment operates FirstEnergy's
generating facilities and purchases from the wholesale market to
meet its
sales obligations. Pursuant to an asset transfer on October 24,
2005,
it now owns as well as operates FirstEnergy's fossil and hydroelectric
generation facilities previously owned by the EUOC. It also purchases
the
entire output of the nuclear plants currently owned or leased by
the EUOC.
This business segment principally derives its revenues from electric
generation sales.
|
Other
operating
segments provide a wide range of services, including heating, ventilation,
air-conditioning, refrigeration, electrical and facility control systems,
high-efficiency electrotechnologies and telecommunication services. FirstEnergy
is in the process of divesting non-core businesses. See Note 6 to the
consolidated financial statements. The assets and revenues for the other
business operations are below the quantifiable threshold for operating segments
for separate disclosure as “reportable segments”.
FIRSTENERGY
INTRA-SYSTEM GENERATION ASSET TRANSFERS
On
May 13,
2005, Penn, and on May 18, 2005 the Ohio Companies, entered into certain
agreements implementing a series of intra-system generation asset transfers.
When fully completed, the asset transfers will result in the respective
undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s
nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively.
The
generating plant interests that are being transferred do not include leasehold
interests of CEI, TE and OE in certain of the plants that are currently subject
to sale and leaseback arrangements with non-affiliates.
On
October 24,
2005, the Ohio Companies and Penn completed the intra-system transfer of
non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee
under a Master Facility Lease with the Ohio Companies and Penn, leased, operated
and maintained the non-nuclear generation assets that it now owns. The asset
transfers were consummated pursuant to the May 13 and May 18, 2005 agreements
and FGCO's purchase option under the Master Facility Lease.
As
contemplated by
the agreements entered into in May 2005, the Ohio Companies and Penn intend
to
transfer their respective interests in the nuclear generation assets to NGC
through, in the case of OE and Penn, a spin-off by way of dividend and, in
the
case of CEI and TE, a sale at net book value. FENOC currently operates and
maintains the nuclear generation assets to be transferred. FirstEnergy currently
expects to complete the nuclear asset transfers in the fourth quarter of 2005,
subject to the receipt of required regulatory approvals.
These
transactions
are pursuant to the Ohio Companies’ and Penn’s restructuring plans that were
approved by the PUCO and the PPUC, respectively, under applicable Ohio and
Pennsylvania electric utility restructuring legislation. Consistent with the
restructuring plans, generation assets that had been owned by the Ohio Companies
and Penn were required to be separated from the regulated delivery business
of
those companies through transfer to a separate corporate entity. The
transactions will essentially complete the divestitures contemplated by the
restructuring plans by transferring the ownership interests to NGC and FGCO
without impacting the operation of the plants.
See
Note 17 for
disclosure of the assets held for sale by the Ohio Companies and Penn as of
September 30, 2005.
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 16 to the consolidated financial statements. The FSG
business segment is included in “Other and Reconciling Adjustments” in this
discussion due to its immaterial impact on current period financial results,
but
is presented separately in segment information provided in Note 16 to the
consolidated financial statements. Net income (loss) by major business segment
is as follows:
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
September
30,
|
|
Increase
|
|
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
|
|
(In
millions, except per share amounts)
|
|
Net
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By
Business Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Services
|
|
|
|
|
$
|
366
|
|
$
|
315
|
|
$
|
51
|
|
$
|
856
|
|
$
|
761
|
|
$
|
95
|
|
Power
supply
management services
|
|
|
|
|
|
10
|
|
|
44
|
|
|
(34
|
)
|
|
(15
|
)
|
|
79
|
|
|
(94
|
)
|
Other
and
reconciling adjustments*
|
|
|
|
|
|
(44
|
)
|
|
(60
|
)
|
|
16
|
|
|
(171
|
)
|
|
(163
|
)
|
|
(8
|
)
|
Total
|
|
|
|
|
$
|
332
|
|
$
|
299
|
|
$
|
33
|
|
$
|
670
|
|
$
|
677
|
|
$
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
|
|
|
$
|
1.01
|
|
$
|
0.90
|
|
$
|
0.11
|
|
$
|
1.99
|
|
$
|
2.05
|
|
$
|
(0.06
|
)
|
Discontinued
operations
|
|
|
|
|
|
--
|
|
|
0.01
|
|
|
(0.01
|
)
|
|
0.05
|
|
|
0.02
|
|
|
0.03
|
|
Net
earnings
per basic share
|
|
|
|
|
$
|
1.01
|
|
$
|
0.91
|
|
$
|
0.10
|
|
$
|
2.04
|
|
$
|
2.07
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before
discontinued operations
|
|
|
|
|
$
|
1.01
|
|
$
|
0.90
|
|
$
|
0.11
|
|
$
|
1.98
|
|
$
|
2.04
|
|
$
|
(0.06
|
)
|
Discontinued
operations
|
|
|
|
|
|
--
|
|
|
0.01
|
|
|
(0.01
|
)
|
|
0.05
|
|
|
0.02
|
|
|
0.03
|
|
Net
earnings
per diluted share
|
|
|
|
|
$
|
1.01
|
|
$
|
0.91
|
|
$
|
0.10
|
|
$
|
2.03
|
|
$
|
2.06
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
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
regulated services segment for the three months and nine months ended
September 30, 2005 increased due to additional customer demand. However,
net income for the power supply management services segment was lower in
both
the three months and nine months ended September 30, 2005 compared to the
same
periods in 2004, as a result of higher costs for fossil fuel, purchased power
(excluding 2004 PJM transactions on a gross basis) and nuclear refueling
costs
which, in aggregate, more than offset the revenue from increased electric
generation sales.
A
decrease in
wholesale electric revenues and purchased power costs in the 2005 periods
compared to the corresponding periods last year primarily resulted from FES
recording PJM sales and purchased power transactions on an hourly net position
basis beginning in the first quarter of 2005 compared with recording each
discrete transaction (on a gross basis) in 2004 (See Note 2 - Accounting
for
Wholesale Energy Transactions). This change had no impact on earnings and
resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM
in January 2005. Wholesale electric revenues and purchased power costs in
the
three months and nine months ended September 30, 2004 each included
additional amounts of $264 million and $828 million, respectively, due to
recording those transactions on a gross basis.
Excluding
the
effect of recording the wholesale electric revenue transactions in PJM on
a
gross basis in 2004, total operating revenues in the three months and nine
months ended September 30, 2005 increased 14.9% and 8.7%, respectively,
reflecting in large part warmer than normal temperatures during the summer
of
2005 compared to 2004.
Summary
of Results of Operations - Third Quarter of 2005 compared with the Third
Quarter
of 2004
Financial
results
for FirstEnergy and its major business segments in the third quarter of 2005
and
2004 were as follows:
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
3rd
Quarter 2005
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Quarterly
Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,432
|
|
$
|
1,684
|
|
$
|
--
|
|
$
|
3,116
|
|
Other
|
|
|
244
|
|
|
28
|
|
|
199
|
|
|
471
|
|
Internal
|
|
|
79
|
|
|
--
|
|
|
(79
|
)
|
|
--
|
|
Total
Revenues
|
|
|
1,755
|
|
|
1,712
|
|
|
120
|
|
|
3,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
--
|
|
|
1,287
|
|
|
--
|
|
|
1,287
|
|
Other
operating
|
|
|
511
|
|
|
364
|
|
|
118
|
|
|
993
|
|
Provision
for
depreciation
|
|
|
137
|
|
|
9
|
|
|
7
|
|
|
153
|
|
Amortization
of regulatory assets
|
|
|
364
|
|
|
--
|
|
|
--
|
|
|
364
|
|
Deferral
of
new regulatory assets
|
|
|
(124
|
)
|
|
--
|
|
|
--
|
|
|
(124
|
)
|
General
taxes
|
|
|
159
|
|
|
24
|
|
|
5
|
|
|
188
|
|
Total
Expenses
|
|
|
1,047
|
|
|
1,684
|
|
|
130
|
|
|
2,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest
charges
|
|
|
88
|
|
|
11
|
|
|
59
|
|
|
158
|
|
Income
taxes
|
|
|
254
|
|
|
7
|
|
|
(24
|
)
|
|
237
|
|
Income
before
discontinued operations
|
|
|
366
|
|
|
10
|
|
|
(45
|
)
|
|
331
|
|
Discontinued
operations
|
|
|
--
|
|
|
--
|
|
|
1
|
|
|
1
|
|
Net
Income
(Loss)
|
|
$
|
366
|
|
$
|
10
|
|
$
|
(44
|
)
|
$
|
332
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
3rd
Quarter 2004
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Quarterly
Financial Results
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,309
|
|
$
|
1,721
|
|
$
|
--
|
|
$
|
3,030
|
|
Other
|
|
|
172
|
|
|
35
|
|
|
148
|
|
|
355
|
|
Internal
|
|
|
80
|
|
|
--
|
|
|
(80
|
)
|
|
--
|
|
Total
Revenues
|
|
|
1,561
|
|
|
1,756
|
|
|
68
|
|
|
3,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
--
|
|
|
1,285
|
|
|
--
|
|
|
1,285
|
|
Other
operating
|
|
|
414
|
|
|
356
|
|
|
99
|
|
|
869
|
|
Provision
for
depreciation
|
|
|
129
|
|
|
9
|
|
|
9
|
|
|
147
|
|
Amortization
of regulatory assets
|
|
|
324
|
|
|
--
|
|
|
--
|
|
|
324
|
|
Deferral
of
new regulatory assets
|
|
|
(79
|
)
|
|
--
|
|
|
--
|
|
|
(79
|
)
|
General
taxes
|
|
|
150
|
|
|
23
|
|
|
5
|
|
|
178
|
|
Total
Expenses
|
|
|
938
|
|
|
1,673
|
|
|
113
|
|
|
2,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest
charges
|
|
|
82
|
|
|
9
|
|
|
60
|
|
|
151
|
|
Income
taxes
|
|
|
226
|
|
|
30
|
|
|
(42
|
)
|
|
214
|
|
Income
before
discontinued operations
|
|
|
315
|
|
|
44
|
|
|
(63
|
)
|
|
296
|
|
Discontinued
operations
|
|
|
--
|
|
|
--
|
|
|
3
|
|
|
3
|
|
Net
Income
(Loss)
|
|
$
|
315
|
|
$
|
44
|
|
$
|
(60
|
)
|
$
|
299
|
|
Change
Between
|
|
|
|
Power
|
|
|
|
|
|
3rd
Quarter 2005 and 2004
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
Quarterly
Financial Results
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Increase
(Decrease)
|
|
Services
|
|
Services
|
|
Adjustments(1)
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
123
|
|
$
|
(37
|
)
|
$
|
--
|
|
$
|
86
|
|
Other
|
|
|
72
|
|
|
(7
|
)
|
|
51
|
|
|
116
|
|
Internal
|
|
|
(1
|
)
|
|
--
|
|
|
1
|
|
|
--
|
|
Total
Revenues
|
|
|
194
|
|
|
(44
|
)
|
|
52
|
|
|
202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
--
|
|
|
2
|
|
|
--
|
|
|
2
|
|
Other
operating
|
|
|
97
|
|
|
8
|
|
|
19
|
|
|
124
|
|
Provision
for
depreciation
|
|
|
8
|
|
|
--
|
|
|
(2
|
)
|
|
6
|
|
Amortization
of regulatory assets
|
|
|
40
|
|
|
--
|
|
|
--
|
|
|
40
|
|
Deferral
of
new regulatory assets
|
|
|
(45
|
)
|
|
--
|
|
|
--
|
|
|
(45
|
)
|
General
taxes
|
|
|
9
|
|
|
1
|
|
|
--
|
|
|
10
|
|
Total
Expenses
|
|
|
109
|
|
|
11
|
|
|
17
|
|
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest
charges
|
|
|
6
|
|
|
2
|
|
|
(1
|
)
|
|
7
|
|
Income
taxes
|
|
|
28
|
|
|
(23
|
)
|
|
18
|
|
|
23
|
|
Income
before
discontinued operations
|
|
|
51
|
|
|
(34
|
)
|
|
18
|
|
|
35
|
|
Discontinued
operations
|
|
|
--
|
|
|
--
|
|
|
(2
|
)
|
|
(2
|
)
|
Net
Income
(Loss)
|
|
$
|
51
|
|
$
|
(34
|
)
|
$
|
16
|
|
$
|
33
|
|
|
(1)
The
impact of
the new Ohio tax legislation is included with FirstEnergy’s other
operating segments and reconciling adjustments.
|
Regulated
Services - Third Quarter 2005 Compared with Third Quarter
2004
Net
income
increased $51 million, or 16% to $366 million, in the third quarter of 2005
compared to $315 million in the third quarter of 2004, as a result of increased
customer usage.
Revenues
-
Total
revenues
increased by $194 million in the third quarter 2005 compared to the same
period
in 2004, resulting from the following sources:
|
|
Three
Months Ended
|
|
|
|
|
September
30,
|
|
|
|
Revenues
by Type of Service
|
|
2005
|
|
2004
|
|
Increase
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
Distribution
services
|
|
$
|
1,432
|
|
$
|
1,309
|
|
$
|
123
|
|
Transmission
services
|
|
|
117
|
|
|
81
|
|
|
36
|
|
Lease
revenue
from affiliates
|
|
|
79
|
|
|
79
|
|
|
--
|
|
Other
|
|
|
127
|
|
|
92
|
|
|
35
|
|
Total
Revenues
|
|
$
|
1,755
|
|
$
|
1,561
|
|
$
|
194
|
|
Changes
in
distribution deliveries by customer class in the third quarter of 2005 compared
with the third quarter of 2004 are summarized in the following
table:
|
|
|
|
|
|
Electric
Distribution Deliveries
|
|
|
|
Increase
|
|
Residential
|
|
|
|
|
|
15.4
|
%
|
Commercial
|
|
|
|
|
|
7.8
|
%
|
Industrial
|
|
|
|
|
|
5.2
|
%
|
Total
Distribution Deliveries
|
|
|
|
|
|
9.6
|
%
|
|
|
|
|
|
|
|
|
Increased
consumption offset in part by lower composite prices to customers resulted
in
higher distribution delivery revenue. The following table summarizes major
factors contributing to the $123 million increase in distribution services
revenue in the third quarter of 2005:
|
|
Increase
|
|
Sources
of Change in Distribution Revenues
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
Changes
in
customer usage
|
|
$
|
135
|
|
Changes
in
prices:
|
|
|
|
|
Rate
changes
--
|
|
|
|
|
Ohio
shopping
credits
|
|
|
(11
|
)
|
JCP&L
rate settlements
|
|
|
21
|
|
Billing
component reallocations
|
|
|
(22
|
)
|
Net
Increase
in Distribution Revenues
|
|
$
|
123
|
|
Distribution
revenues benefited from warmer summer temperatures in the third quarter of
2005,
compared to 2004, that increased the air-conditioning load of residential
and
commercial customers. While industrial deliveries also increased, that impact
was more than offset by lower unit prices to that sector. Higher base rates
from
JCP&L's stipulated rate settlements were more than offset by additional
credits provided to customers under the Ohio transition plan and a reallocation
of billing components primarily related to special contracts. Shopping
credits do not affect current period earnings due to deferral of the incentives
for future recovery from customers.
Transmission
revenues increased $36 million in the third quarter of 2005 from the same
period
last year due in part to increased loads due to warmer weather and higher
transmission usage prices. Other
revenues
increased $35 million primarily due to higher gains realized on nuclear
decommissioning trust investments.
Expenses-
The
increase in
total revenues discussed above was partially offset by the following increases
in total expenses:
· Other
operating
expenses increased by $97 million in the third quarter of 2005 compared to
the
same
period in 2004 primarily due to increased transmission expenses resulting
in part from increased loads
and
higher transmission system usage charges;
· Increased
provision
for depreciation of $8 million that resulted from property additions and
increased
leasehold improvement amortization;
·
Additional
amortization of regulatory assets of $40 million, principally Ohio transition
costs;
|
·
|
Higher general taxes of $9 million resulting from increased EUOC
sales
which increased the Ohio KWH
tax and the Pennsylvania gross receipts
tax;
|
·
Increased
interest
charges of $6 million primarily due to the absence of $11 million in interest
rate swap
savings achieved in the third quarter of 2004; and
·
Higher
income taxes of $28 million due to increased taxable income.
Partially
offsetting those increases was the effect of additional deferred regulatory
assets of $45 million, primarily due to the PUCO-approved deferral of MISO
administrative costs, shopping incentives and related interest.
Power
Supply Management Services - Third Quarter 2005 Compared with Third Quarter
2004
Net
income for this
segment decreased $34 million to $10 million in the third quarter of 2005
from
$44 million in the same period last year, due to a decrease in the gross
generation margin and higher operating costs.
Revenues
-
Excluding
the
effect of the change in recording PJM wholesale transactions on a gross
basis in
2004 ($264 million), electric generation revenues increased $227
million in
the third quarter of 2005 compared to the same period of 2004 primarily
as a
result of a 5.2% increase in KWH sales due to higher retail customer usage
and a
21% rise in unit prices in the wholesale market. The increase in retail
sales
reduced energy available for sale to the wholesale market, resulting in
a 9%
reduction in wholesale sales (before the PJM adjustment).
The
change in
reported segment revenues resulted from the following:
|
|
Three
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Electric
generation sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
1,254
|
|
$
|
1,069
|
|
$
|
185
|
|
Wholesale
|
|
|
430
|
|
|
388
|
|
|
42
|
|
Total
electric generation sales
|
|
|
1,684
|
|
|
1,457
|
|
|
227
|
|
Transmission
|
|
|
16
|
|
|
20
|
|
|
(4
|
)
|
Other
|
|
|
12
|
|
|
15
|
|
|
(3
|
)
|
Total
|
|
|
1,712
|
|
|
1,492
|
|
|
220
|
|
PJM
gross
transactions
|
|
|
--
|
|
|
264
|
|
|
(264
|
)
|
Total
Revenues
|
|
$
|
1,712
|
|
$
|
1,756
|
|
$
|
(44
|
)
|
The
following table
summarizes the price and volume factors contributing to increased sales to
retail and wholesale customers.
|
|
Increase
|
|
Source
of Change in Electric Generation Sales
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of
9.9% increase in customer usage
|
|
$
|
113
|
|
Change
in
prices
|
|
|
72
|
|
|
|
|
185
|
|
Wholesale:
|
|
|
|
|
Effect
of
8.7% reduction in customer usage(1)
|
|
|
(41
|
)
|
Change
in
prices
|
|
|
83
|
|
|
|
|
42
|
|
Net
Increase
in Electric Generation Sales
|
|
$
|
227
|
|
|
|
(1)
Decrease of
46.4% including the effect of the PJM revision.
|
|
Expenses
-
Excluding
the
effect of $264 million of PJM purchased power costs recorded on a gross basis
in
2004, total operating expenses, net interest charges and income taxes increased
in aggregate by $254 million in the third quarter of 2005 compared to the
same
period of 2004. Higher fuel and purchased power costs contributed $2 million
($266 million, net of $264 million PJM effect) of the increase, resulting
from
higher fuel costs of $121 million and increased purchased power costs of
$145
million. Factors contributing to the higher costs are summarized in the
following table:
|
|
Increase
|
|
Source
of Change in Fuel and Purchased Power
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Fuel:
|
|
|
|
|
Change
due to
increased unit costs
|
|
$
|
92
|
|
Change
due to
volume consumed
|
|
|
29
|
|
|
|
|
121
|
|
Purchased
Power:
|
|
|
|
Change
due to
increased unit costs
|
|
|
130
|
|
Change
due to
volume purchased
|
|
|
(16
|
)
|
Reduction
in
costs deferred
|
|
|
31
|
|
|
|
|
145
|
|
PJM
gross
transactions
|
|
|
(264
|
)
|
Net
Increase
in Fuel and Purchased Power Costs
|
|
$
|
2
|
|
|
|
|
|
|
FirstEnergy’s
generation fleet established an output record of 21.7 billion KWH in the
third
quarter of 2005. As a result, increased coal consumption and the related
cost of
emission allowances combined to increase fossil fuel expense. Higher coal
costs
resulted from increased market purchases, market adjustment provisions in
coal
contracts reflecting higher market prices and increased transportation costs.
Emission allowance costs increased primarily from higher prices. To a lesser
extent, fuel expense increased due to higher costs associated with the increase
in generation from the fossil units relative to nuclear generation. Fossil
generation output increased 16% in the third quarter of 2005 while nuclear
output increased by 1%, compared to the same period in 2004.
Other
operating
costs increased $8 million in the third quarter of 2005 compared to the same
period of 2004. This increase resulted from higher transmission costs due
primarily to increased loads and higher transmission system usage charges.
The
higher costs this year were offset in part by lower non-fuel nuclear costs
resulting from expenses incurred late in the third quarter of 2004 in
preparation for the fourth quarter of 2004 Beaver Valley Unit 1 refueling
outage.
Offsetting
higher
operating costs were lower income taxes of $23 million due to lower taxable
income.
Other
-
Third Quarter 2005 Compared with Third Quarter 2004
FirstEnergy’s
financial results from other operating segments and reconciling adjustments,
including interest expense on holding company debt and corporate support
services revenues and expenses, resulted in a net increase of $16 million
in net
income in the third quarter of 2005 compared to the same quarter of 2004.
The
increase was primarily due to the absence this year of losses recognized
in 2004
on the sale of securities and impairment of several partnership
investments.
Summary
of Results of Operations - Nine Months ended September 30, 2005 compared
with
the Nine Months ended September 30, 2004
Financial
results
for FirstEnergy and its major business segments for the nine months ended
September 30, 2005 and 2004 were as follows:
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
Nine
Months ended September 30, 2005
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Financial
Results
|
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
|
(In
millions)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
|
|
$
|
3,759
|
|
$
|
4,273
|
|
$
|
-
|
|
$
|
8,032
|
|
Other
|
|
|
|
|
607
|
|
|
73
|
|
|
565
|
|
|
1,245
|
|
Internal
|
|
|
|
|
237
|
|
|
-
|
|
|
(237
|
)
|
|
-
|
|
Total
Revenues
|
|
|
|
|
4,603
|
|
|
4,346
|
|
|
328
|
|
|
9,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
|
|
-
|
|
|
3,115
|
|
|
-
|
|
|
3,115
|
|
Other
operating
|
|
|
|
|
1,336
|
|
|
1,132
|
|
|
290
|
|
|
2,758
|
|
Provision
for
depreciation
|
|
|
|
|
397
|
|
|
26
|
|
|
21
|
|
|
444
|
|
Amortization
of regulatory assets
|
|
|
|
|
982
|
|
|
-
|
|
|
-
|
|
|
982
|
|
Deferral
of
new regulatory assets
|
|
|
|
|
(303
|
)
|
|
-
|
|
|
-
|
|
|
(303
|
)
|
General
taxes
|
|
|
|
|
455
|
|
|
69
|
|
|
17
|
|
|
541
|
|
Total
Expenses
|
|
|
|
|
2,867
|
|
|
4,342
|
|
|
328
|
|
|
7,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest
charges
|
|
|
|
|
285
|
|
|
29
|
|
|
175
|
|
|
489
|
|
Income
taxes
|
|
|
|
|
595
|
|
|
(10
|
)
|
|
14
|
|
|
599
|
|
Income
before
discontinued operations
|
|
|
|
|
856
|
|
|
(15
|
)
|
|
(189
|
)
|
|
652
|
|
Discontinued
operations
|
|
|
|
|
-
|
|
|
-
|
|
|
18
|
|
|
18
|
|
Net
Income
(Loss)
|
|
|
|
$
|
856
|
|
$
|
(15
|
)
|
$
|
(171
|
)
|
$
|
670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
|
|
|
|
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
Nine
Months ended September 30, 2004
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Financial
Results
|
|
|
Services
|
|
Services
|
|
Adjustments
|
|
Consolidated
|
|
|
|
|
(In
millions)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
|
|
$
|
3,588
|
|
$
|
4,742
|
|
$
|
--
|
|
$
|
8,330
|
|
Other
|
|
|
|
|
461
|
|
|
86
|
|
|
484
|
|
|
1,031
|
|
Internal
|
|
|
|
|
239
|
|
|
--
|
|
|
(239
|
)
|
|
--
|
|
Total
Revenues
|
|
|
|
|
4,288
|
|
|
4,828
|
|
|
245
|
|
|
9,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
|
|
--
|
|
|
3,515
|
|
|
--
|
|
|
3,515
|
|
Other
operating
|
|
|
|
|
1,155
|
|
|
1,058
|
|
|
288
|
|
|
2,501
|
|
Provision
for
depreciation
|
|
|
|
|
384
|
|
|
26
|
|
|
29
|
|
|
439
|
|
Amortization
of regulatory assets
|
|
|
|
|
905
|
|
|
--
|
|
|
--
|
|
|
905
|
|
Deferral
of
new regulatory assets
|
|
|
|
|
(192
|
)
|
|
--
|
|
|
--
|
|
|
(192
|
)
|
General
taxes
|
|
|
|
|
433
|
|
|
65
|
|
|
16
|
|
|
514
|
|
Total
Expenses
|
|
|
|
|
2,685
|
|
|
4,664
|
|
|
333
|
|
|
7,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest
charges
|
|
|
|
|
301
|
|
|
30
|
|
|
171
|
|
|
502
|
|
Income
taxes
|
|
|
|
|
541
|
|
|
55
|
|
|
(90
|
)
|
|
506
|
|
Income
before
discontinued operations
|
|
|
|
|
761
|
|
|
79
|
|
|
(169
|
)
|
|
671
|
|
Discontinued
operations
|
|
|
|
|
--
|
|
|
--
|
|
|
6
|
|
|
6
|
|
Net
Income
(Loss)
|
|
|
|
$
|
761
|
|
$
|
79
|
|
$
|
(163
|
)
|
$
|
677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
|
|
|
|
Change
Between Nine Months ended
|
|
|
|
|
Supply
|
|
Other
and
|
|
|
|
September
30, 2005 vs. 2004
|
|
|
Regulated
|
|
Management
|
|
Reconciling
|
|
FirstEnergy
|
|
Financial
Results
|
|
|
Services
|
|
Services
|
|
Adjustments(1)
|
|
Consolidated
|
|
Increase
(Decrease)
|
|
|
(In
millions)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
|
|
$
|
171
|
|
$
|
(469
|
)
|
$
|
-
|
|
$
|
(298
|
)
|
Other
|
|
|
|
|
146
|
|
|
(13
|
)
|
|
81
|
|
|
214
|
|
Internal
|
|
|
|
|
(2
|
)
|
|
-
|
|
|
2
|
|
|
-
|
|
Total
Revenues
|
|
|
|
|
315
|
|
|
(482
|
)
|
|
83
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and
purchased power
|
|
|
|
|
-
|
|
|
(400
|
)
|
|
-
|
|
|
(400
|
)
|
Other
operating
|
|
|
|
|
181
|
|
|
74
|
|
|
2
|
|
|
257
|
|
Provision
for
depreciation
|
|
|
|
|
13
|
|
|
-
|
|
|
(8
|
)
|
|
5
|
|
Amortization
of regulatory assets
|
|
|
|
|
77
|
|
|
-
|
|
|
-
|
|
|
77
|
|
Deferral
of
new regulatory assets
|
|
|
|
|
(111
|
)
|
|
-
|
|
|
-
|
|
|
(111
|
)
|
General
taxes
|
|
|
|
|
22
|
|
|
4
|
|
|
1
|
|
|
27
|
|
Total
Expenses
|
|
|
|
|
182
|
|
|
(322
|
)
|
|
(5
|
)
|
|
(145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest
charges
|
|
|
|
|
(16
|
)
|
|
(1
|
)
|
|
4
|
|
|
(13
|
)
|
Income
taxes
|
|
|
|
|
54
|
|
|
(65
|
)
|
|
104
|
|
|
93
|
|
Income
before
discontinued operations
|
|
|
|
|
95
|
|
|
(94
|
)
|
|
(20
|
)
|
|
(19
|
)
|
Discontinued
operations
|
|
|
|
|
-
|
|
|
-
|
|
|
12
|
|
|
12
|
|
Net
Income
(Loss)
|
|
|
|
$
|
95
|
|
$
|
(94
|
)
|
$
|
(8
|
)
|
$
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The impact
of the new Ohio tax legislation is included with FirstEnergy's other
operating segments and reconciling
adjustments.
|
Regulated
Services - Nine Months ended September 30, 2005 compared with Nine Months
ended
September 30, 2004
Net
income
increased $95 million to $856 million in the nine months ended September
30,
2005, from $761 million in the same period of 2004, due to increased revenues
partially offset by higher expenses and taxes.
Revenues
-
The
increase in
total revenues resulted from the following:
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
Distribution
services
|
|
$
|
3,759
|
|
$
|
3,588
|
|
$
|
171
|
|
Transmission
services
|
|
|
314
|
|
|
210
|
|
|
104
|
|
Lease
revenue
from affiliates
|
|
|
237
|
|
|
239
|
|
|
(2
|
)
|
Other
|
|
|
293
|
|
|
251
|
|
|
42
|
|
Total
Revenues
|
|
$
|
4,603
|
|
$
|
4,288
|
|
$
|
315
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in
distribution deliveries by customer class are summarized in the following
table:
Electric
Distribution Deliveries
|
|
Increase
|
|
|
|
|
|
Residential
|
|
|
7.9
|
%
|
Commercial
|
|
|
5.2
|
%
|
Industrial
|
|
|
1.8
|
%
|
Total
Distribution Deliveries
|
|
|
5.0
|
%
|
|
|
|
|
|
Increased
customer
consumption offset in part by lower prices resulted in higher distribution
delivery revenues. The following table summarizes major factors contributing
to
the $171 million increase in distribution services revenue in the first
nine
months of 2005:
|
|
Increase
|
|
Sources
of Change in Distribution Revenues
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
Changes
in
customer usage
|
|
$
|
210
|
|
Changes
in
prices:
|
|
|
|
|
Rate
changes
-
|
|
|
|
|
Ohio
shopping
credits
|
|
|
(33
|
)
|
JCP&L
rate settlements
|
|
|
28
|
|
Billing
component reallocation
|
|
|
(34
|
)
|
Net
Increase
in Distribution Revenues |
|
$
|
171
|
|
Distribution
revenues benefited from warmer temperatures in the summer months of 2005
compared to 2004 that increased the air-conditioning load of residential
and
commercial customers. The effect of higher base rates for JCP&L's stipulated
rate settlements in 2005 were more than offset by additional credits provided
to
customers under the Ohio transition plan and a reallocation of billing
components primarily related to special contracts. Shopping credits do
not
affect current period earnings due to deferral of the incentives for future
recovery from customers. While
industrial
deliveries also increased they were more than offset by lower unit
prices.
Transmission
revenues increased $104 million in the nine months ended September 30,
2005
compared to the same period last year due in part to the June 2004 amended
power
supply agreement with FES and increased loads due to warmer summer weather
and
higher transmission usage prices. Other revenues increased $42 million
primarily
due to
higher gains realized on nuclear decommissioning trust investments.
Expenses-
Total
operating
expenses, net of interest charges and income taxes increased in aggregate
by
$220 million in the nine months ended September 30, 2005 compared to the
same
period in 2004 due to the following:
|
· |
Other
operating expenses increased $181 million principally due to
higher
transmission expenses resulting from an amended power supply
agreement
with FES, increased loads, and higher transmission system usage
charges;
|
|
· |
Provision
for
depreciation increased $13 million reflecting the effect of
property
additions, additional costs for decommissioning the Saxton
nuclear unit
and increased leasehold improvement amortization, reflecting
shorter lives
associated with capital additions for leased generating plants
of the Ohio
Companies to correspond to the remaining lease
terms;
|
|
· |
Additional
amortization of regulatory assets of $77 million, principally
Ohio
transition costs;
|
|
·
|
Higher general taxes of $22 million resulting from increased
EUOC sales
which increased the Ohio KWH
tax and the Pennsylvania gross receipts tax and the absence in
2005 of
Pennsylvania property tax
refunds
recognized in 2004; and
|
|
· |
Higher
income
taxes of $54 million due to increased taxable
income.
|
The
following
partially offset these higher costs:
|
· |
Additional
deferrals of regulatory assets of $111 million, stemming from
the deferral
of PUCO-approved
MISO
administrative costs, JCP&L reliability improvements, shopping
incentive credits and relat
interest
on
those deferrals (see Note 14 - Regulatory Matters - Transmission,
New
Jersey); and
|
|
· |
Lower
interest charges of $16 million resulting from debt and preferred
stock
redemptions and refinancings.
|
|
Power
Supply Management Services - Nine Months ended September 30,
2005 compared
with the Nine Months ended September 30,
2004
|
The
net loss for
this segment was $15 million for the nine months ended September 30,
2005
compared to net income of $79 million in the same period last year.
A
reduction in the gross generation margin, higher nuclear operating costs
and
amounts recognized for fines, penalties and obligations associated with
proceedings involving the W.H. Sammis Plant and the Davis-Besse Nuclear
Power
Station contributed to the 2005 net loss.
Revenues
-
Excluding
the
effect of the change in recording PJM wholesale transactions on a gross
basis in
2004 ($828 million), electric generation revenues increased $359
million in
the nine months ended September 30, 2005 compared to the same period
of
2004 as a result of a 2.4% increase in KWH sales and higher unit prices.
The
change in
reported segment revenues resulted from the following:
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
Electric
generation sales:
|
|
|
|
|
|
|
|
Retail
|
|
$
|
3,223
|
|
$
|
2,933
|
|
$
|
290
|
|
Wholesale(1)
|
|
|
1,050
|
|
|
981
|
|
|
69
|
|
Total
Electric Generation Sales
|
|
|
4,273
|
|
|
3,914
|
|
|
359
|
|
Transmission
|
|
|
41
|
|
|
57
|
|
|
(16
|
)
|
Other
|
|
|
32
|
|
|
29
|
|
|
3
|
|
Total
|
|
|
4,346
|
|
|
4,000
|
|
|
346
|
|
PJM
gross
transactions
|
|
|
-
|
|
|
828
|
|
|
(828
|
)
|
Total
Revenues
|
|
$
|
4,346
|
|
$
|
4,828
|
|
$
|
(482
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(1) Excluding
2004 PJM effect of gross transactions.
|
|
|
Higher
electric
generation sales resulted from increased unit prices and increased retail
customer usage. The following table summarizes the price and volume factors
contributing to the increased sales to retail and wholesale
customers.
Source
of Change in Electric Generation Sales
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of
4.5% increase in customer usage
|
|
$
|
140
|
|
Change
in
prices
|
|
|
150
|
|
|
|
|
290
|
|
Wholesale:
|
|
|
|
|
Effect
of
4.4% reduction in customer usage(1)
|
|
|
(48
|
)
|
Change
in
prices
|
|
|
117
|
|
|
|
|
69
|
|
Net
Increase
in Electric Generation Sales
|
|
$
|
359
|
|
|
|
(1)
Decrease of
47.3% including the effect of the PJM revision.
|
|
Expenses
-
Excluding
the
effect of $828 million of PJM purchased power costs recorded on a gross
basis in
2004, total operating expenses, net interest charges and income taxes increased
in aggregate by $440 million in the nine months ended September 30,
2005
compared to the same period of 2004. Higher
fuel and
purchased power costs contributed $428 million of the increase,
resulting
from higher fuel costs of $245 million and increased purchased power costs
of
$183 million. Factors contributing to the higher costs are summarized in
the
following table:
|
|
Increase
|
|
Source
of Change in Fuel and Purchased Power
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
Fuel:
|
|
|
|
|
Change
due to
unit costs
|
|
$
|
212
|
|
Change
due to
volume consumed
|
|
|
33
|
|
|
|
|
245
|
|
|
|
|
|
Purchased
Power:
|
|
|
|
Change
due to
unit costs
|
|
|
255
|
|
Change
due to
volume purchased
|
|
|
(53
|
)
|
Increase in
deferred costs
|
|
|
(19
|
)
|
|
|
|
183
|
|
PJM
Gross
Transactions
|
|
|
(828
|
)
|
Net
Decrease
in Fuel and Purchased Power Costs
|
|
$
|
(400
|
)
|
FirstEnergy’s
generation fleet established an output record of 59.5 billion KWH for
the nine
months ended September 30, 2005. Higher coal costs resulted from
increased
consumption, market adjustment provisions in coal contracts reflecting
higher
market prices and increased transportation costs. Emission allowance
costs
increased primarily from higher prices. To a lesser extent, fuel expense
increased due to the mix of fossil versus nuclear generation resulting
from the
nuclear refueling outages in the first nine months of 2005 following
a year with
no scheduled nuclear refueling outages and improved performance of fossil
generating units. Fossil generation increased 12% in the nine months
ended
September 30, 2005 while nuclear generation decreased by 8% compared
to the
same period of 2004.
Other
operating
costs increased $74 million in the nine months ended September 30, 2005
compared
to the same period of 2004. This increase resulted from higher non-fuel
nuclear
costs. The increase in non-fuel nuclear costs resulted from 2005 refueling
outages at Perry Unit 1 (including an unplanned extension) and Beaver
Valley
Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse
nuclear plant. There were no scheduled nuclear refueling outages in the
first
nine months of 2004. Also included in other operating costs for 2005
were the
EPA settlement loss and NRC fine described above. Offsetting the higher
other
operating costs were reduced non-fuel fossil generation expense of $17
million
due to reduced maintenance outages in 2005 and lower transmission costs
of $15
million, due to an amended power supply agreement with Met-Ed and Penelec.
Partially
offsetting the increase in other operating costs were lower income taxes
of $65
million due to lower taxable income.
Other
-
Nine Months ended September 30, 2005 compared with the Nine Months ended
September 30, 2004
FirstEnergy’s
financial results from other operating segments and reconciling adjustments,
including interest expense on holding company debt and corporate support
services revenues and expenses and the impacts of the new Ohio tax legislation
(discussed below) resulted in a decrease in FirstEnergy’s net income in the nine
months ended September 30, 2005 compared to the same period of 2004.
The
decrease primarily reflected the effect of the new Ohio tax legislation
partially offset by the effect of discontinued operations, which included
an
after-tax net gain of $17 million in 2005 (see Note 6). The following
table
summarizes the sources of income from discontinued
operations:
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
Increase
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Discontinued
operations (net of tax)
|
|
|
|
|
|
|
|
Gain
on
sale:
|
|
|
|
|
|
|
|
|
|
|
Retail
gas
business
|
|
$
|
5
|
|
$
|
-
|
|
$
|
5
|
|
FSG
and MYR
Subsidiaries
|
|
|
12
|
|
|
-
|
|
|
12
|
|
Reclassification
of operating income
|
|
|
2
|
|
|
6
|
|
|
(4
|
)
|
Total
|
|
$
|
19
|
|
$
|
6
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
On
June 30,
2005, the State of Ohio enacted new tax legislation that created a new
CAT tax,
which is based on qualifying “taxable gross receipts” and will not consider any
expenses or costs incurred to generate such receipts, except for items
such as
cash discounts, returns and allowances, and bad debts. The CAT tax was
effective
July 1, 2005, and replaces the Ohio income-based franchise tax and
the Ohio
personal property tax. The CAT tax is phased-in while the current income-based
franchise tax is phased-out over a five-year period at a rate of 20% annually,
beginning with the year ended 2005, and the personal property tax is phased-out
over a four-year period at a rate of approximately 25% annually, beginning
with
the year ended 2005. For example, during the phase-out period the Ohio
income-based franchise tax will be computed consistently with the prior
tax law,
except that the tax liability as computed will be multiplied by 4/5 in
2005; 3/5
in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current
income-based franchise tax over a five-year period. As a result of the
new tax
structure, all net deferred tax benefits that are not expected to reverse
during
the five-year phase-in period were written-off as of June 30, 2005.
The
impact on income taxes associated with the required adjustment to net deferred
taxes for the nine months ended September 30, 2005 was an additional
tax
expense of approximately $72 million, which was partially offset by the
initial
phase-out of the Ohio income-based franchise tax, which reduced income
taxes by
approximately $8 million in the nine months ended September 30,
2005. See
Note 12 to the consolidated financial statements.
Postretirement
Benefits
Postretirement
benefits expense decreased by $17 million in the third quarter of 2005
and $54
million in the nine months ended September 30, 2005 compared to the
corresponding periods of 2004. Pension costs represent most of the reduction
due
to a $500 million voluntary contribution made in 2004 and an increase in
the
market value of plan assets during 2004. The following table summarizes
the net
pension and OPEB expense (excluding amounts capitalized) for the three
months
and nine months ended September 30, 2005 and 2004.
|
|
Three
Months Ended
|
|
|
|
Nine
Months Ended
|
|
|
|
Postretirement
|
|
September
30,
|
|
Increase
|
|
September
30,
|
|
Increase
|
|
Benefits
Expense *
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
$
|
8
|
|
$
|
21
|
|
$
|
(13
|
)
|
$
|
24
|
|
$
|
64
|
|
$
|
(40
|
)
|
OPEB
|
|
|
18
|
|
|
22
|
|
|
(4
|
)
|
|
54
|
|
|
68
|
|
|
(14
|
)
|
Total
|
|
$
|
26
|
|
$
|
43
|
|
$
|
(17
|
)
|
$
|
78
|
|
$
|
132
|
|
$
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Excludes
the capitalized portion of postretirement benefits costs (see Note
10 for
total costs).
|
|
|
The
decrease in
pension and OPEB expenses are included in various cost categories and have
contributed to other cost reductions discussed above.
CAPITAL
RESOURCES AND LIQUIDITY
FirstEnergy’s
cash
requirements in 2005 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions are expected
to be met
without increasing FirstEnergy’s net debt and preferred stock outstanding.
Borrowing capacity under credit facilities is available to manage working
capital requirements.
Changes
in Cash Position
The
primary source
of ongoing cash for FirstEnergy, as a holding company, is cash dividends
from
its subsidiaries. The holding company also has access to $2.0 billion of
short-term financing under a revolving credit facility, subject to short-term
debt limitations under current regulatory approvals of $1.5 billion and
to
outstanding borrowings by subsidiaries of FirstEnergy who are also parties
to
such facility. In the third quarter of 2005, FirstEnergy received
$306 million of cash dividends from its subsidiaries and paid $141
million
in cash dividends to its common shareholders - in the first nine months
of 2005,
it received and paid $846 million and $412 million, respectively. There
are no
material restrictions on the payment of cash dividends by FirstEnergy’s
subsidiaries.
As
of
September 30, 2005, FirstEnergy had $140 million of cash and cash
equivalents ($3 million restricted as an indemnity reserve) compared with
$53
million ($3 million restricted as an indemnity reserve) as of December 31,
2004. The major sources for changes in these balances are summarized
below.
Cash
Flows From Operating Activities
FirstEnergy's
consolidated net cash from operating activities is provided primarily by
its
regulated and power supply businesses (see “RESULTS OF OPERATIONS” above). Net
cash provided by operating activities was $981 million and $528 million
in the
third quarter of 2005 and 2004, respectively, and $1.9 billion and $1.5
billion
in the first nine months of 2005 and 2004, respectively, summarized as
follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
777
|
|
$
|
545
|
|
$
|
1,642
|
|
$
|
1,427
|
|
Pension
trust
contribution(2)
|
|
|
-
|
|
|
(300
|
)
|
|
-
|
|
|
(300
|
) |
Working
capital and other
|
|
|
204
|
|
|
283
|
|
|
270
|
|
|
411
|
|
Total
cash
flows from operating activities
|
|
$
|
981
|
|
$
|
528
|
|
$
|
1,912
|
|
$
|
1,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash
earnings are a non-GAAP measure (see reconciliation
below).
|
|
(2)
Pension
trust contribution net of $200 million of income tax
benefits.
|
|
Cash
earnings, as
disclosed in the table above, are not a measure of performance calculated
in
accordance with GAAP. FirstEnergy believes that cash earnings is a useful
financial measure because it provides investors and management with an
additional means of evaluating its cash-based operating performance. The
following table reconciles cash earnings with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
332
|
|
$
|
299
|
|
$
|
670
|
|
$
|
677
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
153
|
|
|
147
|
|
|
444
|
|
|
439
|
|
Amortization
of regulatory assets
|
|
|
364
|
|
|
324
|
|
|
982
|
|
|
905
|
|
Deferral
of
new regulatory assets
|
|
|
(124
|
)
|
|
(79
|
)
|
|
(303
|
)
|
|
(191
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
26
|
|
|
27
|
|
|
63
|
|
|
72
|
|
Deferred
purchased power and other costs
|
|
|
(39
|
)
|
|
(118
|
)
|
|
(231
|
)
|
|
(263
|
)
|
Deferred
income taxes and investment tax credits(1)
|
|
|
(38
|
)
|
|
(163
|
)
|
|
24
|
|
|
(257
|
)
|
Deferred
rents and lease market valuation liability
|
|
|
30
|
|
|
28
|
|
|
(71
|
)
|
|
(52
|
)
|
Accrued
retirement benefit obligations
|
|
|
56
|
|
|
42
|
|
|
104
|
|
|
107
|
|
Income
from
discontinued operations
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(18
|
)
|
|
(6
|
)
|
Other
non-cash expenses
|
|
|
18
|
|
|
40
|
|
|
(22
|
)
|
|
(4
|
)
|
Cash
earnings
(non-GAAP)
|
|
$
|
777
|
|
$
|
545
|
|
$
|
1,642
|
|
$
|
1,427
|
|
(1)
Excludes
$200 million of deferred tax benefits from pension contribution
in
2004.
|
|
In
the three months
and nine months ended September 30, 2005, cash earnings increased $232
million
and $215 million, respectively. Both periods benefited from increased generation
and distribution revenues aided by warmer summer temperatures that increased
air
conditioning load. In the third quarter of 2005 compared with the third
quarter
of 2004, cash provided from working capital decreased by $79 million, primarily
due to changes in receivables. The use of cash for receivables resulted
in part
from the conversion of the CFC accounts receivable financing to an on-balance
sheet transaction, which added $35 million of receivables to the balance
sheet
as of September 30, 2005. In the first nine months of 2005 compared
to the
first nine months of 2004, working capital changes provided $141 million
less
cash due in part to changes in receivables, materials and supplies, prepayments
and accrued taxes, offset by accounts payable and the funds received as
prepayment for electric usage, under the three-year Energy for Education
II
Program with the Ohio Schools Council.
Cash
Flows
From Financing Activities
In
the third
quarter and first nine months of 2005, cash used for financing activities
was
$580 million and $1.0 billion, respectively, compared to $602 million
and
$1.4 billion in the third quarter and first nine months of 2004, respectively.
The following table summarizes security issuances and
redemptions.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Securities
Issued or Redeemed
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
New
issues
|
|
|
|
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
89
|
|
$
|
77
|
|
$
|
334
|
|
$
|
261
|
|
Secured
notes
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
550
|
|
Long-term
revolving credit
|
|
|
-
|
|
|
10
|
|
|
-
|
|
|
-
|
|
Unsecured
notes
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
150
|
|
|
|
$
|
89
|
|
$
|
87
|
|
$
|
334
|
|
$
|
961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemptions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
mortgage bonds
|
|
$
|
-
|
|
$
|
206
|
|
$
|
178
|
|
$
|
588
|
|
Pollution
control notes
|
|
|
130
|
|
|
80
|
|
|
377
|
|
|
80
|
|
Secured
notes
|
|
|
25
|
|
|
374
|
|
|
74
|
|
|
447
|
|
Long-term
revolving credit
|
|
|
-
|
|
|
-
|
|
|
215
|
|
|
300
|
|
Unsecured
notes
|
|
|
8
|
|
|
112
|
|
|
8
|
|
|
337
|
|
Preferred
stock
|
|
|
30
|
|
|
1
|
|
|
170
|
|
|
1
|
|
|
|
$
|
193
|
|
$
|
773
|
|
$
|
1,022
|
|
$
|
1,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net increase (decrease)
|
|
$
|
(308
|
)
|
$
|
228
|
|
$
|
77
|
|
$
|
(219
|
)
|
FirstEnergy
had
approximately $247 million of short-term indebtedness as of September 30,
2005 compared to approximately $170 million as of December 31, 2004.
Available bank borrowings as of September 30, 2005 included the
following:
Borrowing
Capability
|
|
FirstEnergy
|
|
|
Penelec
|
|
Total
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
Short-term
credit(1)
|
|
$
|
2,020
|
|
|
$
|
-
|
|
$
|
2,020
|
|
Utilized
|
|
|
-
|
|
|
|
-
|
|
|
-
|
|
Letters
of
credit
|
|
|
(137
|
)
|
|
|
-
|
|
|
(137
|
)
|
Net
|
|
|
1,883
|
|
|
|
-
|
|
|
1,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
bank facilities(2)
|
|
|
-
|
|
|
|
75
|
|
|
75
|
|
Utilized
|
|
|
-
|
|
|
|
(75
|
)
|
|
(75
|
)
|
Net
|
|
|
-
|
|
|
|
-
|
|
|
-
|
|
Total
unused
borrowing capability
|
|
$
|
1,883
|
|
|
$
|
-
|
|
$
|
1,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
A $2 billion
revolving credit facility is available in various amounts to
FirstEnergy
and certain
of
its
subsidiaries, including Penelec. A $20 million uncommitted
line of
credit facility added
in
September
2005 is available to FirstEnergy only.
|
(2)
Penelec bank
facility terminated on October 7,
2005.
|
As
of October 24,
2005, the Ohio Companies and Penn had the aggregate capability to issue
approximately $3.8 billion of additional FMB on the basis of property additions
and retired bonds under the terms of their respective mortgage indentures
following the recently completed intra-system transfer of fossil and
hydroelectric generating plants (See Note 17). The issuance of FMB by OE
and CEI
are also subject to provisions of their senior note indentures generally
limiting the incurrence of additional secured debt, subject to certain
exceptions that would permit, among other things, the issuance of secured
debt
(including FMB) (i) supporting pollution control notes or similar obligations,
or (ii) as an extension, renewal or replacement of previously outstanding
secured debt. In addition, these provisions would permit OE and CEI to
incur
additional secured debt not otherwise permitted by a specified exception
of up
to $690 million and $582 million, respectively, as of October 24, 2005.
Under
the provisions of its senior note indenture, JCP&L may issue additional FMB
only as collateral for senior notes. As of October 24, 2005, JCP&L had the
capability to issue $673 million of additional senior notes upon the basis
of
FMB collateral. Based upon applicable earnings coverage tests in their
respective charters, OE, Penn, TE and JCP&L could issue a total of $4.9
billion of preferred stock (assuming no additional debt was issued) as
of
September 30, 2005. It is estimated that the annualized impact of
the
intra-system transfer of fossil and hydroelectric generating plants will
reduce
the aggregate capability of OE, Penn, TE and JCP&L to issue preferred stock
by approximately 10%. CEI, Met-Ed and Penelec have no restrictions on the
issuance of preferred stock.
As
of
September 30, 2005, approximately $1 billion remained unused under
an
existing shelf registration statement, filed by FirstEnergy with the SEC
in
2003, to support future securities issues. 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.
FirstEnergy’s
and
its subsidiaries' working capital and short-term borrowing needs are met
principally with a $2 billion five-year revolving credit facility
(included
in the table above). Borrowings under the facility are available to each
borrower separately and will mature on the earlier of 364 days from the
date of
borrowing and the commitment termination date.
The
following table
summarizes the borrowing sub-limits for each borrower under the facility,
as
well as the limitations on short-term indebtedness applicable to each borrower
under current regulatory approvals and applicable statutory and/or charter
limitations.
|
|
Revolving
|
|
Regulatory
and
|
|
|
|
Credit
Facility
|
|
Other
Short-Term
|
|
Borrower
|
|
Sub-Limit
|
|
Debt
Limitations1
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
FirstEnergy
|
|
$
|
2,000
|
|
$
|
1,500
|
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
51
|
|
CEI
|
|
|
250
|
|
|
500
|
|
TE
|
|
|
250
|
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
416
|
|
Met-Ed
|
|
|
250
|
|
|
300
|
|
Penelec
|
|
|
250
|
|
|
300
|
|
FES
|
|
|
-2
|
|
|
n/a
|
|
ATSI
|
|
|
-2
|
|
|
26
|
|
(1)
As
of
September 30, 2005.
|
(2)
|
Borrowing
sublimits for FES and ATSI may be increased to up to $250 million
and $100
million, respectively, by delivering notice to the administrative
agent
that either (i) such borrower has senior unsecured debt ratings
of at
least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has
guaranteed the obligations of such borrower under the
facility.
|
The
revolving
credit facility, combined with an aggregate $550 million ($395 million
unused as
of September 30, 2005) of accounts receivable financing facilities
for OE,
CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to
meet
short-term working capital requirements for FirstEnergy and its
subsidiaries.
Under
the revolving
credit facility, borrowers may request the issuance of letters of credit
expiring up to one year from the date of issuance. The stated amount of
outstanding letters of credit will count against total commitments available
under the facility and against the applicable borrower’s borrowing sub-limit.
Total unused borrowing capability under existing credit facilities and
accounts
receivable financing facilities totaled $2.36 billion as of September 30,
2005.
The
revolving
credit facility contains financial covenants requiring each borrower to
maintain
a consolidated debt to total capitalization ratio of no more than 0.65
to 1.00.
On October 3, 2005, FirstEnergy obtained a senior unsecured debt rating
upgrade
to BBB- by S&P removing the requirement under the revolving credit facility
to maintain a fixed charge ratio of at least 2.00 to 1.00.
As
of
September 30, 2005, FirstEnergy and subsidiaries’ debt to total
capitalization as defined under the revolving credit facility, were as
follows:
|
|
Debt
|
|
|
|
To
Total
|
|
Borrower
|
|
Capitalization
|
|
FirstEnergy
|
|
|
0.54
to
1.00
|
|
OE
|
|
|
0.39
to
1.00
|
|
Penn
|
|
|
0.32
to
1.00
|
|
CEI
|
|
|
0.57
to
1.00
|
|
TE
|
|
|
0.43
to
1.00
|
|
JCP&L
|
|
|
0.29
to
1.00
|
|
Met-Ed
|
|
|
0.38
to
1.00
|
|
Penelec
|
|
|
0.34
to
1.00
|
|
The
facility does
not contain any 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 third quarter of 2005 was 3.50% for the regulated
companies’ money pool and 3.46% for the unregulated companies' money
pool.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements
in its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base load
generation fleet, low-risk transmission and distribution operations and
rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also noted
as
strengths.
FirstEnergy’s
access to capital markets and costs of financing are influenced by the
ratings
of its securities. The following table displays FirstEnergy’s and its EUOC’s
securities ratings as of October 3, 2005. The ratings outlook from
S&P
and Fitch on all securities is stable. Moody’s outlook on all securities is
Positive.
Ratings
of Securities
|
|
Securities
|
|
S&P
|
|
Moody’s
|
|
Fitch
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
OE
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB-
|
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
BB
|
|
|
|
|
|
|
|
|
|
TE
|
|
Senior
secured
|
|
BBB
|
|
Baa2
|
|
BBB-
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba2
|
|
BB-
|
|
|
|
|
|
|
|
|
|
Penn
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Senior
unsecured (1)
|
|
BBB-
|
|
Baa2
|
|
BBB
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB-
|
|
|
|
|
|
|
|
|
|
JCP&L
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Preferred
stock
|
|
BB+
|
|
Ba1
|
|
BBB
|
|
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
BBB+
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
BBB
|
|
|
|
|
|
|
|
|
|
(1) Penn's
only senior
unsecured debt obligations are notes underlying pollution control revenue
refunding bonds issued
by the Ohio Air Quality Development Authority to which bonds this rating
applies.
On
July 1,
2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series
A
preferred stock at $25.00 per share, plus accrued dividends to the date
of
redemption. TE also repurchased $37 million of pollution control revenue
bonds
on September 1, 2005, with the intent to remarket them by the end
of the
first quarter of 2006.
Cash
Flows From Investing Activities
Net
cash flows used
for investing activities resulted principally from property additions.
Regulated
services expenditures for property additions primarily include expenditures
supporting the distribution of electricity. Capital expenditures by the
power
supply management services segment are principally generation-related.
The
following table summarizes the investment activities for the three months
and
nine months ended September 30, 2005 and 2004 by FirstEnergy’s regulated
services, power supply management services and other
segments:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30, 2005
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(207
|
)
|
$
|
(17
|
)
|
$
|
2
|
|
$
|
(222
|
)
|
Power
supply
management services
|
|
|
(79
|
)
|
|
1
|
|
|
-
|
|
|
(78
|
)
|
Other
|
|
|
(1
|
)
|
|
-
|
|
|
1
|
|
|
-
|
|
Reconciling
items
|
|
|
(7
|
)
|
|
(9
|
)
|
|
5
|
|
|
(11
|
)
|
Total
|
|
$
|
(294
|
)
|
$
|
(25
|
)
|
$
|
8
|
|
$
|
(311
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(157
|
)
|
$
|
242
|
|
$
|
(69
|
)
|
$
|
16
|
|
Power
supply
management services
|
|
|
(46
|
)
|
|
(11
|
)
|
|
-
|
|
|
(57
|
)
|
Other
|
|
|
(1
|
)
|
|
-
|
|
|
(2
|
)
|
|
(3
|
)
|
Reconciling
items
|
|
|
(7
|
)
|
|
10
|
|
|
84
|
|
|
87
|
|
Total
|
|
$
|
(211
|
)
|
$
|
241
|
|
$
|
13
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary
of Cash Flows |
|
Property
|
|
|
|
|
|
|
|
Used
for Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses) |
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2005
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(506
|
)
|
$
|
(13
|
)
|
$
|
(5
|
)
|
$
|
(524
|
)
|
Power
supply
management services
|
|
|
(226
|
)
|
|
-
|
|
|
-
|
|
|
(226
|
)
|
Other
|
|
|
(6
|
)
|
|
19
|
|
|
(18
|
)
|
|
(5
|
)
|
Reconciling
items
|
|
|
(18
|
)
|
|
(9
|
)
|
|
5
|
|
|
(22
|
)
|
Total
|
|
$
|
(756
|
)
|
$
|
(3
|
)
|
$
|
(18
|
)
|
$
|
(777
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
services
|
|
$
|
(377
|
)
|
$
|
196
|
|
$
|
(76
|
)
|
$
|
(257
|
)
|
Power
supply
management services
|
|
|
(149
|
)
|
|
(14
|
)
|
|
-
|
|
|
(163
|
)
|
Other
|
|
|
(3
|
)
|
|
173
|
|
|
2
|
|
|
172
|
|
Reconciling
items
|
|
|
(17
|
)
|
|
31
|
|
|
65
|
|
|
79
|
|
Total
|
|
$
|
(546
|
)
|
$
|
386
|
|
$
|
(9
|
)
|
$
|
(169
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash used for
investing activities was $311 million in the third quarter of 2005 compared
to
$43 million of cash provided from investing activities in the same period
of
2004. The change was primarily due to an $83 million increase in property
additions and the absence in 2005 of $278 million in cash proceeds from
certificates of deposit (released collateral) received in the third quarter
of
2004. Net cash used for investing activities increased by $608 million
in the
first nine months of 2005 compared to the same period of 2004. The increase
principally resulted from a $210 million increase in property additions,
lower
proceeds from the sale of assets of $152 million and the absence in 2005
of $278
million of cash proceeds from certificates of deposit (released collateral)
received in 2004.
In
the last quarter
of 2005, capital requirements for property additions and capital leases
are
expected to be approximately $378 million. FirstEnergy and the Companies
have
additional requirements of approximately $312 million for maturing long-term
debt during the remainder of 2005. These cash requirements are expected
to be
satisfied from internal cash and short-term credit arrangements.
FirstEnergy’s
capital spending for the period 2005-2007 is expected to be about $3.5
billion
(excluding nuclear fuel), of which $1.1 billion applies to 2005. Investments
for
additional nuclear fuel during the 2005-2007 periods are estimated to be
approximately $285 million, of which approximately $59 million applies
to 2005.
During the same period, FirstEnergy’s nuclear fuel investments are expected to
be reduced by approximately $282 million and $86 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.
Such agreements include contract guarantees, surety bonds, and LOCs. Some
of the
guaranteed contracts contain ratings contingent collateralization
provisions.
As
of September 30,
2005, the maximum potential future payments under outstanding guarantees
and
other assurances totaled $2.7 billion as summarized
below:
|
|
Maximum
|
Guarantees
and Other Assurances
|
|
Exposure
|
|
|
(In
millions)
|
FirstEnergy
guarantees of subsidiaries:
|
|
|
Energy
and
energy-related contracts (1)
|
|
$
|
785
|
Other
(2)
|
|
|
503
|
|
|
|
1,288
|
|
|
|
|
Surety
bonds
|
|
|
307
|
Letters
of
credit (3)(4)
|
|
|
1,055
|
|
|
|
|
Total
Guarantees and Other Assurances
|
|
$
|
2,650
|
|
|
|
|
(1)Issued
for a
one-year term, with a 10-day termination right by
FirstEnergy.
|
(2)Issued
for
various terms.
|
|
|
|
(3)Includes
$137
million issued for various terms under LOC capacity available
|
under
FirstEnergy's revolving credit agreement and $299 million outstanding
in
|
support of pollution control revenue bonds issued with various
maturities.
|
(4)Includes
approximately $194 million pledged in connection with the sale
and
|
leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged
in
connection
|
with
the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million
pledged
|
in
connection with the sale and leaseback of Perry Unit 1 by
OE.
|
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved
in
energy marketing 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 and its subsidiaries to fulfill
the obligations of those subsidiaries directly involved in 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-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. The following
table
summarizes collateral provisions in effect as of September 30,
2005:
|
|
|
Total
|
|
Collateral
Paid
|
|
Remaining
|
|
Collateral
Provisions
|
|
|
Exposure
|
|
Cash
|
|
LOC
|
|
Exposure
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit
rating
downgrade
|
|
|
|
$
|
445
|
|
$
|
213
|
|
$
|
18
|
|
$
|
214
|
|
Adverse
event
|
|
|
|
|
77
|
|
|
-
|
|
|
5
|
|
|
72
|
|
Total
|
|
|
|
$
|
522
|
|
$
|
213
|
|
$
|
23
|
|
$
|
286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
a result of
S&P's credit rating upgrade described above, $109 million of cash collateral
was returned to FirstEnergy in October 2005.
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 provided an LOC ($47 million as of September 30,
2005,
which is included in the caption “Other” in the above table of Guarantees and
Other Assurances), which is renewable and declines yearly based upon the
senior
outstanding debt of TEBSA. The LOC was reduced to $36 million on October
15,
2005.
OFF-BALANCE
SHEET ARRANGEMENTS
FirstEnergy
has
obligations that are not included on its Consolidated Balance Sheet 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. The present value of these sale and leaseback operating lease
commitments, net of trust investments, total $1.3 billion as of
September 30, 2005.
FirstEnergy
has
equity ownership interests in certain businesses that are accounted for
under
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 contractual obligations
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 management oversight to risk management activities throughout
the Company.
Commodity
Price Risk
FirstEnergy
is
exposed to price risk primarily due to fluctuating electricity, natural
gas,
coal, nuclear fuel, emission allowance prices and energy transmission.
To manage
the volatility relating to these exposures, it uses a variety of non-derivative
and derivative instruments, including forward contracts, options, futures
contracts and swaps. The derivatives are used principally for hedging purposes
and, to a much lesser extent, for trading purposes. All derivatives that
fall
within the scope of SFAS 133 must be recorded at their fair market value
and
marked to market. The majority of FirstEnergy’s derivative hedging contracts
qualify for the normal purchases and normal sales exception under SFAS
133 and
are therefore excluded from the table below. Of those contracts not exempt
from
such treatment, most are non-trading contracts that do not qualify for
hedge
accounting treatment. The change in the fair value of commodity derivative
contracts related to energy production during the third quarter and first
nine
months of 2005 is summarized in the following table:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
Increase
(Decrease) in the Fair Value
|
|
September
30, 2005
|
|
September
30, 2005
|
|
Of
Commodity Derivative Contracts
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Change
in the Fair Value of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net asset at beginning of period
|
|
$
|
55
|
|
$
|
(2
|
)
|
$
|
53
|
|
$
|
62
|
|
$
|
2
|
|
$
|
64
|
|
New
contract
when entered
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Additions/change
in value of existing contracts
|
|
|
(3
|
)
|
|
3
|
|
|
-
|
|
|
(4
|
)
|
|
5
|
|
|
1
|
|
Change
in
techniques/assumptions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Settled
contracts
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(7
|
)
|
|
-
|
|
|
(7
|
)
|
Sale
of
retail natural gas contracts
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
(6
|
)
|
|
(5
|
)
|
Outstanding
net asset at end of period (1)
|
|
$
|
52
|
|
$
|
1
|
|
$
|
53
|
|
$
|
52
|
|
$
|
1
|
|
$
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Assets at End of Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate
swaps (2)
|
|
|
-
|
|
|
(10
|
)
|
|
(10
|
)
|
|
-
|
|
|
(10
|
)
|
|
(10
|
)
|
Net
Assets - Derivative Contracts at End of Period
|
|
$
|
52
|
|
$
|
(9
|
)
|
$
|
43
|
|
$
|
52
|
|
$
|
(9
|
)
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
|
$
|
(4
|
)
|
$
|
-
|
|
$
|
(4
|
)
|
$
|
(4
|
)
|
$
|
-
|
|
$
|
(4
|
)
|
Balance
Sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
|
$
|
-
|
|
$
|
3
|
|
$
|
3
|
|
$
|
-
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
Regulatory
liability
|
|
$
|
1
|
|
$
|
-
|
|
$
|
1
|
|
$
|
(6
|
)
|
$
|
-
|
|
$
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes
$55 million in non-hedge commodity derivative contracts which are
offset
by a regulatory liability.
|
(2) Interest
rate
swaps are treated as cash flow or fair value hedges. (See Interest
Rate
Swap Agreements - Fair Value Hedges and Forward
|
Starting
Swap Agreements - Cash Flow Hedges)
|
(3) Represents
the change in value of existing contracts, settled contracts and
changes
in techniques/assumptions.
|
Derivatives
are
included on the Consolidated Balance Sheet as of September 30, 2005
as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Current
-
|
|
|
|
|
|
|
|
Other
assets
|
|
$
|
-
|
|
$
|
39
|
|
$
|
39
|
|
Other
liabilities
|
|
|
(1
|
)
|
|
(39
|
)
|
|
(40
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current
-
|
|
|
|
|
|
|
|
|
|
|
Other
deferred charges
|
|
|
56
|
|
|
5
|
|
|
61
|
|
Other
noncurrent liabilities
|
|
|
(3
|
)
|
|
(14
|
)
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
assets
|
|
$
|
52
|
|
$
|
(9
|
)
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
The
valuation of
derivative commodity 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 derivative contracts
by year
are summarized in the following table:
Sources
of Information -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
2005
(1)
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
actively quoted (2)
|
|
$
|
(3
|
)
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(8
|
)
|
Other
external sources (3)
|
|
|
19
|
|
|
7
|
|
|
10
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
36
|
|
Prices
based
on models
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
9
|
|
|
8
|
|
|
8
|
|
|
25
|
|
Total
(4)
|
|
$
|
16
|
|
$
|
4
|
|
$
|
8
|
|
$
|
9
|
|
$
|
8
|
|
$
|
8
|
|
$
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) For
the
last quarter of 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2) Exchange
traded.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3) Broker
quote sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4) Includes
$55 million in non-hedge commodity derivative contracts which are
offset
by a regulatory liability.
|
|
|
|
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 both FirstEnergy's trading and nontrading derivative instruments would
not
have had a material effect on its consolidated financial position (assets,
liabilities and equity) or cash flows as of September 30, 2005.
Based on
derivative contracts held as of September 30, 2005, an adverse 10%
change
in commodity prices would decrease net income by approximately $1 million
for
the next twelve months.
Interest
Rate Swap Agreements - Fair Value Hedges
FirstEnergy
utilizes fixed-to-floating interest rate swap agreements as part of its
ongoing
effort to manage the interest rate risk of its debt portfolio. These derivatives
are treated as fair value hedges of fixed-rate, long-term debt issues
-
protecting against
the risk of changes in the fair value of fixed-rate debt instruments due
to
lower interest rates. Swap maturities, call options, fixed interest rates
and
interest payment dates match those of the underlying obligations. During
the
third quarter of 2005, FirstEnergy executed no new fixed-for-floating interest
rate swaps and unwound swaps with a total notional amount of $350 million
(see
Note 7). As of September 30, 2005, the debt underlying the $1.05
billion
outstanding notional amount of interest rate swaps had a weighted average
fixed
interest rate of 5.66%, which the swaps have effectively converted to a
current
weighted average variable interest rate of 5.23%.
|
|
September
30, 2005
|
|
December
31, 2004
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Interest
Rate Swaps
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(Dollars
in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
to
Floating Rate
|
|
$
|
-
|
|
|
2006
|
|
$
|
-
|
|
$
|
200
|
|
|
2006
|
|
$
|
(1
|
)
|
(Fair
value
hedges)
|
|
|
100
|
|
|
2008
|
|
|
(3
|
)
|
|
100
|
|
|
2008
|
|
|
(1
|
)
|
|
|
|
50
|
|
|
2010
|
|
|
-
|
|
|
100
|
|
|
2010
|
|
|
1
|
|
|
|
|
50
|
|
|
2011
|
|
|
-
|
|
|
100
|
|
|
2011
|
|
|
2
|
|
|
|
|
450
|
|
|
2013
|
|
|
-
|
|
|
400
|
|
|
2013
|
|
|
4
|
|
|
|
|
-
|
|
|
2014
|
|
|
-
|
|
|
100
|
|
|
2014
|
|
|
2
|
|
|
|
|
150
|
|
|
2015
|
|
|
(7
|
)
|
|
150
|
|
|
2015
|
|
|
(7
|
)
|
|
|
|
150
|
|
|
2016
|
|
|
2
|
|
|
200
|
|
|
2016
|
|
|
1
|
|
|
|
|
-
|
|
|
2018
|
|
|
-
|
|
|
150
|
|
|
2018
|
|
|
5
|
|
|
|
|
-
|
|
|
2019
|
|
|
-
|
|
|
50
|
|
|
2019
|
|
|
2
|
|
|
|
|
100
|
|
|
2031
|
|
|
(4
|
)
|
|
100
|
|
|
2031
|
|
|
(4
|
)
|
|
|
$
|
1,050
|
|
|
|
|
$
|
(12
|
)
|
$
|
1,650
|
|
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward
Starting Swap Agreements - Cash Flow Hedges
During
the third
quarter, FirstEnergy entered into several forward starting swap agreements
(forward swap) in order to hedge a portion of the consolidated interest
rate
risk associated with the planned issuance of fixed-rate, long-term debt
securities for one or more of its consolidated entities in the fourth quarter
of
2006. 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. As of September 30, 2005, the forward swaps had a fair
value of
$2 million.
Equity
Price Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at their
market
value of approximately $1.038 billion and $951 million as of September 30,
2005 and December 31, 2004, respectively. A hypothetical 10% decrease
in
prices quoted by stock exchanges would result in a $104 million reduction
in
fair value as of September 30, 2005.
CREDIT
RISK
Credit
risk is the
risk of an obligor’s failure to meet the terms of any investment contract, loan
agreement or otherwise perform as agreed. Credit risk arises from all activities
in which success depends on issuer, borrower or counterparty performance,
whether reflected on or off the balance sheet. FirstEnergy engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often
with
major energy companies within the industry.
FirstEnergy
maintains credit policies with respect to its counterparties to manage
overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions
to
mitigate exposure. As part of its credit program, FirstEnergy aggressively
manages the quality of its portfolio of energy contracts evidenced by a
current
weighted average risk rating for energy contract counterparties of BBB
(S&P). As of September 30, 2005, the largest credit concentration was
with one party, currently rated investment grade that represented 8% of
FirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99%
of credit exposures, net of collateral and reserves, were with investment-grade
counterparties as of September 30, 2005.
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
EUOCs
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. All regulatory assets are expected to be recovered from customers
under the Companies' respective transition and regulatory plans. Based
on those
plans, the Companies continue to bill and collect cost-based rates for
their
transmission and distribution services, which remain regulated; accordingly,
it
is appropriate that the Companies continue the application of SFAS 71
to those
operations.
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
OE
|
|
$
|
845
|
|
$
|
1,116
|
|
$
|
(271
|
)
|
CEI
|
|
|
889
|
|
|
959
|
|
|
(70
|
)
|
TE
|
|
|
310
|
|
|
375
|
|
|
(65
|
)
|
JCP&L
|
|
|
2,311
|
|
|
2,176
|
|
|
135
|
|
Met-Ed
|
|
|
572
|
|
|
693
|
|
|
(121
|
)
|
Penelec
|
|
|
99
|
|
|
200
|
|
|
(101
|
)
|
ATSI
|
|
|
20
|
|
|
13
|
|
|
7
|
|
Total
|
|
$
|
5,046
|
|
$
|
5,532
|
|
$
|
(486
|
)
|
|
|
*Penn
had net
regulatory liabilities of approximately $48 million and $18 million
included
in Noncurrent Liabilities on the Consolidated Balance Sheets as
of
September
30, 2005 and December 31, 2004, respectively.
|
|
Regulatory
assets
by source are as follows:
|
|
September
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets by Source
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
Regulatory
transition costs
|
|
|
$
|
4,169
|
|
$
|
4,889
|
|
$
|
(720
|
)
|
Customer
shopping incentives
|
|
|
|
826
|
|
|
612
|
|
|
214
|
|
Customer
receivables for future income taxes
|
|
|
|
289
|
|
|
246
|
|
|
43
|
|
Societal
benefits charge
|
|
|
|
18
|
|
|
51
|
|
|
(33
|
)
|
Loss
on
reacquired debt
|
|
|
|
83
|
|
|
89
|
|
|
(6
|
)
|
Employee
postretirement benefit costs
|
|
|
|
57
|
|
|
65
|
|
|
(8
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
|
and
spent
fuel disposal costs
|
|
|
|
(172
|
)
|
|
(169
|
)
|
|
(3
|
)
|
Asset
removal
costs
|
|
|
|
(366
|
)
|
|
(340
|
)
|
|
(26
|
)
|
Property
losses and unrecovered plant costs
|
|
|
|
34
|
|
|
50
|
|
|
(16
|
)
|
MISO
transmission costs
|
|
|
|
52
|
|
|
-
|
|
|
52
|
|
JCP&L
reliability costs
|
|
|
|
26
|
|
|
-
|
|
|
26
|
|
Other
|
|
|
|
30
|
|
|
39
|
|
|
(9
|
)
|
Total
|
|
|
$
|
5,046
|
|
$
|
5,532
|
|
$
|
(486
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Reliability
Initiatives
FirstEnergy
is
proceeding with the implementation of the recommendations regarding enhancements
to regional reliability 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, however, may take a different view
as to
recommended enhancements or may recommend additional enhancements in the
future
as the result of adoption of mandatory reliability standards pursuant to
the
Energy Policy Act of 2005 that could require additional, material expenditures.
Finally, the PUCO is continuing to review FirstEnergy's filing that addressed
upgrades to control room computer hardware and software and enhancements
to the
training of control room operators, before determining the next steps,
if any,
in the proceeding.
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. On March 29,
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
a Special
Reliability Master who made recommendations on appropriate courses of action
necessary to ensure system-wide reliability. The Stipulation also incorporates
the Executive Summary and Recommendation portions of the final report of
a
focused audit of JCP&L's Planning and Operations and Maintenance programs
and practices (Focused Audit). A Final Order in the Focused Audit docket
was
issued by the NJBPU on July 23, 2004. On February 11, 2005,
JCP&L
met with the Ratepayer Advocate to discuss reliability improvements. JCP&L
continues to file compliance reports reflecting activities associated with
the
MOU and Stipulation.
The
Energy Policy
Act of 2005 provides for the creation of an ERO to establish and enforce
reliability standards for the bulk power system, subject to FERC review.
On
September 1, 2005, the FERC issued a Notice of Proposed Rulemaking
to
establish certification requirements for the ERO, as well as regional entities
envisioned to assume monitoring and compliance responsibility for the new
reliability standards. The FERC expects to adopt a final rule on or before
February 2006 regarding certification requirements for the ERO and regional
entities.
The
NERC is
expected to reorganize its structure to meet the FERC’s certification
requirements for the ERO. Following adoption of the final rule, the NERC
will be
required to make a filing with the FERC to obtain certification as the
ERO. The
proposed rule also provides for regional reliability organizations designed
to
replace the current regional councils. The “regional entity” may be delegated
authority by the ERO, subject to FERC approval, for enforcing reliability
standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic
Area Council, and Mid-American Interconnected Network
reliability
councils have signed an MOU designed to consolidate their regions into
a new
regional reliability organization known as ReliabilityFirst Corporation.
Their
intent is to file and obtain certification under the final rule as a “regional
entity”. All of FirstEnergy’s facilities would be located within the
ReliabilityFirst region.
On
a parallel path,
the NERC is establishing working groups to develop reliability standards
to be
filed for approval with the FERC following the NERC’s certification as an ERO.
These reliability standards are expected to build on the current NERC Version
0
reliability standards. It is expected that the proposed reliability standards
will be filed with the FERC in early 2006.
The
impact of this
effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance
with all current NERC reliability standards. However, it is expected that
the
FERC will adopt stricter reliability standards than those contained in
the
current NERC Version 0 standards. The financial impact of complying with
the new
standards cannot be determined at this time. However, the Energy Policy
Act of
2005 requires that all prudent costs incurred to comply with the new reliability
standards be recovered in rates.
See
Note 14 to the
consolidated financial statements for a more detailed discussion of reliability
initiatives, including actions by the PPUC, that impact Met-Ed, Penelec
and
Penn.
Ohio
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 competitive
bid
process. The RSP was filed by the Ohio Companies to establish generation
service
rates beginning January 1, 2006, in response to PUCO concerns about
price
and supply uncertainty following the end of the Ohio Companies' transition
plan
market development period. In October 2004, the OCC and NOAC filed appeals
with
the Supreme Court of Ohio to overturn the original June 9, 2004
PUCO order
in this proceeding as well as the associated entries on rehearing. On
September 28, 2005, the Ohio Supreme Court heard oral argument on
the
appeals.
On
May 27,
2005, the Ohio Companies filed an application with the PUCO to establish
a GCAF
rider under the RSP. The application seeks to implement recovery of increased
fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail
customers through a tariff rider to be implemented January 1, 2006.
The
application reflects projected increases in fuel costs in 2006 compared
to 2002
baseline costs. The new rider, after adjustments made in testimony, is
seeking
to recover all costs above the baseline (approximately $88 million in 2006).
Various parties including the OCC have intervened in this case and the
case has
been consolidated with the RCP application discussed below.
On
September 9, 2005, the Ohio Companies filed an application with
the PUCO
that, if approved, would supplement their existing RSP with an RCP. On
September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate
the GCAF rider application with the RCP proceedings and set hearings for
the
consolidated cases to begin November 29, 2005. The RCP is designed
to
provide customers with more certain rate levels than otherwise available
under
the RSP during the plan period. Major provisions of the RCP
include:
· Maintain
the
existing level of base distribution rates through December 31, 2008
for OE
and TE, and
April 30,
2009
for CEI;
· Defer
and
capitalize certain distribution costs to be incurred during the period
January 1, 2006
through
December 31, 2008, not to exceed $150 million in each of the three
years;
· Adjust
the RTC and
extended RTC recovery periods and rate levels so that full recovery of
authorized
costs
will occur as
of December 31, 2008 for OE and TE, and as of December 31,
2010 for
CEI;
· Reduce
the deferred
shopping incentive balances as of January 1, 2006 by up to $75 million
for
OE,
$45
million for TE,
and $85 million for CEI by accelerating the application of each
respective
company's
accumulated
cost of removal regulatory liability; and
· Recover
increased
fuel costs of up to $75 million, $77 million, and $79 million, in 2006,
2007,
and
2008,
respectively,
from all OE and TE distribution and transmission customers through a fuel
recovery
mechanism
and OE, TE, and CEI may defer and capitalize increased fuel costs above
the
amount
collected
through the fuel recovery mechanism.
Under
provisions of
the RSP, the PUCO may require the Ohio Companies to undertake, no more
often
than annually, a competitive bid process to secure generation for the years
2007
and 2008. On July 22, 2005, FirstEnergy filed a competitive bid
process for
the period beginning in 2007 that is similar to the competitive bid process
approved by the PUCO for the Ohio Companies in 2004 which resulted in the
PUCO
accepting no bids. Any acceptance of future competitive bid results would
terminate the RSP pricing, with no accounting impacts to the RSP, and not
until
twelve months after the PUCO authorizes such termination. On September 28,
2005, the PUCO issued an Entry that essentially approved the Ohio Companies'
filing but delayed the proposed timing of the competitive bid process by
four
months, calling for the auction to be held on March 21, 2006.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.
Pennsylvania
In
accordance with
PPUC directives, Met-Ed and Penelec have been negotiating with interested
parties in an attempt to resolve the merger savings issues that are the
subject
of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
of total merger savings is estimated to be approximately $31.5 million.
On
April 13, 2005, the Commonwealth Court issued an interim order in
the
remand proceeding that the parties should report the status of the negotiations
to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals
in May and June 2005 and continue to have settlement discussions.
Met-Ed
and Penelec
purchase a portion of their PLR requirements from FES through a wholesale
power
sales agreement. The PLR sale is automatically extended for each successive
calendar year unless any party elects to cancel the agreement by November 1
of the preceding year. Under the terms of the wholesale agreement, FES
retains
the supply obligation and the supply profit and loss risk for the portion
of
power supply requirements not self-supplied by Met-Ed and Penelec under
their
NUG contracts and other power contracts with nonaffiliated third party
suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to
high
wholesale power prices by providing power at a fixed price for their uncommitted
PLR energy costs during the term of the agreement with FES. Met-Ed and
Penelec
are authorized to defer differences between NUG contract costs and current
market prices. On
November 1,
2005, FES and the other parties to the wholesale power agreement amended
the
agreement to provide FES the right over the next year to terminate the
agreement
at any time upon 60 days notice. If
the wholesale
power agreement were terminated, Met-Ed and Penelec would need to satisfy
the
applicable portion of their PLR obligations from other sources at prevailing
prices, which are likely to be higher than the current price charged by
FES
under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
costs could materially increase.
On
January 12,
2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral
of
transmission-related costs beginning January 1, 2005, estimated
to be
approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny
Electric Cooperative and Pennsylvania Rural Electric Association have all
intervened in the case. To date no hearing schedule has been established,
and
neither company has yet implemented deferral accounting for these
costs.
On
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for
its
customers at set rates following the end of its transition period on December
31, 2006. Penn is recommending that the Request for Proposal process cover
the
period of January 1, 2007 through May 31, 2008. Under Pennsylvania's
electric competition law, Penn is required to secure generation supply
for
customers who do not choose alternative suppliers for their
electricity.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania.
New
Jersey
The
2003 NJBPU
decision on JCP&L's base electric rate proceeding (Phase I order) disallowed
certain regulatory assets and provided for an interim return on equity
of 9.5%
on JCP&L's rate base. The Phase I Order also provided for a Phase II
proceeding in which the NJBPU would review whether JCP&L is in compliance
with current service reliability and quality standards and determine whether
the
expenditures and projects undertaken by JCP&L to increase its system
reliability are prudent and reasonable for rate recovery. Depending on
its
assessment of JCP&L's service reliability, the NJBPU could have increased
JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On
August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an
interim motion and a supplemental and amended motion for rehearing and
reconsideration of the Phase I Order, respectively. On July 7, 2004,
the
NJBPU granted limited reconsideration and rehearing on the following issues:
(1)
deferred cost disallowances; (2) the capital structure including the rate
of
return; (3) merger savings, including amortization of costs to achieve
merger
savings; and (4) decommissioning costs.
On
July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for the recovery of
system
reliability costs and a 9.75% return on equity. The filing also requested
an
increase to the MTC deferred balance recovery of approximately $20 million
annually.
On
May 25,
2005, the NJBPU approved two stipulated settlement agreements. The first
stipulation between JCP&L and the NJBPU staff resolves all of the issues
associated with JCP&L's motion for reconsideration of the 2003 NJBPU order
Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the
Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase
II proceeding. The stipulated settlements provide for, among other things,
the
following:
· An
annual increase
in distribution revenues of $23 million, effective June 1, 2005,
associated
with the
Phase I
Order
reconsideration;
· An
annual increase
in distribution revenues of $36 million, effective June 1, 2005,
related to
JCP&L's
Phase II
Petition;
· An
annual reduction
in both rates and amortization expense of $8 million, effective June 1,
2005, in
anticipation
of an
NJBPU order regarding JCP&L's request to securitize up to $277 million of
its deferred
cost
balance;
· An
increase in
JCP&L's authorized return on common equity from 9.5% to 9.75%;
and
· A
commitment by
JCP&L to maintain a target level of customer service reliability with a
reduction in
JCP&L's
authorized return on common equity from 9.75% to 9.5% if the target is
not met
for two
consecutive
quarters.
The authorized return on common equity would then be restored to 9.75%
if
the
target
is met for two
consecutive quarters.
The
Phase II
stipulation included an agreement that the distribution revenue increase
also
reflects a three-year amortization of JCP&L's one-time service reliability
improvement costs incurred in 2003-2005. This resulted in the creation
of a
regulatory asset associated with accelerated tree trimming and other reliability
costs which were expensed in 2003 and 2004. The establishment of the new
regulatory asset of approximately $28 million resulted in an increase to
net
income of approximately $16 million ($0.05 per share of FirstEnergy common
stock) in the second quarter of 2005.
JCP&L
sells all
self-supplied energy (NUGs and owned generation) to the wholesale market
with
offsetting credits to its deferred energy balance with the exception of
300 MW
from JCP&L's NUG committed supply currently being used to serve BGS
customers pursuant to NJBPU order for the period June 1, 2005 through May
31,
2006. New BGS tariffs reflecting the results of a February 2005 auction
for the
BGS supply became effective June 1, 2005. On July 1, 2005,
JCP&L
filed its BGS procurement proposals for post transition year four. The
auction
is scheduled to take place in February 2006 for the annual supply period
beginning June 1, 2006.
In
accordance with an
April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004
supporting a continuation of the current level and duration of the funding
of
TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The Ratepayer Advocate filed comments on
February 28, 2005. On March 18, 2005, JCP&L filed a response to
those comments. A schedule for further proceedings has not yet been
set.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in New Jersey.
Transmission
On
December 30, 2004, the Ohio Companies filed with the PUCO two applications
related to the recovery of transmission and ancillary service related costs.
The
first application seeks recovery of these costs beginning January 1,
2006.
At the time of filing the application, these costs were estimated to be
approximately $30 million per year; however, the Ohio Companies anticipate
that
this amount will increase. The Ohio Companies requested that these costs
be
recovered through a rider that would be effective on January 1,
2006 and
adjusted each July 1 thereafter. The Ohio Companies reached a settlement
with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only
other
party in this proceeding, Dominion Retail, Inc., agreed not to oppose the
settlement. This settlement, which was filed with the PUCO on July 22,
2005, provides for the rider recovery requested by the Ohio Companies,
with
carrying charges applied in the subsequent year’s rider for any over or under
collection while the then-current rider is in effect. The PUCO approved
the
settlement stipulation on August 31, 2005. The incremental Transmission
and
Ancillary service revenues expected to be recovered from January through
June
2006 are approximately $61.2 million. This value includes the recovery
of the
2005 deferred MISO expenses as described below. In May 2006, the Ohio Companies
will file a modification to the rider which will determine revenues from
July
2006 through June 2007.
The
second
application sought authority to defer costs associated with transmission
and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO
granted the
accounting authority for the Ohio Companies to defer incremental transmission
and ancillary service-related charges incurred as a participant in the
MISO, but
only for those costs incurred during the period December 30, 2004
through
December 31, 2005. Permission to defer costs incurred prior to
December 31, 2004 was denied. The PUCO also authorized the Ohio
Companies
to accrue carrying charges on the deferred balances. An application filed
with
the PUCO to recover these deferred charges over a five-year period through
the
rider, beginning in 2006, was approved in a PUCO order issued on August 31,
2005 approving the stipulation referred to above. The OCC, OPAE and the
Ohio
Companies each filed applications for rehearing. The Ohio Companies sought
authority to defer the transmission and ancillary service related costs
incurred
during the period October 1, 2003 through December 29, 2004,
while
both OCC and OPAE sought to have the PUCO deny deferral of all costs.
On
July 6, 2005, the PUCO denied the Ohio Companies' and OCC’s applications
and, at the request of the Ohio Companies, struck as untimely OPAE’s
application. The OCC filed a notice of appeal with the Ohio Supreme Court
on
August 31, 2005. On September 30, 2005, in accordance with appellate
procedure, the PUCO filed with the Ohio Supreme Court the record in this
case.
The Companies' brief will be due thirty days after the OCC files its brief,
which, absent any time extensions, must be filed no later than November
9,
2005.
On
January 31,
2005, certain PJM transmission owners made three filings 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. Second, the
FERC
approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted
the proposed formula rate, subject to referral and hearing procedures.
On
September 30, 2005, the PJM transmission owners filed a request
for
rehearing of the May 31, 2005 order. The rate design and formula
rate
filings continue to be litigated before the FERC. The outcome of these
two cases
cannot be predicted.
Environmental
Matters
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 are both probable and reasonably estimable.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
National
Ambient Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
for fine
particulate matter. On March 10, 2005, the EPA finalized the "Clean
Air
Interstate Rule" 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 nonattainment of the NAAQS for fine particles
and/or
the "8-hour" ozone NAAQS in other states. CAIR provides each affected state
until 2006 to develop implementing regulation 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)
in all cases from
the 2003 levels. The Companies’ Michigan, Ohio and Pennsylvania fossil-fired
generation facilities will be subject to the caps on SO2
and NOx
emissions, whereas
their New Jersey fossil-fired generation facilities will be subject to
a cap on
NOx
emissions only.
According to the EPA, SO2
emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by
the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2
emissions in
affected states to just 2.5 million tons annually. NOx
emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by
the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOx
cap of 1.3 million
tons annually. The future cost of compliance with these regulations may
be
substantial and will depend on how they are ultimately implemented by the
states
in which the Companies operate affected facilities.
Mercury
Emissions
In
December 2000,
the EPA announced it would proceed with the development of regulations
regarding
hazardous air pollutants from electric power plants, identifying mercury
as the
hazardous air pollutant of greatest concern. On March 14, 2005,
the EPA
finalized the "Clean Air Mercury Rule," which provides for a cap-and-trade
program to reduce mercury emissions from coal-fired power plants in two
phases.
Initially, mercury emissions will be capped nationally at 38 tons by 2010
(as a
"co-benefit" from implementation of SO2
and NOx
emission caps
under the EPA's CAIR program). Phase II of the mercury cap-and-trade program
will cap nationwide mercury emissions from coal-fired power plants at 15
tons
per year by 2018. However, the final rules give states substantial discretion
in
developing rules to implement these programs. In addition, both
the CAIR
and the Clean Air Mercury rule 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.
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 is owned by OE and Penn. In addition,
the DOJ filed eight civil complaints against various investor-owned utilities,
including a complaint against OE and Penn in the U.S. District Court for
the
Southern District of Ohio. These cases are referred to as New Source Review
cases. On March 18, 2005, OE and Penn announced that they had reached
a
settlement with the EPA, the DOJ and three states (Connecticut, New Jersey,
and
New York) that resolved all issues related to the W. H. Sammis Plant New
Source
Review litigation. This settlement agreement, which is in the form of a
Consent
Decree, was approved by the Court on July 11, 2005, requires OE
and Penn to
reduce NOx and SO2
emission
at the W.
H. Sammis Plant and other coal-fired plants through the installation of
pollution control devices. Capital expenditures necessary to meet those
requirements are currently estimated to be $1.5 billion (the primary portion
of
which is expected to be spent in the 2008 to 2011 time period). As disclosed
in
FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement
with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer,
procure, and construct air quality control systems for the reduction of
sulfur
dioxide emissions. The settlement agreement also requires OE and Penn to
spend
up to $25 million toward environmentally beneficial projects, which include
wind
energy purchased power agreements over a 20-year term. OE and Penn agreed
to pay
a civil penalty of $8.5 million. Results for the first quarter of 2005
included
the penalties payable by OE and Penn of $7.8 million and $0.7 million,
respectively. OE and Penn also recognized liabilities of $9.2 million and
$0.8
million, respectively, for probable future cash contributions toward
environmentally beneficial projects during the first quarter of
2005.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (Protocol), to address global warming by reducing the
amount
of man-made greenhouse gases emitted by developed countries by 5.2% from
1990
levels between 2008 and 2012. The United States signed the Protocol in
1998 but
it failed to receive the two-thirds vote of the United States Senate required
for ratification. However, the Bush administration has committed the United
States to a voluntary climate change strategy to reduce domestic greenhouse
gas
intensity - the ratio of emissions to economic output - by 18 percent through
2012. The Energy Policy Act of 2005 established a Committee on Climate
change
Technology to coordinate federal climate change activities and promote
the
development and deployment of GHG reducing technologies.
The
Companies
cannot currently estimate the financial impact of climate change policies,
although the potential restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per
kilowatt-hour of electricity generated by the Companies is lower than many
regional competitors due to the Companies' diversified generation sources
which
include low or non-CO2
emitting gas-fired
and nuclear generators.
Regulation
of
Hazardous Waste
The
Companies have
been named as PRPs at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation, and Liability Act of
1980.
Allegations of disposal of hazardous substances at historical sites and
the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on
a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
September 30, 2005, based on estimates of the total costs of cleanup,
the
Companies' proportionate responsibility for such costs and the financial
ability
of other nonaffiliated 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 $64 million (JCP&L -
$46.8 million, CEI
-
$2.3 million, TE
-
$0.2 million,
Met-Ed -
$0.1 million and
other -
$14.6 million)
have been accrued through September 30, 2005.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FirstEnergy's normal business operations pending against FirstEnergy
and its subsidiaries. The other material items not otherwise discussed
above are
described below.
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 concludes, 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 website (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 also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. FirstEnergy notes, however, that the FERC or
other
applicable government agencies and reliability coordinators may take a
different
view as to recommended enhancements or may recommend additional enhancements
in
the future that could require additional, material expenditures. Finally,
the
PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to
control room computer hardware and software and enhancements to the training
of
control room operators, before determining the next steps, if any, in the
proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two such cases were originally
filed in Ohio State courts but subsequently dismissed for lack of subject
matter
jurisdiction and further appeals were unsuccessful. In both such 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. Of the four other pending PUCO complaint cases, three were
filed by
various insurance carriers either in their own name or as subrogees in
the name
of their insured. In each such case, the carriers seek reimbursement against
various FirstEnergy companies (and, in one case, against PJM, MISO and
American
Electric Power Co. as well) for claims they paid to their insureds allegedly
due
to the loss of power on August 14, 2003. The listed insureds in these cases,
in
many instances, are not customers of any FirstEnergy company. The fourth
case
involves the claim of a non-customer seeking reimbursement for losses incurred
when its store was burglarized on August 14, 2003. In addition to these
six
cases, the Ohio Companies were named as respondents in a regulatory proceeding
that was initiated at the PUCO in response to complaints alleging failure
to
provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. No estimate of potential liability
has been
undertaken for any of these cases.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. In particular, if FirstEnergy or
its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition, results of operations and cash
flows.
FENOC
received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection
and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power
Station.
On December 10, 2004, FirstEnergy received a letter from the United
States
Attorney's Office stating that FENOC is a target of the federal grand jury
investigation into alleged false statements made to the NRC in the Fall
of 2001
in response to NRC Bulletin 2001-01. The letter also said that the designation
of FENOC as a target indicates that, in the view of the prosecutors assigned
to
the matter, it is likely that federal charges will be returned against
FENOC by
the grand jury. On February 10, 2005, FENOC received an additional
subpoena
for documents related to root cause reports regarding reactor head degradation
and the assessment of reactor head management issues at Davis-Besse.
On May 11,
2005, FENOC received a subpoena for documents related to outside meetings
attended by Davis-Besse personnel on corrosion and cracking of control
rod drive
mechanisms and additional root cause evaluations.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related
to
the degradation of the Davis-Besse reactor vessel head issue described
above.
FirstEnergy accrued $2.0 million for a potential fine prior to 2005 and
accrued
the remaining liability for the proposed fine during the first quarter
of 2005.
On September 14, 2005, FENOC filed its response to the NOV with
the NRC.
FENOC accepted full responsibility for the past failure to properly implement
its boric acid corrosion control and corrective action programs. The NRC
NOV
indicated that the violations do not represent current licensee performance.
FirstEnergy paid the penalty in the third quarter of 2005.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
based on the events surrounding Davis-Besse, it could have a material adverse
effect on FirstEnergy's or its subsidiaries' financial condition, results
of
operations and cash flows.
Effective
July 1, 2005 the NRC oversight panel for Davis-Besse was terminated
and
Davis-Besse returned to the standard NRC reactor oversight process. At
that
time, NRC inspections were augmented to include inspections to support
the NRC's
Confirmatory Order dated March 8, 2004 that was issued at the time
of
startup and to address an NRC White Finding related to the performance
of the
emergency sirens.
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. FENOC operates the Perry Nuclear
Power
Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however,
see Note 17 regarding FirstEnergy’s pending intra-system generation asset
transfers, which include owned portions of the plant). On
April 4,
2005, the NRC held a public forum to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter
to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to
the NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" and met all cornerstone objectives although it remained under heightened
NRC oversight since August 2004. During the public forum 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 May 26, 2005,
the NRC
held a public meeting to discuss its oversight of the Perry Plant. While
the NRC
stated that the plant continued to operate safely, the NRC also stated
that the
overall performance had not substantially improved since the heightened
inspection was initiated. The NRC reiterated this conclusion in its mid-year
assessment letter dated August 30, 2005. On September 28, 2005,
the NRC
sent a CAL to FENOC describing commitments that FENOC had made to improve
the
performance of Perry 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. If performance does not improve, the NRC has
a range
of options under the Reactor Oversight Process, from increased oversight
to
possible impact to the plant’s operating authority. As a result, these matters
could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed
informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage,
have
become the subject of a formal order of investigation. The SEC's formal
order of
investigation also encompasses issues raised during the SEC's examination
of
FirstEnergy and the Companies under the PUHCA. Concurrent with this
notification, FirstEnergy received a subpoena asking for background documents
and documents related to the restatements and Davis-Besse issues. On
December 30, 2004, FirstEnergy received a subpoena asking for documents
relating to issues raised during the SEC's PUHCA examination. On August
24, 2005
additional information was requested regarding Davis-Besse. FirstEnergy
has
cooperated fully with the informal inquiry and will continue to do so with
the
formal investigation.
On
August 22,
2005, a class action complaint was filed against OE in Jefferson County,
Ohio
Common Pleas Court seeking compensatory and punitive damages to be determined
at
trial based on claims of negligence and eight other tort counts alleging
damages
from the W.H. Sammis Plant air emissions. The two named plaintiffs are
also
seeking injunctive relief to eliminate harmful emissions and repair property
damage and the institution of a medical monitoring program for class members.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator
decided not to hear testimony on damages and closed the proceedings. On
September 9, 2005, the Arbitrator issued an opinion to award approximately
$16.1 million to the bargaining unit employees. JCP&L initiated an appeal of
this award by filing a motion to vacate in Federal court in New Jersey
on
October 18, 2005. JCP&L recognized a liability for the potential $16.1
million award during the three months ended September 30, 2005.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of
a newly
formed municipal electric utility. The complaint was filed on May 28,
2003,
and OE timely filed its response on June 30, 2003. In a related
filing, the
Ohio Companies filed for approval with the PUCO a tariff that would specifically
allow the collection of transition charges from customers of municipal
electric
utilities formed after 1998. An
adverse ruling
could negatively affect full recovery of transition charges by the utility.
Hearings on the matter were held in August 2005. Initial briefs from all
parties
were filed on September 22, 2005 and reply briefs were filed on
October 14, 2005. It is unknown when the PUCO will rule on this
case.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters,
it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP
No. FAS
13-1, "Accounting for Rental Costs Incurred during the Construction
Period"
Issued
in October
2005, FSP No. FAS 13-1 requires rental costs associated with ground or
building
operating leases that are incurred during a construction period to
be
recognized as rental expense. The effective date of the FSP guidance is
the
first reporting period beginning after December 15, 2005. FirstEnergy is
currently evaluating this FSP, and its impact on the financial
statements.
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or
more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the
EITF
reached a consensus that an exchange of inventory should be accounted for
at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, FirstEnergy will adopt this EITF
effective for new arrangements entered into, or modifications or renewals
of
existing arrangements, in interim or annual periods beginning after March
15,
2006. See Note 2 for an example of FirstEnergy's application of this
Issue.
|
EITF
Issue No. 05-6, "Determining the Amortization Period for Leasehold
Improvements Purchased after Lease Inception or Acquired in a
Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6. EITF
05-6
addresses the amortization period for leasehold improvements that were
either
acquired in a business combination or placed in service significantly after
and
not contemplated at or near the beginning of the initial lease term. For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that includes
required lease periods and renewals that are deemed to be reasonably assured
at
the date of acquisition. Leasehold improvements that are placed in service
significantly after and not contemplated at or near the beginning of the
lease
term should be amortized over the shorter of the useful life of the assets
or a
term that includes required lease periods and renewals that are deemed
to be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with FirstEnergy's current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the
fair
value of an asset retirement obligation that is conditional on a future
event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective for FirstEnergy in the fourth quarter
of 2005.
FirstEnergy and the Companies are currently evaluating the effect this
Interpretation will have on their financial statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement of APB
Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and reporting
a
change in accounting principle. It applies to all voluntary changes in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions. This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of
the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening
balance
of retained earnings (or other appropriate components of equity or net
assets in
the statement of financial position) for that period rather than being
reported
in the Consolidated Statements of Income. This Statement also requires
that a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate
affected
by a change in accounting principle. The provisions of this Statement are
effective for accounting changes and corrections of errors made in fiscal
years
beginning after December 15, 2005. FirstEnergy and the Companies
will adopt
this Statement effective January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion
No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows
of the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for FirstEnergy.
This FSP is not expected to have a material impact on FirstEnergy's financial
statements.
SFAS
123(R),
“Share-Based Payment”
In
December 2004,
the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing
stock options in the financial statements. Important to applying the new
standard is understanding how to (1) measure the fair value of stock-based
compensation awards and (2) recognize the related compensation cost for
those
awards. For an award to qualify for equity classification, it must meet
certain
criteria in SFAS 123(R). An award that does not meet those criteria will
be
classified as a liability and remeasured each period. SFAS 123(R) retains
SFAS
123's requirements on accounting for income tax effects of stock-based
compensation. In April 2005, the SEC delayed the effective date of SFAS
123(R)
to annual, rather than interim, periods that begin after June 15,
2005. The
SEC’s new rule results in a six-month deferral for companies with a fiscal
year
beginning January 1. Therefore, FirstEnergy will adopt this Statement
effective January 1, 2006. FirstEnergy expects to adopt modified
prospective application, without restatement of prior interim periods.
Potential
cumulative adjustments, if any, have not yet been determined. FirstEnergy
uses
the Black-Scholes option-pricing model to value options for disclosure
purposes
only and expects to apply this pricing model upon adoption of SFAS 123(R).
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
of idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be
“so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective
for
inventory costs incurred by FirstEnergy beginning January 1, 2006.
FirstEnergy is currently evaluating this Standard and does not expect it
to have
a material impact on the financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application to
Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security Whose
Cost
Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
loss no later than when the impairment is deemed other than temporary,
even if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP in
the fourth
quarter of 2005, which would require prospective application with an effective
date for reporting periods beginning after December 15, 2005. FirstEnergy
is
currently evaluating this FSP and any impact on its investments.
FSP
109-1,
“Application of FASB Statement No. 109, Accounting for Income Taxes, to
the Tax
Deduction and Qualified Production Activities Provided by the American
Jobs
Creation Act of 2004”
Issued
in December
2004, FSP 109-1 provides guidance related to the provision within the American
Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified
production activities. The Act includes a tax deduction of up to nine percent
(when fully phased-in) of the lesser of (a) “qualified production activities
income,” as defined in the Act, or (b) taxable income (after the deduction for
the utilization of any net operating loss carryforwards). The FASB believes
that
the deduction should be accounted for as a special deduction in accordance
with
SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's
accounting.
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
825,790
|
|
$
|
766,336
|
|
$
|
2,268,760
|
|
$
|
2,227,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
15,158
|
|
|
15,244
|
|
|
39,080
|
|
|
44,158
|
|
Purchased
power
|
|
|
229,561
|
|
|
242,835
|
|
|
703,658
|
|
|
730,542
|
|
Nuclear
operating costs
|
|
|
76,254
|
|
|
81,244
|
|
|
264,514
|
|
|
235,277
|
|
Other
operating costs
|
|
|
114,762
|
|
|
99,132
|
|
|
293,530
|
|
|
276,289
|
|
Provision
for
depreciation
|
|
|
30,169
|
|
|
30,702
|
|
|
87,875
|
|
|
90,846
|
|
Amortization
of regulatory assets
|
|
|
126,439
|
|
|
103,211
|
|
|
347,880
|
|
|
317,030
|
|
Deferral
of
new regulatory assets
|
|
|
(43,929
|
)
|
|
(25,728
|
)
|
|
(107,750
|
)
|
|
(69,790
|
)
|
General
taxes
|
|
|
51,945
|
|
|
47,634
|
|
|
146,066
|
|
|
135,688
|
|
Income
taxes
|
|
|
99,778
|
|
|
76,502
|
|
|
245,942
|
|
|
203,863
|
|
Total
operating expenses and taxes
|
|
|
700,137
|
|
|
670,776
|
|
|
2,020,795
|
|
|
1,963,903
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
125,653
|
|
|
95,560
|
|
|
247,965
|
|
|
264,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
20,069
|
|
|
17,141
|
|
|
37,352
|
|
|
50,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
|
12,989
|
|
|
10,657
|
|
|
44,330
|
|
|
43,641
|
|
Allowance
for
borrowed funds used during construction
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
capitalized interest
|
|
|
(3,014
|
)
|
|
(1,950
|
)
|
|
(8,255
|
)
|
|
(4,924
|
)
|
Other
interest expense
|
|
|
4,193
|
|
|
640
|
|
|
12,457
|
|
|
7,576
|
|
Subsidiary's
preferred stock dividend requirements
|
|
|
156
|
|
|
639
|
|
|
1,534
|
|
|
1,919
|
|
Net
interest
charges
|
|
|
14,324
|
|
|
9,986
|
|
|
50,066
|
|
|
48,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
131,398
|
|
|
102,715
|
|
|
235,251
|
|
|
266,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
659
|
|
|
623
|
|
|
1,976
|
|
|
1,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
130,739
|
|
$
|
102,092
|
|
$
|
233,275
|
|
$
|
264,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
131,398
|
|
$
|
102,715
|
|
$
|
235,251
|
|
$
|
266,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
loss on available for sale securities
|
|
|
(3,402
|
)
|
|
(6,913
|
)
|
|
(19,079
|
)
|
|
(2,767
|
)
|
Income
tax
benefit related to other comprehensive income
|
|
|
2,043
|
|
|
2,850
|
|
|
7,713
|
|
|
1,141
|
|
Other
comprehensive loss, net of tax
|
|
|
(1,359
|
)
|
|
(4,063
|
)
|
|
(11,366
|
)
|
|
(1,626
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
130,039
|
|
$
|
98,652
|
|
$
|
223,885
|
|
$
|
264,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Ohio Edison
Company are an integral part of these
|
|
|
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
5,573,996
|
|
$
|
5,440,374
|
|
Less
-
Accumulated provision for depreciation
|
|
|
2,793,343
|
|
|
2,716,851
|
|
|
|
|
2,780,653
|
|
|
2,723,523
|
|
Construction
work in progress -
|
|
|
|
|
|
|
|
Electric
plant
|
|
|
246,325
|
|
|
203,167
|
|
Nuclear
fuel
|
|
|
17,972
|
|
|
21,694
|
|
|
|
|
264,297
|
|
|
224,861
|
|
|
|
|
3,044,950
|
|
|
2,948,384
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Investment
in
lease obligation bonds
|
|
|
341,335
|
|
|
354,707
|
|
Nuclear
plant
decommissioning trusts
|
|
|
462,439
|
|
|
436,134
|
|
Long-term
notes receivable from associated companies
|
|
|
207,089
|
|
|
208,170
|
|
Other
|
|
|
44,623
|
|
|
48,579
|
|
|
|
|
1,055,486
|
|
|
1,047,590
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
900
|
|
|
1,230
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $7,312,000 and $6,302,000,
respectively,
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
285,462
|
|
|
274,304
|
|
Associated
companies
|
|
|
121,262
|
|
|
245,148
|
|
Other
(less
accumulated provisions of $14,000 and $64,000,
respectively,
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
20,653
|
|
|
18,385
|
|
Notes
receivable from associated companies
|
|
|
798,513
|
|
|
538,871
|
|
Materials
and
supplies, at average cost
|
|
|
92,610
|
|
|
90,072
|
|
Prepayments
and other
|
|
|
17,336
|
|
|
13,104
|
|
|
|
|
1,336,736
|
|
|
1,181,114
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
844,590
|
|
|
1,115,627
|
|
Property
taxes
|
|
|
61,419
|
|
|
61,419
|
|
Unamortized
sale and leaseback costs
|
|
|
56,477
|
|
|
60,242
|
|
Other
|
|
|
67,093
|
|
|
68,275
|
|
|
|
|
1,029,579
|
|
|
1,305,563
|
|
|
|
$
|
6,466,751
|
|
$
|
6,482,651
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 175,000,000 shares - 100 shares
outstanding
|
|
$
|
2,099,099
|
|
$
|
2,098,729
|
|
Accumulated
other comprehensive loss
|
|
|
(58,484
|
)
|
|
(47,118
|
)
|
Retained
earnings
|
|
|
434,473
|
|
|
442,198
|
|
Total
common
stockholder's equity
|
|
|
2,475,088
|
|
|
2,493,809
|
|
Preferred
stock
|
|
|
60,965
|
|
|
60,965
|
|
Preferred
stock of consolidated subsidiary
|
|
|
14,105
|
|
|
39,105
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,099,147
|
|
|
1,114,914
|
|
|
|
|
3,649,305
|
|
|
3,708,793
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
273,656
|
|
|
398,263
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
120,971
|
|
|
11,852
|
|
Other
|
|
|
123,584
|
|
|
167,007
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
81,980
|
|
|
187,921
|
|
Other
|
|
|
11,289
|
|
|
10,582
|
|
Accrued
taxes
|
|
|
213,843
|
|
|
153,400
|
|
Other
|
|
|
117,268
|
|
|
74,663
|
|
|
|
|
942,591
|
|
|
1,003,688
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
688,702
|
|
|
766,276
|
|
Accumulated
deferred investment tax credits
|
|
|
52,108
|
|
|
62,471
|
|
Asset
retirement obligation
|
|
|
364,525
|
|
|
339,134
|
|
Retirement
benefits
|
|
|
320,044
|
|
|
307,880
|
|
Other
|
|
|
449,476
|
|
|
294,409
|
|
|
|
|
1,874,855
|
|
|
1,770,170
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
6,466,751
|
|
$
|
6,482,651
|
|
|
|
|
|
|
|
|
|
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
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
131,398
|
|
$
|
102,715
|
|
$
|
235,251
|
|
$
|
266,148
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
30,169
|
|
|
30,702
|
|
|
87,875
|
|
|
90,846
|
|
Amortization
of regulatory assets
|
|
|
126,439
|
|
|
103,211
|
|
|
347,880
|
|
|
317,030
|
|
Deferral
of
new regulatory assets
|
|
|
(43,929
|
)
|
|
(25,728
|
)
|
|
(107,750
|
)
|
|
(69,790
|
)
|
Nuclear
fuel
and lease amortization
|
|
|
11,867
|
|
|
11,914
|
|
|
30,530
|
|
|
33,766
|
|
Amortization
of lease costs
|
|
|
32,963
|
|
|
33,037
|
|
|
30,011
|
|
|
30,585
|
|
Amortization
of electric service obligation
|
|
|
(4,565
|
)
|
|
-
|
|
|
(8,556
|
)
|
|
-
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(17,787
|
)
|
|
(11,374
|
)
|
|
(22,929
|
)
|
|
(61,961
|
)
|
Accrued
retirement benefit obligations
|
|
|
5,503
|
|
|
7,253
|
|
|
12,164
|
|
|
24,482
|
|
Accrued
compensation, net
|
|
|
1,254
|
|
|
1,106
|
|
|
(1,903
|
)
|
|
5,138
|
|
Pension
trust
contribution
|
|
|
-
|
|
|
(72,763
|
)
|
|
-
|
|
|
(72,763
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
32,715
|
|
|
(86,506
|
)
|
|
110,460
|
|
|
(10,734
|
)
|
Materials
and
supplies
|
|
|
15,611
|
|
|
(2,930
|
)
|
|
(2,538
|
)
|
|
(8,796
|
)
|
Prepayments
and other current assets
|
|
|
2,988
|
|
|
4,878
|
|
|
(4,232
|
)
|
|
(1,636
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(20,007
|
)
|
|
115,690
|
|
|
(105,234
|
)
|
|
21,905
|
|
Accrued
taxes
|
|
|
41,365
|
|
|
(4,464
|
)
|
|
60,443
|
|
|
(346,918
|
)
|
Accrued
interest
|
|
|
2,458
|
|
|
3,028
|
|
|
1,667
|
|
|
2,918
|
|
Prepayment
for electric service - education programs
|
|
|
-
|
|
|
-
|
|
|
136,142
|
|
|
-
|
|
Other
|
|
|
(11,504
|
)
|
|
2,572
|
|
|
1,372
|
|
|
(8,624
|
)
|
Net
cash
provided from operating activities
|
|
|
336,938
|
|
|
212,341
|
|
|
800,653
|
|
|
211,596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
-
|
|
|
146,450
|
|
|
30,000
|
|
Short-term
borrowings, net
|
|
|
18,254
|
|
|
91,072
|
|
|
65,696
|
|
|
13,258
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
-
|
|
|
(37,750
|
)
|
|
-
|
|
Long-term
debt
|
|
|
(17,819
|
)
|
|
(36,090
|
)
|
|
(278,327
|
)
|
|
(152,900
|
)
|
Dividend
Payments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(64,000
|
)
|
|
(68,000
|
)
|
|
(241,000
|
)
|
|
(239,000
|
)
|
Preferred
stock
|
|
|
(659
|
)
|
|
(623
|
)
|
|
(1,976
|
)
|
|
(1,843
|
)
|
Net
cash used
for financing activities
|
|
|
(64,224
|
)
|
|
(13,641
|
)
|
|
(346,907
|
)
|
|
(350,485
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(69,346
|
)
|
|
(61,682
|
)
|
|
(190,804
|
)
|
|
(146,645
|
)
|
Contributions
to nuclear decommissioning trusts
|
|
|
(7,885
|
)
|
|
(7,885
|
)
|
|
(23,655
|
)
|
|
(23,655
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(200,021
|
)
|
|
(378,081
|
)
|
|
(258,561
|
)
|
|
30,709
|
|
Proceeds
from
certificates of deposit
|
|
|
-
|
|
|
277,763
|
|
|
-
|
|
|
277,763
|
|
Other
|
|
|
4,155
|
|
|
(29,200
|
)
|
|
18,944
|
|
|
113
|
|
Net
cash
provided from (used for) investing activities
|
|
|
(273,097
|
)
|
|
(199,085
|
)
|
|
(454,076
|
)
|
|
138,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
decrease
in cash and cash equivalents
|
|
|
(383
|
)
|
|
(385
|
)
|
|
(330
|
)
|
|
(604
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
1,283
|
|
|
1,664
|
|
|
1,230
|
|
|
1,883
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
900
|
|
$
|
1,279
|
|
$
|
900
|
|
$
|
1,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Stockholders
and Board of
Directors
of Ohio
Edison Company:
We
have reviewed
the accompanying consolidated balance sheet of Ohio Edison Company and its
subsidiaries as of September 30, 2005, and the related consolidated
statements of income and comprehensive income and cash flows for each of the
three-month and nine-month periods ended September 30, 2005 and 2004.
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, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G)
to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 7 to those consolidated financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
OHIO
EDISON
COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
OE
is a wholly
owned electric utility subsidiary of FirstEnergy. OE and its wholly owned
subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania,
providing regulated electric distribution services. The OE Companies also
provide generation services to those customers electing to retain the OE
Companies as their power supplier. The OE Companies provide power directly
to
wholesale customers under previously negotiated contracts, as well as to
some
alternative energy suppliers under OE’s transition plan. The OE Companies have
unbundled the price of electricity into its component elements - including
generation, transmission, distribution and transition charges. Power supply
requirements of the OE Companies are provided by FES -- an affiliated
company.
Results
of Operations
Earnings
on common
stock in the third quarter of 2005 increased to $131 million from $102 million
in the third quarter of 2004. The increase in earnings resulted primarily
from
higher operating revenues and lower purchased power and nuclear operating
costs,
partially offset by increases in regulatory asset amortization, other operating
costs and income taxes. During the first nine months of 2005, earnings on
common
stock decreased to $233 million from $264 million in the same period of 2004.
The decrease in earnings for the first nine months of 2005 primarily resulted
from increases in nuclear operating costs, regulatory asset amortization
and a
one-time income tax charge that occurred in the second quarter of 2005, as
well
as a decrease in other income. These reductions to earnings were partially
offset by higher operating revenues and lower fuel and purchased power costs.
Operating
revenues
increased by $59 million or 7.8% in the third quarter of 2005 compared with
the
same period in 2004. Higher revenues for the quarter primarily resulted from
increased retail generation and distribution revenues of $23 million and
$33
million, respectively. During the first nine months of 2005 compared to the
same
period in 2004, operating revenues increased by $41 million or 1.8%. Higher
revenues for the first nine months of 2005 were due to increases in retail
generation and distribution revenues of $36 million and $40 million,
respectively, partially offset by a $37 million decrease in wholesale sales.
Lower
wholesale
revenues for the first nine months of 2005 reflected decreased sales to FES
of
$57 million (12.1% KWH sales decrease), due to reduced nuclear generation
available for sale. The decreased sales to FES were partially offset by
increased sales of $21 million to non-affiliated customers (including MSG
sales). Under its Ohio transition plan, OE is required to provide MSG to
non-affiliated alternative suppliers (see Outlook - Regulatory Matters).
Increased
retail
generation revenues for the third quarter of 2005 resulted from higher sales
to
residential, commercial and industrial customers of $10 million, $2 million
and
$11 million, respectively. The increased generation KWH sales to residential
(14.0%) and commercial (6.1%) customers were due to warmer than normal
temperatures in the third quarter of 2005. Increased industrial revenues
reflected a 6.5% increase in generation KWH sales. Partially offsetting the
increase in residential KWH sales was an increase in customer shopping.
Generation services provided to residential customers by alternative suppliers
as a percent of total residential sales delivered in OE’s service area increased
by 1.2 percentage points compared with the third quarter of 2004. Commercial
and
industrial customer shopping remained relatively unchanged.
Retail
generation
revenues increased for the first nine months of 2005 compared to the same
period
of 2004 in all customer sectors (residential - $15 million, commercial -
$7
million and industrial - $14 million). The higher revenues were due to increased
generation KWH sales (residential - 6.8%, commercial - 4.2% and industrial
-
1.0%). Residential and industrial KWH sales increases were partially offset
by
increases in customer shopping by 1.1 and 1.7 percentage points, respectively,
while commercial shopping remained relatively unchanged.
Revenues
from
distribution throughput increased $33 million in the third quarter of 2005
compared with the same period in 2004. Distribution deliveries to residential,
commercial and industrial customers increased by $26 million, $4 million
and $3 million, respectively, due to increased KWH deliveries. The increases
from distribution deliveries were partially offset by lower composite unit
prices in all sectors.
Revenues
from
distribution throughput increased $40 million in the first nine months of
2005
compared with the same period in 2004 due to higher revenues from residential
and commercial customers, partially offset by lower industrial sector revenues.
Residential and commercial distribution revenues increased $40 million and
$3 million, respectively, reflecting higher KWH deliveries partially
offset
by lower composite prices. Industrial distribution revenues decreased by
$3
million due to lower composite unit prices, partially offset by an increase
in
KWH distribution deliveries.
Under
the Ohio
transition plan, OE provides incentives to customers to encourage switching
to
alternative energy providers. OE’s revenues were reduced by $3 million from
additional credits in the third quarter and $7 million in the first nine
months
of 2005 compared to the same periods in 2004. These revenue reductions are
deferred for future recovery from customers under OE’s transition plan and do
not affect current period earnings (See Regulatory Matters below).
Changes
in KWH
sales by customer class in the three months and nine months ended
September 30, 2005 from the corresponding periods of 2004 are summarized
in
the following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
9.1
|
%
|
|
3.9
|
%
|
Wholesale
|
|
|
(1.2
|
)%
|
|
(9.4
|
)%
|
Total
Electric Generation Sales
|
|
|
4.0
|
%
|
|
(2.6
|
)%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
15.9
|
%
|
|
8.3
|
%
|
Commercial
|
|
|
6.3
|
%
|
|
4.2
|
%
|
Industrial
|
|
|
6.9
|
%
|
|
3.4
|
%
|
Total
Distribution Deliveries
|
|
|
9.8
|
%
|
|
5.3
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes increased by $29 million in the third quarter and $57
million
in the first nine months of 2005 from the same periods of 2004. The following
table presents changes from the prior year by expense
category.
Operating
Expenses and Taxes - Changes
|
|
Three
Months
|
|
Nine
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
costs
|
|
$
|
--
|
|
$
|
(5
|
)
|
Purchased
power costs
|
|
|
(13
|
)
|
|
(27
|
)
|
Nuclear
operating costs
|
|
|
(5
|
)
|
|
29
|
|
Other
operating costs
|
|
|
16
|
|
|
17
|
|
Provision
for
depreciation
|
|
|
(1
|
)
|
|
(3
|
)
|
Amortization
of regulatory assets
|
|
|
23
|
|
|
31
|
|
Deferral
of
new regulatory assets
|
|
|
(18
|
)
|
|
(38
|
)
|
General
taxes
|
|
|
4
|
|
|
11
|
|
Income
taxes
|
|
|
23
|
|
|
42
|
|
Net
increase in operating expenses and taxes
|
|
$
|
29
|
|
$
|
57
|
|
Lower
fuel costs in
the first nine months of 2005, compared with the same periods of 2004, resulted
from decreased nuclear generation - down 12.1%. Purchased power costs were
lower
in both periods of 2005, reflecting lower unit costs partially offset by
higher
KWH purchases in the third quarter of 2005. KWH purchases were relatively
unchanged in the first nine months of 2005. Nuclear operating costs decreased
in
the third quarter of 2005 compared to the same quarter in 2004 primarily
due to
a decrease in non-fuel nuclear operating costs at Perry Unit 1 and Beaver
Valley
Unit 2. Nuclear operating costs increased during the first nine months of
2005
primarily due to the costs from the Beaver Valley Unit 2 refueling outage
(started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage
initiated in the first quarter of 2005 that was completed on May 6, 2005.
There
were no nuclear refueling outages in the same periods last year. The increases
in other operating costs in the third quarter and first nine months of 2005,
compared to the same periods of 2004, resulted primarily from increased MISO
transmission expenses, partially offset by lower employee benefits
expenses.
The
decrease in
depreciation expense in the first nine months of 2005 compared with the same
period of 2004 was attributable to revised estimated service life assumptions
for fossil generating plants (see Note 3). Higher regulatory asset amortization
in the three-month and nine-month periods was primarily due to increased
amortization of transition costs being recovered under the RSP. Increases
in
regulatory asset deferrals for both periods resulted from higher shopping
incentive deferrals and related interest ($4 million and $11 million,
respectively), and the PUCO-approved MISO administrative cost deferrals and
related interest ($14 million and $27 million, respectively, see Outlook
-
Regulatory Matters).
General
taxes
increased in the third quarter and first nine months of 2005 compared to
the
same periods of 2004 due to the effect of higher KWH sales which increased
Ohio
KWH excise taxes in both periods. The increase in the first nine months of
2005
also reflected the absence of a $6 million Pennsylvania property tax refund
recognized in the second quarter of 2004.
Income
taxes
increased in the first nine months of 2005 compared to the same periods of
2004,
primarily due to the effects of new tax legislation in Ohio. On June 30,
2005,
the State of Ohio enacted new tax legislation that created a new CAT tax,
which
is based on qualifying “taxable gross receipts” and will not consider any
expenses or costs incurred to generate such receipts, except for items such
as
cash discounts, returns and allowances, and bad debts. The CAT tax was effective
July 1, 2005, and replaces the Ohio income-based franchise tax and
the Ohio
personal property tax. The CAT tax is phased-in while the current income-based
franchise tax is phased-out over a five-year period at a rate of 20% annually,
beginning with the year ended 2005, and personal property tax is phased-out
over
a four-year period at a rate of approximately 25% annually, beginning with
the
year ended 2005. During the phase-out period the Ohio income tax will be
computed consistently with the prior tax law, except that the tax liability
as
computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and
1/5 in
2008, therefore eliminating the current income-based franchise tax over a
five-year period.
As
a result of the
new tax structure, all net deferred tax benefits that are not expected to
reverse during the five-year phase-in period were written-off as of
June 30, 2005. The
impact on
income taxes associated with the required adjustment to net deferred taxes
for
the nine months ended September 30, 2005 was an additional tax expense
of
approximately $36 million, which was partially offset by the initial phase-out
of the Ohio income-based franchise tax, which reduced income taxes by
approximately $7 million in the nine months ended September 30, 2005.
See
Note 12 to the consolidated financial statements.
Other
Income
Other
income
decreased $13 million in the first nine months of 2005 compared with the
same
period of 2004, primarily due to an $8.5 million civil penalty payable to
the
Department of Justice and a $10 million liability for environmental projects
recognized in connection with the W.H. Sammis Plant settlement (see Outlook
-
Environmental Matters), partially offset by higher nuclear decommissioning
trust
realized gains.
Net
Interest
Charges
Net
interest
charges increased by $4 million in the third quarter and $2 million in the
first
nine months of 2005 compared with the same periods of 2004, reflecting increased
short-term borrowings from associated companies at a higher rate of
interest.
Capital
Resources and Liquidity
OE’s
cash
requirements for the remainder of 2005 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing OE’s net debt and preferred stock
outstanding. Borrowing capacity under credit facilities is available to manage
working capital requirements. Thereafter, OE expects to use a combination
of
cash from operations and funds from the capital markets.
Changes
in Cash
Position
As
of September 30,
2005, OE's cash and cash equivalents of approximately $1 million remained
unchanged from December 31, 2004.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities during the third quarter and first nine months of 2005,
compared with the corresponding periods in 2004 were as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
273
|
|
$
|
224
|
|
$
|
603
|
|
$
|
607
|
|
Pension
trust
contribution (2)
|
|
|
--
|
|
|
(44
|
)
|
|
--
|
|
|
(44
|
)
|
Working
capital and other
|
|
|
64
|
|
|
32
|
|
|
198
|
|
|
(351
|
)
|
Total
cash
flows from operating activities
|
|
$
|
337
|
|
$
|
212
|
|
$
|
801
|
|
$
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash
earnings is a non-GAAP measure (see reconciliation
below).
|
|
|
|
|
|
|
|
|
|
|
(2)
Pension
trust contribution net of $29 million of income tax
benefits.
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings, as
disclosed in the table above, are not a measure of performance calculated
in
accordance with GAAP. OE believes that cash earnings is a useful financial
measure because it provides investors and management with an additional means
of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
131
|
|
$
|
103
|
|
$
|
235
|
|
$
|
266
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
30
|
|
|
31
|
|
|
88
|
|
|
91
|
|
Amortization
of regulatory assets
|
|
|
126
|
|
|
103
|
|
|
348
|
|
|
317
|
|
Amortization
of lease costs
|
|
|
33
|
|
|
33
|
|
|
30
|
|
|
31
|
|
Nuclear
fuel
and capital lease amortization
|
|
|
12
|
|
|
12
|
|
|
31
|
|
|
34
|
|
Deferral
of
new regulatory assets
|
|
|
(44
|
)
|
|
(26
|
)
|
|
(108
|
)
|
|
(70
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(18
|
)
|
|
(40
|
)
|
|
(23
|
)
|
|
(91
|
)
|
Other
non-cash items
|
|
|
3
|
|
|
8
|
|
|
2
|
|
|
29
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
273
|
|
$
|
224
|
|
$
|
603
|
|
$
|
607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided
from operating activities increased $125 million in the third quarter of
2005,
compared with the third quarter of 2004, due to a $32 million increase from
changes in working capital, the absence of a $44 million after-tax
voluntary pension trust contribution made in the third quarter of 2004 and
a $49
million increase in cash earnings as described above and under “Results from
Operations”. The increase in working capital primarily reflects changes in
accrued taxes of $46 million (including a $249 million reallocation of tax
liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing
agreement), partially offset by changes in accounts payable and accounts
receivable of $16 million.
Net
cash provided
from operating activities increased $589 million in the first nine months
of
2005, compared with the same period in 2004, due to a $549 million increase
from
changes in working capital, the absence of a $44 million after-tax
voluntary pension trust contribution made in the third quarter of 2004,
partially offset by a $4 million decrease in cash earnings as described
above and under “Results from Operations”. The increase in working capital
primarily reflects changes in accrued taxes of $407 million (including a
$249
million reallocation of tax liabilities among the FirstEnergy subsidiaries
pursuant to the tax sharing agreement) and $136 million of funds received
for
the Energy for Education program in the second quarter of 2005.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities increased to $64 million in the third quarter of 2005
from
$14 million in the third quarter of 2004. The increase primarily resulted
from a
$72 million decrease in new short-term borrowings, partially offset by an
$18
million decrease in redemptions and repayments. Net cash used for financing
activities decreased to $347 million in the first nine months of 2005 from
$350
million in the same period of 2004. The decrease was due to a $169 million
increase in new debt and short term borrowings partially offset by a $163
million increase in net debt and preferred stock redemptions.
On
May 16,
2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock
at
$102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock
at
$100 per share, including accrued dividends to the date of redemption.
OE
had
approximately $799 million of cash and temporary cash investments (which
include
short-term notes receivable from associated companies) and $245 million of
short-term indebtedness as of September 30, 2005. OE has authorization
from
the PUCO to incur short-term debt of up to $500 million (including bank
facilities and the utility money pool described below). Penn has authorization
from the SEC to incur short-term debt up to its charter limit of
$51 million (including the utility money pool).
OES
Capital is a
wholly owned subsidiary of OE whose borrowings are secured by customer accounts
receivable purchased from OE. OES Capital can borrow up to $170 million under
a
receivables financing arrangement. As a separate legal entity with separate
creditors, OES Capital would have to satisfy its obligations to creditors
before
any of its remaining assets could be made available to OE. As of
September 30, 2005, the facility was drawn for
$120 million.
Penn
Power Funding
LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
company whose borrowings are secured by customer accounts receivable purchased
from Penn. Penn Funding can borrow up to $25 million under a receivables
financing arrangement. As a separate legal entity with separate creditors,
Penn
Funding would have to satisfy its obligations to creditors before any of
its
remaining assets could be made available to Penn.
As of
September 30, 2005, the facility was not drawn. On July 15,
2005, the
facility was renewed until June 29, 2006. The annual facility fee
is 0.25%
on the entire finance limit.
As
of October 24,
2005, OE and Penn had the aggregate capability to issue approximately $1.1
billion of additional FMB on the basis of property additions and retired
bonds
under the terms of their respective mortgage indentures following the recently
completed intra-system transfer of fossil generating plants (see Note 17).
The
issuance of FMB by OE is also subject to provisions of its 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 to
incur
additional secured debt not otherwise permitted by a specified exception
of up
to $690 million as of October 24, 2005. Based upon applicable earnings coverage
tests in their respective charters, OE and Penn could issue a total of $2.8
billion of preferred stock (assuming no additional debt was issued) as of
September 30, 2005. It is estimated that the annualized impact of
the
intra-system transfer of fossil generating plants will reduce the aggregate
capability of OE and Penn to issue preferred stock by approximately 17%.
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as Borrowers, entered into a syndicated $2 billion five-year revolving credit
facility. Borrowings under the facility are available to each Borrower
separately and mature on the earlier of 364 days from the date of borrowing
or
the commitment termination date, as the same may be extended. OE's and Penn’s
borrowing limits under the facility are $550 million.
OE
and Penn have
the ability to borrow from their regulated affiliates and FirstEnergy to
meet
their short-term working capital requirements. FESC administers this money
pool
and tracks surplus funds of FirstEnergy and its regulated subsidiaries.
Companies receiving a loan under the money pool agreements must repay the
principal amount, together with accrued interest, within 364 days of borrowing
the funds. The rate of interest is the same for each company receiving a
loan
from the pool and is based on the average cost of funds available through
the
pool. The average interest rate for borrowings in the third quarter of 2005
was
3.50%.
OE’s
access to
capital markets and costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements in
its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base load
generation fleet, low-risk transmission and distribution operations and rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also noted
as
strengths.
Cash
Flows From
Investing Activities
Net
cash used for
investing activities increased by $74 million in the third quarter of 2005
and
$592 million in the first nine months of 2005, from the same periods
of
2004. These increases resulted primarily from $278 million in cash
proceeds
from certificates of deposit during the third quarter 2004. Loans to associated
companies decreased $178 million in the third quarter of 2005, partially
offsetting the proceeds from certificates of deposit, and increased
$289 million in the first nine months of 2005.
In
the last quarter
of 2005, capital requirements for property additions and capital leases
are
expected to be approximately $82 million. OE has additional requirements
of
approximately $8 million to meet sinking fund requirements for preferred
stock
and maturing long-term debt (excluding Penn’s optional redemptions disclosed
above) during the remainder of 2005. These cash requirements are expected
to be
satisfied from internal cash and short-term credit arrangements. OE’s capital
spending for the period 2005-2007 is expected to be about $667 million
of which
approximately $233 million applies to 2005.
FirstEnergy
Intra-System Generation Asset Transfers
On
May 13,
2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain
agreements implementing a series of intra-system generation asset transfers.
When fully completed, the asset transfers will result in the respective
undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s
nuclear and non-nuclear plants being owned by NGC, and FGCO, respectively.
The
generating plant interests that are being transferred do not include OE’s
leasehold interests in certain of the plants that are currently subject
to sale
and leaseback arrangements with non-affiliates.
On
October 24,
2005, the OE Companies completed the transfer of non-nuclear generation
assets
to FGCO. The OE Companies currently expect to complete the transfer of
nuclear
generation assets to NGC through a spin-off by way of dividend before the
end of
2005. Consummation of the nuclear transfer remains subject to necessary
regulatory approvals.
These
transactions
are being undertaken in connection with the Ohio Companies’ and Penn’s
restructuring plans that were approved by the PUCO and the PPUC, respectively,
under applicable Ohio and Pennsylvania electric utility restructuring
legislation. Consistent with the restructuring plans, generation assets
that had
been owned by the Ohio Companies and Penn were required to be separated
from the
regulated delivery business of those companies through transfer to a separate
corporate entity. FENOC currently operates and maintains the nuclear generation
assets to be transferred. FGCO, as lessee under a Master Facility Lease,
leased,
operated and maintained the non-nuclear generation assets that it now owns.
The
transactions will essentially complete the divestitures contemplated by
the
restructuring plans by transferring the ownership interests to NGC and
FGCO,
respectively, without impacting the operation of the plants.
See
Note 17 to the
consolidated financial statements for OE's and Penn’s disclosure of the assets
held for sale as of September 30, 2005.
Off-Balance
Sheet Arrangements
Obligations
not
included on OE’s Consolidated Balance Sheets primarily consist of sale and
leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2.
The
present value of these operating lease commitments, net of trust investments,
was $678 million as of September 30, 2005.
Equity
Price Risk
Included
in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $262 million and $248 million
as
of September 30, 2005 and December 31, 2004, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $26
million
reduction in fair value as of September 30, 2005. Changes in the fair value
of
these investments are recorded in OCI unless recognized as a result of
a sale or
recognized as regulatory assets or liabilities.
Outlook
The
electric
industry continues to transition to a more competitive environment and all
of
the OE Companies’ customers can select alternative energy suppliers. The OE
Companies continue to deliver power to residential homes and businesses through
their existing distribution system, which remains regulated. Customer rates
have
been restructured into separate components to support customer choice. In
Ohio
and Pennsylvania, the OE Companies have a continuing responsibility to provide
power to those customers not choosing to receive power from an alternative
energy supplier subject to certain limits.
Regulatory
Matters
In
2001, Ohio
customer rates were restructured to establish separate charges for transmission,
distribution, transition cost recovery and a generation-related component.
When
one of OE's customers elects to obtain power from an alternative supplier,
OE
reduces the customer's bill with a "generation shopping credit," based on
the
generation component (plus an incentive), and the customer receives a generation
charge from the alternative supplier. OE has continuing PLR responsibility
to
its franchise customers through December 31, 2008 unless the PUCO
accepts
future competitive bid results prior to the end of that period under the
revised
RSP.
As
part of OE's
transition plan, it is obligated to supply electricity to customers who do
not
choose an alternative supplier. OE is also required to provide 560 MW of
low
cost supply (MSG) to unaffiliated alternative suppliers who serve customers
within its service area. FES acts as an alternate supplier for a portion
of the
load in OE's franchise area.
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 competitive
bid
process. The RSP was filed by the Ohio Companies to establish generation
service
rates beginning January 1, 2006, in response to PUCO concerns about
price
and supply uncertainty following the end of the Ohio Companies' transition
plan
market development period. In October 2004, the OCC and NOAC filed appeals
with
the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO
order
in this proceeding as well as the associated entries on rehearing. On
September 28, 2005, the Ohio Supreme Court heard oral argument on
the
appeals.
On
May 27,
2005, OE filed an application with the PUCO to establish a GCAF rider under
the
RSP. The application seeks to implement recovery of increased fuel costs
from
2006 through 2008 applicable to OE’s retail customers through a tariff rider to
be implemented January 1, 2006. The application reflects projected
increases in fuel costs in 2006 compared to 2002 baseline costs. The new
rider,
after adjustments made in testimony, is seeking to recover all costs above
the
baseline (approximately $88 million in 2006 for all of the Ohio Companies).
Various parties including the OCC have intervened in this case and the case
has
been consolidated with the RCP application discussed below.
On
September 9,
2005, OE filed an application with the PUCO that, if approved, would supplement
its existing RSP with an RCP. On September 27, 2005, the PUCO granted
FirstEnergy's motion to consolidate the GCAF rider application with the RCP
proceedings and set hearings for the consolidated cases to begin
November 29, 2005. The RCP is designed to provide customers with more
certain rate levels than otherwise available under the RSP during the plan
period, and to provide OE with financial results generally comparable to
those
attained under the RSP. Major provisions of the RCP include:
· Maintain
the
existing level of base distribution rates through December 31, 2008 for
OE;
· Defer
and
capitalize certain distribution costs to be incurred by all of the Ohio
Companies during
the
period January 1,
2006 through December 31, 2008, not to exceed $150 million in each of
the
three
years;
· Adjust
the RTC and
extended RTC recovery periods and rate levels so that full recovery
of
authorized
costs will
occur as of December 31, 2008 for OE;
· Reduce
the deferred
shopping incentive balance as of January 1, 2006 by up to $75 million for
OE
by
accelerating the
application of its accumulated cost of removal regulatory liability;
and
· Recover
increased
fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007,
and
2008,
respectively,
from all OE and TE distribution and transmission customers through a
fuel
recovery
mechanism.
OE may defer and capitalize increased fuel costs above the amount
collected
through the
fuel recovery mechanism.
Under
provisions of
the RSP, the PUCO may require OE to undertake, no more often than annually,
a
competitive bid process to secure generation for the years 2007 and 2008.
On
July 22, 2005, FirstEnergy filed a competitive
bid
process for the period beginning in 2007 that is similar to the competitive
bid
process approved by the PUCO for OE in 2004, which resulted in the PUCO
accepting no bids. Any acceptance of future competitive bid results would
terminate the RSP pricing, with no accounting impacts to the RSP, and not
until
twelve months after the PUCO authorizes such termination. On September 28,
2005, the PUCO issued an Entry that essentially approved the Ohio Companies'
filing but delayed the proposed timing of the competitive bid process by
four
months, calling for the auction to be held on March 21, 2006.
On
December 30, 2004, OE filed with the PUCO two applications
related to
the recovery of transmission and ancillary service related costs. The first
application seeks recovery of these costs beginning January 1, 2006.
At the
time of filing the application, these costs were estimated to be approximately
$14 million per year; however, OE anticipates that this amount will increase.
OE
requested that these costs be recovered through a rider that would be effective
on January 1, 2006 and adjusted each July 1 thereafter. OE
reached a
settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE.
The
only other party in this proceeding, Dominion Retail, Inc., agreed not to
oppose
the settlement. This settlement, which was filed with the PUCO on July 22,
2005, provides for the rider recovery requested by OE, with carrying charges
applied in the subsequent year’s rider for any over or under collection while
the then-current rider is in effect. The PUCO approved the settlement
stipulation on August 31, 2005. The incremental Transmission and Ancillary
service revenues expected to be recovered from January through June 2006
are
approximately $30.6 million. This value includes the recovery of the 2005
deferred MISO expenses as described below. In May 2006, OE will file a
modification to the rider which will determine revenues from July 2006 through
June 2007.
The
second
application seeks authority to defer costs associated with transmission and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO granted
the
accounting authority for OE to defer incremental transmission and ancillary
service-related charges incurred as a participant in MISO, but only for those
costs incurred during the period December 30, 2004 through December 31,
2005. Permission to defer costs incurred prior to December 31, 2004 was denied.
The PUCO also authorized OE to accrue carrying charges on the deferred balances.
An application filed with the PUCO to recover these deferred charges over
a
five-year period through the rider, beginning in 2006, was approved in a
PUCO
order issued on August 31, 2005 approving the stipulation referred
to
above. The OCC, OPAE and OE each filed applications for rehearing. OE sought
authority to defer the transmission and ancillary service related costs incurred
during the period October 1, 2003 through December 29, 2004, while
both OCC
and OPAE sought to have the PUCO deny deferral of all costs. On July 6,
2005, the PUCO denied OE's and OCC’s applications and, at the request of OE,
struck as untimely OPAE’s application. The OCC filed a notice of appeal with the
Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance
with appellate procedure, the PUCO filed with the Ohio Supreme Court the
record
in this case. The Companies’ brief will be due thirty days after the OCC files
its brief, which, absent any time extensions, must be filed no later than
November 9, 2005.
OE
and Penn record
as regulatory assets costs which have been authorized by the PUCO, the PPUC
and
the FERC for recovery from customers in future periods and, without such
authorization, the costs would have been charged to income when incurred.
OE’s
regulatory assets as of September 30, 2005 and December 31, 2004,
were $0.8
billion and $1.1 billion, respectively. OE is deferring customer shopping
incentives and interest costs as new regulatory assets in accordance with
its
transition and rate stabilization plans. These regulatory assets total $302
million as of September 30, 2005 and, under the RSP, will be recovered
through a surcharge rate equal to the RTC rate in effect when the transition
costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the
estimated net amortization of regulatory transition costs and deferred shopping
incentive balances under the proposed RCP and current RSP. Penn's net regulatory
asset components aggregate as net regulatory liabilities of approximately
$48
million and $18 million, and are included in Other Noncurrent Liabilities
on the
Consolidated Balance Sheet as of September 30, 2005 and December 31,
2004, respectively.
On
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for its
customers at set rates following the end of its transition period on December
31, 2006. Penn is recommending that the Request for Proposal process cover
the
period of January 1, 2007 through May 31, 2008. Under Pennsylvania's
electric competition law, Penn is required to secure generation supply for
customers who do not choose alternative suppliers for their
electricity.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio and Pennsylvania and a detailed discussion
of
reliability initiatives, including actions by the PPUC, that impact
Penn.
Environmental
Matters
OE
accrues
environmental liabilities only when it concludes that it is probable that
it has
an obligation for such costs and can reasonably estimate the amount of such
costs. Unasserted claims are reflected in OE's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
National
Ambient Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for
fine
particulate matter. On March 10, 2005, the EPA finalized the "Clean
Air
Interstate Rule" covering a total of 28 states (including 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
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS
in
other states. CAIR provides each affected state until 2006 to develop
implementing regulation 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)
in all cases from
the 2003 levels. The OE Companies’ Ohio and Pennsylvania fossil-fuel generation
facilities will be subject to the caps on SO2
and 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 the OE Companies operate affected facilities.
Mercury
Emissions
In
December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury
as the
hazardous air pollutant of greatest concern. On March 14, 2005, the
EPA
finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade
program to reduce mercury emissions from coal-fired power plants in two phases.
Initially, mercury emissions will be capped nationally at 38 tons by 2010
as a
"co-benefit" from implementation of SO2
and NOx
emission caps
under the EPA's CAIR program. Phase II of the mercury cap-and-trade program
will
cap nationwide mercury emissions from coal-fired power plants at 15 tons
per
year by 2018. However,
the final
rules give states substantial discretion in developing rules to implement
these programs. In addition, both the CAIR and the Clean Air Mercury rule
have
been challenged in the United States Court of Appeals for the District of
Columbia. Future cost of compliance with these regulations may be
substantial.
W.
H. Sammis
Plant
In
1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities alleging violations
of
the Clean Air Act based on operation and maintenance of 44 power plants,
including the W. H. Sammis Plant, which is owned by OE and Penn. In addition,
the DOJ filed eight civil complaints against various investor-owned utilities,
including a complaint against OE and Penn in the U.S. District Court for
the
Southern District of Ohio. These cases are referred to as New Source Review
cases. On March 18, 2005, OE and Penn announced that they had reached
a
settlement with the EPA, the DOJ and three states (Connecticut, New Jersey,
and
New York) that resolved all issues related to the W. H. Sammis Plant New
Source
Review litigation. This settlement agreement, which is in the form of a Consent
Decree, was approved by the Court on July 11, 2005, requires OE and
Penn to
reduce NOx
and SO2
emissions at the
W. H. Sammis Plant and other coal-fired plants through the installation of
pollution control devices. Capital expenditures necessary to meet those
requirements are currently estimated to be $1.5 billion (the primary portion
of
which is expected to be spent in the 2008 to 2011 time period). The settlement
agreement also requires OE and Penn to spend up to $25 million toward
environmentally beneficial projects, which include wind energy purchased
power
agreements over a 20-year term. OE and Penn agreed to pay a civil penalty
of
$8.5 million. Results for the first quarter of 2005 included the penalties
payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE
and
Penn also recognized liabilities of $9.2 million and $0.8 million, respectively,
for probable future cash contributions toward environmentally beneficial
projects during the first quarter of 2005.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (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 Protocol in 1998 but it failed
to
receive the two-thirds vote of the United States Senate required for
ratification. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity -
the
ratio of emissions to economic output - by 18 percent through 2012. The Energy
Policy Act of 2005 established a Committee on Climate Change Technology to
coordinate federal climate change activities and promote the development
and
deployment of GHG reducing technologies.
The
OE Companies
cannot currently estimate the financial impact of climate change policies,
although the potential restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per KWH
of electricity generated by the OE Companies is lower than many regional
competitors due to the OE Companies' diversified generation sources which
include low or non-CO2
emitting
gas-fired
and nuclear generators.
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.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to OE's normal business operations pending against OE and its
subsidiaries. The other material items not otherwise discussed above are
described below.
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 concludes, 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 website (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 also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. FirstEnergy notes, however, that the FERC or
other
applicable government agencies and reliability coordinators may take a different
view as to recommended enhancements or may recommend additional enhancements
in
the future that could require additional, material expenditures. Finally,
the
PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to
control room computer hardware and software and enhancements to the training
of
control room operators, before determining the next steps, if any, in the
proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two such cases were
originally filed in Ohio State courts but subsequently dismissed for lack
of
subject matter jurisdiction and further appeals were unsuccessful. In both
such
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. Of the four other pending PUCO complaint cases, three were filed
by
various insurance carriers either in their own name as subrogees or in the
name
of their insured. In each such case, the carriers seek reimbursement against
various FirstEnergy companies (and, in one case, against PJM, MISO and American
Electric Power Co. as well) for claims they paid to their insureds allegedly
due
to the loss of power on August 14, 2003. The listed insureds in these cases,
in
many instances, are not customers of any FirstEnergy company. The fourth
case
involves the claim of a non-customer seeking reimbursement for losses incurred
when its store was burglarized on August 14, 2003. In addition to these six
cases, the Ohio Companies were named as respondents in a regulatory proceeding
that was initiated at the PUCO in response to complaints alleging failure
to
provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. No estimate of potential liability
has been
undertaken for any of these cases.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14, 2003
power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. In particular, if FirstEnergy or
its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition, results of operations and cash
flows.
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 effective corrective action. FENOC operates the Perry Nuclear Power Plant,
in which the OE Companies have a 35.24% interest (however, see Note 17 regarding
FirstEnergy’s pending intra-system generation asset transfers, which include
owned portions of the plant).
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the
NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to
be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix.
On
May 26,
2005, the NRC held a public meeting to discuss its oversight of the Perry
Plant.
While the NRC stated that the plant continued to operate safely, the NRC
also
stated that the overall performance had not substantially improved since
the
heightened inspection was initiated. The
NRC reiterated
this conclusion in its mid-year assessment letter dated August 30, 2005.
On
September 28, 2005, the NRC sent a CAL to FENOC describing commitments
that
FENOC had made to improve the performance of Perry 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.
If performance
does not improve, the NRC has a range of options under the Reactor Oversight
Process from increased oversight to possible impact to the plant’s operating
authority. As a result, these matters could have a material adverse effect
on
FirstEnergy's or its subsidiaries' financial condition, results of operations
and cash flows.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and OE, and the Davis-Besse extended outage (OE has no interest
in
Davis-Besse), have become the subject of a formal order of investigation.
The
SEC's formal order of investigation also encompasses issues raised during
the
SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent
with this notification, FirstEnergy received a subpoena asking for background
documents and documents related to the restatements and Davis-Besse issues.
On
December 30, 2004, FirstEnergy received a subpoena asking for documents
relating to issues raised during the SEC's PUHCA examination. On August 24,
2005 additional information was requested regarding Davis-Besse. FirstEnergy
has
cooperated fully with the informal inquiry and will continue to do so with
the
formal investigation.
On
August 22,
2005, a class action complaint was filed against OE in Jefferson County,
Ohio
Common Pleas Court seeking compensatory and punitive damages to be determined
at
trial based on claims of negligence and eight other tort counts alleging
damages
from the W.H. Sammis Plant air emissions. The two named plaintiffs are also
seeking injunctive relief to eliminate harmful emissions and repair property
damage and the institution of a medical monitoring program for class members.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of a
newly
formed municipal electric utility. The complaint was filed on May 28,
2003,
and OE timely filed its response on June 30, 2003. In a related filing,
the
Ohio Companies filed for approval with the PUCO of a tariff that would
specifically allow the collection of transition charges from customers of
municipal electric utilities formed after 1998. An adverse ruling could
negatively affect full recovery of transition charges by the utility. Hearings
on the matter were held in August 2005. Initial briefs from all parties were
filed on September 22, 2005 and reply briefs were filed on October 14,
2005. It is unknown when the PUCO will rule on this case.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters, it
could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13,”Accounting for Purchases and Sales of Inventory with the Same
Counterparty”
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or
more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the EITF
reached a consensus that an exchange of inventory should be accounted for
at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, OE will adopt this EITF effective
for
new arrangements entered into, or modifications or renewals of existing
arrangements, in interim or annual periods beginning after March 15, 2006.
|
EITF
Issue No. 05-6, “Determining the Amortization Period for Leasehold
Improvements Purchased after Lease Inception or Acquired in a Business
Combination”
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6. EITF
05-6
addresses the amortization period for leasehold improvements that were either
acquired in a business combination or placed in service significantly after
and
not contemplated at or near the beginning of the initial lease term. For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that includes
required lease periods and renewals that are deemed to be reasonably assured
at
the date of acquisition. Leasehold improvements that are placed in service
significantly after and not contemplated at or near the beginning of the
lease
term should be amortized over the shorter of the useful life of the assets
or a
term that includes required lease periods and renewals that are deemed to
be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with the OE current
accounting.
|
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an
interpretation of FASB Statement No.
143”
|
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the second period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. Therefore, OE will adopt this Interpretation
in
the fourth quarter of 2005. OE is currently evaluating the effect this standard
will have on its financial statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement of APB
Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and reporting
a
change in accounting principle. It applies to all voluntary changes in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions. This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of
the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings (or other appropriate components of equity or net assets
in
the statement of financial position) for that period rather than being reported
in an income statement. This Statement also requires that a change in
depreciation, amortization, or depletion method for long-lived, nonfinancial
assets be accounted for as a change in accounting estimate affected by a
change
in accounting principle. The provisions of this Statement are effective for
accounting changes and corrections of errors made in fiscal years beginning
after December 15, 2005. OE will adopt this Statement effective January
1,
2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows of
the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective for nonmonetary exchanges occurring
in fiscal periods beginning after June 15, 2005 and are to be applied
prospectively. As a result, OE will adopt this Statement effective
January 1, 2006, and does not expect it to have a material impact
on its
financial statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be “so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective
for
inventory costs incurred by OE beginning January 1, 2006. OE is currently
evaluating this Standard and does not expect it to have a material impact
on the
financial statements.
FSP
FAS 115-1,
“The Meaning of Other-Than-Temporary Impairment and its Application to Certain
Investments”
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security Whose
Cost
Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
loss no later than when the impairment is deemed other than temporary, even
if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP in the
fourth
quarter of 2005, which would require prospective application with an effective
date for reporting periods beginning after December 15, 2005. OE is currently
evaluating this FSP and any impact on its investments.
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
526,421
|
|
$
|
504,848
|
|
|
|
$
|
1,408,341
|
|
$
|
1,372,259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
24,701
|
|
|
21,011
|
|
|
|
|
64,138
|
|
|
57,583
|
|
Purchased
power
|
|
|
129,640
|
|
|
140,988
|
|
|
|
|
411,366
|
|
|
412,170
|
|
Nuclear
operating costs
|
|
|
26,252
|
|
|
28,766
|
|
|
|
|
121,765
|
|
|
80,002
|
|
Other
operating costs
|
|
|
89,475
|
|
|
76,196
|
|
|
|
|
227,759
|
|
|
219,857
|
|
Provision
for
depreciation
|
|
|
36,100
|
|
|
33,096
|
|
|
|
|
100,602
|
|
|
98,060
|
|
Amortization
of regulatory assets
|
|
|
68,455
|
|
|
53,732
|
|
|
|
|
177,497
|
|
|
151,822
|
|
Deferral
of
new regulatory assets
|
|
|
(60,519
|
)
|
|
(40,596
|
)
|
|
|
|
(126,508
|
)
|
|
(92,032
|
)
|
General
taxes
|
|
|
40,054
|
|
|
37,348
|
|
|
|
|
115,546
|
|
|
110,646
|
|
Income
taxes
|
|
|
55,286
|
|
|
51,883
|
|
|
|
|
94,897
|
|
|
81,057
|
|
Total
operating expenses and taxes
|
|
|
409,444
|
|
|
402,424
|
|
|
|
|
1,187,062
|
|
|
1,119,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
116,977
|
|
|
102,424
|
|
|
|
|
221,279
|
|
|
253,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
24,117
|
|
|
8,264
|
|
|
|
|
37,691
|
|
|
29,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
|
27,090
|
|
|
24,061
|
|
|
|
|
83,452
|
|
|
92,967
|
|
Allowance
for
borrowed funds used during construction
|
|
|
(1,129
|
)
|
|
(1,056
|
)
|
|
|
|
(2,012
|
)
|
|
(3,782
|
)
|
Other
interest expense
|
|
|
4,696
|
|
|
5,239
|
|
|
|
|
12,952
|
|
|
12,750
|
|
Net
interest
charges
|
|
|
30,657
|
|
|
28,244
|
|
|
|
|
94,392
|
|
|
101,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
110,437
|
|
|
82,444
|
|
|
|
|
164,578
|
|
|
180,644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
-
|
|
|
1,754
|
|
|
|
|
2,918
|
|
|
5,253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
110,437
|
|
$
|
80,690
|
|
|
|
$
|
161,660
|
|
$
|
175,391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
110,437
|
|
$
|
82,444
|
|
|
|
$
|
164,578
|
|
$
|
180,644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
(6,574
|
)
|
|
991
|
|
|
|
|
(9,144
|
)
|
|
(1,332
|
)
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
|
(2,510
|
)
|
|
406
|
|
|
|
|
(3,433
|
)
|
|
(546
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
(4,064
|
)
|
|
585
|
|
|
|
|
(5,711
|
)
|
|
(786
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
106,373
|
|
$
|
83,029
|
|
|
|
$
|
158,867
|
|
$
|
179,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Cleveland
Electric Illuminating Company are an
|
|
|
integral
part
of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
4,498,876
|
|
$
|
4,418,313
|
|
Less
-
Accumulated provision for depreciation
|
|
|
2,020,868
|
|
|
1,961,737
|
|
|
|
|
2,478,008
|
|
|
2,456,576
|
|
Construction
work in progress -
|
|
|
|
|
|
|
|
Electric
plant
|
|
|
90,911
|
|
|
85,258
|
|
Nuclear
fuel
|
|
|
8,632
|
|
|
30,827
|
|
|
|
|
99,543
|
|
|
116,085
|
|
|
|
|
2,577,551
|
|
|
2,572,661
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Investment
in
lessor notes
|
|
|
564,169
|
|
|
596,645
|
|
Nuclear
plant
decommissioning trusts
|
|
|
427,920
|
|
|
383,875
|
|
Long-term
notes receivable from associated companies
|
|
|
8,774
|
|
|
97,489
|
|
Other
|
|
|
16,028
|
|
|
17,001
|
|
|
|
|
1,016,891
|
|
|
1,095,010
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
207
|
|
|
197
|
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provision of $5,309,000 for uncollectible accounts
in
2005)
|
|
|
255,769
|
|
|
11,537
|
|
Associated
companies
|
|
|
19,883
|
|
|
33,414
|
|
Other
(less
accumulated provisions of $6,000 and $293,000, respectively,
|
|
|
9,651
|
|
|
152,785
|
|
for
uncollectible accounts)
|
|
|
|
|
|
|
|
Notes
receivable from associated companies
|
|
|
-
|
|
|
521
|
|
Materials
and
supplies, at average cost
|
|
|
72,506
|
|
|
58,922
|
|
Prepayments
and other
|
|
|
2,769
|
|
|
2,136
|
|
|
|
|
360,785
|
|
|
259,512
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,966
|
|
|
1,693,629
|
|
Regulatory
assets
|
|
|
889,127
|
|
|
958,986
|
|
Property
taxes
|
|
|
77,792
|
|
|
77,792
|
|
Other
|
|
|
29,995
|
|
|
32,875
|
|
|
|
|
2,685,880
|
|
|
2,763,282
|
|
|
|
$
|
6,641,107
|
|
$
|
6,690,465
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
79,590,689
shares outstanding
|
|
$
|
1,356,998
|
|
$
|
1,281,962
|
|
Accumulated
other comprehensive income
|
|
|
12,148
|
|
|
17,859
|
|
Retained
earnings
|
|
|
574,394
|
|
|
553,740
|
|
Total
common
stockholder's equity
|
|
|
1,943,540
|
|
|
1,853,561
|
|
Preferred
stock
|
|
|
-
|
|
|
96,404
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,939,730
|
|
|
1,970,117
|
|
|
|
|
3,883,270
|
|
|
3,920,082
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
75,706
|
|
|
76,701
|
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
518,784
|
|
|
488,633
|
|
Other
|
|
|
35,000
|
|
|
-
|
|
Accounts
payable-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
33,802
|
|
|
150,141
|
|
Other
|
|
|
6,702
|
|
|
9,271
|
|
Accrued
taxes
|
|
|
156,630
|
|
|
129,454
|
|
Accrued
interest
|
|
|
27,242
|
|
|
22,102
|
|
Lease
market
valuation liability
|
|
|
60,200
|
|
|
60,200
|
|
Other
|
|
|
39,094
|
|
|
61,131
|
|
|
|
|
953,160
|
|
|
997,633
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
552,072
|
|
|
540,211
|
|
Accumulated
deferred investment tax credits
|
|
|
58,736
|
|
|
60,901
|
|
Lease
market
valuation liability
|
|
|
623,100
|
|
|
668,200
|
|
Asset
retirement obligation
|
|
|
280,765
|
|
|
272,123
|
|
Retirement
benefits
|
|
|
86,597
|
|
|
82,306
|
|
Other
|
|
|
203,407
|
|
|
149,009
|
|
|
|
|
1,804,677
|
|
|
1,772,750
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
6,641,107
|
|
$
|
6,690,465
|
|
|
|
|
|
|
|
|
|
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
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
110,437
|
|
$
|
82,444
|
|
$
|
164,578
|
|
$
|
180,644
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
36,100
|
|
|
33,096
|
|
|
100,602
|
|
|
98,060
|
|
Amortization
of regulatory assets
|
|
|
68,455
|
|
|
53,732
|
|
|
177,497
|
|
|
151,822
|
|
Deferral
of
new regulatory assets
|
|
|
(60,519
|
)
|
|
(40,596
|
)
|
|
(126,508
|
)
|
|
(92,032
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
8,236
|
|
|
7,804
|
|
|
19,017
|
|
|
20,420
|
|
Amortization
of electric service obligation
|
|
|
(2,155
|
)
|
|
(3,336
|
)
|
|
(12,278
|
)
|
|
(12,877
|
)
|
Deferred
rents and lease market valuation liability
|
|
|
(13,439
|
)
|
|
(14,324
|
)
|
|
(67,130
|
)
|
|
(56,182
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
10,484
|
|
|
13,019
|
|
|
14,934
|
|
|
11,392
|
|
Accrued
retirement benefit obligations
|
|
|
2,169
|
|
|
2,854
|
|
|
4,291
|
|
|
10,900
|
|
Accrued
compensation, net
|
|
|
1,201
|
|
|
1,303
|
|
|
(1,294
|
)
|
|
3,232
|
|
Pension
trust
contribution
|
|
|
-
|
|
|
(31,718
|
)
|
|
-
|
|
|
(31,718
|
)
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
10,507
|
|
|
(3,422
|
)
|
|
(87,567
|
)
|
|
106,421
|
|
Materials
and
supplies
|
|
|
15,207
|
|
|
(2,238
|
)
|
|
(13,584
|
)
|
|
(7,711
|
)
|
Prepayments
and other current assets
|
|
|
(821
|
)
|
|
1,512
|
|
|
(633
|
)
|
|
3,409
|
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(157,188
|
)
|
|
60,237
|
|
|
(118,908
|
)
|
|
1,889
|
|
Accrued
taxes
|
|
|
33,955
|
|
|
(15,630
|
)
|
|
27,176
|
|
|
(52,495
|
)
|
Accrued
interest
|
|
|
5,460
|
|
|
(3,218
|
)
|
|
5,140
|
|
|
(2,371
|
)
|
Prepayment
for electric service - education programs
|
|
|
-
|
|
|
-
|
|
|
67,589
|
|
|
-
|
|
Other
|
|
|
(18,457
|
)
|
|
(3,335
|
)
|
|
(26,328
|
)
|
|
(40,193
|
)
|
Net
cash
provided from operating activities
|
|
|
49,632
|
|
|
138,184
|
|
|
126,594
|
|
|
292,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
87,772
|
|
|
44,330
|
|
|
141,056
|
|
|
125,238
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
213,682
|
|
|
53,369
|
|
|
132,770
|
|
Equity
contributions from parent
|
|
|
-
|
|
|
-
|
|
|
75,000
|
|
|
-
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
(1,000
|
)
|
|
(101,900
|
)
|
|
(1,000
|
)
|
Long-term
debt
|
|
|
(90,859
|
)
|
|
(327,171
|
)
|
|
(147,789
|
)
|
|
(335,272
|
)
|
Short-term
borrowings, net
|
|
|
(5,505
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(17,000
|
)
|
|
-
|
|
|
(141,000
|
)
|
|
(145,000
|
)
|
Preferred
stock
|
|
|
-
|
|
|
(1,755
|
)
|
|
(2,260
|
)
|
|
(5,253
|
)
|
Net
cash used
for financing activities
|
|
|
(25,592
|
)
|
|
(71,914
|
)
|
|
(123,524
|
)
|
|
(228,517
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(37,809
|
)
|
|
(32,238
|
)
|
|
(98,053
|
)
|
|
(70,967
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
22,309
|
|
|
(850
|
)
|
|
89,236
|
|
|
9,964
|
|
Investments
in lessor notes
|
|
|
3
|
|
|
(11,699
|
)
|
|
32,476
|
|
|
9,266
|
|
Contributions
to nuclear decommissioning trusts
|
|
|
(7,256
|
)
|
|
(7,256
|
)
|
|
(21,768
|
)
|
|
(21,768
|
)
|
Other
|
|
|
(1,287
|
)
|
|
(14,227
|
)
|
|
(4,951
|
)
|
|
(15,170
|
)
|
Net
cash used
for investing activities
|
|
|
(24,040
|
)
|
|
(66,270
|
)
|
|
(3,060
|
)
|
|
(88,675
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
10
|
|
|
(24,582
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
207
|
|
|
200
|
|
|
197
|
|
|
24,782
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
207
|
|
$
|
200
|
|
$
|
207
|
|
$
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Stockholders
and Board of
Directors
of The
Cleveland Electric Illuminating Company:
We
have reviewed
the accompanying consolidated balance sheet of The Cleveland Electric
Illuminating Company and its subsidiaries as of September 30, 2005, and the
related consolidated statements of income and comprehensive income and cash
flows for each of the three-month and nine-month periods ended September
30,
2005 and 2004. 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, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note
2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
CEI
is a wholly
owned, electric utility subsidiary of FirstEnergy. CEI conducts business
in
portions of Ohio, providing regulated electric distribution services. CEI
also
provides generation services to those customers electing to retain CEI as
their
power supplier. CEI provides power directly to alternative energy suppliers
under CEI’s transition plan. CEI has unbundled the price of electricity into its
component elements -- including generation, transmission, distribution and
transition charges. Power supply requirements of CEI are provided by FES
-- an
affiliated company.
Results
of Operations
Earnings
on common
stock in the third quarter of 2005 increased to $110 million from $81 million
in
the third quarter of 2005. Increased earnings in the third quarter of 2005
resulted primarily from higher operating revenues and lower purchased power
costs, which were partially offset by higher regulatory asset amortization
and
higher other operating costs. For the first nine months of 2005, earnings
on
common stock decreased to $162 million from $175 million in the same period
of
2004. Lower earnings for the first nine months of 2005 resulted primarily
from
higher nuclear operating costs, higher regulatory asset amortization and
other
operating costs and a one-time income tax charge; those effects were partially
offset by increased operating revenues and lower net interest
charges.
Operating
revenues
increased by $22 million or 4.3% in the third quarter of 2005 from the same
period in 2004. Higher revenues resulted primarily from increases in retail
generation and distribution revenues of $3 million and $19 million,
respectively, and a $5 million increase in revenues from wholesale sales.
During
the first nine months of 2005, operating revenues increased by $36 million
or
2.6%,
compared to the same period in 2004. Higher revenues were due to increases
in
retail generation and distribution revenues of $13 million and $23 million,
respectively, and a $2 million increase in revenues from wholesale
sales.
Increased
retail
generation revenues for the third quarter of 2005 resulted from higher
industrial unit prices and higher residential KWH sales, partially offset
by
lower unit prices and KWH sales for commercial customers. An 18.7% increase
in
residential KWH sales during the third quarter was primarily due to warmer
weather in CEI's service area, as compared to last year. An increase in
residential customer shopping by 1.7 percentage points in the third quarter
of
2005 partially offset the higher generation KWH sales as compared to 2004.
Increased retail generation revenues for the first nine months of 2005 resulted
from higher industrial unit prices and higher residential KWH sales, partially
offset by lower commercial and industrial KWH sales. The decrease in residential
customer shopping by 0.7 percentage points in the first nine months of 2005
contributed slightly to the higher generation KWH sales for the period as
compared to last year.
Revenue
from
wholesale sales increased by $5 million during the third quarter of 2005,
reflecting the effect of a 2.5% increase in KWH sales. The increase in wholesale
sales was primarily due to a 13.6% KWH increase in MSG sales to non-affiliated
wholesale customers ($3.5 million). Under its Ohio transition plan, CEI is
required to provide MSG to non-affiliated alternative suppliers (see Outlook
-
Regulatory Matters). Increased sales to FES of $1.5 million (1.3% KWH increase)
also contributed to the third quarter results. In the first nine months of
2005,
wholesale sales revenue increased by $2 million. A $20 million increase (23.0%
KWH increase) in MSG sales to non-affiliated wholesale customers was partially
offset by an $18 million decrease in sales (6.7% KWH decrease) to
FES.
Revenues
from
distribution throughput increased $19 million in the third quarter of 2005
compared with the same quarter of 2004. The increase was due to higher
residential and industrial revenues ($18 million and $5 million, respectively),
reflecting increased distribution deliveries in the third quarter of 2005,
in
part due to warmer weather. These increases were partially offset by lower
commercial revenues of $4 million as a result of lower unit prices.
Revenues
from
distribution throughput increased $23 million in the first nine months of
2005
compared with the same period in 2004 due to higher revenues in the residential
sector ($28 million), partially offset by lower industrial revenues ($4
million). Higher distribution deliveries in the residential sector were
partially offset by lower unit prices and decreased KWH deliveries to industrial
customers. Revenues in the commercial sector increased slightly ($0.4 million)
as higher distribution deliveries were almost totally offset by lower unit
prices.
Changes
in KWH
sales by customer class in the three months and nine months ended
September 30, 2005 from the corresponding periods of 2004 are summarized
in
the following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
0.6
|
%
|
|
(0.3
|
)%
|
Wholesale
|
|
|
2.5
|
%
|
|
(4.0
|
)%
|
Total
Electric Generation Sales
|
|
|
1.7
|
%
|
|
(2.5
|
)%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
18.7
|
%
|
|
9.7
|
%
|
Commercial
|
|
|
1.5
|
%
|
|
3.3
|
%
|
Industrial
|
|
|
2.8
|
%
|
|
(1.0
|
)%
|
Total
Distribution Deliveries
|
|
|
6.6
|
%
|
|
2.9
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes increased by $7 million in the third quarter and $68 million
in the first nine months of 2005 from the same periods of 2004. The following
table presents changes from the prior year by expense
category.
|
|
|
|
|
|
|
|
Three
|
|
Nine
|
|
Operating
Expenses and Taxes - Changes
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
costs
|
|
$
|
3
|
|
$
|
6
|
|
Purchased
power costs
|
|
|
(11
|
)
|
|
(1
|
)
|
Nuclear
operating costs
|
|
|
(2
|
)
|
|
42
|
|
Other
operating costs
|
|
|
13
|
|
|
8
|
|
Provision
for
depreciation
|
|
|
3
|
|
|
3
|
|
Amortization
of regulatory assets
|
|
|
15
|
|
|
26
|
|
Deferral
of
new regulatory assets
|
|
|
(20
|
)
|
|
(35
|
)
|
General
taxes
|
|
|
3
|
|
|
5
|
|
Income
taxes
|
|
|
3
|
|
|
14
|
|
Net
increase in operating expenses and taxes
|
|
$
|
7
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
Higher
fuel costs
in the third quarter and first nine months of 2005, compared to the same
periods
last year, were primarily due to increased fossil fuel expenses associated
with
higher fossil generation levels in 2005. Lower purchased power costs in the
third quarter of 2005, compared with the third quarter of 2004, reflected
both
lower unit costs and lower KWH purchased. The increase in nuclear operating
costs in the first nine months of 2005, compared to the same period last
year,
was primarily due to a refueling outage (including an unplanned extension)
at
the Perry Plant in 2005 and a refueling outage at Beaver Valley Unit 2. A
mid-cycle inspection outage at the Davis-Besse Plant in the first quarter
of
2005 also contributed to higher nuclear operating costs in the first nine
months
of 2005. There were no scheduled outages in the first nine months of 2004.
Higher other operating costs in the third quarter and first nine months of
2005,
compared to the same periods last year, were primarily due to transmission
expenses related to MISO Day 2 transactions that began on April 1, 2005.
Higher
regulatory
asset amortization in the third quarter and first nine months of 2005, compared
to the same periods last year, was primarily due to increased amortization
of
transition costs being recovered under the RSP. Increases in regulatory asset
deferrals for both the third quarter and first nine months in 2005, compared
to
the same periods in 2004, resulted from higher shopping incentive deferrals
and
related interest, and the PUCO-approved MISO administrative cost deferrals,
including interest, that began in the second quarter of 2005 (see Outlook
-
Regulatory Matters).
On
June 30, 2005,
the State of Ohio enacted new tax legislation that created
a new CAT tax,
which is based on qualifying “taxable gross receipts” and will not consider any
expenses or costs incurred to generate such receipts, except for items such
as
cash discounts, returns and allowances, and bad debts. The CAT tax was effective
July 1, 2005, and replaces the Ohio income-based franchise tax and
the Ohio
personal property tax. The CAT tax is phased-in while the current income-based
franchise tax is phased-out over a five-year period at a rate of 20% annually,
beginning with the year ended 2005, and personal property tax is phased-out
over
a four-year period at a rate of 25% annually, beginning with the year ended
2005. For example, during the phase-out period the Ohio income-based franchise
tax will be computed consistently with prior tax law, except that the tax
liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5
in
2007 and 1/5 in 2008, therefore eliminating the current income-based franchise
tax over a five-year period. As a result of the new tax structure, all net
deferred tax benefits that are not expected to reverse during the five-year
phase-in period were written-off as of June 30, 2005. The impact on
income
taxes associated with the new tax legislation for the first nine months of
2005
was additional tax expense of approximately $8 million to adjust net deferred
taxes and $2 million associated with the phase-out of the Ohio income-based
franchise tax. See Note 12 to the consolidated financial
statements.
Other
Income
Other
income
increased by $16 million in the third quarter of 2005 compared with the same
period of 2004, primarily due to higher nuclear decommissioning trust realized
gains.
Net
Interest
Charges
Net
interest
charges in the first nine months of 2005 decreased by $8 million compared
with
the same period last year, reflecting the effects of net redemptions and
refinancings since October 1, 2004.
Capital
Resources and Liquidity
CEI’s
cash
requirements for the remainder of 2005 for operating expenses and construction
expenditures are expected to be met without increasing net debt. Thereafter,
CEI
expects to use a combination of cash from operations and funds from the
capital
markets.
As
of September 30,
2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000
as
of December 31, 2004. The major sources of changes in these balances
are
summarized below.
Cash
Flows from
Operating Activities
Cash
provided by
operating activities during the third quarter and first nine months of 2005,
compared with the corresponding periods in 2004, were as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
161
|
|
$
|
123
|
|
$
|
274
|
|
$
|
302
|
|
Pension
trust
contribution (2)
|
|
|
--
|
|
|
(19
|
)
|
|
--
|
|
|
(19
|
)
|
Working
capital and other
|
|
|
(111
|
)
|
|
35
|
|
|
(147
|
)
|
|
10
|
|
Total
cash
flows from operating activities
|
|
$
|
50
|
|
$
|
139
|
|
$
|
127
|
|
$
|
293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash
earnings is a non-GAAP measure (see reconciliation below).
(2)
Pension
contribution net of $13 million of income tax benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings, as
disclosed in the table above, are not a measure of performance calculated
in
accordance with GAAP. CEI believes that cash earnings is a useful financial
measure because it provides investors and management with an additional means
of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
110
|
|
$
|
83
|
|
$
|
164
|
|
$
|
181
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
36
|
|
|
33
|
|
|
101
|
|
|
98
|
|
Amortization
of regulatory assets
|
|
|
68
|
|
|
54
|
|
|
177
|
|
|
152
|
|
Deferral
of
new regulatory assets
|
|
|
(60
|
)
|
|
(41
|
)
|
|
(126
|
)
|
|
(92
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
8
|
|
|
7
|
|
|
19
|
|
|
20
|
|
Amortization
of electric service obligation
|
|
|
(2
|
)
|
|
(3
|
)
|
|
(12
|
)
|
|
(13
|
)
|
Deferred
rents and lease market valuation liability
|
|
|
(13
|
)
|
|
(14
|
)
|
|
(67
|
)
|
|
(56
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
10
|
|
|
--
|
|
|
15
|
|
|
(2
|
)
|
Accrued
retirement benefit obligations
|
|
|
2
|
|
|
3
|
|
|
4
|
|
|
11
|
|
Accrued
compensation, net
|
|
|
2
|
|
|
1
|
|
|
(1
|
)
|
|
3
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
161
|
|
$
|
123
|
|
$
|
274
|
|
$
|
302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
increase in
cash earnings of $38 million for the third quarter and the decrease of $28
million for the first nine months of 2005, as compared to the respective
periods
of 2004, are described above under "Results of Operations". The primary factors
contributing to the changes in working capital and other for the third quarter
of 2005 are changes in accounts payable of $217 million, partially offset
by
changes in accrued taxes of $50 million. The primary factors contributing
to the
changes in working capital and other for the first nine months of 2005 are
changes in accounts receivable of $194 million and accounts payable of $121
million, partially offset by changes in accrued taxes of $80 million and
the $68
million received in the second quarter of 2005 for prepaid electric service
under the Ohio Schools Council’s Energy for Education Program.
Cash
Flows from
Financing Activities
Net
cash used for
financing activities decreased $46 million in the third quarter of 2005 from
the
third quarter of 2004. The decrease resulted from a $62 million decrease
in net
debt redemptions, partially offset by higher common stock dividends to
FirstEnergy of $17 million. Net
cash used for
financing activities decreased $105 million in the first nine months of 2005
from the same period last year. The decrease resulted primarily from lower
net
debt redemptions and common stock dividends to FirstEnergy and a
$75 million
equity contribution from FirstEnergy in the second quarter of 2005, partially
offset by an increase in preferred stock redemptions.
CEI
had $207,000 of
cash and temporary investments and approximately $554 million of short-term
indebtedness as of September 30, 2005. CEI has obtained authorization from
the
PUCO to incur short-term debt of up to $500 million (including the utility
money
pool described below). As of October 24, 2005, CEI had the capability to
issue
$1.6 billion of additional FMB on the basis of property additions and retired
bonds under the terms of its mortgage indenture following
the
recently completed intra-system transfer of fossil and hydroelectric generating
plants (See Note 17). The
issuance of FMB
by CEI is subject to a provision of its senior note indenture generally limiting
the incurrence of additional secured debt, subject to certain exceptions
that
would permit, among other things, the issuance of secured debt (including
FMB)
(i) supporting pollution control notes or similar obligations, or (ii) as
an
extension, renewal or replacement of previously outstanding secured debt.
In
addition, this provision would permit CEI to incur additional secured debt
not
otherwise permitted by a specified exception of up to $582 million as of
September 30, 2005. CEI has no restrictions on the issuance of preferred
stock.
CFC
is a wholly
owned subsidiary of CEI whose borrowings are secured by customer accounts
receivable purchased from CEI and TE. CFC can borrow up to $200 million under
a
receivables financing arrangement. As a separate legal entity with separate
creditors, CFC would have to satisfy its obligations to creditors before
any of
its remaining assets could be made available to CEI. As of September 30,
2005,
the facility was drawn for $35 million.
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as Borrowers, entered into a syndicated $2 billion five-year revolving credit
facility. Borrowings under the facility are available to each Borrower
separately and will mature on the earlier of 364 days from the date of borrowing
and the commitment termination date, as the same may be extended. CEI’s
borrowing limit under the facility is $250 million.
CEI
has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal amount, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and
is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the third quarter of 2005 was
3.50%.
CEI’s
access to
capital markets and costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements in
its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base load
generation fleet, low-risk transmission and distribution operations and rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also noted
as
strengths.
Cash
Flows from
Investing Activities
In
the third
quarter and first nine months of 2005, net cash used for investing activities
decreased $42 million and $86 million, respectively, from the corresponding
periods of 2004. The decrease in funds used for investing activities for
both
periods primarily reflected increases in loan payments received from associated
companies, partially offset by increased property additions.
In
the last quarter
of 2005, capital requirements for property additions are expected to be about
$37 million. These cash requirements are expected to be satisfied from internal
cash and short-term credit arrangements. CEI has no additional requirements
for
sinking fund requirements for preferred stock and debt during the remainder
of
2005. CEI’s capital spending for the period 2005-2007 is expected to be about
$368 million of which approximately $124 million applies to 2005.
FirstEnergy
Intra-System Generation Asset Transfers
On
May 18,
2005, OE, CEI and TE, entered into certain agreements implementing a series
of
intra-system generation asset transfers. When fully completed, the asset
transfers will result in the respective undivided ownership interests of
the
Ohio Companies in FirstEnergy’s nuclear and non-nuclear plants being owned by
NGC, and FGCO, respectively. The generating plant interests that are being
transferred do not include CEI’s leasehold interests in certain of the plants
that are currently subject to sale and leaseback arrangements with
non-affiliates.
On
October
24, 2005,
CEI completed the transfer of non-nuclear generation assets to FGCO. CEI
currently expects to complete the transfer
of nuclear
generation assets to NGC at book value before the end of 2005. Consummation
of
the nuclear transfer remains subject to necessary regulatory
approvals.
These
transactions
are being undertaken in connection with the Ohio Companies’ restructuring plans
that were approved by the PUCO under applicable Ohio electric utility
restructuring legislation. Consistent with the restructuring plans, generation
assets that had been owned by the Ohio Companies were required to be separated
from the regulated delivery business of those companies through transfer
to a
separate corporate entity. FENOC currently operates and maintains the nuclear
generation assets to be transferred. FGCO, as lessee under a Master Facility
Lease, leased, operated and maintained the non-nuclear generation assets
that it
now owns. The transactions will essentially complete the divestitures
contemplated by the restructuring plans by transferring the ownership interests
to NGC and FGCO, respectively, without impacting the operation of the plants.
See
Note 17 to the
consolidated financial statements for CEI’s disclosure of the assets held for
sale as of September 30, 2005.
Off-Balance
Sheet Arrangements
Obligations
not
included on CEI’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant. As of September
30,
2005, the present value of these operating lease commitments, net of trust
investments, total $103 million.
CEI
sells
substantially all of its retail customer receivables to CFC, its wholly owned
subsidiary. As of June 16, 2005, the CFC receivables financing structure
was renewed and restructured from an off-balance sheet transaction to an
on-balance sheet transaction. Under the new structure, any borrowings under
the
facility appear on the balance sheet as short-term debt.
Equity
Price Risk
Included
in CEI’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $277 million and $242 million
as
of September 30, 2005 and December 31, 2004, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $28 million
reduction in fair value as of September 30, 2005.
Outlook
The
electric
industry continues to transition to a more competitive environment and all
of
CEI's customers can select alternative energy suppliers. CEI continues to
deliver power to residential homes and businesses through its existing
distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. CEI has
a
continuing responsibility to provide power to those customers not choosing
to
receive power from an alternative energy supplier subject to certain limits.
Regulatory
Matters
In
2001, Ohio
customer rates were restructured to establish separate charges for transmission,
distribution, transition cost recovery and a generation-related component.
When
one of CEI's customers elects to obtain power from an alternative supplier,
CEI
reduces the customer's bill with a "generation shopping credit," based on
the
generation component (plus an incentive), and the customer receives a generation
charge from the alternative supplier. CEI has continuing PLR responsibility
to
its franchise customers through December 31, 2008 unless the PUCO
accepts
future competitive bid results prior to the end of that period under the
revised
RSP.
As
part of CEI's
transition plan, it is obligated to supply electricity to customers who do
not
choose an alternative supplier. CEI is also required to provide 400 MW of
low
cost supply (MSG) to unaffiliated alternative suppliers who serve customers
within its service area. FES acts as an alternate supplier for a portion
of the
load in CEI's franchise area.
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 competitive
bid
process. The RSP was filed by the Ohio Companies to establish generation
service
rates beginning January 1, 2006, in response to PUCO concerns about
price
and supply uncertainty following the end of the Ohio Companies' transition
plan
market development period. In October 2004, the OCC and NOAC filed appeals
with
the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO
order
in this proceeding as well as the associated entries on rehearing. On
September 28, 2005, the Ohio Supreme Court heard oral argument on
the
appeals.
On
May 27,
2005, CEI filed an application with the PUCO to establish a GCAF rider under
the
RSP. The application seeks to implement recovery of increased fuel costs
from
2006 through 2008 applicable to CEI’s retail customers through a tariff rider to
be implemented January 1, 2006. The application reflects projected
increases in fuel costs in 2006 compared to 2002 baseline costs. The new
rider,
after adjustments made in testimony, is seeking to recover all costs above
the
baseline (approximately $88 million in 2006 for all of the Ohio Companies).
Various parties including the OCC have intervened in this case and the case
has
been consolidated with the RCP application discussed below.
On
September 9,
2005, CEI filed an application with the PUCO that, if approved, would supplement
its existing RSP with an RCP. On September 27, 2005, the PUCO granted
FirstEnergy's motion to consolidate the GCAF rider application with the RCP
proceedings and set hearings for the consolidated cases to begin
November 29, 2005. The RCP is designed to provide customers with more
certain rate levels than otherwise available under the RSP during the plan
period. Major provisions of the RCP include:
· Maintain
the
existing level of base distribution rates through April 30, 2009 for
CEI;
· Defer
and
capitalize certain distribution costs to be incurred by all of the Ohio
Companies during the
period
January 1, 2006 through December 31, 2008, not to exceed $150
million
in each of the three
years;
· Adjust
the RTC and
extended RTC recovery periods and rate levels so that full recovery of
authorized
costs
will occur as
of December 31, 2010 for CEI;
· Reduce
the deferred
shopping incentive balances as of January 1, 2006 by up to $85 million
for
CEI
by
accelerating the
application of its accumulated cost of removal regulatory liability;
and
· Defer
and
capitalize all of CEI's allowable fuel cost increases until January 1,
2009.
Under
provisions of
the RSP, the PUCO may require CEI to undertake, no more often than annually,
a
competitive bid process to secure generation for the years 2007 and 2008.
On
July 22, 2005, FirstEnergy filed a competitive bid process for the
period
beginning in 2007 that is similar to the competitive bid process approved
by the
PUCO for CEI in 2004, which resulted in the PUCO accepting no bids. Any
acceptance of future competitive bid results would terminate the RSP pricing,
with no accounting impacts to the RSP, and not until twelve months after
the
PUCO authorizes such termination. On September 28, 2005, the PUCO
issued an
Entry that essentially approved the Ohio Companies' filing but delayed the
proposed timing of the competitive bid process by four months, calling for
the
auction to be held on March 21, 2006.
On
December 30, 2004, CEI filed with the PUCO two applications related
to the
recovery of transmission and ancillary service related costs. The first
application seeks recovery of these costs beginning January 1, 2006.
At the
time of filing the application, these costs were estimated to be approximately
$16
million per year; however,
CEI anticipates
that this amount will increase. CEI requested that these costs be recovered
through a rider that would be effective on January 1, 2006 and adjusted
each July 1 thereafter. CEI reached a settlement with OCC, PUCO staff,
Industrial Energy Users - Ohio and OPAE. The only other party in this
proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This
settlement, which was filed with the PUCO on July 22, 2005, provides
for
the rider recovery requested by CEI, with carrying charges applied in the
subsequent year’s rider for any over or under collection while the then-current
rider is in effect. The PUCO approved the settlement stipulation on
August 31, 2005. The incremental Transmission and Ancillary service
revenues expected to be recovered from January through June 2006 are
approximately $23.9 million.
This value
includes the recovery of the 2005 deferred MISO expenses as described below.
In
May 2006, CEI will file a modification to the rider which will determine
revenues from July 2006 through June 2007.
The
second
application sought authority to defer costs associated with transmission
and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO granted
the
accounting authority for CEI to defer incremental transmission and ancillary
service-related charges incurred as a participant in MISO, but only for those
costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 30, 2004 was denied. The PUCO also authorized CEI to accrue
carrying charges on the deferred balances. An application filed with the
PUCO to
recover these deferred charges over a five-year period through the rider,
beginning in 2006, was approved in a PUCO order issued on August 31,
2005,
approving the stipulation referred to above. The OCC, OPAE and CEI each filed
applications for rehearing. CEI sought authority to defer the transmission
and
ancillary service-related costs incurred during the period October 1,
2003
through December 29, 2004, while both OCC and OPAE sought to have
the PUCO
deny deferral of all costs. On July 6, 2005, the PUCO denied CEI’s and
OCC’s applications and, at the request of CEI, struck as untimely OPAE’s
application. The OCC filed a notice of appeal with the Ohio Supreme Court
on
August 31, 2005. On
September 30,
2005, in accordance with appellate procedure, the PUCO filed with the Ohio
Supreme Court the record in this case. The Companies' brief will be due thirty
days after the OCC files its brief, which, absent any time extensions, must
be
filed no later than November 9, 2005.
CEI
records as
regulatory assets costs which have been authorized by the PUCO and the FERC
for
recovery from
customers in
future periods and, without such authorization, the costs would have been
charged to income when incurred. CEI's regulatory assets as of September
30,
2005 and December 2004 were $0.9 billion and $1.0 billion, respectively.
CEI is
deferring customer shopping incentives and interest costs as new regulatory
assets in accordance with its transition and rate stabilization plans. These
regulatory assets total $402 million as of September 30, 2005 and under the
RSP,
will be recovered through a surcharge rate equal to the RTC rate in effect
when
the transition costs have been fully recovered. See Note 14 “Regulatory Matters
- Ohio” for the estimated net amortization of regulatory transition costs and
deferred shopping incentive balances under the proposed RCP and current
RSP.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.
Environmental
Matters
CEI
accrues
environmental liabilities only when it concludes 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 CEI’s determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by
December 1,
2005.
National
Ambient Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for
fine
particulate matter. On March 10, 2005, the EPA finalized the "Clean
Air
Interstate Rule" covering a total of 28 states (including 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
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS
in
other states. CAIR provides each affected state until 2006 to develop
implementing regulation 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)
in all cases from
the 2003 levels. CEI's Ohio and Pennsylvania fossil-fuel generation facilities
will be subject to the caps on SO2
and 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 CEI 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. On March 14, 2005, the
EPA
finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade
program to reduce mercury emissions from coal-fired power plants in two phases.
Initially, mercury emissions will be capped nationally at 38 tons by 2010
as a
"co-benefit" from implementation of SO2
and NOx
emission caps
under the EPA's CAIR program. Phase II of the mercury cap-and-trade program
will
cap nationwide mercury emissions from coal-fired power plants at 15 tons
per
year by 2018. However,
the final
rules give states substantial discretion in developing rules to implement
these programs. In addition, both the CAIR and the Clean Air Mercury rule
have
been challenged in the United States Court of Appeals for the District of
Columbia. Future cost of compliance with these regulations may be
substantial.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (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 Protocol in 1998 but it failed
to
receive the two-thirds vote of the United States Senate required for
ratification. However, the Bush administration has committed the United States
to a voluntary climate change strategy to reduce domestic GHG intensity -
the
ratio of emissions to economic output - by 18 percent through 2012. The Energy
Policy Act of 2005 established a Committee on Climate Change Technology to
coordinate federal climate change activities and promote the development
and
deployment of GHG reducing technologies.
CEI
cannot
currently estimate the financial impact of climate change policies, although
the
potential restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per KWH
of electricity generated by CEI is lower than many regional competitors due
to
CEI's diversified generation sources which include low or non-CO2
emitting gas-fired
and nuclear generators.
Regulation
of
Hazardous Waste
CEI
has been named
a PRP at waste disposal sites, which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations
of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site are liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of September 30, 2005,
based on estimates of the total costs of cleanup, CEI's proportionate
responsibility for such costs and the financial ability of other nonaffiliated
entities to pay. Included in Other Noncurrent Liabilities are accrued
liabilities aggregating approximately $2.3 million as of September
30,
2005.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to CEI's normal business operations pending against CEI and its
subsidiaries. The other material items not otherwise discussed above are
described below.
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 concludes, 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 website (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 also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as of September
30, 2005 for any expenditures in excess of those actually incurred through
that
date. FirstEnergy notes, however, that FERC or other applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the
future
that could require additional, material expenditures. Finally, the PUCO is
continuing to review FirstEnergy’s filing that addressed upgrades to control
room computer hardware and software and enhancements to the training of control
room operators, before determining the next steps, if any, in the
proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two such cases were
originally filed in Ohio State courts but subsequently dismissed for lack
of
subject matter jurisdiction and further appeals were unsuccessful. In both
such
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. Of the four other pending PUCO complaint cases, three were filed
by
various insurance carriers either in their own name or as subrogees in the
name
of their insureds. In each such case, the carriers seek reimbursement against
various FirstEnergy companies (and, in one case, against PJM, MISO and American
Electric Power Co. as well) for claims they paid to their insureds allegedly
due
to the loss of power on August 14, 2003. The listed insureds in these cases,
in
many instances, are not customers of any FirstEnergy company. The fourth
case
involves the claim of a non-customer seeking reimbursement for losses incurred
when its store was burglarized on August 14, 2003. In addition to these six
cases, the Ohio Companies were named as respondents in a regulatory proceeding
that was initiated at the PUCO in response to complaints alleging failure
to
provide reasonable and adequate service stemming primarily from the
August 14, 2003 power
outages. No
estimate of potential liability has been undertaken for any of these cases.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14, 2003
power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. In particular, if FirstEnergy or
its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition, results of operations and cash
flows.
FENOC
received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station,
in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy
received a letter from the United States Attorney's Office stating that FENOC
is
a target of the federal grand jury investigation into alleged false statements
made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01.
The
letter also said that the designation of FENOC as a target indicates that,
in
the view of the prosecutors assigned to the matter, it is likely that federal
charges will be returned against FENOC by the grand jury. On February 10,
2005, FENOC received an additional subpoena for documents related to root
cause
reports regarding reactor head degradation and the assessment of reactor
head
management issues at Davis-Besse. On May 11, 2005, FENOC received
a
subpoena for documents related to outside meetings attended by Davis-Besse
personnel on corrosion and cracking of control rod drive mechanisms and
additional root cause evaluations.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related
to
the degradation of the Davis-Besse reactor vessel head issue described above.
CEI accrued $1.0 million for a potential fine prior to 2005 and accrued the
remaining liability for its share of the proposed fine of $1.8 million during
the first quarter of 2005. On September 14, 2005, FENOC filed its
response
to the NOV with the NRC. FENOC accepted full responsibility for the past
failure
to properly implement its boric acid corrosion control and corrective action
programs. The NRC NOV indicated that the violations do not represent current
licensee performance. FirstEnergy paid the penalty in the third quarter of
2005.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
based on the events surrounding Davis-Besse, it could have a material adverse
effect on FirstEnergy's or its subsidiaries' financial condition, results
of
operations and cash flows.
Effective
July 1, 2005 the NRC oversight panel for Davis-Besse was terminated
and
Davis-Besse returned to the standard NRC reactor oversight process. At that
time, NRC inspections were augmented to include inspections to support the
NRC's
Confirmatory Order dated March 8, 2004 that was issued at the time
of
startup and to address an NRC White Finding related to emergency
sirens.
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 effective corrective action. FENOC operates the Perry Nuclear Power Plant,
in which CEI has a 44.85% interest (however, see Note 17 regarding FirstEnergy’s
pending intra-system generation asset transfers, which include owned portions
of
the plant).
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the
NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to
be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action
Matrix.
On
May 26,
2005, the NRC held a public meeting to discuss its oversight of the Perry
Plant.
While the NRC stated that the plant continued to operate safely, the NRC
also
stated that the overall performance had not substantially improved since
the
heightened inspection was initiated. The NRC reiterated this conclusion
in its
mid-year assessment letter dated August 30, 2005. On September 28,
2005, the NRC sent a CAL to FENOC describing commitments that FENOC had
made to
improve the performance of Perry 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. If performance does not improve, the NRC
has a
range of options under the Reactor Oversight Process, from increased oversight
to possible impact to the plant’s operating authority. As a result, these
matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed
informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and CEI, and the Davis-Besse extended outage, have become the
subject of a formal order of investigation. The SEC's formal order of
investigation also encompasses issues raised during the SEC's examination
of
FirstEnergy and the Companies under the PUHCA. Concurrent with this
notification, FirstEnergy received a subpoena asking for background documents
and documents related to the restatements and Davis-Besse issues. On
December 30, 2004, FirstEnergy received a subpoena asking for documents
relating to issues raised during the SEC's PUHCA examination. On August 24,
2005 additional information was requested regarding Davis Besse. FirstEnergy
has
cooperated fully with the informal inquiry and will continue to do so with
the
formal investigation.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of
a newly
formed municipal electric utility. The complaint was filed on May 28,
2003,
and OE timely filed its response on June 30, 2003. In a related
filing, the
Ohio Companies filed for approval with the PUCO of a tariff that would
specifically allow the collection of transition charges from customers
of
municipal electric utilities formed after 1998. An
adverse ruling
could negatively affect full recovery of transition charges by CEI. Hearings
on
the matter were held in August 2005. Initial briefs from all parties were
filed
on September 22, 2005 and reply briefs were filed on October 14,
2005.
It is unknown when the PUCO will rule on this case.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters,
it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or
more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the
EITF
reached a consensus that an exchange of inventory should be accounted for
at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, CEI will adopt this EITF effective
for
new arrangements entered into, or modifications or renewals of existing
arrangements, in interim or annual periods beginning after March 15, 2006.
|
EITF
Issue No. 05-6, "Determining the Amortization Period for Leasehold
Improvements Purchased after Lease Inception or Acquired in a
Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6. EITF
05-6
addresses the amortization period for leasehold improvements that were
either
acquired in a business combination or placed in service significantly after
and
not contemplated at or near the beginning of the initial lease term. For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that includes
required lease periods and renewals that are deemed to be reasonably assured
at
the date of acquisition. Leasehold improvements that are placed in service
significantly after and not contemplated at or near the beginning of the
lease
term should be amortized over the shorter of the useful life of the assets
or a
term that includes required lease periods and renewals that are deemed
to be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with CEI’s current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective for CEI in the fourth quarter of 2005. CEI
is
currently evaluating the effect this Interpretation will have on its financial
statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement of APB
Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and reporting
a
change in accounting principle. It applies to all voluntary changes in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions. This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of
the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings (or other appropriate components of equity or net assets
in
the statement of financial position) for that period rather than being reported
in the Consolidated Statements of Income. This Statement also requires that
a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate affected
by a change in accounting principle. The provisions of this Statement are
effective for accounting changes and corrections of errors made in fiscal
years
beginning after December 15, 2005. CEI will adopt this Statement effective
January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows of
the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for CEI.
This
FSP is not expected to have a material impact on CEI’s financial
statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of
idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be “so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective
for
inventory costs incurred by CEI beginning January 1, 2006. CEI is
currently
evaluating this Standard and does not expect it to have a material impact
on its
financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application to Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security Whose
Cost
Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
loss no later than when the impairment is deemed other than temporary, even
if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP in the
fourth
quarter of 2005, which would require prospective application with an effective
date for reporting periods beginning after December 15, 2005. CEI is currently
evaluating this FSP and any impact on its investments.
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
286,960
|
|
$
|
276,342
|
|
$
|
787,824
|
|
$
|
755,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
16,501
|
|
|
13,908
|
|
|
43,474
|
|
|
37,195
|
|
Purchased
power
|
|
|
73,144
|
|
|
79,774
|
|
|
225,600
|
|
|
236,869
|
|
Nuclear
operating costs
|
|
|
39,207
|
|
|
43,827
|
|
|
145,059
|
|
|
122,685
|
|
Other
operating costs
|
|
|
48,164
|
|
|
43,865
|
|
|
123,823
|
|
|
121,228
|
|
Provision
for
depreciation
|
|
|
18,835
|
|
|
14,588
|
|
|
48,724
|
|
|
43,021
|
|
Amortization
of regulatory assets
|
|
|
39,576
|
|
|
41,037
|
|
|
107,672
|
|
|
102,065
|
|
Deferral
of
new regulatory assets
|
|
|
(19,379
|
)
|
|
(12,442
|
)
|
|
(41,473
|
)
|
|
(29,664
|
)
|
General
taxes
|
|
|
14,159
|
|
|
14,924
|
|
|
41,960
|
|
|
41,252
|
|
Income
taxes
|
|
|
20,311
|
|
|
11,963
|
|
|
44,160
|
|
|
18,465
|
|
Total
operating expenses and taxes
|
|
|
250,518
|
|
|
251,444
|
|
|
738,999
|
|
|
693,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
36,442
|
|
|
24,898
|
|
|
48,825
|
|
|
61,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
12,283
|
|
|
4,172
|
|
|
18,173
|
|
|
14,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
|
3,912
|
|
|
4,015
|
|
|
12,655
|
|
|
23,057
|
|
Allowance
for
borrowed funds used during construction
|
|
|
(372
|
)
|
|
(741
|
)
|
|
(117
|
)
|
|
(2,843
|
)
|
Other
interest expense
|
|
|
2,958
|
|
|
1,350
|
|
|
4,192
|
|
|
2,945
|
|
Net
interest
charges
|
|
|
6,498
|
|
|
4,624
|
|
|
16,730
|
|
|
23,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
42,227
|
|
|
24,446
|
|
|
50,268
|
|
|
53,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
1,687
|
|
|
2,211
|
|
|
6,109
|
|
|
6,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
40,540
|
|
$
|
22,235
|
|
$
|
44,159
|
|
$
|
46,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
42,227
|
|
$
|
24,446
|
|
$
|
50,268
|
|
$
|
53,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on available for sale securities
|
|
|
(4,511
|
)
|
|
913
|
|
|
(6,695
|
)
|
|
(379
|
)
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
|
(1,743
|
)
|
|
375
|
|
|
(2,534
|
)
|
|
(155
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
(2,768
|
)
|
|
538
|
|
|
(4,161
|
)
|
|
(224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
39,459
|
|
$
|
24,984
|
|
$
|
46,107
|
|
$
|
53,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Toledo
Edison Company are an integral part of these
statements.
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
1,906,941
|
|
$
|
1,856,478
|
|
Less
-
Accumulated provision for depreciation
|
|
|
820,562
|
|
|
778,864
|
|
|
|
|
1,086,379
|
|
|
1,077,614
|
|
Construction
work in progress -
|
|
|
|
|
|
|
|
Electric
plant
|
|
|
55,376
|
|
|
58,535
|
|
Nuclear
fuel
|
|
|
7,370
|
|
|
15,998
|
|
|
|
|
62,746
|
|
|
74,533
|
|
|
|
|
1,149,125
|
|
|
1,152,147
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Investment
in
lessor notes
|
|
|
178,765
|
|
|
190,692
|
|
Nuclear
plant
decommissioning trusts
|
|
|
335,553
|
|
|
297,803
|
|
Long-term
notes receivable from associated companies
|
|
|
39,964
|
|
|
39,975
|
|
Other
|
|
|
1,741
|
|
|
2,031
|
|
|
|
|
556,023
|
|
|
530,501
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
15
|
|
|
15
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provision of $2,000 for
|
|
|
|
|
|
|
|
uncollectible
accounts in 2004)
|
|
|
2,412
|
|
|
4,858
|
|
Associated
companies
|
|
|
10,168
|
|
|
36,570
|
|
Other
|
|
|
8,658
|
|
|
3,842
|
|
Notes
receivable from associated companies
|
|
|
52,639
|
|
|
135,683
|
|
Materials
and
supplies, at average cost
|
|
|
42,404
|
|
|
40,280
|
|
Prepayments
and other
|
|
|
1,712
|
|
|
1,150
|
|
|
|
|
118,008
|
|
|
222,398
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
501,022
|
|
|
504,522
|
|
Regulatory
assets
|
|
|
309,835
|
|
|
374,814
|
|
Property
taxes
|
|
|
24,100
|
|
|
24,100
|
|
Other
|
|
|
26,520
|
|
|
25,424
|
|
|
|
|
861,477
|
|
|
928,860
|
|
|
|
$
|
2,684,633
|
|
$
|
2,833,906
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
Common
stock,
$5 par value, authorized 60,000,000 shares -
|
|
|
|
|
|
|
|
39,133,887
shares outstanding
|
|
$
|
195,670
|
|
$
|
195,670
|
|
Other
paid-in
capital
|
|
|
428,572
|
|
|
428,559
|
|
Accumulated
other comprehensive income
|
|
|
15,878
|
|
|
20,039
|
|
Retained
earnings
|
|
|
225,218
|
|
|
191,059
|
|
Total
common
stockholder's equity
|
|
|
865,338
|
|
|
835,327
|
|
Preferred
stock
|
|
|
96,000
|
|
|
126,000
|
|
Long-term
debt
|
|
|
296,373
|
|
|
300,299
|
|
|
|
|
1,257,711
|
|
|
1,261,626
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
53,650
|
|
|
90,950
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
28,456
|
|
|
110,047
|
|
Other
|
|
|
3,252
|
|
|
2,247
|
|
Notes
payable
to associated companies
|
|
|
378,190
|
|
|
429,517
|
|
Accrued
taxes
|
|
|
72,214
|
|
|
46,957
|
|
Lease
market
valuation liability
|
|
|
24,600
|
|
|
24,600
|
|
Other
|
|
|
28,735
|
|
|
53,055
|
|
|
|
|
589,097
|
|
|
757,373
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
222,985
|
|
|
221,950
|
|
Accumulated
deferred investment tax credits
|
|
|
24,697
|
|
|
25,102
|
|
Lease
market
valuation liability
|
|
|
249,550
|
|
|
268,000
|
|
Retirement
benefits
|
|
|
42,998
|
|
|
39,227
|
|
Asset
retirement obligation
|
|
|
200,078
|
|
|
194,315
|
|
Other
|
|
|
97,517
|
|
|
66,313
|
|
|
|
|
837,825
|
|
|
814,907
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
2,684,633
|
|
$
|
2,833,906
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
The Toledo
Edison Company are an integral part of these blance sheets.
|
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
42,227
|
|
$
|
24,446
|
|
$
|
50,268
|
|
$
|
53,555
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
18,835
|
|
|
14,588
|
|
|
48,724
|
|
|
43,021
|
|
Amortization
of regulatory assets
|
|
|
39,576
|
|
|
41,037
|
|
|
107,672
|
|
|
102,065
|
|
Deferral
of
new regulatory assets
|
|
|
(19,379
|
)
|
|
(12,442
|
)
|
|
(41,473
|
)
|
|
(29,664
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
5,682
|
|
|
7,058
|
|
|
13,816
|
|
|
17,596
|
|
Amortization
of electric service obligation
|
|
|
(1,910
|
)
|
|
-
|
|
|
(3,301
|
)
|
|
-
|
|
Deferred
rents and lease market valuation liability
|
|
|
10,310
|
|
|
9,689
|
|
|
(34,156
|
)
|
|
(26,585
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(12,798
|
)
|
|
(4,608
|
)
|
|
(4,605
|
)
|
|
(9,290
|
)
|
Accrued
retirement benefit obligations
|
|
|
1,534
|
|
|
1,324
|
|
|
3,771
|
|
|
4,733
|
|
Accrued
compensation, net
|
|
|
404
|
|
|
516
|
|
|
(333
|
)
|
|
1,477
|
|
Pension
trust
contribution
|
|
|
-
|
|
|
(12,572
|
)
|
|
-
|
|
|
(12,572
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
3,423
|
|
|
69,908
|
|
|
15,962
|
|
|
95,383
|
|
Materials
and
supplies
|
|
|
3,788
|
|
|
(725
|
)
|
|
(2,124
|
)
|
|
(4,376
|
)
|
Prepayments
and other current assets
|
|
|
(970
|
)
|
|
677
|
|
|
(562
|
)
|
|
5,971
|
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(6,215
|
)
|
|
6,202
|
|
|
(80,586
|
)
|
|
(9,568
|
)
|
Accrued
taxes
|
|
|
14,748
|
|
|
(3,508
|
)
|
|
25,257
|
|
|
227
|
|
Accrued
interest
|
|
|
(369
|
)
|
|
(7,169
|
)
|
|
(565
|
)
|
|
(7,540
|
)
|
Prepayment
for electric service -- education programs
|
|
|
-
|
|
|
-
|
|
|
37,954
|
|
|
-
|
|
Other
|
|
|
(14,392
|
)
|
|
(10,020
|
)
|
|
(22,999
|
)
|
|
(9,679
|
)
|
Net
cash
provided from operating activities
|
|
|
84,494
|
|
|
124,401
|
|
|
112,720
|
|
|
214,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
30,500
|
|
|
45,000
|
|
|
103,500
|
|
Short-term
borrowings, net
|
|
|
45,054
|
|
|
146,370
|
|
|
-
|
|
|
29,310
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
(30,000
|
)
|
|
-
|
|
|
(30,000
|
)
|
|
-
|
|
Long-term
debt
|
|
|
(36,821
|
)
|
|
(246,591
|
)
|
|
(83,754
|
)
|
|
(261,591
|
)
|
Short-term
borrowings, net
|
|
|
-
|
|
|
-
|
|
|
(51,327
|
)
|
|
-
|
|
Dividend
Payments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
-
|
|
|
(10,000
|
)
|
|
-
|
|
Preferred
stock
|
|
|
(1,687
|
)
|
|
(2,211
|
)
|
|
(6,109
|
)
|
|
(6,633
|
)
|
Net
cash used
for financing activities
|
|
|
(23,454
|
)
|
|
(71,932
|
)
|
|
(136,190
|
)
|
|
(135,414
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(17,951
|
)
|
|
(16,950
|
)
|
|
(50,119
|
)
|
|
(36,377
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(36,490
|
)
|
|
(20,389
|
)
|
|
83,055
|
|
|
(21,046
|
)
|
Investments
in lessor notes
|
|
|
32
|
|
|
-
|
|
|
11,927
|
|
|
10,280
|
|
Contributions
to nuclear decommissioning trusts
|
|
|
(7,135
|
)
|
|
(7,135
|
)
|
|
(21,406
|
)
|
|
(21,406
|
)
|
Other
|
|
|
504
|
|
|
(7,995
|
)
|
|
13
|
|
|
(13,013
|
)
|
Net
cash
provided from (used for) investing activities
|
|
|
(61,040
|
)
|
|
(52,469
|
)
|
|
23,470
|
|
|
(81,562
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(2,222
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
15
|
|
|
15
|
|
|
15
|
|
|
2,237
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
15
|
|
$
|
15
|
|
$
|
15
|
|
$
|
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 Stockholders
and Board of
Directors
of The
Toledo Edison Company:
We
have reviewed
the accompanying consolidated balance sheet of The Toledo Edison Company
and its
subsidiary as of September 30, 2005, and the related consolidated
statements of income and comprehensive income and cash flows for each of
the
three-month and nine-month periods ended September 30, 2005 and
2004. 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, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note
2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
THE
TOLEDO
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
TE
is a wholly
owned electric utility subsidiary of FirstEnergy. TE conducts business
in
northwestern Ohio, providing regulated electric distribution services.
TE also
provides generation services to those customers electing to retain TE as
their
power supplier. TE provides power directly to some alternative energy suppliers
under TE’s transition plan. TE has unbundled the price of electricity into its
component elements - including generation, transmission, distribution and
transition charges. TE’s power supply requirements are provided by FES - an
affiliated company.
Results
of Operations
Earnings
on common
stock in the third quarter of 2005 increased to $41 million from $22 million
in
the third quarter of 2004. The increase in earnings resulted primarily
from
higher operating revenues and other income, partially offset by increased
financing costs. Earnings
on common
stock in the first
nine
months
of 2005 decreased to $44
million from
$47
million in the
first nine months of 2004. The decrease in earnings resulted primarily
from
higher nuclear operating costs and a one-time income tax charge, partially
offset by higher operating revenues and lower financing costs.
Operating
revenues
increased by $11 million, or 3.8%, in the third quarter of 2005 compared
to the
third quarter of 2004. Higher revenues in the third quarter of 2005 resulted
from increased retail generation revenues of $13 million and distribution
revenues of $2 million, partially offset by a decrease in wholesales sales
(primarily to FES) of $4 million and an increase in shopping incentive
credits
of $1 million. Retail generation revenues increased as a result of increased
KWH
sales (residential - $1 million, commercial - $1 million and industrial
- $11
million). Higher residential and commercial revenues reflected increased
KWH
sales (8.0% and 9.2%, respectively) and higher unit prices. KWH sales to
residential and commercial customers increased primarily due to warmer
weather
which increased air-conditioning loads. Additionally, generation services
provided to commercial customers by alternative suppliers as a percent
of total
commercial sales delivered in TE’s service area decreased by 2.1 percentage
points compared with the third quarter of 2004. Industrial revenues increased
as
a result of higher unit prices and a 4.2% increase in KWH sales.
Revenues
from
distribution throughput increased by $2 million in the third quarter of
2005
from the corresponding quarter of 2004. The increase was due to higher
residential and commercial revenues ($8 million and $0.2 million,
respectively), partially offset by a decrease in industrial revenues ($7
million). The impact of higher residential and commercial KWH sales contributed
to the increase; lower industrial unit prices more than offset an increase
in
KWH sales to industrial customers.
Operating
revenues
increased by $33 million, or 4.3%, in the first nine months of 2005 compared
to
the same period of 2004. The higher revenues resulted from increased retail
generation revenues of $35 million and wholesales sales of $2 million,
partially
offset by an increase in shopping incentive credits of $3 million. Retail
generation revenues increased as a result of higher KWH sales (residential
- $2
million, commercial - $4 million, industrial - $29 million). Higher residential
and commercial revenues reflected increased KWH sales (6.9% and 12.2%,
respectively) and higher unit prices. Residential and commercial sales
volumes
increased primarily due to warmer weather. The increase in commercial revenues
also reflects a reduction by 2.5 percentage points in customer shopping
compared
with the same period of 2004. Industrial revenues increased as a result
of
higher unit prices and a 0.6% increase in KWH sales.
Revenues
from
distribution throughput decreased by $0.4 million in the first nine months
of
2005 from the same period in 2004. The decrease was due to lower industrial
revenues ($22 million), partially offset by increases in residential and
commercial revenues ($15 million and $6 million, respectively). The impact
from
lower industrial unit prices more than offset the higher KWH sales in all
customer classes.
Under
the Ohio
transition plan, TE provides incentives to customers to encourage switching
to
alternative energy providers. TE’s revenues were reduced by $1 million from
additional credits in the third quarter and $3 million in the first nine
months
of 2005 compared with the same periods of 2004. These revenue reductions
are
deferred for future recovery under TE’s transition plan and do not affect
current period earnings (see Regulatory Matters below).
Changes
in KWH
sales by customer class in the three months and nine months ended
September 30, 2005 from the corresponding periods of 2004, are summarized
in the following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
6.0
|
%
|
|
3.9
|
%
|
Wholesale
|
|
|
3.5
|
%
|
|
3.4
|
%
|
Total
Electric Generation Sales
|
|
|
4.6
|
%
|
|
3.7
|
%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
16.7
|
%
|
|
12.0
|
%
|
Commercial
|
|
|
4.7
|
%
|
|
6.8
|
%
|
Industrial
|
|
|
4.8
|
%
|
|
1.2
|
%
|
Total
Distribution Deliveries
|
|
|
7.7
|
%
|
|
5.3
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes decreased $1 million in the third quarter and increased
$46
million in the first nine months of 2005 from the same periods in 2004.
The
following table presents changes from the prior year by expense category.
|
|
Three
|
|
Nine
|
|
Operating
Expenses and Taxes - Changes
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
(In
millions)
|
|
Fuel
costs
|
|
$
|
3
|
|
$
|
6
|
|
Purchased
power costs
|
|
|
(7
|
)
|
|
(11
|
)
|
Nuclear
operating costs
|
|
|
(4
|
)
|
|
22
|
|
Other
operating costs
|
|
|
4
|
|
|
3
|
|
Provision
for
depreciation
|
|
|
4
|
|
|
6
|
|
Amortization
of regulatory assets
|
|
|
(1
|
)
|
|
6
|
|
Deferral
of
new regulatory assets
|
|
|
(7
|
)
|
|
(12
|
)
|
General
taxes
|
|
|
(1
|
)
|
|
1
|
|
Income
taxes
|
|
|
8
|
|
|
25
|
|
Net
increase (decrease) in operating expenses and
taxes
|
|
$
|
(1
|
)
|
$
|
46
|
|
|
|
|
|
|
|
|
|
Higher
fuel costs
in the third quarter and first nine months of 2005, compared with the same
periods of 2004, resulted primarily from increased fossil-fired generation
from
the Mansfield Plant, up 5.7% and 7.1% during the respective periods. Purchased
power costs decreased in both periods due to lower unit costs and reduced
KWH
purchases. Nuclear operating costs decreased in the third quarter of 2005
primarily from lower employee benefit costs and operating expenses for
the
nuclear generating units. Nuclear operating costs increased in the nine-month
period due to a scheduled refueling outage (including an unplanned extension)
at
the Perry Plant, a mid-cycle inspection outage at the Davis-Besse Plant
during
the first quarter of 2005, and the Beaver Valley Unit 2 refueling outage
in the
second quarter of 2005, compared to no scheduled outages in the first nine
months of 2004. Other operating costs increased in both periods of 2005
compared
to the same periods of 2004 primarily because of MISO Day 2 expenses that
began
on April 1, 2005, partially offset by lower Beaver Valley Unit 2
letter of
credit fees, insurance settlements and lower employee benefits
costs.
Depreciation
charges increased by $4 million in the third quarter and $6 million in
first
nine months of 2005 compared to the same periods of 2004 primarily due
to
property additions and reduced amortization periods for expenditures on
leased
generating plants to conform to the lease terms. These increases were partially
offset by the effect of revised service life assumptions for fossil generating
plants (See Note 3). Regulatory asset amortization increased in the first
nine
months of 2005 due to the increased amortization of transition costs being
recovered under the RSP. Deferrals of new regulatory assets increased in
the
third quarter and first nine months of 2005 compared to the same periods
of
2004, primarily due to higher shopping incentives and related interest
($2
million and $5 million, respectively) and the deferral of the PUCO-approved
MISO
administrative expenses and related interest ($5 million and $6 million,
respectively).
On
June 30,
2005, the State of Ohio enacted new tax legislation that created a new
CAT tax,
which is based on qualifying “taxable gross receipts” and will not consider any
expenses or costs incurred to generate such receipts, except for items
such as
cash discounts, returns and allowances, and bad debts. The CAT tax is effective
July 1, 2005, and replaces the Ohio income-based franchise tax and
the Ohio
personal property tax. The CAT tax is phased-in while the current income-based
franchise tax is phased-out over a five-year period at a rate of 20% annually,
beginning with the year ended 2005, and personal property tax is phased-out
over
a four-year period at a rate of approximately 25%, annually beginning with
the
year ended 2005. For example, during the phase-out period the Ohio income-based
franchise tax will be computed consistently with the prior tax law, except
that
the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in
2006;
2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based
franchise tax over a five-year period. As a result of the new tax structure,
all
net deferred tax benefits that are not expected to reverse during the five-year
phase-in period were written-off as of June 30, 2005. The impact
on income
taxes associated with the required adjustment to net deferred taxes for
the nine
months ended September 30, 2005 was additional tax expense of $17.5
million, which was partially offset by the phase-out of the Ohio income
tax
which reduced income taxes by $0.7 million in the third quarter of 2005
and $1.2
million for the nine months ended September 30, 2005. See Note 12
to the
consolidated financial statements.
Other
Income
Other
income
increased by $8 million in the third quarter of 2005 and $3 million in
the first
nine months of 2005 compared with the same periods of 2004, primarily due
to
higher nuclear decommissioning trust realized gains, partially offset by
lower
interest income earned on associated company notes receivable that were
repaid
in May 2005. Additionally, the recognition of a $1.6 million NRC fine related
to
the Davis-Besse Plant (see Outlook - Other Legal Proceedings) during the
first
quarter of 2005 partially offset the increase in other income during the
first
nine months of 2005.
Net
Interest
Charges
Net
interest
charges increased by $2 million in the third quarter of 2005 compared with
the
same period in 2004, primarily related to higher interest rates charged
for
money pool borrowings from associated companies in 2005. The average interest
rate for borrowings in the third quarter of 2005 was 3.50% versus 1.28%
in the
same period in 2004. However, net interest charges decreased by $6 million
in
the first nine months of 2005 compared with the same period of 2004, reflecting
redemptions and refinancings since October 1, 2004.
Capital
Resources and Liquidity
TE’s
cash
requirements for the remainder of 2005 for operating expenses and construction
expenditures are expected to be met without increasing its
net debt and
preferred stock outstanding. Thereafter, TE expects to meet its contractual
obligations with a combination of cash from operations and funds from the
capital markets.
Changes
in Cash
Position
As
of
September 30, 2005, TE's cash and cash equivalents of $15,000 remained
unchanged from December 31, 2004.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities during the third quarter and first nine months of
2005,
compared with the corresponding period of 2004 were as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings(1)
|
|
$
|
84
|
|
$
|
77
|
|
$
|
140
|
|
$
|
152
|
|
Pension
trust
contribution(2)
|
|
|
--
|
|
|
(8
|
)
|
|
--
|
|
|
(8
|
)
|
Working
capital and other
|
|
|
--
|
|
|
55
|
|
|
(27
|
)
|
|
71
|
|
Total
cash
flows from operating activities
|
|
$
|
84
|
|
$
|
124
|
|
$
|
113
|
|
$
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash earnings are a non-GAAP measure (see reconciliation
below).
|
|
|
(2)
Pension trust contribution net of $5 million of income
tax
benefits.
|
|
|
Cash
earnings, as
disclosed in the table above, are not a measure of performance calculated
in
accordance with GAAP. TE
believes that cash
earnings is a useful financial measure because it provides investors and
management with an additional means of evaluating its cash-based operating
performance. The following table reconciles cash earnings with net
income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
42
|
|
$
|
24
|
|
$
|
50
|
|
$
|
54
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
19
|
|
|
15
|
|
|
49
|
|
|
43
|
|
Amortization
of regulatory assets
|
|
|
40
|
|
|
41
|
|
|
108
|
|
|
102
|
|
Deferral
of
new regulatory assets
|
|
|
(20
|
)
|
|
(12
|
)
|
|
(42
|
)
|
|
(30
|
)
|
Nuclear
fuel
and capital lease amortization
|
|
|
6
|
|
|
7
|
|
|
14
|
|
|
18
|
|
Amortization
of electric service obligation
|
|
|
(2
|
)
|
|
--
|
|
|
(3
|
)
|
|
-
|
|
Deferred
rents and above-market lease liability
|
|
|
10
|
|
|
10
|
|
|
(34
|
)
|
|
(27
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(13
|
)
|
|
(8
|
)
|
|
(5
|
)
|
|
(14
|
)
|
Accrued
retirement benefits obligations
|
|
|
2
|
|
|
1
|
|
|
4
|
|
|
5
|
|
Accrued
compensation, net
|
|
|
-
|
|
|
(1
|
)
|
|
(1
|
)
|
|
1
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
84
|
|
$
|
77
|
|
$
|
140
|
|
$
|
152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided
from operating activities decreased by $40 million in the third quarter
of 2005
from the third quarter of 2004 as a result of a $55 million decrease from
working capital, partially offset by a $7 million increase in cash earnings
as
described above and under “Results of Operations” and the absence of an $8
million after-tax voluntary pension trust contribution made in the third
quarter
of 2004. Net cash provided from operating activities decreased by $102
million
in the first nine months of 2005 compared to the same period last year
as a
result of a $98 million change in working capital and a $12 million decrease
in
cash earnings as described above and under “Results of Operations,” partially
offset by the absence of an $8 million after-tax voluntary pension trust
contribution made in 2004. The change in working capital for both periods
was
primarily due to changes in accounts payable, accrued taxes and receivables,
partially offset in the nine-month period of 2005 by funds received for
prepaid
electric service under the Ohio Schools Council’s Energy for Education Program
that began in the second quarter of 2005.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities decreased by $48 million and increased by $1 million
in the
third quarter and first nine months of 2005, respectively, as compared
to the
same periods of 2004. The activities in both periods reflect an increase
in net
debt redemptions and preferred stock redemptions. The increase in the nine-month
period of 2005 also included a $10 million increase in common stock dividends
to
FirstEnergy.
On
July 1,
2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series
A
preferred stock at $25.00 per share, plus accrued dividends to the date
of
redemption. TE also repurchased $37 million of pollution control revenue
bonds
on September 1, 2005, with the intent to remarket them by the end
of the
first quarter of 2006.
TE
had $53 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and $378 million of short-term indebtedness
as of
September 30, 2005. TE has authorization from the PUCO to incur
short-term
debt of up to $500 million (including the utility money pool described
below).
As of October 24, 2005, TE had the capability to issue $1.0 billion of
additional FMB on the basis of property additions and retired bonds under
the
terms of its mortgage indenture following the recently completed intra-system
transfer of fossil generating plants (See Note 17). Based upon applicable
earnings coverage tests, TE could issue up to $1.15 billion of preferred
stock
(assuming no additional debt was issued) as of September 30, 2005.
It is
estimated that the annualized impact of the intra-system transfer of fossil
generating plants will reduce the capability of TE to issue preferred stock
by
approximately $16 million.
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as Borrowers, entered into a syndicated $2 billion five-year revolving
credit
facility. Borrowings under the facility are available to each Borrower
separately and will mature on the earlier of 364 days from the date of
borrowing
and the commitment termination date, as the same may be extended. TE's
borrowing
limit under the facility is $250 million.
TE
has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies
receiving
a loan under the money pool agreements must repay the principal, together
with
accrued interest, within 364 days of borrowing the funds. The rate of interest
is the same for each company receiving a loan from the pool and is based
on the
average cost of funds available through the pool. The average interest
rate for
borrowings in the third quarter of 2005 was 3.50%.
TE’s
access to
capital markets and costs of financing are dependent on the ratings of
its
securities and the securities of FirstEnergy.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements
in its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base load
generation fleet, low-risk transmission and distribution operations and
rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also noted
as
strengths.
Cash
Flows From
Investing Activities
Net
cash used for
investing activities increased by $9 million in the third quarter of 2005
compared with from the same period of 2004. Net cash provided from investing
activities increased by $105 million in the first nine months of 2005,
from the
same period of 2004. These increases were primarily due to changes from
loan
activity with associated companies during the periods, partially offset
by
increased property additions in the nine-month period.
In
the last quarter
of 2005, TE’s capital spending is expected to be about $25 million. These cash
requirements are expected to be satisfied from internal cash and short-term
borrowings. TE’s
capital
spending for the period 2005-2007 is expected to be about $192 million,
of which
approximately $64 million applies to 2005.
FirstEnergy
Intra-System Generation Asset Transfers
On
May 18,
2005, OE, CEI and TE, entered into certain agreements implementing a series
of
intra-system generation asset transfers. When fully completed, the asset
transfers will result in the respective undivided ownership interests of
the
Ohio Companies in FirstEnergy’s nuclear and non-nuclear plants being owned by
NGC and FGCO, respectively. The generating plant interests that are being
transferred do not include TE’s leasehold interests in certain of the plants
that are currently subject to sale and leaseback arrangements with
non-affiliates.
On
October 24,
2005, TE completed the transfer of non-nuclear generation assets to FGCO.
TE
currently expects to complete the transfer of nuclear generation assets
to NGC
at book value before the end of 2005. Consummation of the nuclear transfer
remains subject to necessary regulatory approvals.
These
transactions
are being undertaken in connection with the Ohio Companies’ restructuring plans
that were approved by the PUCO under applicable Ohio electric utility
restructuring legislation. Consistent with the restructuring plans, generation
assets that had been owned by the Ohio Companies were required to be separated
from the regulated delivery business of those companies through transfer
to a
separate corporate entity. FENOC currently operates and maintains the nuclear
generation assets to be transferred. FGCO, as lessee under a Master Facility
Lease, leased, operated and maintained the non-nuclear generation assets
that it
now owns. The transactions will essentially complete the divestitures
contemplated by the restructuring plans by transferring the ownership interests
to NGC and FGCO, respectively, without impacting the operation of the plants.
See
Note 17 to the
consolidated financial statements for TE’s disclosure of the assets held for
sale as of September 30, 2005.
Off-Balance
Sheet Arrangements
Obligations
not
included on TE’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
Unit 2. As of September 30, 2005, the present value of these operating
lease commitments, net of trust investments, totaled $541 million.
TE
sells
substantially all of its retail customer receivables to CFC, a wholly owned
subsidiary of CEI. As of June 16, 2005, the CFC receivables financing
structure was renewed and restructured from an off-balance sheet transaction
to
an on-balance sheet transaction. Under the new structure, any borrowings
under
the facility appear on the balance sheet as short-term debt.
Equity
Price Risk
Included
in TE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $217 million and $188 million
as
of September 30, 2005 and December 31, 2004, respectively.
A
hypothetical 10% decrease in prices quoted by stock exchanges would result
in a
$22 million reduction in fair value as of September 30, 2005. Changes
in
the fair value of these investments are recorded in OCI unless recognized
as a
result of sales.
Outlook
The electric industry continues to transition to a more competitive environment
and all of TE's customers can select alternative energy suppliers. TE continues
to deliver power to residential homes and businesses through its existing
distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. TE has
a
continuing responsibility to provide power to those customers not choosing
to
receive power from an alternative energy supplier subject to certain
limits.
Regulatory
Matters
In
2001, Ohio
customer rates were restructured to establish separate charges for transmission,
distribution, transition cost recovery and a generation-related component.
When
one of TE's customers elects to obtain power from an alternative supplier,
TE
reduces the customer's bill with a "generation shopping credit," based
on the
generation component plus an incentive, and the customer receives a generation
charge from the alternative supplier. TE has continuing PLR responsibility
to
its franchise customers through December 31, 2008 unless the PUCO
accepts
future competitive bid results prior to the end of that period under the
revised
RSP.
As
part of TE's
transition plan, it is obligated to supply electricity to customers who
do not
choose an alternative supplier. TE is also required to provide 160 MW of
low
cost supply (MSG) to unaffiliated alternative suppliers who serve customers
within its service area. FES acts as an alternate supplier for a portion
of the
load in TE's franchise area.
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 competitive
bid
process. The RSP was filed by the Ohio Companies to establish generation
service
rates beginning January 1, 2006, in response to PUCO concerns about
price
and supply uncertainty following the end of the Ohio Companies' transition
plan
market development period. In October 2004, the OCC and NOAC filed appeals
with
the Supreme Court of Ohio to overturn the original June 9, 2004
PUCO order
in this proceeding as well as the associated entries on rehearing. On
September 28, 2005, the Ohio Supreme Court heard oral argument on
the
appeals.
On
May 27,
2005, TE filed an application with the PUCO to establish a GCAF rider under
its
RSP. The application seeks to implement recovery of increased fuel costs
from
2006 through 2008 applicable to TE’s retail customers through a tariff rider to
be implemented January 1, 2006. The application reflects projected
increases in fuel costs in 2006 compared to 2002 baseline costs. The new
rider,
after adjustments made in testimony, is seeking to recover all costs above
the
baseline (approximately $88 million in 2006 for all the Ohio Companies).
Various
parties including the OCC have intervened in this case and the case has
been
consolidated with the RCP application discussed below.
On
September 9, 2005, TE filed an application with the PUCO that, if
approved,
would supplement its existing RSP with an RCP. On September 27,
2005, the
PUCO granted FirstEnergy's motion to consolidate the GCAF rider application
with
the RCP proceedings and set hearings for the consolidated cases to begin
November 29, 2005. The RCP is designed to provide customers with
more
certain rate levels than otherwise available under the RSP during the plan
period. Major provisions of the RCP include:
· |
Maintain
the
existing level of base distribution rates through December 31,
2008
for TE;
|
· |
Defer
and
capitalize certain distribution costs to be incurred by all of
the Ohio
Companies during the
period
January 1, 2006 through December 31, 2008, not
to exceed $150
million in each of the three
years;
|
· |
Adjust
the RTC
and extended RTC recovery periods and rate levels so that full
recovery of
authorized
costs
will
occur as of December 31, 2008 for
TE;
|
· |
Reduce
the
deferred shopping incentive balances as of January 1,
2006 by up to
$45 million for TE
by
accelerating
the application of its accumulated cost of removal regulatory
liability;
and
|
· |
Recover
increased fuel costs of up to $75 million, $77 million, and $79
million,
in 2006, 2007, and
2008,
respectively, from all OE and TE distribution and transmission
customers
through a fuel
recovery
mechanism. TE may defer and capitalize increased fuel costs above
the
amount collected
through
the
fuel recovery mechanism.
|
Under
provisions of
the RSP, the
PUCO may require
TE to undertake, no more often than annually, a competitive bid process
to
secure generation for the years 2007 and 2008. On July 22, 2005,
FirstEnergy filed a competitive bid process for the period beginning in
2007
that is similar to the competitive bid process approved by the PUCO for
TE in
2004, which resulted in the PUCO accepting no bids. Any acceptance of future
competitive bid results would terminate the RSP pricing, with no accounting
impacts to the RSP, and not until twelve months after the PUCO authorizes
such
termination. On September 28, 2005, the PUCO issued an Entry that
essentially approved the Ohio Companies’ filing but delayed the proposed timing
of the competitive bid process by four months, calling for the auction
to be
held on March 21, 2006.
On
December 30, 2004, TE filed with the PUCO two applications related
to the
recovery of transmission and ancillary service related costs. The first
application seeks recovery of these costs beginning January 1, 2006.
At the
time of filing the application, these costs were estimated to be approximately
$0.1 million per year; however, TE anticipates that this amount will increase.
TE requested that these costs be recovered through a rider that would be
effective on January 1, 2006 and adjusted each July 1 thereafter.
TE
reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio
and
OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed
not
to oppose the settlement. This settlement, which was filed with the PUCO
on
July 22, 2005, provides for the rider recovery requested by TE,
with
carrying charges applied in the subsequent year’s rider for any over or under
collection while the then-current rider is in effect. The PUCO approved
the
settlement stipulation on August 31, 2005. The incremental Transmission
and
Ancillary service revenues expected to be recovered from January through
June
2006 are approximately $6.7 million. This value includes the recovery of
the
2005 deferred MISO expenses as described below. In May 2006, TE will file
a
modification to the rider which will determine revenues from July 2006
through
June 2007.
The
second
application seeks authority to defer costs associated with transmission
and
ancillary service related costs incurred during the period from October 1,
2003 through December 31, 2005. On May 18, 2005, the PUCO
granted the
accounting authority for TE to defer incremental transmission and ancillary
service-related charges incurred as a participant in the MISO, but only
for
those costs incurred during the period December 30, 2004 through
December 31, 2005. Permission to defer costs incurred prior to
December 31, 2004 was denied. The PUCO also authorized TE to accrue
carrying charges on the deferred balances. An application filed with the
PUCO to
recover these deferred charges over a five-year period through the rider,
beginning in 2006, was approved in a PUCO order issued on August 31,
2005.
The OCC, OPAE and TE each filed applications for rehearing. TE sought authority
to defer the transmission and ancillary service related costs incurred
during
the period October 1, 2003 through December 29, 2004, while
both OCC
and OPAE sought to have the PUCO deny deferral of all costs. On
July 6,
2005, the PUCO denied TE's and OCC’s applications and, at the request of TE,
struck as untimely OPAE’s application. The OCC filed a notice of appeal with the
Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance
with
appellate procedure, the PUCO filed with the Ohio Supreme Court the record
in
this case. The Companies' brief will be due thirty days after the OCC files
its
brief, which, absent any time extensions, must be filed no later than November
9, 2005.
TE
records as
regulatory assets costs which have been authorized by the PUCO and the
FERC for
recovery from customers in future periods and, without such authorization,
the
costs would have been charged to income when incurred. TE's regulatory
assets as
of September 30, 2005 and December 31, 2004, were $310 million
and
$375 million, respectively. TE is deferring customer shopping incentives
and
interest costs as new regulatory assets in accordance with its transition
and
rate stabilization plans. These regulatory assets total $122 million as
of
September 30, 2005 and, under the RSP, will be recovered through
a
surcharge rate equal to the RTC rate in effect when the transition costs
have
been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated
net amortization of regulatory transition costs and deferred shopping incentive
balances under the proposed RCP and current RSP.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.
Environmental
Matters
TE
accrues
environmental liabilities only when it concludes that it is probable that
it has
an obligation for such costs and can reasonably estimate the amount of
such
costs. Unasserted claims are reflected in TE's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
National
Ambient Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
for fine
particulate matter. On March 10, 2005, the EPA finalized the "Clean
Air
Interstate Rule" covering a total of 28 states (including 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
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone
NAAQS in
other states. CAIR provides each affected state until 2006 to develop
implementing regulation 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)
in all cases from
the 2003 levels. TE's Ohio and Pennsylvania fossil-fired generation facilities
will be subject to the caps on SO2
and 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 TE 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. On March 14, 2005,
the EPA
finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade
program to reduce mercury emissions from coal-fired power plants in two
phases.
Initially, mercury emissions will be capped nationally at 38 tons by 2010
as a
"co-benefit" from implementation of SO2
and NOx
emission caps
under the EPA's CAIR program. Phase II of the mercury cap-and-trade program
will
cap nationwide mercury emissions from coal-fired power plants at 15 tons
per
year by 2018. However, the final rules give states substantial discretion
in
developing rules to implement these programs. In addition, both
the CAIR
and the Clean Air Mercury rule have been challenged in the United States
Court
of Appeals for the District of Columbia. Future cost of compliance
with
these regulations may be substantial.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (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 Protocol in 1998 but it failed
to
receive the two-thirds vote of the United States Senate required for
ratification. However, the Bush administration has committed the United
States
to a voluntary climate change strategy to reduce domestic GHG intensity
- the
ratio of emissions to economic output - by 18 percent through 2012. The
Energy
Policy Act of 2005 established a Committee on Climate Change Technology
to
coordinate federal climate change activities and promote the development
and
deployment of GHG reducing technologies.
TE
cannot currently
estimate the financial impact of climate change policies, although the
potential
restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per KWH
of electricity generated by TE is lower than many regional competitors
due to
TE's diversified generation sources which include low or non-CO2
emitting gas-fired
and nuclear generators.
Regulation
of
Hazardous Waste
TE
has been named a
PRP at waste disposal sites, which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations
of
disposal of hazardous substances at historical sites and the liability
involved
are often unsubstantiated and subject to dispute; however, federal law
provides
that all PRPs for a particular site are liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have
been
recognized on the Consolidated Balance Sheet as of September 30,
2005,
based on estimates of the total costs of cleanup, TE's proportionate
responsibility for such costs and the financial ability of other nonaffiliated
entities to pay. Included in Other Noncurrent Liabilities are accrued
liabilities aggregating approximately $0.2 million as of September 30,
2005.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to TE's normal business operations pending against TE and its
subsidiaries. The other material items not otherwise discussed above are
described below.
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 concludes, 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 website (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 also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. FirstEnergy notes, however, that FERC or other
applicable government agencies and reliability coordinators may take a
different
view as to recommended enhancements or may recommend additional enhancements
in
the future that could require additional, material expenditures. Finally,
the
PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to
control room computer hardware and software and enhancements to the training
of
control room operators, before determining the next steps, if any, in the
proceeding.
FirstEnergy
companies also are defending six separate complaint cases before the PUCO
relating to the August 14, 2003 power outage. Two such cases were originally
filed in Ohio State courts but subsequently dismissed for lack of subject
matter
jurisdiction and further appeals were unsuccessful. In both such 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. Of the four other pending PUCO complaint cases, three were
filed by
various insurance carriers either in their own name as subrogees or in
the name
of their insured. In each such case, the carriers seek reimbursement against
various FirstEnergy companies (and, in one case, against PJM, MISO and
American
Electric Power Co. as well) for claims they paid to their insureds allegedly
due
to the loss of power on August 14, 2003. The listed insureds in these cases,
in
many instances, are not customers of any FirstEnergy company. The fourth
case
involves the claim of a non-customer seeking reimbursement for losses incurred
when its store was burglarized on August 14, 2003. In addition to these
six
cases, the Ohio Companies were named as respondents in a regulatory proceeding
that was initiated at the PUCO in response to complaints alleging failure
to
provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. No estimate of potential liability
has been
undertaken for any of these cases.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. In particular, if FirstEnergy or
its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition, results of operations and cash
flows.
FENOC
received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection
and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power
Station,
in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy
received a letter from the United States Attorney's Office stating that
FENOC is
a target of the federal grand jury investigation into alleged false statements
made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01.
The
letter also said that the designation of FENOC as a target indicates that,
in
the view of the prosecutors assigned to the matter, it is likely that federal
charges will be returned against FENOC by the grand jury. On February 10,
2005, FENOC received an additional subpoena for documents related to root
cause
reports regarding reactor head degradation and the assessment of reactor
head
management issues at Davis-Besse.
On May 11,
2005, FENOC received a subpoena for documents related to outside meetings
attended by Davis-Besse personnel on corrosion and cracking of control
rod drive
mechanisms and additional root cause evaluations.
On
April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related
to
the degradation of the Davis-Besse reactor vessel head issue described
above. TE
accrued $1.0 million for a potential fine prior to 2005 and accrued the
remaining liability for its share of the proposed fine of $1.65 million
during
the first quarter of 2005. On September 14, 2005, FENOC filed its
response
to the NOV with the NRC. FENOC accepted full responsibility for the past
failure
to properly implement its boric acid corrosion control and corrective action
programs. The NRC NOV indicated that the violations do not represent current
licensee performance. FirstEnergy paid the penalty in the third quarter
of
2005.
If
it were
ultimately determined that FirstEnergy or its subsidiaries has legal liability
based on events surrounding Davis-Besse, it could have a material adverse
effect
on FirstEnergy's or any of its subsidiaries' financial condition, results
of
operations and cash flows.
Effective
July 1, 2005 the NRC oversight panel for Davis-Besse was terminated
and
Davis-Besse returned to the standard NRC reactor oversight process. At
that
time, NRC inspections were augmented to include inspections to support
the NRC's
Confirmatory Order dated March 8, 2004 that was issued at the time
of
startup and to address an NRC White Finding related to the performance
of the
emergency sirens.
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 effective corrective action. FENOC operates the Perry Nuclear Power
Plant,
in which TE has a 19.91% interest (however,
see Note
17 regarding FirstEnergy’s pending intra-system generation asset transfers,
which include owned portions of the plant).
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter
to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to
the NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During
the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to
be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the
Action
Matrix.
On
May 26,
2005, the NRC held a public meeting to discuss its oversight of the Perry
Plant.
While the NRC stated that the plant continued to operate safely, the NRC
also
stated that the overall performance had not substantially improved since
the
heightened inspection was initiated. The NRC reiterated this conclusion
in its
mid-year assessment letter dated August 30, 2005. On September 28,
2005,
the NRC sent a CAL to FENOC describing commitments that FENOC had made
to
improve the performance of Perry 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. If performance does not improve, the NRC
has a
range of options under the Reactor Oversight Process from increased oversight
to
possible impact to the plant’s operating authority. As a result, these matters
could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
On
October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed
informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results
by
FirstEnergy and TE, and the Davis-Besse extended outage, have become the
subject
of a formal order of investigation. The SEC's formal order of investigation
also
encompasses issues raised during the SEC's examination of FirstEnergy and
the
Companies under the PUHCA. Concurrent with this notification, FirstEnergy
received a subpoena asking for background documents and documents related
to the
restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
received a subpoena asking for documents relating to issues raised during
the
SEC's PUHCA examination. On
August 24,
2005, additional information was requested regarding Davis-Besse. FirstEnergy
has cooperated fully with the informal inquiry and will continue to do
so with
the formal investigation.
The
City of Huron
filed a complaint against OE with the PUCO challenging the ability of electric
distribution utilities to collect transition charges from a customer of
a newly
formed municipal electric utility. The complaint was filed on May 28,
2003,
and OE timely filed its response on June 30, 2003. In a related
filing, the
Ohio Companies filed for approval with the PUCO of a tariff that would
specifically allow the collection of transition charges from customers
of
municipal electric utilities formed after 1998. An
adverse ruling
could negatively affect full recovery of transition charges by TE. Hearings
on
the matter were held in August 2005. Initial briefs from all parties were
filed
on September 22, 2005 and reply briefs were filed on October 14,
2005.
It is unknown when the PUCO will rule on this case.
If
it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters,
it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition, results of operations and cash flows.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or
more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the
EITF
reached a consensus that an exchange of inventory should be accounted for
at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, TE will adopt this EITF effective
for
new arrangements entered into, or modifications or renewals of existing
arrangements, in interim or annual periods beginning after March 15, 2006.
|
EITF
Issue No. 05-6, "Determining the Amortization Period for Leasehold
Improvements Purchased after Lease Inception or Acquired in a
Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6. EITF
05-6
addresses the amortization period for leasehold improvements that were
either
acquired in a business combination or placed in service significantly after
and
not contemplated at or near the beginning of the initial lease term. For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that includes
required lease periods and renewals that are deemed to be reasonably assured
at
the date of acquisition. Leasehold improvements that are placed in service
significantly after and not contemplated at or near the beginning of the
lease
term should be amortized over the shorter of the useful life of the assets
or a
term that includes required lease periods and renewals that are deemed
to be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with TE’s current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the
fair
value of an asset retirement obligation that is conditional on a future
event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective for TE in the fourth quarter of 2005.
TE is
currently evaluating the effect this Interpretation will have on its financial
statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement of APB
Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and reporting
a
change in accounting principle. It applies to all voluntary changes in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions. This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of
the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening
balance
of retained earnings (or other appropriate components of equity or net
assets in
the statement of financial position) for that period rather than being
reported
in the Consolidated Statements of Income. This Statement also requires
that a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate
affected
by a change in accounting principle. The provisions of this Statement are
effective for accounting changes and corrections of errors made in fiscal
years
beginning after December 15, 2005. TE will adopt this Statement
effective
January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion
No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows
of the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for TE.
This FSP
is not expected to have a material impact on TE’s financial
statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
of idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be
“so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective
for
inventory costs incurred by TE beginning January 1, 2006. TE is
currently
evaluating this Standard and does not expect it to have a material impact
on its
financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application to
Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security Whose
Cost
Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
loss no later than when the impairment is deemed other than temporary,
even if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP in
the fourth
quarter of 2005, which would require prospective application with an effective
date for reporting periods beginning after December 15, 2005. TE is currently
evaluating this FSP and any impact on its investments.
PENNSYLVANIA
POWER COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
145,540
|
|
$
|
143,340
|
|
$
|
414,306
|
|
$
|
420,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
6,205
|
|
|
6,347
|
|
|
17,351
|
|
|
18,408
|
|
Purchased
power
|
|
|
42,242
|
|
|
44,096
|
|
|
131,948
|
|
|
136,699
|
|
Nuclear
operating costs
|
|
|
16,997
|
|
|
19,934
|
|
|
56,710
|
|
|
55,737
|
|
Other
operating costs
|
|
|
19,030
|
|
|
16,212
|
|
|
48,541
|
|
|
45,371
|
|
Provision
for
depreciation
|
|
|
3,847
|
|
|
3,556
|
|
|
11,351
|
|
|
10,390
|
|
Amortization
of regulatory assets
|
|
|
9,784
|
|
|
9,979
|
|
|
29,499
|
|
|
30,082
|
|
General
taxes
|
|
|
6,836
|
|
|
6,416
|
|
|
19,752
|
|
|
17,538
|
|
Income
taxes
|
|
|
17,402
|
|
|
16,541
|
|
|
43,055
|
|
|
46,425
|
|
Total
operating expenses and taxes
|
|
|
122,343
|
|
|
123,081
|
|
|
358,207
|
|
|
360,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
23,197
|
|
|
20,259
|
|
|
56,099
|
|
|
59,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
549
|
|
|
745
|
|
|
623
|
|
|
2,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
2,371
|
|
|
1,911
|
|
|
7,477
|
|
|
7,434
|
|
Allowance
for
borrowed funds used during construction
|
|
|
(1,665
|
)
|
|
(1,271
|
)
|
|
(4,508
|
)
|
|
(3,197
|
)
|
Net
interest
charges
|
|
|
706
|
|
|
640
|
|
|
2,969
|
|
|
4,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
23,040
|
|
|
20,364
|
|
|
53,753
|
|
|
57,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
156
|
|
|
639
|
|
|
1,534
|
|
|
1,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
22,884
|
|
$
|
19,725
|
|
$
|
52,219
|
|
$
|
56,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
23,040
|
|
$
|
20,364
|
|
$
|
53,753
|
|
$
|
57,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
23,040
|
|
$
|
20,364
|
|
$
|
53,753
|
|
$
|
57,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral part of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
POWER COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
907,382
|
|
$
|
866,303
|
|
Less
-
Accumulated provision for depreciation
|
|
|
378,707
|
|
|
356,020
|
|
|
|
|
528,675
|
|
|
510,283
|
|
Construction
work in progress -
|
|
|
|
|
|
|
|
Electric
plant
|
|
|
133,790
|
|
|
104,366
|
|
Nuclear
fuel
|
|
|
10,428
|
|
|
3,362
|
|
|
|
|
144,218
|
|
|
107,728
|
|
|
|
|
672,893
|
|
|
618,011
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
146,706
|
|
|
143,062
|
|
Long-term
notes receivable from associated companies
|
|
|
32,864
|
|
|
32,985
|
|
Other
|
|
|
502
|
|
|
722
|
|
|
|
|
180,072
|
|
|
176,769
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
24
|
|
|
38
|
|
Notes
receivable from associated companies
|
|
|
566
|
|
|
431
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $1,066,000 and $888,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
44,990
|
|
|
44,282
|
|
Associated
companies
|
|
|
6,206
|
|
|
23,016
|
|
Other
|
|
|
2,617
|
|
|
1,656
|
|
Materials
and
supplies, at average cost
|
|
|
37,974
|
|
|
37,923
|
|
Prepayments
and other
|
|
|
12,110
|
|
|
8,924
|
|
|
|
|
104,487
|
|
|
116,270
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES
|
|
|
10,721
|
|
|
10,106
|
|
|
|
$
|
968,173
|
|
$
|
921,156
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
Common
stock,
$30 par value, authorized 6,500,000 shares -
|
|
|
|
|
|
|
|
6,290,000
shares outstanding
|
|
$
|
188,700
|
|
$
|
188,700
|
|
Other
paid-in
capital
|
|
|
65,035
|
|
|
64,690
|
|
Accumulated
other comprehensive loss
|
|
|
(13,706
|
)
|
|
(13,706
|
)
|
Retained
earnings
|
|
|
131,914
|
|
|
87,695
|
|
Total
common
stockholder's equity
|
|
|
371,943
|
|
|
327,379
|
|
Preferred
stock
|
|
|
14,105
|
|
|
39,105
|
|
Long-term
debt
and other long-term obligations
|
|
|
121,170
|
|
|
133,887
|
|
|
|
|
507,218
|
|
|
500,371
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
25,774
|
|
|
26,524
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
34,821
|
|
|
11,852
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
16,864
|
|
|
46,368
|
|
Other
|
|
|
1,884
|
|
|
1,436
|
|
Accrued
taxes
|
|
|
26,163
|
|
|
14,055
|
|
Accrued
interest
|
|
|
1,635
|
|
|
1,872
|
|
Other
|
|
|
8,491
|
|
|
8,802
|
|
|
|
|
115,632
|
|
|
110,909
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
79,801
|
|
|
93,418
|
|
Asset
retirement obligation
|
|
|
155,959
|
|
|
138,284
|
|
Retirement
benefits
|
|
|
51,389
|
|
|
49,834
|
|
Regulatory
liabilities
|
|
|
47,809
|
|
|
18,454
|
|
Other
|
|
|
10,365
|
|
|
9,886
|
|
|
|
|
345,323
|
|
|
309,876
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
968,173
|
|
$
|
921,156
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral part of these balance
sheets.
|
|
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
POWER COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
23,040
|
|
$
|
20,364
|
|
$
|
53,753
|
|
$
|
57,978
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for depreciation
|
|
|
3,847
|
|
|
3,556
|
|
|
11,351
|
|
|
10,390
|
|
Amortization
of regulatory assets
|
|
|
9,784
|
|
|
9,979
|
|
|
29,499
|
|
|
30,082
|
|
Nuclear
fuel and other amortization
|
|
|
4,634
|
|
|
4,550
|
|
|
12,912
|
|
|
13,546
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(2,612
|
)
|
|
(501
|
)
|
|
(7,567
|
)
|
|
(2,852
|
)
|
Pension
trust contribution
|
|
|
-
|
|
|
(12,934
|
)
|
|
-
|
|
|
(12,934
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
4,303
|
|
|
(30,285
|
)
|
|
15,141
|
|
|
(10,551
|
)
|
Materials
and
supplies
|
|
|
755
|
|
|
(1,078
|
)
|
|
(51
|
)
|
|
(3,374
|
)
|
Prepayments
and other current assets
|
|
|
5,074
|
|
|
4,164
|
|
|
(3,186
|
)
|
|
(3,977
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(9,161
|
)
|
|
40,306
|
|
|
(29,056
|
)
|
|
21,678
|
|
Accrued
taxes
|
|
|
5
|
|
|
(2,485
|
)
|
|
12,108
|
|
|
2,301
|
|
Accrued
interest
|
|
|
(353
|
)
|
|
(986
|
)
|
|
(237
|
)
|
|
(2,415
|
)
|
Other
|
|
|
564
|
|
|
1,353
|
|
|
1,027
|
|
|
5,294
|
|
Net
cash
provided from operating activities
|
|
|
39,880
|
|
|
36,003
|
|
|
95,694
|
|
|
105,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
-
|
|
|
22,969
|
|
|
10,789
|
|
Equity
contribution from parent
|
|
|
-
|
|
|
25,000
|
|
|
-
|
|
|
25,000
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock
|
|
|
-
|
|
|
-
|
|
|
(37,750
|
)
|
|
-
|
|
Long-term
debt
|
|
|
(39
|
)
|
|
(20,508
|
)
|
|
(849
|
)
|
|
(63,297
|
)
|
Short-term
borrowings, net
|
|
|
(10,776
|
)
|
|
(11,414
|
)
|
|
-
|
|
|
-
|
|
Dividend
Payments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
-
|
|
|
-
|
|
|
(8,000
|
)
|
|
(23,000
|
)
|
Preferred
stock
|
|
|
(156
|
)
|
|
(639
|
)
|
|
(1,534
|
)
|
|
(1,919
|
)
|
Net
cash used
for financing activities
|
|
|
(10,971
|
)
|
|
(7,561
|
)
|
|
(25,164
|
)
|
|
(52,427
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(28,537
|
)
|
|
(24,670
|
)
|
|
(69,630
|
)
|
|
(56,080
|
)
|
Contributions
to nuclear decommissioning trusts
|
|
|
(399
|
)
|
|
(399
|
)
|
|
(1,196
|
)
|
|
(1,196
|
)
|
Loan
repayments from (loans to) associated companies
|
|
|
(187
|
)
|
|
(36
|
)
|
|
(14
|
)
|
|
5,975
|
|
Other
|
|
|
214
|
|
|
(3,337
|
)
|
|
296
|
|
|
(1,440
|
)
|
Net
cash used
for investing activities
|
|
|
(28,909
|
)
|
|
(28,442
|
)
|
|
(70,544
|
)
|
|
(52,741
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
(14
|
)
|
|
(2
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
24
|
|
|
38
|
|
|
38
|
|
|
40
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
24
|
|
$
|
38
|
|
$
|
24
|
|
$
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate to
Pennsylvania
Power Company are an integral part of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
To
the Stockholders
and Board of
Directors
of
Pennsylvania Power Company:
We
have reviewed
the accompanying consolidated balance sheet of Pennsylvania Power Company
and
its subsidiary as of September 30, 2005, and the related consolidated
statements of income and comprehensive income and cash flows for each of
the
three-month and nine-month periods ended September 30, 2005 and
2004. 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, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note
2(G) to
those consolidated financial statements) dated March 7, 2005, 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, 2004, is fairly stated in all material respects
in
relation to the consolidated balance sheet from which it has been
derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
PENNSYLVANIA
POWER COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
Penn
is a wholly
owned, electric utility subsidiary of OE. Penn conducts business in western
Pennsylvania, providing regulated electric distribution services. Penn
also
provides generation services to those customers electing to retain Penn
as their
power supplier. Penn provides power directly to wholesale customers under
previously negotiated contracts. Penn has unbundled the price of electricity
into its component elements - including generation, transmission, distribution
and transition charges. Its power supply requirements are provided by FES
- an
affiliated company.
Results
of Operations
Earnings
on common
stock in the third quarter of 2005 increased to $23 million from $20 million
in
the third quarter of 2004. The increased earnings resulted primarily from
higher
operating revenues and lower operating expenses and taxes. Earnings on
common
stock for the first nine months of 2005 decreased to $52 million from $56
million for the same period of 2004. The lower earnings resulted primarily
from
a decrease in operating revenues and other income, partially offset by
lower
operating expenses and taxes and lower net interest charges.
Operating
revenues
increased by $2 million, or 1.5%, in the third quarter of 2005 compared
with the
third quarter of 2004. Higher revenues in the third quarter of 2005 primarily
resulted from increased retail generation sales revenues of $6 million
and a $2
million increase in rental revenues, partially offset by a $6 million decrease
in wholesale sales to FES. Retail generation sales increased as a result
of
increased KWH sales to residential (7.6%) and commercial (4.0%) customers,
due
to warmer weather in Penn's service area, and a 19.8% KWH sales increase
to
industrial customers, primarily within the steel sector.
Revenues
from
distribution deliveries in the third quarter of 2005 increased slightly
from the
third quarter of 2004, as lower unit prices partially offset a 10.2% increase
in
KWH sales. The lower unit prices were primarily attributable to changes
in
Penn's CTC rate schedules in April 2005 as a result of the annual CTC
reconciliation. Increased revenues from distribution deliveries to residential
($0.3 million) and industrial ($0.8 million) customers were offset by a
$1
million decrease in revenues from commercial customers.
Operating
revenues
decreased by $6 million in the first nine months of 2005 compared with
the same
period of 2004. The lower operating revenues reflected a $24 million decrease
in
wholesale sales to FES, partially offset by higher retail sales of $14
million.
Higher retail electric generation revenues of $14 million resulted from
increased KWH sales to all sectors (Residential - 8.0%, Commercial - 5.6%
and
Industrial - 1.5%) and higher unit prices for commercial and industrial
customers.
In
the first nine
months of 2005, revenues from distribution deliveries increased by $0.3
million
compared to the same period of 2004. An increase in total KWH deliveries
of 5.0%
was offset by lower unit prices, reflecting the changes in Penn's CTC rates
discussed above. Increased revenues from distribution deliveries to residential
customers of $4 million were partially offset by lower revenues from commercial
($1 million) and industrial ($2 million) customers.
Changes
in
kilowatt-hour sales by customer class in the three months and nine months
ended
September 30, 2005 from the corresponding periods of 2004 are summarized
in the
following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
10.2
|
%
|
|
5.0
|
%
|
Wholesale
|
|
|
(1.4
|
)%
|
|
(5.5
|
)%
|
Total
Electric Generation Sales
|
|
|
3.1
|
%
|
|
(1.4
|
)%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
7.6
|
%
|
|
8.0
|
%
|
Commercial
|
|
|
4.0
|
%
|
|
5.6
|
%
|
Industrial
|
|
|
19.8
|
%
|
|
1.5
|
%
|
Total
Distribution Deliveries
|
|
|
10.2
|
%
|
|
5.0
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes decreased by $1 million in the third quarter and $2
million
in the first nine months of 2005 from the same periods of 2004. The following
table presents changes from the prior year by expense
category.
|
|
Three
|
|
Nine
|
|
Operating
Expenses and Taxes - Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
|
|
Fuel
costs
|
|
$
|
-
|
|
$
|
(1
|
)
|
Purchased
power costs
|
|
|
(2
|
)
|
|
(4
|
)
|
Nuclear
operating costs
|
|
|
(3
|
)
|
|
1
|
|
Other
operating costs
|
|
|
3
|
|
|
3
|
|
General
taxes
|
|
|
-
|
|
|
2
|
|
Income
taxes
|
|
|
1
|
|
|
(3
|
)
|
Net
decrease in operating expenses and taxes
|
|
$
|
(1
|
)
|
$
|
(2
|
)
|
|
|
|
|
|
|
|
|
The
decrease
in purchased power
costs in the three months and nine months ended September 30, 2005 resulted
from
lower unit prices for power. Nuclear operating costs were lower in the
third
quarter of 2005, reflecting a decrease in labor and postretirement benefit
expenses from the third quarter of 2004. Other operating costs were higher
in
the three months and nine months ended September 30, 2005 as the result
of
increased transmission related expenses associated with MISO's energy market
that began on April 1, 2005.
Other
Income
Other
income (net
of income taxes) decreased slightly in the third quarter and by $2 million
in
the first nine months of 2005, compared with the same periods in 2004.
The
decrease in the nine month period reflects liabilities recognized in the
first
quarter of 2005 related to the W. H. Sammis Plant settlement (see Outlook
-
Environmental Matters).
Net
Interest
Charges
Net
interest
charges decreased by $1 million in the nine months ended September 30,
2005 from
the corresponding period last year, reflecting redemptions of $40 million
principal amount of debt securities since October 1, 2004.
Capital
Resources and Liquidity
Penn’s
cash
requirements for operating expenses, construction expenditures, scheduled
debt
maturities and preferred stock redemptions are expected to be met with
a combination
of cash from operations and funds from the capital markets.
Borrowing capacity
under credit facilities is available to manage working capital requirements.
Changes
in Cash
Position
As
of September 30,
2005, Penn had $24,000 of cash and cash equivalents, compared with $38,000
as of
December 31, 2004. The major changes in these balances are summarized
below.
Cash
Flows From
Operating Activities
Net
cash provided
from operating activities in the three months and nine months ended September
30, 2005, compared with the corresponding 2004 periods, was as
follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
40
|
|
$
|
34
|
|
$
|
101
|
|
$
|
108
|
|
Pension
trust
contribution(2)
|
|
|
-
|
|
|
(8
|
)
|
|
-
|
|
|
(8
|
)
|
Working
capital and other
|
|
|
-
|
|
|
10
|
|
|
(5
|
)
|
|
5
|
|
Total
cash
flows from operating activities
|
|
$
|
40
|
|
$
|
36
|
|
$
|
96
|
|
$
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash
earnings is a non-GAAP measure (see reconciliation below).
(2)
Pension
trust contribution net of $5 million of income tax
benefits.
|
|
|
|
|
|
|
|
Cash
earnings (in
the table above) are not a measure of performance calculated in accordance
with
GAAP. Penn believes that cash earnings is a useful financial measure because
it
provides investors and management with an additional means of evaluating
its
cash-based operating performance. The following table reconciles cash earnings
with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
23
|
|
$
|
20
|
|
$
|
54
|
|
$
|
58
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
4
|
|
|
4
|
|
|
11
|
|
|
10
|
|
Amortization
of regulatory assets
|
|
|
10
|
|
|
10
|
|
|
29
|
|
|
30
|
|
Nuclear
fuel
and other amortization
|
|
|
5
|
|
|
4
|
|
|
13
|
|
|
14
|
|
Deferred
income taxes and investment tax credits, net
|
|
|
(3
|
)
|
|
(5
|
)
|
|
(8
|
)
|
|
(8
|
)
|
Other
non-cash items
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
4
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
40
|
|
$
|
34
|
|
$
|
101
|
|
$
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
$6 million
increase in cash earnings in the third quarter of 2005 and the $7 million
decrease in cash earnings for the first nine months of 2005, as compared
to the
corresponding periods of 2004, are described under “Results of Operations.” The
$10 million change in working capital and other in the three-month period
was
primarily due to a $49 million change in accounts payable, partially offset
by
changes of $35 million in receivables, $2 million in materials and supplies,
and
$2 million in accrued taxes. The $10 million change in working capital
and other
in the nine-month period was primarily due to a $51 million change in accounts
payable, partially offset by changes of $26 million in receivables, $3
million
in materials and supplies, and $10 million in accrued taxes.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities totaled $11 million in the third quarter of 2005,
compared
with $8 million in the same period last year. The $3 million increase resulted
primarily from the absence of a $25 million equity contribution from OE
in the
third quarter of 2004, partially offset by a $21 million decrease in debt
redemptions and repayments in the third quarter of 2005.
Net
cash used for
financing activities totaled $25 million in the nine months ended September
30,
2005, compared with $52 million in the same period last year. The $27 million
decrease resulted primarily from reduced long-term debt redemptions and
common
stock dividend payments in the first nine months of 2005, offset by reduced
short-term borrowings and OE's $25 million equity contribution in
2004.
On
May 16,
2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred
stock at
$102.29 per share and all 250,000 outstanding shares of 7.75% preferred
stock at
$100 per share, both plus accrued dividends to the date of redemption.
The total
par value of the preferred stock redeemed was $37.8 million.
Penn
had $590,000
of cash and temporary investments (which included short-term notes receivable
from associated companies) and $35 million of short-term indebtedness as
of
September 30, 2005. Penn has authorization from the SEC to incur short-term
debt
up to its charter limit of $51 million. As of October 24, 2005, Penn had
the
capability to issue approximately $520 million of additional FMB on the
basis of
property additions and retired bonds following the recently completed
intra-system transfer of fossil generating plants (See Note 17) . Based
upon
applicable earnings coverage tests, Penn could issue up to $383 million
of
preferred stock (assuming no additional debt was issued) as of September
30,
2005. It is estimated that the annualized impact of the intra-system transfer
of
fossil generating plants will reduce the capability of Penn to issue preferred
stock by approximately 14%. The above financing capabilities do not take
into
consideration changes related to the intercompany transfer of generating
assets
(see Note 17).
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as Borrowers, entered into a syndicated $2 billion five-year revolving
credit
facility. Borrowings under the facility are available to each Borrower
separately and will mature on the earlier of 364 days from the date of
borrowing
and the commitment termination date, as the same may be extended. Penn's
borrowing limit under the facility is $51 million.
Penn
has the
ability to borrow from its regulated affiliates and FirstEnergy to meet
its
short-term working capital requirements. FESC administers this money pool
and
tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
receiving a loan under the money pool agreements must repay the principal
amount
of such a loan, together with accrued interest, within 364 days of borrowing
the
funds. The rate of interest is the same for each company receiving a loan
from
the pool and is based on the average cost of funds available through the
pool.
The average interest rate for borrowings under these arrangements in the
third
quarter of 2005 was 3.50%.
Penn
Power Funding
LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability
company whose borrowings are secured by customer accounts receivable purchased
from Penn. Penn Funding can borrow up to $25 million under a receivables
financing arrangement. As a separate legal entity with separate creditors,
Penn
Funding would have to satisfy its obligations to creditors before any of
its
remaining assets could be made available to Penn. The facility was not
drawn as
of September 30, 2005. On July 15, 2005, the facility was renewed
until
June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.
Penn’s
access to
capital markets and costs of financing are dependent on the ratings of
its
securities and the securities of OE and FirstEnergy.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements
in its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one
notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base load
generation fleet, low-risk transmission and distribution operations and
rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also noted
as
strengths.
Cash
Flows From
Investing Activities
Net
cash used in
investing activities totaled $29 million in the third quarter of 2005,
compared
with $28 million in the third quarter of 2004. For the nine months ended
September 30, 2005, net cash used in investing activities totaled $71 million,
compared with $53 million in the same period last year. The $18 million
increase
was primarily the result of higher expenditures for property additions
in 2005
and reduced loan repayments from associated companies.
In
the last quarter
of 2005, capital requirements for property additions are expected to be
about
$32 million. Penn also expects to contribute up to $63 million (unfunded
liability recognized as of September 30, 2005) for nuclear decommissioning
in
connection with the generation asset transfers described below, and has
additional requirements of $0.5 million to meet sinking fund requirements
for
long-term debt during the remainder of 2005. These cash requirements are
expected to be satisfied from internal cash and short-term credit arrangements.
Penn's capital spending for the period 2005-2007 is expected to be about
$227
million, of which approximately $87 million applies to 2005. Penn had no
other
material obligations as of September 30, 2005 that have not been recognized
on
its Consolidated Balance Sheet.
On
July 22, 2005,
the Philadelphia Stock Exchange (Exchange) filed an application with the
SEC for
termination of the listing of the following three series of Penn’s cumulative
preferred stock, $100 par value, as such series no longer met the Exchange’s
technical listing requirements regarding the number of outstanding shares
and
the number of holders: 4.24% Series, 4.25% Series and 4.64% Series. On
August
17, 2005, the SEC granted the Exchange's application for delisting effective
August 18, 2005.
Equity
Price Risk
Included
in Penn’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $60 million and $57 million
as of
September 30, 2005 and December 31, 2004, respectively. A hypothetical
10%
decrease in prices quoted by stock exchanges would result in a $6 million
reduction in fair value as of September 30, 2005.
FirstEnergy
Intra-System Generation Asset Transfers
On
May 13,
2005, Penn entered into an agreement to transfer its ownership interests
in its
nuclear and fossil generating facilities to NGC and FGCO, respectively.
On
October 24,
2005, Penn completed the transfer of fossil generation assets to FGCO.
Penn
currently expects to complete the transfer of nuclear generation assets
to NGC
through a spin-off by way of dividend before the end of 2005. Consummation
of
the nuclear transfer remains subject to necessary regulatory approvals.
These
transactions
are being undertaken in connection with Penn’s restructuring plan that was
approved by the PPUC under applicable Pennsylvania electric utility
restructuring legislation. Consistent with the restructuring plan, Penn’s
generation assets were required to be separated from the regulated delivery
business through transfers to a separate corporate entity. FENOC currently
operates and maintains the nuclear generation assets to be transferred.
FGCO, as
lessee under a Master Facility Lease, leased, operated and maintained the
non-nuclear generation assets that it now owns. The transactions will
essentially complete the divestitures contemplated by the restructuring
plan by
transferring the ownership interests to NGC and FGCO, respectively, without
impacting the operation of the plants.
See
Note 17 to the
consolidated financial statements for disclosure of Penn's assets held
for sale
as of September 30, 2005.
Regulatory
Matters
Regulatory
assets
and liabilities are costs which have been authorized by the PPUC and the
FERC
for recovery from or credit to customers in future periods and, without
such
authorization, would have been charged or credited to income when incurred.
Penn's net regulatory liabilities were approximately $48 million and $18
million
as of September 30, 2005 and December 31, 2004, respectively, and
are
included in Noncurrent Liabilities on the Consolidated Balance
Sheets.
In
October 11,
2005, Penn filed a plan with the PPUC to secure electricity supply for
its
customers at set rates following the end of its transition period on
December 31, 2006. Penn is recommending that the Request for Proposal
process cover the period of January 1, 2007 through May 31,
2008.
Under Pennsylvania's electric competition law, Penn is required to secure
generation supply for customers who do not choose alternative suppliers
for
their electricity.
See
Note 14 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania, including a more detailed discussion
of
reliability initiatives.
Environmental
Matters
Penn
accrues
environmental liabilities when it concludes that it is probable that it
has an
obligation for such costs and can reasonably estimate the amount of such
costs.
Unasserted claims are reflected in Penn’s determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
National
Ambient Air Quality Standards
In
July 1997, the
EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS
for fine
particulate matter. On March 10, 2005, the EPA finalized the "Clean
Air
Interstate Rule" covering a total of 28 states (including 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
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone
NAAQS in
other states. CAIR provides each affected state until 2006 to develop
implementing regulations to achieve additional reductions of NOx
and SO2
emissions in two
phases (Phase I in 2009 for NOx,
2010 for
SO2
and Phase II in
2015 for both NOx
and SO2),
in all cases
from the 2003 levels. Penn's Ohio and Pennsylvania fossil-fired generation
facilities will be subject to the caps on SO2
and 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 Penn 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. On March 14, 2005,
the EPA
finalized the "Clean Air Mercury Rule," 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 Clean Air Mercury rule have been challenged in the United States
Court
of Appeals for the District of Columbia. Future cost of compliance
with
these regulations may be substantial.
W.
H. Sammis
Plant
In
1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities alleging violations
of
the Clean Air Act based on operation and maintenance of 44 power plants,
including the W. H. Sammis Plant, which was owned at that time by OE
and Penn.
In addition, the DOJ filed eight civil complaints against various investor-owned
utilities, including a complaint against OE and Penn in the U.S. District
Court
for the Southern District of Ohio. These cases are referred to as New
Source
Review cases. On March 18, 2005, OE and Penn announced that they
had
reached a settlement with the EPA, the DOJ and three states (Connecticut,
New
Jersey, and New York) that resolved all issues related to the W. H. Sammis
Plant
New Source Review litigation. This settlement agreement, which is in
the form of
a Consent Decree, was approved by the Court on July 11, 2005,
requires OE
and Penn to reduce NOx
and SO2
emission
at W. H.
Sammis Plant and other coal-fired plants through the installation of
pollution
control devices. Capital expenditures necessary to meet those requirements
are
currently estimated to be $1.5 billion (the primary portion of which
is expected
to be spent in the 2008 to 2011 time period). The settlement agreement
also
requires OE and Penn to spend up to $25 million toward environmentally
beneficial projects, which include wind energy purchased power agreements
over a
20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million,
of
which Penn's share was $0.7 million. Results for the first quarter of
2005
included the $0.7 million penalty payable by Penn and a $0.8 million
liability
for probable future cash contributions toward environmentally beneficial
projects.
Climate
Change
In
December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (Protocol), to address global warming by reducing
the amount
of man-made greenhouse gases emitted by developed countries by 5.2% from
1990
levels between 2008 and 2012. The United States signed the Protocol in
1998 but
it failed to receive the two-thirds vote of the United States Senate
required
for ratification. However, the Bush administration has committed the
United
States to a voluntary climate change strategy to reduce domestic greenhouse
gas
intensity - the ratio of emissions to economic output - by 18 percent
through
2012. The Energy Policy Act of 2005 established a Committee on Climate
Change
Technology to coordinate federal climate change activities and promote
the
development and deployment of GHG reducing technologies.
Penn
cannot
currently estimate the financial impact of climate change policies, although
the
potential restrictions on CO2
emissions could
require significant capital and other expenditures. However, the CO2
emissions per KWH
of electricity generated by Penn is lower than many regional competitors
due to
Penn's diversified generation sources which include low or non-CO2
emitting gas-fired
and nuclear generators.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to Penn's normal business operations pending against Penn. The
other
material items not otherwise discussed above are described below.
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 website (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 also is proceeding with
the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. 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. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the
proceeding.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome of any
of
these proceedings or whether any further regulatory proceedings or legal
actions
may be initiated against the Companies. In particular, if FirstEnergy or
its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition, results of operations and cash
flows.
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 effective corrective action. FENOC operates the Perry Nuclear Power
Plant,
in which Penn currently has a 5.24% interest (however, see Note 17 regarding
FirstEnergy’s pending intra-system generation asset transfers, which will
include owned portions of the plant).
On
April 4,
2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter
to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to
the NRC,
overall the Perry Plant operated "in a manner that preserved public health
and
safety" even though it remained under heightened NRC oversight. During
the
public meeting and in the annual assessment, the NRC indicated that additional
inspections will continue and that the plant must improve performance to
be
removed from the Multiple/Repetitive Degraded Cornerstone Column of the
Action
Matrix.
On
May 26,
2005, the NRC held a public meeting to discuss its oversight of the Perry
Plant.
While the NRC stated that the plant continued to operate safely, the NRC
also
stated that the overall performance had not substantially improved since
the
heightened inspection was initiated. The NRC reiterated this conclusion
in its
mid-year assessment letter dated August 30, 2005. On September 28,
2005, the NRC sent a CAL to FENOC describing commitments that FENOC had
made to
improve the performance of Perry 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. If performance does not improve, the NRC
has a
range of options under the Reactor Oversight Process, from increased oversight
to possible impact to the plant’s operating authority. As a result, these
matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two or
more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement, the
EITF
reached a consensus that an exchange of inventory should be accounted for
at
fair value. Although electric power is not capable of being held in inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, Penn will adopt this EITF effective
for
new arrangements entered into, or modifications or renewals of existing
arrangements, in interim or annual periods beginning after March 15, 2006.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the
fair
value of an asset retirement obligation that is conditional on a future
event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective for Penn in the fourth quarter of 2005.
Penn is
currently evaluating the effect this Interpretation will have on its financial
statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement of APB
Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and reporting
a
change in accounting principle. It applies to all voluntary changes in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions. This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of
the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening
balance
of retained earnings (or other appropriate components of equity or net
assets in
the statement of financial position) for that period rather than being
reported
in the Consolidated Statements of Income. This Statement also requires
that a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate
affected
by a change in accounting principle. The provisions of this Statement are
effective for accounting changes and corrections of errors made in fiscal
years
beginning after December 15, 2005. Penn will adopt this Statement
effective
January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion
No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows
of the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for Penn.
This
FSP is not expected to have a material impact on Penn's financial
statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
of idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be
“so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective
for
inventory costs incurred by Penn beginning January 1, 2006. Penn
is
currently evaluating this Standard and does not expect it to have a material
impact on the financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application to
Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP
FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security Whose
Cost
Exceeds Fair Value," (2) clarify that an investor should recognize an impairment
loss no later than when the impairment is deemed other than temporary,
even if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP in
the fourth
quarter of 2005, which would require prospective application with an effective
date for reporting periods beginning after December 15, 2005. Penn is currently
evaluating this FSP and any impact on its investments.
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
900,247
|
|
$
|
706,613
|
|
$
|
2,024,630
|
|
$
|
1,754,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
517,212
|
|
|
387,282
|
|
|
1,115,737
|
|
|
943,757
|
|
Other
operating costs
|
|
|
112,690
|
|
|
91,516
|
|
|
293,996
|
|
|
259,176
|
|
Provision
for
depreciation
|
|
|
19,659
|
|
|
18,435
|
|
|
59,721
|
|
|
56,603
|
|
Amortization
of regulatory assets
|
|
|
84,388
|
|
|
84,271
|
|
|
223,012
|
|
|
216,705
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
-
|
|
|
(27,765
|
)
|
|
-
|
|
General
taxes
|
|
|
19,538
|
|
|
17,901
|
|
|
49,802
|
|
|
48,571
|
|
Income
taxes
|
|
|
55,729
|
|
|
35,099
|
|
|
110,578
|
|
|
70,555
|
|
Total
operating expenses and taxes
|
|
|
809,216
|
|
|
634,504
|
|
|
1,825,081
|
|
|
1,595,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
91,031
|
|
|
72,109
|
|
|
199,549
|
|
|
159,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
3,014
|
|
|
1,996
|
|
|
3,331
|
|
|
4,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
|
18,162
|
|
|
21,709
|
|
|
56,843
|
|
|
62,240
|
|
Allowance
for
borrowed funds used during construction
|
|
|
(497
|
)
|
|
(169
|
)
|
|
(1,337
|
)
|
|
(440
|
)
|
Deferred
interest
|
|
|
(1,069
|
)
|
|
(871
|
)
|
|
(2,896
|
)
|
|
(2,685
|
)
|
Other
interest expense
|
|
|
2,283
|
|
|
1,105
|
|
|
5,262
|
|
|
1,958
|
|
Net
interest
charges
|
|
|
18,879
|
|
|
21,774
|
|
|
57,872
|
|
|
61,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
75,166
|
|
|
52,331
|
|
|
145,008
|
|
|
102,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED
STOCK DIVIDEND REQUIREMENTS
|
|
|
125
|
|
|
125
|
|
|
375
|
|
|
375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
ON COMMON STOCK
|
|
$
|
75,041
|
|
$
|
52,206
|
|
$
|
144,633
|
|
$
|
102,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
75,166
|
|
$
|
52,331
|
|
$
|
145,008
|
|
$
|
102,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain on derivative hedges
|
|
|
102
|
|
|
173
|
|
|
208
|
|
|
217
|
|
Unrealized
loss on available for sale securities
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(8
|
)
|
Other
comprehensive income
|
|
|
102
|
|
|
173
|
|
|
208
|
|
|
209
|
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
|
42
|
|
|
(1,542
|
)
|
|
85
|
|
|
(1,546
|
)
|
Other
comprehensive income, net of tax
|
|
|
60
|
|
|
1,715
|
|
|
123
|
|
|
1,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
75,226
|
|
$
|
54,046
|
|
$
|
145,131
|
|
$
|
104,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to Jersey
Central Power & Light Company are an integral part of these
statements.
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
3,840,213
|
|
$
|
3,730,767
|
|
Less
-
Accumulated provision for depreciation
|
|
|
1,424,801
|
|
|
1,380,775
|
|
|
|
|
2,415,412
|
|
|
2,349,992
|
|
Construction
work in progress
|
|
|
85,335
|
|
|
75,012
|
|
|
|
|
2,500,747
|
|
|
2,425,004
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
143,937
|
|
|
138,205
|
|
Nuclear
fuel
disposal trust
|
|
|
164,070
|
|
|
159,696
|
|
Long-term
notes receivable from associated companies
|
|
|
19,751
|
|
|
20,436
|
|
Other
|
|
|
16,597
|
|
|
19,379
|
|
|
|
|
344,355
|
|
|
337,716
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
571
|
|
|
162
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,264,000 and $3,881,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
313,730
|
|
|
201,415
|
|
Associated
companies
|
|
|
1,171
|
|
|
86,531
|
|
Other
(less
accumulated provisions of $239,000 and $162,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
38,569
|
|
|
39,898
|
|
Materials
and
supplies, at average cost
|
|
|
1,863
|
|
|
2,435
|
|
Prepayments
and other
|
|
|
33,254
|
|
|
31,489
|
|
|
|
|
389,158
|
|
|
361,930
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
2,310,532
|
|
|
2,176,520
|
|
Goodwill
|
|
|
1,983,699
|
|
|
1,985,036
|
|
Other
|
|
|
2,850
|
|
|
4,978
|
|
|
|
|
4,297,081
|
|
|
4,166,534
|
|
|
|
$
|
7,531,341
|
|
$
|
7,291,184
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
Common
stock,
$10 par value, authorized 16,000,000 shares -
|
|
|
|
|
|
|
|
15,371,270
shares outstanding
|
|
$
|
153,713
|
|
$
|
153,713
|
|
Other
paid-in
capital
|
|
|
3,014,600
|
|
|
3,013,912
|
|
Accumulated
other comprehensive loss
|
|
|
(55,411
|
)
|
|
(55,534
|
)
|
Retained
earnings
|
|
|
104,904
|
|
|
43,271
|
|
Total
common
stockholder's equity
|
|
|
3,217,806
|
|
|
3,155,362
|
|
Preferred
stock
|
|
|
12,649
|
|
|
12,649
|
|
Long-term
debt
and other long-term obligations
|
|
|
1,017,478
|
|
|
1,238,984
|
|
|
|
|
4,247,933
|
|
|
4,406,995
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
167,045
|
|
|
16,866
|
|
Notes
payable
-
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
114,932
|
|
|
248,532
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
8,968
|
|
|
20,605
|
|
Other
|
|
|
162,583
|
|
|
124,733
|
|
Accrued
taxes
|
|
|
78,342
|
|
|
2,626
|
|
Accrued
interest
|
|
|
23,535
|
|
|
10,359
|
|
Other
|
|
|
152,638
|
|
|
65,130
|
|
|
|
|
708,043
|
|
|
488,851
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
1,410,659
|
|
|
1,268,478
|
|
Accumulated
deferred income taxes
|
|
|
670,514
|
|
|
645,741
|
|
Nuclear
fuel
disposal costs
|
|
|
173,591
|
|
|
169,884
|
|
Asset
retirement obligation
|
|
|
76,002
|
|
|
72,655
|
|
Retirement
benefits
|
|
|
100,567
|
|
|
103,036
|
|
Other
|
|
|
144,032
|
|
|
135,544
|
|
|
|
|
2,575,365
|
|
|
2,395,338
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
7,531,341
|
|
$
|
7,291,184
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to Jersey
Central Power & Light Company are an integral
part
of these blance sheets.
|
|
|
|
|
|
|
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
75,166
|
|
$
|
52,331
|
|
$
|
145,008
|
|
$
|
102,565
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
19,659
|
|
|
18,436
|
|
|
59,721
|
|
|
56,603
|
|
Amortization
of regulatory assets
|
|
|
84,388
|
|
|
84,269
|
|
|
223,012
|
|
|
216,704
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
-
|
|
|
(27,765
|
)
|
|
-
|
|
Deferred
purchased power and other costs
|
|
|
(42,381
|
)
|
|
(77,162
|
)
|
|
(168,646
|
)
|
|
(155,552
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(11,222
|
)
|
|
6,165
|
|
|
5,204
|
|
|
(13,582
|
)
|
Accrued
retirement benefit obligation
|
|
|
813
|
|
|
2,888
|
|
|
(2,468
|
)
|
|
(5,880
|
)
|
Accrued
compensation, net
|
|
|
671
|
|
|
1,547
|
|
|
(4,077
|
)
|
|
731
|
|
NUG
power
contract restructuring
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
52,800
|
|
Cash
collateral from suppliers
|
|
|
76,978
|
|
|
-
|
|
|
76,978
|
|
|
-
|
|
Pension
trust
contribution
|
|
|
-
|
|
|
(62,499
|
)
|
|
-
|
|
|
(62,499
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(39,897
|
)
|
|
(34,749
|
)
|
|
(25,626
|
)
|
|
(26,906
|
)
|
Materials
and
supplies
|
|
|
395
|
|
|
64
|
|
|
572
|
|
|
411
|
|
Prepayments
and other current assets
|
|
|
64,761
|
|
|
34,664
|
|
|
(1,764
|
)
|
|
(5,040
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(5,873
|
)
|
|
57,485
|
|
|
26,214
|
|
|
58,430
|
|
Accrued
taxes
|
|
|
18,498
|
|
|
(27,924
|
)
|
|
75,716
|
|
|
35,844
|
|
Accrued
interest
|
|
|
13,765
|
|
|
16,709
|
|
|
13,176
|
|
|
11,481
|
|
Other
|
|
|
6,928
|
|
|
27,603
|
|
|
23,982
|
|
|
8,539
|
|
Net
cash
provided from operating activities
|
|
|
262,649
|
|
|
99,827
|
|
|
419,237
|
|
|
274,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
300,000
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(4,321
|
)
|
|
(7,082
|
)
|
|
(67,648
|
)
|
|
(304,150
|
)
|
Short-term
borrowings, net
|
|
|
(164,172
|
)
|
|
(456
|
)
|
|
(133,600
|
)
|
|
(72,648
|
)
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(43,000
|
)
|
|
(40,000
|
)
|
|
(83,000
|
)
|
|
(60,000
|
)
|
Preferred
stock
|
|
|
(125
|
)
|
|
(125
|
)
|
|
(375
|
)
|
|
(375
|
)
|
Net
cash used
for financing activities
|
|
|
(211,618
|
)
|
|
(47,663
|
)
|
|
(284,623
|
)
|
|
(137,173
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(50,837
|
)
|
|
(52,507
|
)
|
|
(133,498
|
)
|
|
(135,932
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
15
|
|
|
(711
|
)
|
|
685
|
|
|
(1,122
|
)
|
Other
|
|
|
(50
|
)
|
|
1,049
|
|
|
(1,392
|
)
|
|
(416
|
)
|
Net
cash used
for investing activities
|
|
|
(50,872
|
)
|
|
(52,169
|
)
|
|
(134,205
|
)
|
|
(137,470
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase
(decrease) in cash and cash equivalents
|
|
|
159
|
|
|
(5
|
)
|
|
409
|
|
|
6
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
412
|
|
|
282
|
|
|
162
|
|
|
271
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
571
|
|
$
|
277
|
|
$
|
571
|
|
$
|
277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Stockholders
and Board of
Directors
of Jersey
Central
Power
&
Light
Company:
We
have reviewed
the accompanying consolidated balance sheet of Jersey Central Power
& Light
Company and its subsidiaries as of September 30, 2005, and the related
consolidated statements of income and comprehensive income and cash
flows for
each of the three-month and nine-month periods ended September 30,
2005 and
2004. 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, 2004, and the related consolidated statements of
income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which
contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in
Note 9 to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as
of
December 31, 2003 as discussed in Note 6 to those consolidated
financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to the
consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
JERSEY
CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
JCP&L
is a
wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
business in New Jersey, providing regulated electric transmission and
distribution services. JCP&L also provides generation services to those
customers electing to retain JCP&L as their power supplier. JCP&L has
restructured its electric rates into unbundled service charges and
transition
cost recovery charges. JCP&L continues to deliver power to homes and
businesses through its existing distribution system.
Results
of Operations
Earnings
on common
stock in the third quarter of 2005 increased to $75 million from $52
million in
the third quarter of 2004. During the first nine months of 2005, earnings
on
common stock increased to $145 million compared to $102 million for
the same
period of 2004. The increase in earnings for both periods was primarily
due to
higher operating revenues partially offset by increases in purchased
power
costs, other operating costs and income taxes. Other operating costs
in both
periods of 2005 included a charge of $16 million for potential awards
related to
a labor arbitration decision (see note 13 - Other Legal Matters).
Operating
revenues
increased $194 million or 27.4% in the third quarter and $270 million
or 15.4%
in the first nine months of 2005 compared with the same periods in
2004.
Increases in both periods were due to higher retail electric generation,
distribution and wholesale revenues.
Retail
generation
revenues increased by $82 million in the third quarter and $134 million
in the
first nine months of 2005 as compared to the previous year. Higher
KWH sales to
residential and commercial customers increased generation revenues
by $45
million in the third quarter and $81 million in the first nine months
of 2005.
Commercial generation revenue increased for the same periods of 2005
by $33
million and $54 million, respectively. The increases were attributable
to higher
KWH sales (residential - 14.9% and commercial - 20.3% in the third
quarter of
2005; residential - 15.3% and commercial - 13.4% for the first nine
months of
2005) primarily due to warmer weather and reduced customer shopping.
Generation
provided by alternative suppliers to residential and commercial customers
as a
percent of total sales delivered in JCP&L’s service area decreased by 6.9
and 4.6 percentage points, respectively, in the first nine months of
2005.
Industrial generation revenue increased by $4 million in the third
quarter, but
declined $2 million in the first nine months of 2005 reflecting the
effect of a
25.6% KWH sales increase in the third quarter and a 9.3% decline in
the first
nine months of 2005.
Revenues
from
wholesale sales increased by $49 million in the third quarter and $42
in the
first nine months of 2005 as compared to the previous year, principally
due to
increased prices in 2005. KWH sales to the wholesale sector increased
in the
quarter (5.5%) but declined for the first nine months (8.5%).
Distribution
revenues increased by $62 million in the third quarter and $96 million
in the
first nine months of 2005, as compared to the same periods of 2004,
due to
increased KWH deliveries to all customer sectors and higher composite
unit
prices, caused in part by the June 1, 2005 rate increase.
Changes
in KWH
sales by customer class in the three months and nine months ended
September 30, 2005 compared to the same periods of 2004 are
summarized in
the following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Electric
Generation:
|
|
|
|
|
|
Retail
|
|
|
17.2
|
%
|
|
13.4
|
%
|
Wholesale
|
|
|
5.5
|
%
|
|
(8.5
|
)%
|
Total
Electric Generation Sales
|
|
|
14.8
|
%
|
|
8.2
|
%
|
|
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
|
|
Residential
|
|
|
15.6
|
%
|
|
7.4
|
%
|
Commercial
|
|
|
13.4
|
%
|
|
6.7
|
%
|
Industrial
|
|
|
5.4
|
%
|
|
0.4
|
%
|
Total
Distribution Deliveries
|
|
|
13.4
|
%
|
|
6.2
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes increased by $175 million in the third quarter and
$230
million in the first nine months of 2005 compared with the same periods
of 2004.
The following table presents changes from the prior year by expense
category.
|
|
Three
|
|
Nine
|
|
Operating
Expenses and Taxes - Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
130
|
|
$
|
172
|
|
Other
operating costs
|
|
|
21
|
|
|
35
|
|
Provision
for
depreciation
|
|
|
1
|
|
|
3
|
|
Amortization
of regulatory assets
|
|
|
-
|
|
|
7
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
(28
|
)
|
General
taxes
|
|
|
2
|
|
|
1
|
|
Income
taxes
|
|
|
21
|
|
|
40
|
|
Net
increase in operating expenses and taxes
|
|
$
|
175
|
|
$
|
230
|
|
|
|
|
|
|
|
|
|
Purchased
power
costs increased by $130 million in the third quarter and $172 million
in the
first nine months of 2005 as compared to the same periods in 2004 due
to higher
KWH purchases to meet increased retail generation sales and, to a lesser
extent,
higher unit costs. Other operating costs increased $21 million in the
third
quarter of 2005 and $35 million in the first nine months of 2005 compared
to the
same periods of 2004, reflecting $16 million of expenses resulting
from a
JCP&L arbitration decision.
Deferral
of new
regulatory assets decreased expenses by $28 million in the first nine
months of
2005, reflecting the NJBPU’s (see Regulatory Matters) approval for JCP&L to
defer $28 million of previously incurred reliability expenses. Amortization
of
regulatory assets increased $7 million in the first nine months of
2005 due to
an increase in the level of MTC revenue recovery.
Capital
Resources and Liquidity
JCP&L’s
cash
requirements for the remainder of 2005 for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met with
cash from
operations.
Changes
in Cash
Position
As
of
September 30, 2005, JCP&L had $571,000 of cash and cash equivalents
compared with $162,000 as of December 31, 2004. The major sources
for
changes in these balances are summarized below.
Cash
Flows From
Operating Activities
Cash
provided from
operating activities in the third quarter and in the first nine months
of 2005
compared with the corresponding periods of 2004, were as follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
204
|
|
$
|
64
|
|
$
|
307
|
|
$
|
177
|
|
Pension
trust
contribution (2)
|
|
|
-
|
|
|
(37
|
)
|
|
-
|
|
|
(37
|
)
|
Working
capital and other
|
|
|
58
|
|
|
73
|
|
|
112
|
|
|
135
|
|
Total
cash
flows from operating activities
|
|
$
|
262
|
|
$
|
100
|
|
$
|
419
|
|
$
|
275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash earnings is a non-GAAP measure (see reconciliation
below).
(2)
Pension trust contribution net of $25 million of income tax
benefits.
|
|
|
|
|
|
|
|
|
|
Cash
earnings, as
disclosed in the table above, are not a measure of performance calculated
in
accordance with GAAP. JCP&L believes that cash earnings is a useful
financial measure because it provides investors and management with
an
additional means of evaluating its cash-based operating performance.
The
following table reconciles cash earnings with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
75
|
|
$
|
52
|
|
$
|
145
|
|
$
|
103
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
20
|
|
|
18
|
|
|
60
|
|
|
57
|
|
Amortization
of regulatory assets
|
|
|
84
|
|
|
84
|
|
|
223
|
|
|
217
|
|
Deferral
of
new regulatory assets
|
|
|
-
|
|
|
-
|
|
|
(28
|
)
|
|
-
|
|
Deferred
purchased power and other costs
|
|
|
(42
|
)
|
|
(77
|
)
|
|
(169
|
)
|
|
(156
|
)
|
Deferred
income taxes & investment tax credits, net
|
|
|
(11
|
)
|
|
(19
|
)
|
|
5
|
|
|
(39
|
)
|
Other
non-cash items
|
|
|
78
|
|
|
6
|
|
|
71
|
|
|
(5
|
)
|
Cash
earnings
(Non-GAAP)
|
|
$
|
204
|
|
$
|
64
|
|
$
|
307
|
|
$
|
177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
$140 million
and $130 million increases in cash earnings for the third quarter and
the first
nine months of 2005, respectively, are described above under “Results of
Operations”. The $15 million and $23 million decrease for the third quarter and
the first nine months of 2005 from working capital primarily resulted
from a
reduction in accounts payables partially offset by an increase in accrued
taxes.
In the first nine months of 2004, JCP&L received $52.8 million in connection
with restructuring a NUG power contract.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities was $212 million in the third quarter of 2005
compared to
$48 million in the third quarter of 2004. The increase resulted from
redemptions
of short-term debt in the third quarter of 2005. Net cash used for
financing
activities was $285 million for the first nine months of 2005 and $137
million
for the same period of 2004. The $148 million increase resulted from
a $124
million increase in net debt redemptions and a $23 million increase
in common
stock dividends to FirstEnergy.
JCP&L
had
approximately $571,000 of cash and temporary investments and $115 million
of
short-term indebtedness as of September 30, 2005. JCP&L has
authorization from the SEC to incur short-term debt up to its charter
limit of
$1.8 billion (including the utility money pool). JCP&L will not issue FMB
other than as collateral for senior notes, since its senior note indentures
prohibit (subject to certain exceptions) JCP&L from issuing any debt which
is senior to the senior notes. As of September 30, 2005, JCP&L had the
capability to issue $673 million of additional senior notes based upon
FMB
collateral. Based upon applicable earnings coverage tests and its charter,
JCP&L could issue $976 million of preferred stock (assuming no additional
debt was issued) as of September 30, 2005.
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as Borrowers, entered into a syndicated $2 billion five-year revolving
credit
facility. Borrowings under the facility are available to each Borrower
separately and mature on the earlier of 364 days from the date of borrowing
or
the commitment termination date, as the same may be extended. JCP&L’s
borrowing limit under the facility is $425 million.
JCP&L
has the
ability to borrow from FirstEnergy and its regulated affiliates to
meet its
short-term working capital requirements. FESC administers this money
pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries.
Companies
receiving a loan under the money pool agreements must repay the principal,
together with accrued interest, within 364 days of borrowing the funds.
The rate
of interest is the same for each company receiving a loan from the
pool and is
based on the average cost of funds available through the pool. The
average
interest rate for borrowings was 3.50% in the third quarter of 2005
and 3.03% in
the first nine months of 2005.
JCP&L’s
access
to capital markets and costs of financing are influenced by the ratings
of its
securities and the securities of FirstEnergy. The
ratings outlook
from S&P and Fitch on all securities is stable. Moody’s outlook on all
securities is positive.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements
in its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by
one notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the
nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base
load
generation fleet, low-risk transmission and distribution operations
and rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also
noted as
strengths.
Cash
Flows From
Investing Activities
Net
cash used for
investing activities was $51 million in the third quarter and $134
million for
the first nine months of 2005 compared to $52 million and $137 million
for the
same periods of 2004. JCP&L’s capital spending for the period 2005-2007 is
expected to be about $511 million of which approximately $185 million
applies to
2005. In the last quarter of 2005, capital requirements for property
additions
and improvements are expected to be about $52 million.
Market
Risk Information
JCP&L
uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price fluctuations. FirstEnergy’s Risk Policy
Committee, comprised of members of senior management, provides general
management oversight to risk management activities.
Commodity
Price
Risk
JCP&L
is
exposed to price risk primarily due to fluctuating electricity and
natural gas
prices. To manage the volatility relating to these exposures, it uses
a variety
of non-derivative and derivative instruments, including forward contracts,
options and futures contracts. The derivatives are used for hedging
purposes.
Most of its non-hedge derivative contracts represent non-trading positions
that
do not qualify for hedge treatment under SFAS 133. As of September 30,
2005, JCP&L had commodity derivative contracts with a fair value of $14
million. A decrease of $1 million in the value of this asset was recorded
in the
first nine months of 2005 as a decrease in a regulatory liability,
and
therefore, had no impact on net income.
The
valuation of
derivative commodity contracts is based on observable market information
to the
extent that such information is available. In cases where such information
is
not available, JCP&L relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate
of related
price volatility. JCP&L uses these results to develop estimates of fair
value for financial reporting purposes and for internal management
decision
making. Sources of information for valuation of derivative contracts
as of
September 30, 2005 are summarized by year in the following
table:
Sources
of Information
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
|
|
2005(1)
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
Thereafter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
based
on external sources(2)
|
|
|
|
|
$
|
3
|
|
$
|
2
|
|
$
|
3
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
8
|
|
Prices
based
on models
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
6
|
|
Total
|
|
|
|
|
$
|
3
|
|
$
|
2
|
|
$
|
3
|
|
$
|
2
|
|
$
|
2
|
|
$
|
2
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) For
the last quarter of 2005.
(2) Broker
quote sheets.
|
JCP&L
performs
sensitivity analyses to estimate its exposure to the market risk of
its
commodity position. A hypothetical 10% adverse shift in quoted market
prices in
the near term on derivative instruments would not have had a material
effect on
its consolidated financial position or cash flows as of September 30,
2005.
Equity
Price
Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at
their current
market value of approximately $82 million and $80 million as of
September 30, 2005 and December 31, 2004, respectively.
A hypothetical
10% decrease in prices quoted by stock exchanges would result in an
$8 million
reduction in fair value as of September 30, 2005.
Regulatory
Matters
Regulatory
assets
are costs which have been authorized by the NJBPU and the FERC for
recovery from
customers in future periods and, without such authorization, would
have been
charged to income when incurred. JCP&L's regulatory assets as of
September 30, 2005 and December 31, 2004 were $2.3 billion
and $2.2
billion, respectively.
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 MTC rates. As of
September 30, 2005, the accumulated deferred cost balance totaled
approximately $508 million. New Jersey law allows for securitization
of
JCP&L's deferred balance upon application by JCP&L and a determination
by the NJBPU that the conditions of the New Jersey restructuring legislation
are
met. On February 14, 2003, JCP&L filed for approval of the
securitization of the July 31, 2003 deferred balance. JCP&L is in
discussions with the NJBPU staff as a result of the stipulated settlement
agreements (as further discussed below) which recommended that the
NJBPU issue
an order regarding JCP&L's application. On July 20, 2005, JCP&L
requested the NJBPU to set a procedural schedule for this matter and
is awaiting
NJBPU action.
The
2003 NJBPU
decision on JCP&L's base electric rate proceeding (the Phase I Order)
disallowed certain regulatory assets and provided for an interim return
on
equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a
Phase II proceeding in which the NJBPU would review whether JCP&L is in
compliance with current service reliability and quality standards and
determine
whether the expenditures and projects undertaken by JCP&L to increase its
system reliability are prudent and reasonable for rate recovery. Depending
on
its assessment of JCP&L's service reliability, the NJBPU could have
increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On
August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an
interim motion and a supplemental and amended motion for rehearing
and
reconsideration of the Phase I Order, respectively. On July 7,
2004, the
NJPBU granted limited reconsideration and rehearing on the following
issues: (1)
deferred cost disallowances; (2) the capital structure including the
rate of
return; (3) merger savings, including amortization of costs to achieve
merger
savings; and (4) decommissioning costs.
On
July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for the recovery
of system
reliability costs and a 9.75% return on equity. The filing also requested
an
increase to the MTC deferred balance recovery of approximately $20
million
annually.
On
May 25,
2005, the NJBPU approved two stipulated settlement agreements. The
first
stipulation between JCP&L and the NJBPU staff resolves all of the issues
associated with JCP&L's motion for reconsideration of the Phase I Order. The
second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate
resolves all of the issues associated with JCP&L's Phase II proceeding. The
stipulated settlements provide for, among other things, the
following:
· An
annual increase
in distribution revenues of $23 million effective June 1, 2005,
associated
with the
Phase I
Order
reconsideration;
· An
annual increase
in distribution revenues of $36 million effective June 1, 2005,
related to
JCP&L's
Phase II
Petition;
· An
annual reduction
in both rates and amortization expense of $8 million, effective June 1,
2005, in
anticipation
of an
NJBPU order regarding JCP&L's request to securitize up to $277 million of
its deferred
cost
balance;
· An
increase in
JCP&L's authorized return on common equity from 9.5% to 9.75%;
and
· A
commitment by
JCP&L to maintain a target level of customer service reliability with a
reduction in
JCP&L's
authorized return on common equity from 9.75% to 9.5% if the target
is not met
for two
consecutive
quarters.
The authorized return on common equity would then be restored to 9.75%
if
the
target
is met for two
consecutive quarters.
The
Phase II
stipulation included an agreement that the distribution revenue increase
also
reflects a three-year amortization of JCP&L's one-time service reliability
improvement costs incurred in 2003-2005. This resulted in the creation
of a
regulatory asset associated with accelerated tree trimming and other
reliability
costs which were expensed in 2003 and 2004. The establishment of the
new
regulatory asset of approximately $28 million resulted in an increase
to net
income of approximately $16 million ($0.05 per share of FirstEnergy
common
stock) in the second quarter of 2005.
JCP&L
sells all
self-supplied energy (NUGs and owned generation) to the wholesale
market with
offsetting credits to its deferred energy balance with the exception
of 300 MW
from JCP&L's NUG committed supply currently being used to serve BGS
customers pursuant to NJBPU order for the period June 1, 2005
through May
31, 2006. New BGS tariffs reflecting the results of a February 2005
auction for
the BGS supply became effective June 1, 2005. On July 1,
2005,
JCP&L filed its BGS procurement proposals for post transition year four.
The
auction is scheduled to take place in February 2006 for the annual
supply period
beginning June 1, 2006.
In
accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting a continuation of the current level and duration
of the funding
of TMI-2 decommissioning costs by New Jersey customers without a
reduction,
termination or capping of the funding. On September 30, 2004,
JCP&L
filed an updated TMI-2 decommissioning study. This study resulted
in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars)
compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The Ratepayer Advocate filed comments on
February 28, 2005. On March 18, 2005, JCP&L filed a response to
those comments. A schedule for further proceedings has not yet been
set.
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. On March 29,
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 a Special
Reliability Master who made recommendations on appropriate courses
of action
necessary to ensure system-wide reliability. The Stipulation also
incorporates
the Executive Summary and Recommendation portions of the final report
of a
focused audit of JCP&L's Planning and Operations and Maintenance programs
and practices (Focused Audit). A final order in the Focused Audit
docket was
issued by the NJBPU on July 23, 2004. On February 11,
2005, JCP&L
met with the Ratepayer Advocate to discuss reliability improvements.
JCP&L
continues to file compliance reports reflecting activities associated
with the
MOU and Stipulation.
On
January 31,
2005, certain PJM transmission owners made three filings 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. Second,
the FERC
approved the proposed Schedule 12 rate harmonization. Third, the
FERC accepted
the proposed formula rate, subject to referral and hearing procedures.
On
September 30, 2005, the PJM transmission owners filed a request
for
rehearing of the May 31, 2005 order. The rate design and formula
rate
filings continue to be litigated before the FERC. The outcome of
these two cases
cannot be predicted.
See
Note 14 to the
consolidated financial statements for further details and a complete
discussion
of regulatory matters in New Jersey.
Environmental
Matters
JCP&L
accrues
environmental liabilities when it concludes that it is probable that
it has an
obligation for such costs and can reasonably estimate the amount
of such costs.
Unasserted claims are reflected in JCP&L’s determination of environmental
liabilities and are accrued in the period that they are both probable
and
reasonably estimable.
JCP&L
has been
named a PRP at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation and Liability
Act of 1980.
Allegations of disposal of hazardous substances at historical sites
and the
liability involved are often unsubstantiated and subject to dispute;
however,
federal law provides that all PRPs for a particular site are liable
on a joint
and several basis. Therefore, environmental liabilities that are
considered
probable have been recognized on the Consolidated Balance Sheet as
of
September 30, 2005, based on estimates of the total costs
of cleanup,
JCP&L's proportionate responsibility for such costs and the financial
ability of other nonaffiliated 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. Included in Other Noncurrent Liabilities are
accrued
liabilities aggregating approximately $46.8 million as of September 30,
2005.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to normal business operations pending against JCP&L. 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. On September 8, 2004, the New Jersey Supreme Court denied
the
motions filed by plaintiffs and JCP&L for leave to appeal the decision of
the Appellate Division. JCP&L has filed a motion for summary judgment.
FirstEnergy is unable to predict the outcome of these matters and no
liability
has been accrued as of September 30, 2005.
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 concludes, 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 website (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 also is proceeding
with the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as
of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. 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. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the
proceeding.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State
Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this
matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome
of any of
these proceedings or whether any further regulatory proceedings or
legal actions
may be initiated against the Companies. In particular, if FirstEnergy
or its
subsidiaries were ultimately determined to have legal liability in
connection
with these proceedings, it could have a material adverse effect on
FirstEnergy's
or its subsidiaries' financial condition, results of operations and
cash
flows.
Other
Legal
Matters
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond
to
emergency power outages. On May 20, 2004, an arbitration panel
concluded
that the call-out procedure violated the parties’ collective bargaining
agreement. At the conclusion of the June 1, 2005 hearing, the
Arbitrator
decided not to hear testimony on damages and closed the proceedings.
On
September 9, 2005, the Arbitrator issued an opinion to award
approximately
$16.1 million to the bargaining unit employees. JCP&L initiated an appeal of
this award by filing a motion to vacate in Federal Court in New Jersey
on
October 18, 2005. JCP&L recognized a liability for the potential $16.1
million award during the three months ended September 30,
2005.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two
or more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement,
the EITF
reached a consensus that an exchange of inventory should be accounted
for at
fair value. Although electric power is not capable of being held in
inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, JCP&L will adopt this EITF
effective for new arrangements entered into, or modifications or renewals
of
existing arrangements, in interim or annual periods beginning after
March 15, 2006.
|
EITF
Issue No. 05-6, "Determining the Amortization Period for
Leasehold
Improvements Purchased after Lease Inception or Acquired
in a Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6.
EITF 05-6
addresses the amortization period for leasehold improvements that were
either
acquired in a business combination or placed in service significantly
after and
not contemplated at or near the beginning of the initial lease term.
For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that
includes
required lease periods and renewals that are deemed to be reasonably
assured at
the date of acquisition. Leasehold improvements that are placed in
service
significantly after and not contemplated at or near the beginning of
the lease
term should be amortized over the shorter of the useful life of the
assets or a
term that includes required lease periods and renewals that are deemed
to be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with JCP&L's current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for
the fair
value of an asset retirement obligation that is conditional on a future
event,
if the fair value of the liability can be reasonably estimated. In
instances
where there is insufficient information to estimate the liability,
the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair
value
cannot be reasonably estimated, that fact and the reasons why must
be disclosed.
This Interpretation is effective for JCP&L in the fourth quarter of 2005.
JCP&L is currently evaluating the effect this Interpretation will have
on its financial statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement
of APB Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and
reporting a
change in accounting principle. It applies to all voluntary changes
in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions.
This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect
of the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of
the
beginning of the earliest period for which retrospective application
is
practicable and that a corresponding adjustment be made to the opening
balance
of retained earnings (or other appropriate components of equity or
net assets in
the statement of financial position) for that period rather than being
reported
in the Consolidated Statements of Income. This Statement also requires
that a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate
affected
by a change in accounting principle. The provisions of this Statement
are
effective for accounting changes and corrections of errors made in
fiscal years
beginning after December 15, 2005. JCP&L will adopt this Statement
effective January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion
No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the
assets
exchanged. The guidance in APB 29 included certain exceptions to that
principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows
of the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for
FirstEnergy.
This FSP is not expected to have a material impact on JCP&L's financial
statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
of idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may
be “so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as
current
period costs. In addition, this Statement requires that allocation
of fixed
production overheads to the cost of conversion be based on the normal
capacity
of the production facilities. The provisions of this statement are
effective for
inventory costs incurred by JCP&L beginning January 1, 2006. JCP&L
is currently evaluating this Standard and does not expect it to have
a material
impact on the financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application
to Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1.
FSP FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security
Whose Cost
Exceeds Fair Value," (2) clarify that an investor should recognize
an impairment
loss no later than when the impairment is deemed other than temporary,
even if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP
in the fourth
quarter of 2005, which would require prospective application for reporting
periods beginning after December 15, 2005. JCP&L is currently evaluating
this FSP and any impact on its investments.
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
333,180
|
|
$
|
285,419
|
|
$
|
892,097
|
|
$
|
788,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
186,148
|
|
|
146,938
|
|
|
467,911
|
|
|
421,660
|
|
Other
operating costs
|
|
|
81,774
|
|
|
50,141
|
|
|
192,892
|
|
|
130,210
|
|
Provision
for
depreciation
|
|
|
9,323
|
|
|
10,648
|
|
|
32,221
|
|
|
30,370
|
|
Amortization
of regulatory assets
|
|
|
32,853
|
|
|
30,291
|
|
|
86,760
|
|
|
78,737
|
|
General
taxes
|
|
|
19,906
|
|
|
18,680
|
|
|
56,201
|
|
|
53,103
|
|
Income
taxes
|
|
|
(2,111
|
)
|
|
8,448
|
|
|
9,754
|
|
|
17,179
|
|
Total
operating expenses and taxes
|
|
|
327,893
|
|
|
265,146
|
|
|
845,739
|
|
|
731,259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
5,287
|
|
|
20,273
|
|
|
46,358
|
|
|
57,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
6,459
|
|
|
6,888
|
|
|
19,897
|
|
|
18,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
|
8,941
|
|
|
8,823
|
|
|
27,886
|
|
|
31,208
|
|
Allowance
for
borrowed funds used during construction
|
|
|
(150
|
)
|
|
(65
|
)
|
|
(401
|
)
|
|
(208
|
)
|
Other
interest expense
|
|
|
1,950
|
|
|
1,326
|
|
|
5,626
|
|
|
2,846
|
|
Net
interest
charges
|
|
|
10,741
|
|
|
10,084
|
|
|
33,111
|
|
|
33,846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
1,005
|
|
|
17,077
|
|
|
33,144
|
|
|
41,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
84
|
|
|
84
|
|
|
252
|
|
|
(3,182
|
)
|
Unrealized
gain (loss) on available for sale securities
|
|
|
67
|
|
|
-
|
|
|
67
|
|
|
(53
|
)
|
Other
comprehensive income (loss)
|
|
|
151
|
|
|
84
|
|
|
319
|
|
|
(3,235
|
)
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
|
62
|
|
|
(1,314
|
)
|
|
132
|
|
|
(1,342
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
89
|
|
|
1,398
|
|
|
187
|
|
|
(1,893
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$
|
1,094
|
|
$
|
18,475
|
|
$
|
33,331
|
|
$
|
39,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they relate
to Metropolitan
Edison Company are an integral part of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
1,841,450
|
|
$
|
1,800,569
|
|
Less
-
Accumulated provision for depreciation
|
|
|
712,549
|
|
|
709,895
|
|
|
|
|
1,128,901
|
|
|
1,090,674
|
|
Construction
work in progress
|
|
|
7,458
|
|
|
21,735
|
|
|
|
|
1,136,359
|
|
|
1,112,409
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
229,437
|
|
|
216,951
|
|
Long-term
notes receivable from associated companies
|
|
|
11,162
|
|
|
10,453
|
|
Other
|
|
|
29,355
|
|
|
34,767
|
|
|
|
|
269,954
|
|
|
262,171
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
120
|
|
|
120
|
|
Notes
receivable from associated companies
|
|
|
15,793
|
|
|
18,769
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,320,000 and $4,578,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
131,213
|
|
|
119,858
|
|
Associated
companies
|
|
|
1,401
|
|
|
118,245
|
|
Other
|
|
|
7,684
|
|
|
15,493
|
|
Prepayments
and other
|
|
|
13,285
|
|
|
11,057
|
|
|
|
|
169,496
|
|
|
283,542
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
867,649
|
|
|
869,585
|
|
Regulatory
assets
|
|
|
571,745
|
|
|
693,133
|
|
Other
|
|
|
24,055
|
|
|
24,438
|
|
|
|
|
1,463,449
|
|
|
1,587,156
|
|
|
|
$
|
3,039,258
|
|
$
|
3,245,278
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
Common
stock,
without par value, authorized 900,000 shares -
|
|
|
|
|
|
|
|
859,500
shares
outstanding
|
|
$
|
1,290,296
|
|
$
|
1,289,943
|
|
Accumulated
other comprehensive loss
|
|
|
(43,303
|
)
|
|
(43,490
|
)
|
Retained
earnings
|
|
|
28,110
|
|
|
38,966
|
|
Total
common
stockholder's equity
|
|
|
1,275,103
|
|
|
1,285,419
|
|
Long-term
debt
and other long-term obligations
|
|
|
594,116
|
|
|
701,736
|
|
|
|
|
1,869,219
|
|
|
1,987,155
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
100,000
|
|
|
30,435
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
76,755
|
|
|
80,090
|
|
Other
|
|
|
-
|
|
|
-
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
39,505
|
|
|
88,879
|
|
Other
|
|
|
30,966
|
|
|
26,097
|
|
Accrued
taxes
|
|
|
2,247
|
|
|
11,957
|
|
Accrued
interest
|
|
|
9,462
|
|
|
11,618
|
|
Other
|
|
|
20,008
|
|
|
23,076
|
|
|
|
|
278,943
|
|
|
272,152
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
309,979
|
|
|
305,389
|
|
Accumulated
deferred investment tax credits
|
|
|
10,250
|
|
|
10,868
|
|
Power
purchase
contract loss liability
|
|
|
250,024
|
|
|
349,980
|
|
Asset
retirement obligation
|
|
|
139,216
|
|
|
132,887
|
|
Retirement
benefits
|
|
|
77,501
|
|
|
82,218
|
|
Nuclear
fuel
disposal costs
|
|
|
39,213
|
|
|
38,408
|
|
Other
|
|
|
64,913
|
|
|
66,221
|
|
|
|
|
891,096
|
|
|
985,971
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
3,039,258
|
|
$
|
3,245,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
1,005
|
|
$
|
17,077
|
|
$
|
33,144
|
|
$
|
41,786
|
|
Adjustments
to reconcile net income to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
9,323
|
|
|
10,648
|
|
|
32,221
|
|
|
30,370
|
|
Amortization
of regulatory assets
|
|
|
32,853
|
|
|
30,291
|
|
|
86,760
|
|
|
78,737
|
|
Deferred
costs recoverable as regulatory assets
|
|
|
8,521
|
|
|
(15,629
|
)
|
|
(21,491
|
)
|
|
(45,616
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(8,438
|
)
|
|
666
|
|
|
(10,336
|
)
|
|
(4,853
|
)
|
Accrued
retirement benefit obligation
|
|
|
(1,514
|
)
|
|
(273
|
)
|
|
(4,717
|
)
|
|
492
|
|
Accrued
compensation, net
|
|
|
1,527
|
|
|
649
|
|
|
211
|
|
|
201
|
|
Pension
trust
contribution
|
|
|
-
|
|
|
(38,823
|
)
|
|
-
|
|
|
(38,823
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
3,088
|
|
|
(2,599
|
)
|
|
113,298
|
|
|
29,943
|
|
Materials
and
supplies
|
|
|
(1
|
)
|
|
5
|
|
|
(19
|
)
|
|
41
|
|
Prepayments
and other current assets
|
|
|
18,978
|
|
|
14,298
|
|
|
(2,209
|
)
|
|
(15,027
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
6,088
|
|
|
(12,536
|
)
|
|
(44,505
|
)
|
|
(17,857
|
)
|
Accrued
taxes
|
|
|
(4,526
|
)
|
|
(145
|
)
|
|
(9,710
|
)
|
|
(6,255
|
)
|
Accrued
interest
|
|
|
(1,269
|
)
|
|
(3,006
|
)
|
|
(2,156
|
)
|
|
(127
|
)
|
Other
|
|
|
(7,701
|
)
|
|
(7,356
|
)
|
|
(24,063
|
)
|
|
(9,581
|
)
|
Net
cash
provided from (used for) operating activities
|
|
|
57,934
|
|
|
(6,733
|
)
|
|
146,428
|
|
|
43,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
247,607
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
70,000
|
|
|
-
|
|
|
4,665
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
(45,936
|
)
|
|
(37,830
|
)
|
|
(196,371
|
)
|
Short-term
borrowings, net
|
|
|
(24,266
|
)
|
|
-
|
|
|
(3,335
|
)
|
|
-
|
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(10,000
|
)
|
|
(10,000
|
)
|
|
(44,000
|
)
|
|
(35,000
|
)
|
Net
cash
provided from (used for) financing activities
|
|
|
(34,266
|
)
|
|
14,064
|
|
|
(85,165
|
)
|
|
20,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(21,680
|
)
|
|
(12,390
|
)
|
|
(56,075
|
)
|
|
(33,733
|
)
|
Contributions
to nuclear decommissioning trusts
|
|
|
(2,370
|
)
|
|
(2,371
|
)
|
|
(7,112
|
)
|
|
(7,113
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(1,072
|
)
|
|
17,989
|
|
|
2,267
|
|
|
(13,046
|
)
|
Other
|
|
|
1,454
|
|
|
(10,559
|
)
|
|
(343
|
)
|
|
(10,441
|
)
|
Net
cash
provided used for investing activities
|
|
|
(23,668
|
)
|
|
(7,331
|
)
|
|
(61,263
|
)
|
|
(64,333
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(1
|
)
|
Cash
and cash
equivalents at beginning of period
|
|
|
120
|
|
|
120
|
|
|
120
|
|
|
121
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
120
|
|
$
|
120
|
|
$
|
120
|
|
$
|
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 Stockholders
and Board of
Directors
of
Metropolitan Edison Company:
We
have reviewed
the accompanying consolidated balance sheet of Metropolitan Edison
Company and
its subsidiaries as of September 30, 2005, and the related consolidated
statements of income and comprehensive income and cash flows
for each of the
three-month and nine-month periods ended September 30, 2005 and
2004. 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, 2004, and the related consolidated statements
of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which
contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed
in Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities
as of
December 31, 2003 as discussed in Note 6 to those consolidated
financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to
the consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
METROPOLITAN
EDISON COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
Met-Ed
is a wholly
owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts
business in
eastern Pennsylvania, providing regulated electric transmission
and distribution
services. Met-Ed also provides generation service to those customers
electing to
retain Met-Ed as their power supplier. Met-Ed has unbundled the
price for
electricity into its component elements - including generation,
transmission,
distribution and transition charges. Met-Ed continues to deliver
power to homes
and businesses through its existing distribution system.
Results
of Operations
Net
income
decreased to $1
million for the
third quarter of 2005 from $17 million in the third quarter of
2004. The
decrease
in net
income primarily resulted from higher purchased power costs,
transmission
expenses, and amortization of regulatory assets, partially offset
by higher
operating revenues and lower depreciation and income taxes. For
the first nine
months of 2005, net income decreased to $33 million from $42
million in the same
period of 2004. The decrease in net
income primarily
resulted from higher purchased power costs, transmission expenses,
and
amortization of regulatory assets, partially offset by higher
operating revenues
and other income and lower income taxes as discussed below.
Operating
revenues
increased by $48 million, or 16.7%, in the third quarter of 2005
and $104
million, or 13.2%, in the first nine months of 2005, compared
with the same
periods of 2004. Increases in both periods were due, in part,
to higher retail
generation electric revenues from all customer sectors ($17 million
for the
third quarter and $41 million for the first nine months of 2005).
The increases
in retail generation KWH sales for both periods of 2005 were
mainly attributable
to warmer weather and reduced customer shopping - primarily in
the industrial
sector. Industrial customer shopping decreased by 4.9% and 11.2%
percentage
points in the third quarter and first nine months of 2005, respectively.
While
higher generation sales in the third quarter of 2005 were offset
by slightly
lower composite unit prices, overall higher composite unit prices
during the
nine-month period also contributed to the increase in generation
revenues.
Revenues
from
distribution throughput increased by $13 million in the third
quarter and by $23
million in the first nine months of 2005 compared with the same
periods of 2004.
Increases in both periods of 2005 were primarily due to higher
KWH deliveries
and slightly higher unit prices. Increased transmission revenues
of $17 million
in the third quarter and $32 million in the first nine months
of 2005 also
contributed to higher operating revenues. These increases were
due to a change
in the power supply agreement with FES in the second quarter
of 2004. This
change also resulted in higher transmission expenses as discussed
further below.
In the first nine months of 2005, operating revenues also included
a $4 million
payment received under a contract provision associated with the
prior sale of
TMI Unit 1. Under the contract, additional payments are received
if subsequent
energy prices rise above specific levels and are credited to
Met-Ed’s customers,
resulting in no net impact to earnings.
Changes
in KWH
sales by customer class in the three months and nine months ended
September 30, 2005 compared to the same periods of 2004
are summarized in
the following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
|
Residential
|
|
|
15.5
|
%
|
|
7.6
|
%
|
Commercial
|
|
|
10.1
|
%
|
|
7.6
|
%
|
Industrial
|
|
|
9.1
|
%
|
|
17.0
|
%
|
Total
Retail Electric Generation Sales
|
|
|
11.9
|
%
|
|
9.9
|
%
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
15.5
|
%
|
|
7.5
|
%
|
Commercial
|
|
|
10.0
|
%
|
|
6.7
|
%
|
Industrial
|
|
|
3.2
|
%
|
|
1.9
|
%
|
Total
Distribution Deliveries
|
|
|
10.0
|
%
|
|
5.6
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes increased by $63 million in the third quarter
and by $114
million in the first nine months of 2005 compared with the same
periods of 2004.
The following table presents changes from the prior year by expense
category:
|
|
Three
|
|
Nine
|
|
Operating
Expenses and Taxes - Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
39
|
|
$
|
46
|
|
Other
operating costs
|
|
|
32
|
|
|
62
|
|
Provision
for
depreciation
|
|
|
(1
|
)
|
|
2
|
|
Amortization
of regulatory assets
|
|
|
3
|
|
|
8
|
|
General
taxes
|
|
|
1
|
|
|
3
|
|
Income
taxes
|
|
|
(11
|
) |
|
(7
|
) |
Net
increase in operating expenses and taxes
|
|
$
|
63
|
|
$
|
114
|
|
|
|
|
|
|
|
|
|
Purchased
power
costs increased by $39 million in the third quarter and $46
million in the first
nine months of 2005 compared with the same periods of 2004.
The increases in
both periods were primarily due to increased third party power
purchases ($47
million in the third quarter and $92 million in the first nine
months of 2005)
and NUG contract purchases ($21 million in the third quarter
and $29 million in
the first nine months of 2005) partially offset by reduced
purchased power from
FES ($30 million in the third quarter and $77 million in the
first nine months
of 2005). These changes, for both periods, were due to increased
KWH purchased
to meet increased retail generation sales requirements offset
by slightly lower
unit costs.
Other
operating
costs increased by $32 million in the third quarter and by
$62 million in first
nine months of 2005 compared with the same periods of 2004.
The increases in
both periods were primarily caused by higher PJM congestion
charges and
transmission expenses as a result of the change in the power
supply agreement
with FES discussed above.
In
the first nine
months of 2005, depreciation expense increased due to additions
to the asset
base and higher costs to decommission the Saxton nuclear plant
as compared to
the same period of 2004. For both periods of 2005, regulatory
asset amortization
reflected increases associated with the level of CTC revenue
recovery, partially
offset by lower amortization related to above market NUG costs
as compared to
the prior year periods.
General
taxes
increased in both periods primarily as a result of higher gross
receipt taxes
associated with the increase in KWH sales. Income taxes decreased
in the third
quarter and first nine months of 2005 due to lower taxable
income.
Capital
Resources and Liquidity
Met-Ed’s
cash
requirements for the remainder of 2005, for operating expenses,
construction
expenditures and scheduled debt maturities are expected to
be met with cash from
operations.
Changes
in Cash
Position
As
of
September 30, 2005, Met-Ed’s cash and cash equivalents of $120,000 remained
unchanged from December 31, 2004.
Cash
Flows From
Operating Activities
Cash
provided from
(used for) operating activities during the third quarter and
first nine months
of 2005, compared with the corresponding periods of 2004 were
as
follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
43
|
|
$
|
27
|
|
$
|
116
|
|
$
|
85
|
|
Pension
trust
contribution (2)
|
|
|
-
|
|
|
(23
|
)
|
|
-
|
|
|
(23
|
)
|
Working
capital and other
|
|
|
15
|
|
|
(11
|
)
|
|
30
|
|
|
(19
|
)
|
Total
cash
flows from operating activities
|
|
$
|
58
|
|
$
|
(7
|
)
|
$
|
146
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash
earnings is a non-GAAP measure (see reconciliation below).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
Pension
trust
contribution net of $16 million of income tax benefits.
|
|
|
|
|
|
|
|
Cash
earnings, as
disclosed in the table above, are not a measure of performance
calculated in
accordance with GAAP. Met-Ed believes that cash earnings is a
useful financial
measure because it provides investors and management with an
additional means of
evaluating its cash-based operating performance. The following
table reconciles
cash earnings with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(GAAP)
|
|
$
|
1
|
|
$
|
17
|
|
$
|
33
|
|
$
|
42
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
9
|
|
|
11
|
|
|
32
|
|
|
30
|
|
Amortization
of regulatory assets
|
|
|
33
|
|
|
30
|
|
|
87
|
|
|
79
|
|
Deferred
costs recoverable as regulatory assets
|
|
|
8
|
|
|
(16
|
)
|
|
(22
|
)
|
|
(46
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(8
|
)
|
|
(16
|
)
|
|
(10
|
)
|
|
(21
|
)
|
Other
non-cash charges
|
|
|
-
|
|
|
1
|
|
|
(4
|
)
|
|
1
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
43
|
|
$
|
27
|
|
$
|
116
|
|
$
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
$16 million and
$31 million increases in cash earnings for the third quarter
and first nine
months of 2005, respectively, are described above under “Results of Operations”.
Net cash from operating activities increased in the third quarter
and the first
nine months due to the absence of a $23 million after-tax voluntary
pension
contribution made in the third quarter of 2004. The $26 million
change in
working capital in the third quarter of 2005 primarily resulted
from changes of
$6 million in accounts receivable, $19 million in accounts payable
and $5
million in prepayments, offset by a change of $4 million in accrued
taxes. The
$49 million change in working capital for the first nine months
of 2005
primarily resulted from net changes in accounts receivable and
accounts payable
from associated companies of $52 million and $13 million in prepayments,
partially offset by changes of $11 million in customer deposits,
$3 million in
accrued taxes and $2 million in accrued interest.
Cash
Flows From
Financing Activities
For
the third
quarter of 2005, net cash used for financing activities was $34
million compared
to $14 million of cash provided from financing activities in
the third quarter
of 2004. The $48 million decrease resulted primarily from a $70
million
reduction in new debt financing compared to the third quarter
of 2004 offset in
part by a $22 million reduction in debt redemptions. For the
first nine months
of 2005, net cash used for financing activities was $85 million
compared to $21
million of net cash provided from financing activities in the
same period of
2004. The $106 million change reflected a $252 million reduction
in new debt
financing and a $9 million increase in common stock dividends
to FirstEnergy,
partially offset by a $155 million decrease in debt redemptions
compared to the
same period of 2004.
As
of
September 30, 2005, Met-Ed had approximately $16 million
of cash and
temporary investments (including short-term notes receivable
from associated
companies) and $77 million of short-term borrowings outstanding.
Met-Ed has
authorization from the SEC to incur short-term debt up to $250
million
(including the utility money pool). Under the terms of Met-Ed’s senior note
indenture, no more first mortgage bonds can be issued as long
as the senior
bonds are outstanding. Met-Ed had no restrictions on the issuance
of preferred
stock.
Met-Ed
Funding LLC
(Met-Ed Funding), a wholly owned subsidiary of Met-Ed, is a limited
liability
company whose borrowings are secured by customer accounts receivable
purchased
from Met-Ed. Met-Ed Funding can borrow up to $80 million under
a receivables
financing arrangement. As a separate legal entity with separate
creditors,
Met-Ed Funding would have to satisfy its obligations to creditors
before any of
its remaining assets could be made available to Met-Ed. On July
15, 2005, the
facility was renewed until June 29, 2006. As of September 30,
2005,
the facility was undrawn. The annual facility fee is 0.25% on the
entire finance
limit.
Met-Ed
has the
ability to borrow from its regulated affiliates and FirstEnergy
to meet its
short-term working capital requirements. FESC administers this
money pools and
tracks surplus funds of FirstEnergy and the respective regulated
subsidiaries,
as well as proceeds available from bank borrowings. Companies receiving
a loan
under the money pool agreements must repay the principal amount
of the loan,
together with accrued interest, within 364 days of borrowing the
funds. The rate
of interest is the same for each company receiving a loan from
the pool and is
based on the average cost of funds available through the pool.
The average
interest rate for borrowings in the third quarter of 2005 was
3.50%.
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as borrowers, entered into a syndicated $2 billion five-year revolving
credit
facility. Borrowings under the facility are available to each borrower
separately and mature on the earlier of 364 days from the date
of borrowing or
the commitment termination date, as the same may be extended. Met-Ed’s borrowing
limit under the facility is $250 million.
Met-Ed’s
access to
capital markets and costs of financing are dependent on the ratings
of its
securities and that of FirstEnergy. The ratings outlook from S&P and Fitch
on all securities is stable. Moody’s outlook on all securities is
positive.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries
to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear
operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses
and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements
in its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC
to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC
by one notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for
the nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost
base load
generation fleet, low-risk transmission and distribution operations
and rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also
noted as
strengths.
Cash
Flows From
Investing Activities
In
the third
quarter of 2005, net cash used for investing activities totaled
$24 million,
compared to $7 million in the third quarter of 2004. The change
in the third
quarter of 2005 primarily resulted from a $19 million increase
in loan
repayments to associated companies and a $9 million increase in
property
additions, partially offset by a $9 million capital transfer from
FESC in the
third quarter of 2004. In the first nine months of 2005, net cash
used for
investing activities totaled $61 million compared to $64 million
in the same
period of 2004. The change resulted from a $15 million increase
in loan
repayments from associated companies and the previously mentioned
capital
transfer, partially offset by a $22 million increase in property
additions.
Expenditures for property additions primarily support Met-Ed’s energy delivery
operations.
Met-Ed's
capital
spending for the period 2005 through 2007 is expected to be about
$205 million,
of which approximately $68 million applies to 2005. In the last
quarter of 2005,
capital requirements for property additions are expected to be
about $14
million. These cash requirements are expected to be satisfied from
internal cash
and short-term credit arrangements. Met-Ed has no additional requirements
for
maturing long-term debt during the remainder of 2005.
Market
Risk Information
Met-Ed
uses various
market risk sensitive instruments, including derivative contracts,
primarily to
manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk
Policy Committee, comprised of members of senior management, provides
general
management oversight to risk management activities.
Commodity
Price
Risk
Met-Ed
is exposed
to price risk primarily resulting from fluctuating electricity
and natural gas
prices. To manage the volatility relating to these exposures,
it uses a variety
of non-derivative and derivative instruments, including options
and futures
contracts. The derivatives are used for hedging purposes. Most
of Met-Ed's
non-hedge derivative contracts represent non-trading positions
that do not
qualify for hedge treatment under SFAS 133. As of September 30,
2005,
Met-Ed’s commodity derivative contract was an embedded option with a
fair value
of $28 million. A $4 million net decrease in the value of this
asset was
recorded as a decrease in regulatory liabilities, and therefore,
had no impact
on net income.
The
valuation of
derivative commodity contracts is based on observable market
information to the
extent that such information is available. In cases where such
information is
not available, Met-Ed relies on model-based information. The
model provides
estimates of future regional prices for electricity and an estimate
of related
price volatility. Met-Ed uses these results to develop estimates
of fair value
for financial reporting purposes and for internal management
decision making.
Sources of information for the valuation of derivative contracts
as of
September 30, 2005 are summarized by year in the following
table:
Sources
of Information -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
|
|
2005(1)
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
Thereafter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
based
on external sources(2)
|
|
|
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
15
|
|
Prices
based
on models
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5
|
|
|
4
|
|
|
4
|
|
|
13
|
|
Total
|
|
|
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
5
|
|
$
|
4
|
|
$
|
4
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) For
the
last quarter of 2005.
(2) Broker
quote sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met-Ed
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 derivative instruments would not have had a material effect
on its
consolidated financial position or cash flows as of September 30,
2005.
Equity
Price
Risk
Included
in
Met-Ed's nuclear decommissioning trust investments are marketable
equity
securities carried at their market value of approximately $138
million as of
September 30, 2005 and $134 million as of December 31,
2004. A
hypothetical 10% decrease in prices quoted by stock exchanges
would result in a
$14 million reduction in fair value as of September 30,
2005.
Regulatory
Matters
Regulatory
assets
are costs which have been authorized by the PPUC and the FERC
for recovery from
customers in future periods and, without such authorization,
would have been
charged to income when incurred. Met-Ed's regulatory assets as
of
September 30, 2005 and December 31, 2004 were $572
million and $693
million, respectively.
In
accordance with
PPUC directives, Met-Ed and Penelec have been negotiating with
interested
parties in an attempt to resolve the merger savings issues that
are the subject
of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
of total merger savings is estimated to be approximately $31.5
million. On
April 13, 2005, the Commonwealth Court issued an interim
order in the
remand proceeding that the parties should report the status of
the negotiations
to the PPUC with a copy to the ALJ. The parties exchanged settlement
proposals
in May and June 2005 and continue to have settlement discussions.
In
an
October 16, 2003 order, the PPUC approved September 30,
2004 as the
date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC
order also
denied their accounting treatment request regarding the CTC rate/shopping
credit
swap by requiring Met-Ed and Penelec to treat the stipulated
CTC rates that were
in effect from January 1, 2002 on a retroactive basis.
On October 22,
2003, Met-Ed and Penelec filed an Objection with the Commonwealth
Court asking
that the Court reverse this PPUC finding; a Commonwealth Court
judge
subsequently denied their Objection on October 27, 2003
without
explanation. On October 31, 2003, Met-Ed and Penelec filed
an Application
for Clarification of the Court order with the judge, a Petition
for Review of
the PPUC's October 2 and October 16, 2003 Orders,
and an application
for reargument, if the judge, in his clarification order, indicates
that
Met-Ed's and Penelec's Objection was intended to be denied on
the merits. The
Reargument Brief before the Commonwealth Court was filed on January 28,
2005.
Met-Ed
purchases a
portion of its PLR requirements from FES through a wholesale
power sales
agreement. The PLR sale is automatically extended for each successive
calendar
year unless any party elects to cancel the agreement by November 1
of the
preceding year. Under the terms of the wholesale agreement, FES
retains the
supply obligation and the supply profit and loss risk, for the
portion of power
supply requirements not self-supplied by Met-Ed under its NUG
contracts and
other power contracts with nonaffiliated third party suppliers.
This arrangement
reduces Met-Ed's exposure to high wholesale power prices by providing
power at a
fixed price for their uncommitted PLR energy costs during the
term of the
agreement with FES. Met-Ed is authorized to defer differences
between NUG
contract costs and current market prices. On
November 1,
2005, FES and the other parties to the wholesale power agreement
amended the
agreement to provide FES the right over the next year to terminate
the agreement
at any time upon 60 days notice. If
the wholesale
power agreement were terminated, Met-Ed and Penelec would need
to satisfy the
applicable portion of their PLR obligations from other sources
at prevailing
prices, which are likely to be higher than the current price
charged by FES
under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
costs could materially increase.
On
January 12,
2005, Met-Ed filed a request with the PPUC for deferral of transmission-related
costs beginning January 1, 2005, estimated to be approximately
$4 million
per month. The
OCA, OSBA, OTS,
MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania
Rural Electric
Association have all intervened in the case. To date no hearing
schedule has
been established, and Met-Ed has not yet implemented deferral
accounting for
these costs.
On
January 31,
2005, certain PJM transmission owners made three filings 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.
Second, the FERC
approved the proposed Schedule 12 rate harmonization. Third,
the FERC accepted
the proposed formula rate, subject to referral and hearing procedures.
On
June 30, 2005, the PJM transmission owners filed a request
for rehearing of
the May 31, 2005 order. The rate design and formula rate
filings continue
to be litigated before the FERC. The outcome of these two cases
cannot be
predicted.
See
Note 14 to the
consolidated financial statements for further details and a complete
discussion
of regulatory matters in Pennsylvania including a more detailed
discussion of
reliability initiatives, including actions by the PPUC, that
impact
Met-Ed.
Environmental
Matters
Met-Ed
accrues
environmental liabilities 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 Met-Ed’s determination of
environmental liabilities and are accrued in the period that
they are both
probable and reasonably estimable.
Met-Ed
has been
named as a PRP at waste disposal sites, which may require cleanup
under the
Comprehensive Environmental Response, Compensation, and Liability
Act of 1980.
Allegations of disposal of hazardous substances at historical
sites and the
liability involved are often unsubstantiated and subject to dispute;
however,
federal law provides that all PRPs for a particular site are
liable on a joint
and several basis. Therefore, environmental liabilities that
are considered
probable have been recognized on the Consolidated Balance Sheet
as of
September 30, 2005, based on estimates of the total costs
of cleanup,
Met-Ed’s proportionate responsibility for such costs and the financial
ability
of other nonaffiliated entities to pay.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
See
Note 13(B) to
the consolidated financial statements for further details and
a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and
proceedings
related to Met-Ed's normal business operations pending against
Met-Ed. The other
material items not otherwise discussed above are described below.
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 concludes, 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 website (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 also is proceeding
with the
implementation of the recommendations regarding enhancements
to regional
reliability 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, and therefore FirstEnergy has not accrued a liability
as of
September 30, 2005 for any expenditures in excess of those
actually
incurred through that date. 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. Finally, the PUCO
is continuing to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control
room
operators, before determining the next steps, if any, in the
proceeding.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York
State Supreme
Court. In this case, several plaintiffs in the New York City
metropolitan area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy
affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed
in Michigan State
Court by an individual who is not a customer of any FirstEnergy
company. A
responsive pleading to this matter is not due until on or about
December 1,
2005. No estimate of potential liability has been undertaken
in this matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome
of any of
these proceedings or whether any further regulatory proceedings
or legal actions
may be initiated against the Companies. In particular, if FirstEnergy
or its
subsidiaries were ultimately determined to have legal liability
in connection
with these proceedings, it could have a material adverse effect
on FirstEnergy's
or its subsidiaries' financial condition, results of operations
and cash
flows.
See
Note 13(C) to
the consolidated financial statements for further details and
a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with
the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding
that two or more
legally separate exchange transactions with the same counterparty
should be
combined and considered as a single arrangement for purposes
of applying APB 29,
when the transactions were entered into "in contemplation" of
one another. If
two transactions are combined and considered a single arrangement,
the EITF
reached a consensus that an exchange of inventory should be accounted
for at
fair value. Although electric power is not capable of being held
in inventory,
there is no substantive conceptual distinction between exchanges
involving power
and other storable inventory. Therefore, Met-Ed will adopt this
EITF effective
for new arrangements entered into, or modifications or renewals
of existing
arrangements, in interim or annual periods beginning after March
15, 2006.
|
EITF
Issue No. 05-6, "Determining the Amortization Period
for Leasehold
Improvements Purchased after Lease Inception or Acquired
in a Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue
05-6. EITF 05-6
addresses the amortization period for leasehold improvements
that were either
acquired in a business combination or placed in service significantly
after and
not contemplated at or near the beginning of the initial lease
term. For
leasehold improvements acquired in a business combination, the
amortization
period is the shorter of the useful life of the assets or a term
that includes
required lease periods and renewals that are deemed to be reasonably
assured at
the date of acquisition. Leasehold improvements that are placed
in service
significantly after and not contemplated at or near the beginning
of the lease
term should be amortized over the shorter of the useful life
of the assets or a
term that includes required lease periods and renewals that are
deemed to be
reasonably assured at the date the leasehold improvements are
purchased. This
EITF was effective July 1, 2005 and is consistent with
Met-Ed's current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an
interpretation of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing
of liability
recognition for conditional asset retirement obligations. Under
this
interpretation, companies are required to recognize a liability
for the fair
value of an asset retirement obligation that is conditional on
a future event,
if the fair value of the liability can be reasonably estimated.
In instances
where there is insufficient information to estimate the liability,
the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If
the fair value
cannot be reasonably estimated, that fact and the reasons why
must be disclosed.
This Interpretation is effective for Met-Ed in the fourth quarter
of 2005.
Met-Ed is currently evaluating the effect this Interpretation
will have on its
financial statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement
of APB Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting
and reporting a
change in accounting principle. It applies to all voluntary changes
in
accounting principle and to changes required by an accounting
pronouncement when
that pronouncement does not include specific transition provisions.
This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative
effect of the
change. In those instances, this Statement requires that the
new accounting
principle be applied to the balances of assets and liabilities
as of the
beginning of the earliest period for which retrospective application
is
practicable and that a corresponding adjustment be made to the
opening balance
of retained earnings (or other appropriate components of equity
or net assets in
the statement of financial position) for that period rather than
being reported
in the Consolidated Statements of Income. This Statement also
requires that a
change in depreciation, amortization, or depletion method for
long-lived,
nonfinancial assets be accounted for as a change in accounting
estimate affected
by a change in accounting principle. The provisions of this Statement
are
effective for accounting changes and corrections of errors made
in fiscal years
beginning after December 15, 2005. Met-Ed will adopt this
Statement
effective January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB
Opinion No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on
the principle that
nonmonetary assets should be measured based on the fair value
of the assets
exchanged. The guidance in APB 29 included certain exceptions
to that principle.
SFAS 153 eliminates the exception from fair value measurement
for nonmonetary
exchanges of similar productive assets and replaces it with an
exception for
exchanges that do not have commercial substance. This Statement
specifies that a
nonmonetary exchange has commercial substance if the future cash
flows of the
entity are expected to change significantly as a result of the
exchange. The
provisions of this Statement are effective January 1,
2006 for Met-Ed. This
FSP is not expected to have a material impact on Met-Ed's financial
statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal
amounts of idle
facility expense, freight, handling costs and wasted material
(spoilage).
Previous guidance stated that in some circumstances these costs
may be “so
abnormal” that they would require treatment as current period costs. SFAS
151
requires abnormal amounts for these items to always be recorded
as current
period costs. In addition, this Statement requires that allocation
of fixed
production overheads to the cost of conversion be based on the
normal capacity
of the production facilities. The provisions of this statement
are effective for
inventory costs incurred by Met-Ed beginning January 1,
2006. Met-Ed is
currently evaluating this Standard and does not expect it to
have a material
impact on the financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application
to Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS
115-1. FSP FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security
Whose Cost
Exceeds Fair Value," (2) clarify that an investor should recognize
an impairment
loss no later than when the impairment is deemed other than temporary,
even if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods
beginning
after September 15, 2005. The FASB expects to issue this
FSP in the fourth
quarter of 2005, which would require prospective application with
an effective
date for reporting periods beginning after December 15,
2005. Met-Ed is
currently evaluating this FSP and any impact on its investments.
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES
|
|
$
|
290,451
|
|
$
|
254,339
|
|
$
|
846,477
|
|
$
|
752,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES AND TAXES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
178,090
|
|
|
137,146
|
|
|
467,639
|
|
|
432,974
|
|
Other
operating costs
|
|
|
66,417
|
|
|
37,100
|
|
|
183,024
|
|
|
122,988
|
|
Provision
for
depreciation
|
|
|
12,736
|
|
|
12,281
|
|
|
37,721
|
|
|
35,229
|
|
Amortization
of regulatory assets
|
|
|
12,627
|
|
|
11,759
|
|
|
38,930
|
|
|
39,130
|
|
General
taxes
|
|
|
17,552
|
|
|
16,913
|
|
|
51,892
|
|
|
50,795
|
|
Income
taxes
|
|
|
(3,101
|
)
|
|
11,693
|
|
|
14,991
|
|
|
16,000
|
|
Total
operating expenses and taxes
|
|
|
284,321
|
|
|
226,892
|
|
|
794,197
|
|
|
697,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
6,130
|
|
|
27,447
|
|
|
52,280
|
|
|
55,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (net of income taxes)
|
|
|
1,057
|
|
|
1,300
|
|
|
1,477
|
|
|
1,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on
long-term debt
|
|
|
7,305
|
|
|
7,513
|
|
|
22,187
|
|
|
22,528
|
|
Allowance
for
borrowed funds used during construction
|
|
|
(285
|
)
|
|
(60
|
)
|
|
(674
|
)
|
|
(192
|
)
|
Deferred
interest
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
190
|
|
Other
interest
expense
|
|
|
2,536
|
|
|
3,058
|
|
|
7,392
|
|
|
8,063
|
|
Net
interest
charges
|
|
|
9,556
|
|
|
10,511
|
|
|
28,905
|
|
|
30,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
(2,369
|
)
|
|
18,236
|
|
|
24,852
|
|
|
26,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gain (loss) on derivative hedges
|
|
|
17
|
|
|
17
|
|
|
49
|
|
|
(618
|
)
|
Unrealized
gain (loss) on available for sale securities
|
|
|
18
|
|
|
7
|
|
|
(3
|
)
|
|
(3
|
)
|
Other
comprehensive income (loss)
|
|
|
35
|
|
|
24
|
|
|
46
|
|
|
(621
|
)
|
Income
tax
expense (benefit) related to other comprehensive income
|
|
|
20
|
|
|
(256
|
)
|
|
20
|
|
|
(258
|
)
|
Other
comprehensive income (loss), net of tax
|
|
|
15
|
|
|
280
|
|
|
26
|
|
|
(363
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME (LOSS)
|
|
$
|
(2,354
|
)
|
$
|
18,516
|
|
$
|
24,878
|
|
$
|
26,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
preceding
Notes to Consolidated Financial Statements as they
relate to Pennsylvania
Electric Company are an integral part of these statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
UTILITY
PLANT:
|
|
|
|
|
|
In
service
|
|
$
|
2,004,891
|
|
$
|
1,981,846
|
|
Less
-
Accumulated provision for depreciation
|
|
|
772,818
|
|
|
776,904
|
|
|
|
|
1,232,073
|
|
|
1,204,942
|
|
Construction
work in progress
|
|
|
23,622
|
|
|
22,816
|
|
|
|
|
1,255,695
|
|
|
1,227,758
|
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear
plant
decommissioning trusts
|
|
|
111,826
|
|
|
109,620
|
|
Non-utility
generation trusts
|
|
|
97,473
|
|
|
95,991
|
|
Long-term
notes receivable from associated companies
|
|
|
15,629
|
|
|
14,001
|
|
Other
|
|
|
14,855
|
|
|
18,746
|
|
|
|
|
239,783
|
|
|
238,358
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
|
35
|
|
|
36
|
|
Notes
receivable from associated companies
|
|
|
-
|
|
|
7,352
|
|
Receivables
-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $4,095,000 and $4,712,000,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
120,580
|
|
|
121,112
|
|
Associated
companies
|
|
|
6,339
|
|
|
97,528
|
|
Other
|
|
|
7,369
|
|
|
12,778
|
|
Prepayments
and other
|
|
|
15,818
|
|
|
7,198
|
|
|
|
|
150,141
|
|
|
246,004
|
|
DEFERRED
CHARGES:
|
|
|
|
|
|
|
|
Goodwill
|
|
|
886,559
|
|
|
888,011
|
|
Regulatory
assets
|
|
|
99,491
|
|
|
200,173
|
|
Other
|
|
|
13,234
|
|
|
13,448
|
|
|
|
|
999,284
|
|
|
1,101,632
|
|
|
|
$
|
2,644,903
|
|
$
|
2,813,752
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
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
|
|
|
1,206,358
|
|
|
1,205,948
|
|
Accumulated
other comprehensive loss
|
|
|
(52,787
|
)
|
|
(52,813
|
)
|
Retained
earnings
|
|
|
38,920
|
|
|
46,068
|
|
Total
common
stockholder's equity
|
|
|
1,298,303
|
|
|
1,305,015
|
|
Long-term
debt
and other long-term obligations
|
|
|
478,954
|
|
|
481,871
|
|
|
|
|
1,777,257
|
|
|
1,786,886
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
|
4
|
|
|
8,248
|
|
Short-term
borrowings -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
114,749
|
|
|
241,496
|
|
Other
|
|
|
75,000
|
|
|
-
|
|
Accounts
payable -
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
30,456
|
|
|
56,154
|
|
Other
|
|
|
35,987
|
|
|
25,960
|
|
Accrued
taxes
|
|
|
19,234
|
|
|
7,999
|
|
Accrued
interest
|
|
|
15,289
|
|
|
9,695
|
|
Other
|
|
|
19,264
|
|
|
23,750
|
|
|
|
|
309,983
|
|
|
373,302
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Power
purchase
contract loss liability
|
|
|
259,675
|
|
|
382,548
|
|
Retirement
benefits
|
|
|
121,251
|
|
|
118,247
|
|
Asset
retirement obligation
|
|
|
69,608
|
|
|
66,443
|
|
Accumulated
deferred income taxes
|
|
|
56,029
|
|
|
37,318
|
|
Other
|
|
|
51,100
|
|
|
49,008
|
|
|
|
|
557,663
|
|
|
653,564
|
|
COMMITMENTS
AND CONTINGENCIES (Note 13)
|
|
|
|
|
|
|
|
|
|
$
|
2,644,903
|
|
$
|
2,813,752
|
|
|
|
|
|
|
|
|
|
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
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net
income
(loss)
|
|
$
|
(2,369
|
)
|
$
|
18,236
|
|
$
|
24,852
|
|
$
|
26,944
|
|
Adjustments
to
reconcile net income (loss) to net cash from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
activities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
12,736
|
|
|
12,281
|
|
|
37,721
|
|
|
35,229
|
|
Amortization
of regulatory assets
|
|
|
12,627
|
|
|
11,759
|
|
|
38,930
|
|
|
39,130
|
|
Deferred
costs
recoverable as regulatory assets
|
|
|
(5,355
|
)
|
|
(25,618
|
)
|
|
(41,301
|
)
|
|
(62,122
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(5,412
|
)
|
|
28,574
|
|
|
(2,765
|
)
|
|
30,308
|
|
Accrued
retirement benefit obligations
|
|
|
1,100
|
|
|
1,164
|
|
|
3,005
|
|
|
4,805
|
|
Accrued
compensation, net
|
|
|
691
|
|
|
894
|
|
|
(1,695
|
)
|
|
2,271
|
|
Pension
trust
contribution
|
|
|
-
|
|
|
(50,281
|
)
|
|
-
|
|
|
(50,281
|
)
|
Decrease
(increase) in operating assets -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
17,528
|
|
|
(17,689
|
)
|
|
97,130
|
|
|
35,806
|
|
Prepayments and other current assets
|
|
|
13,487
|
|
|
9,703
|
|
|
(8,620
|
)
|
|
(25,247
|
)
|
Increase
(decrease) in operating liabilities -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
4,662
|
|
|
(23,255
|
)
|
|
(15,671
|
)
|
|
(38,015
|
)
|
Accrued taxes
|
|
|
507
|
|
|
2
|
|
|
11,235
|
|
|
(7,572
|
)
|
Accrued interest
|
|
|
5,628
|
|
|
5,605
|
|
|
5,594
|
|
|
2,856
|
|
Other
|
|
|
(1,460
|
)
|
|
562
|
|
|
2,905
|
|
|
24,851
|
|
Net cash provided from (used for) operating
activities
|
|
|
54,370
|
|
|
(28,063
|
)
|
|
151,320
|
|
|
18,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
150,000
|
|
Short-term
borrowings, net
|
|
|
-
|
|
|
158,282
|
|
|
-
|
|
|
165,918
|
|
Redemptions
and Repayments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(8,013
|
)
|
|
(103,241
|
)
|
|
(11,534
|
)
|
|
(228,453
|
)
|
Short-term
borrowings, net
|
|
|
(15,139
|
)
|
|
-
|
|
|
(51,747
|
)
|
|
-
|
|
Dividend
Payments -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(2,000
|
)
|
|
(3,000
|
)
|
|
(32,000
|
)
|
|
(8,000
|
)
|
Net
cash provided from (used for) financing activities
|
|
|
(25,152
|
)
|
|
52,041
|
|
|
(95,281
|
)
|
|
79,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(27,997
|
)
|
|
(10,192
|
)
|
|
(61,680
|
)
|
|
(33,428
|
)
|
Non-utility
generation trust contribution
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(50,614
|
)
|
Loan
repayments from (loans to) associated companies, net
|
|
|
(1,287
|
)
|
|
(3,124
|
)
|
|
5,724
|
|
|
(3,144
|
)
|
Other,
net
|
|
|
66
|
|
|
(10,662
|
)
|
|
(84
|
)
|
|
(11,242
|
)
|
Net
cash
used for investing activities
|
|
|
(29,218
|
)
|
|
(23,978
|
)
|
|
(56,040
|
)
|
|
(98,428
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in
cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
(1
|
)
|
|
-
|
|
Cash
and cash
equivalents at beginning of period
|
|
|
35
|
|
|
36
|
|
|
36
|
|
|
36
|
|
Cash
and cash
equivalents at end of period
|
|
$
|
35
|
|
$
|
36
|
|
$
|
35
|
|
$
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Stockholders
and Board of
Directors
of
Pennsylvania Electric Company:
We
have reviewed
the accompanying consolidated balance sheet of Pennsylvania Electric
Company and
its subsidiaries as of September 30, 2005, and the related consolidated
statements of income and comprehensive income and cash flows for each
of the
three-month and nine-month periods ended September 30, 2005
and 2004. 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, 2004, and the related consolidated statements of
income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which
contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in
Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as
of
December 31, 2003 as discussed in Note 6 to those consolidated
financial
statements) dated March 7, 2005, 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,
2004, is fairly stated in all material respects in relation to the
consolidated
balance sheet from which it has been derived.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
November
1,
2005
PENNSYLVANIA
ELECTRIC COMPANY
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
RESULTS
OF
OPERATIONS AND FINANCIAL CONDITION
Penelec
is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts
business in
northern, western and south central Pennsylvania, providing regulated
transmission and distribution services. Penelec also provides generation
services to those customers electing to retain Penelec as their power
supplier.
Penelec has unbundled the price for electricity into its component
elements -
including generation, transmission, distribution and transition
charges.
Results
of Operations
Penelec
recognized
a net loss of $2 million in the third quarter of 2005, compared to
$18 million
in net income in the third quarter of 2004. During the first nine months
of
2005, net income decreased to $25 million compared to $27 million in
the first
nine months of 2004. The decrease in both periods resulted from higher
purchased
power and other operating costs, partially offset by higher operating
revenues
and lower income taxes.
Operating
revenues
increased by $36 million in the third quarter and $93 million in the
first nine
months of 2005 compared to the same periods of 2004. Increases in both
periods
were due to higher retail generation revenues in all sectors ($14 million
for
the quarter and $23 million for the first nine months). The increases
in retail
generation KWH sales in both periods of 2005 were mainly due to the
warmer
weather in 2005 compared to 2004. While the higher generation sales
in the third
quarter were offset by slightly lower composite unit prices, overall
higher
composite unit prices - especially in the industrial sector - for the
nine-month
period further contributed to the increase in generation revenues.
Distribution
revenues increased by $4 million in the third quarter and by $6 million
in the
first nine months of 2005 compared to the same periods of 2004. Increases
in
both periods were due to higher KWH deliveries partially offset by
lower unit
prices. Also contributing to higher operating revenues was an increase
in
transmission revenues of $18 million in the third quarter and $61 million
in the
first nine months of 2005. These increases were due to a change in
the power
supply agreement with FES in the second quarter of 2004. This change
also
resulted in higher transmission expenses as discussed further
below.
Changes
in KWH
sales by customer class in the three months and nine months ended
September 30, 2005 from the corresponding periods of 2004 are
summarized in
the following table:
|
|
Three
|
|
Nine
|
|
Changes
in KWH Sales
|
|
Months
|
|
Months
|
|
Increase
(Decrease)
|
|
|
|
|
|
Retail
Electric Generation:
|
|
|
|
|
Residential
|
|
|
8.8
|
%
|
|
4.2
|
%
|
Commercial
|
|
|
7.0
|
%
|
|
4.3
|
%
|
Industrial
|
|
|
17.0
|
%
|
|
7.3
|
%
|
Total
Retail Electric Generation Sales
|
|
|
10.2
|
%
|
|
5.1
|
%
|
|
|
|
|
|
|
Distribution
Deliveries:
|
|
|
|
|
|
Residential
|
|
|
8.7
|
%
|
|
4.1
|
%
|
Commercial
|
|
|
6.6
|
%
|
|
4.1
|
%
|
Industrial
|
|
|
8.3
|
%
|
|
5.2
|
%
|
Total
Distribution Deliveries
|
|
|
7.8
|
%
|
|
4.5
|
%
|
|
|
|
|
|
|
|
|
Operating
Expenses and Taxes
Total
operating
expenses and taxes increased by $57 million in the third quarter and
$97 million
in the first nine months of 2005 compared with the same periods in
2004. The
following table presents changes from the prior year by expense category:
|
|
Three
|
|
Nine
|
|
Operating
Expenses and Taxes - Changes
|
|
Months
|
|
Months
|
|
|
|
(In
millions)
|
Increase
(Decrease)
|
|
|
|
|
|
Purchased
power costs
|
|
$
|
41
|
|
$
|
35
|
|
Other
operating costs
|
|
|
29
|
|
|
60
|
|
Provision
for
depreciation
|
|
|
-
|
|
|
2
|
|
Amortization
of regulatory assets
|
|
|
1
|
|
|
-
|
|
General
taxes
|
|
|
1
|
|
|
1
|
|
Income
taxes
|
|
|
(15
|
)
|
|
(1
|
)
|
Net
increase in operating expenses and taxes
|
|
$
|
57
|
|
$
|
97
|
|
|
|
|
|
|
|
|
|
Purchased
power
costs increased by $41 million or 29.9% in the third quarter and $35
million or
8.0% in the first nine months of 2005 compared to the same periods
of 2004. The
increase in the third quarter of 2005 is due to increased KWH purchased
to meet
increased retail generation sales requirements, and higher unit costs.
Third-party power purchases and NUG costs increased $48 million and
$20 million,
respectively, in the third quarter of 2005, partially offset by reduced
purchased power from FES of $27 million. The increase in the first
nine months
is due to increased KWH purchased to meet sales requirements partially
offset by
lower unit costs. Increases from third-party power purchases and NUG
costs of
$81 million and $21 million, respectively, in the first nine months
of 2005,
were partially offset by reduced purchased power from FES of $67
million.
Other
operating
costs increased by $29 million in the third quarter and $60 million
in the first
nine months of 2005 compared to same periods in 2004. The increases
in both
periods were primarily due to increased transmission expenses in 2005
as a
result of the change in the power supply agreement with FES referred
to above.
The increased transmission expenses were partially offset by reduced
labor costs
that were charged to capital projects. Income taxes decreased in the
third
quarter of 2005 due to lower pre-tax income compared to the third quarter
of
2004.
Capital
Resources and Liquidity
Penelec’s
cash
requirements for the remainder of 2005 for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met with
cash from
operations.
Changes
in Cash
Position
As
of September 30,
2005, Penelec had $35,000 of cash and cash equivalents compared with
$36,000 as
of December 31, 2004. The major sources for changes in these
balances are
summarized below.
Cash
Flows From
Operating Activities
Net
cash provided
from (used for) operating activities in the third quarter and first
nine months
of 2005, compared with the corresponding periods in 2004, are summarized
as
follows:
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Operating
Cash Flows
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
earnings
(1)
|
|
$
|
14
|
|
$
|
27
|
|
$
|
59
|
|
$
|
56
|
|
Pension
trust
contribution (2)
|
|
|
-
|
|
|
(30
|
)
|
|
-
|
|
|
(30
|
)
|
Working
capital and other
|
|
|
40
|
|
|
(25
|
)
|
|
92
|
|
|
(7
|
)
|
Total
cash
flows from operating activities
|
|
$
|
54
|
|
$
|
(28
|
)
|
$
|
151
|
|
$
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Cash
earnings is a non-GAAP measure (see reconciliation below).
(2)
Pension trust contribution net of $20 million of income tax
benefits.
Cash
earnings, as
disclosed in the table above, are not a measure of performance calculated
in
accordance with GAAP. Penelec believes that cash earnings is a useful
financial
measure because it provides investors and management with an additional
means of
evaluating its cash-based operating performance. The following table
reconciles
cash earnings with net income.
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
September
30,
|
|
Reconciliation
of Cash Earnings
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
(loss) (GAAP)
|
|
$
|
(2
|
)
|
$
|
18
|
|
$
|
25
|
|
$
|
27
|
|
Non-cash
charges (credits):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for
depreciation
|
|
|
13
|
|
|
12
|
|
|
38
|
|
|
35
|
|
Amortization
of regulatory assets
|
|
|
12
|
|
|
12
|
|
|
39
|
|
|
39
|
|
Deferred
costs recoverable as regulatory assets
|
|
|
(5
|
)
|
|
(26
|
)
|
|
(41
|
)
|
|
(62
|
)
|
Deferred
income taxes and investment tax credits, net
|
|
|
(6
|
)
|
|
9
|
|
|
(3
|
)
|
|
10
|
|
Other
non-cash items
|
|
|
2
|
|
|
2
|
|
|
1
|
|
|
7
|
|
Cash
earnings
(Non-GAAP)
|
|
$
|
14
|
|
$
|
27
|
|
$
|
59
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash from
operating activities increased $82 million in the third quarter of
2005,
compared with the third quarter of 2004, due to a $66 million increase
from
changes in working capital, an absence of a $30 million after-tax voluntary
pension contribution made in the third quarter of 2004, and partially
offset by
a $13 million decrease in cash earnings as described above under “Results of
Operations”. The increase in working capital primarily reflects net changes in
accounts receivable and accounts payable to associated companies of
$42 million
and a $22 million increase in purchase power accounts payable.
Net
cash from
operating activities increased $132 million in the first nine months
of 2005,
compared with the same period of 2004, due to a $100 million increase
from
changes in working capital, an absence of the $30 million after-tax
voluntary
pension contribution, and a $3 million increase in cash earnings as
described
above under “Results of Operations”. The increase in working capital primarily
reflects changes in accounts receivable to associated companies of
$61 million,
$30 million increase in purchase power and other accounts payable,
and $19
million change in accrued taxes, partially offset by changes in customer
deposits.
Cash
Flows From
Financing Activities
Net
cash used for
financing activities was $25 million in the third quarter of 2005 compared
to
net cash provided from financing activities of $52 million in the third
quarter
of 2004. The net change reflects a $1 million decrease in common stock
dividends
to FirstEnergy and a $173 million increase in repayments of short-term
borrowings, offset by a $95 million decrease in debt redemptions.
Net
cash used for
financing activities was $95 million for the first nine months of 2005
compared
to net cash provided from financing activities of $79 million in the
first nine
months of 2004. The net change of $174 million reflects $150 million
of
long-term debt financing in 2004, a $24 million increase in common
stock
dividends to FirstEnergy in 2005 and a $218 million increase in repayments
of
short-term borrowings, offset by a $217 million decrease in debt
redemptions.
Penelec
had
approximately $35,000 of cash and temporary investments (which included
short-term notes receivable from associated companies) and approximately
$190
million of short-term indebtedness as of September 30, 2005.
Penelec has
authorization from the SEC to incur short-term debt of up to $250 million
(including the utility money pool). Penelec will not issue FMB other
than as
collateral for senior notes, since its senior note indentures prohibit
(subject
to certain exceptions) Penelec from issuing any debt which is senior
to the
senior notes. As of September 30, 2005, Penelec had the capability
to issue
$18 million of additional senior notes based upon FMB collateral. Penelec
has no
restrictions on the issuance of preferred stock.
Penelec
Funding LLC
(Penelec Funding), a wholly owned subsidiary of Penelec, is a limited
liability
company whose borrowings are secured by customer accounts receivable
purchased
from Penelec. Penelec Funding can borrow up to $75 million under a
receivables
financing arrangement. As a separate legal entity with separate creditors,
Penelec Funding would have to satisfy its obligations to creditors
before any of
its remaining assets could be made available to Penelec. On July 15,
2005,
the facility was renewed until June 29, 2006. The facility was
undrawn as
of September 30, 2005. The annual facility fee is 0.25% on the
entire
finance limit.
On
June 14,
2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI,
as Borrowers, entered into a syndicated $2 billion five-year revolving
credit
facility. Borrowings under the facility are available to each Borrower
separately and mature on the earlier of 364 days from the date of borrowing
or
the commitment termination date, as the same may be extended. Penelec's
borrowing limit under the facility is $250 million.
Penelec
has the
ability to borrow from its regulated affiliates and FirstEnergy to
meet its
short-term working capital requirements. FESC administers this money
pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries.
Companies
receiving a loan under the money pool agreements must repay the principal,
together with accrued interest, within 364 days of borrowing the funds.
The rate
of interest is the same for each company receiving a loan from the
pool and is
based on the average cost of funds available through the pool. The
average
interest rate for borrowings under these arrangements in the third
quarter of
2005 was 3.5%.
On
July 18,
2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to
positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook
resulted from steady financial improvement and steps taken by management
to
improve operations, including the stabilization of its nuclear operations.
Moody’s further stated that the revision in their outlook recognized
management’s regional strategy of focusing on its core utility businesses and
the improvement in FirstEnergy’s credit profile stemming from the application of
free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could
be considered if FirstEnergy continues to achieve planned improvements
in its
operations and balance sheet.
On
October 3,
2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to
'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings
at the holding company to 'BBB-' from 'BB+' and each of the EUOC by
one notch
above the previous rating. S&P noted that the upgrade followed the
continuation of a good operating track record, specifically for the
nuclear
fleet through the third quarter 2005. S&P also stated that FirstEnergy’s
rating reflects the benefits of supportive regulation, low-cost base
load
generation fleet, low-risk transmission and distribution operations
and rate
certainty in Ohio. FirstEnergy’s ability to consistently generate free cash
flow, good liquidity, and an improving financial profile were also
noted as
strengths.
Penelec’s
access to
capital markets and costs of financing are influenced by the ratings
of its
securities and the securities of FirstEnergy. The ratings outlook from
S&P
and Fitch on all securities is stable. Moody’s outlook on all securities is
positive.
Cash
Flows From
Investing Activities
Cash
used for
investing activities was $29 million in the third quarter of 2005 compared
to
$24 million in the third quarter of 2004. The increase was primarily
due to
higher property additions, partially offset by lower loan repayments
from
associated companies and the absence in 2005 of an $11 million capital
transfer
from FESC that took place in September 2004. Cash used for investing
activities
was $56 million in the first nine months of 2005 compared to $98 million
in the
first nine months of 2004. The decrease was primarily due to a $51
million
repayment to the NUG trust fund in 2004, increased loans from associated
companies, and the $11 million capital transfer from above, partially
offset by
higher property additions in 2005. Capital expenditures for property
additions
primarily support Penelec’s energy delivery operations.
Penelec’s
capital
spending for the period 2005-2007 is expected to be about $272 million
for
property additions and improvements, of which about $91 million applies
to 2005.
In the last quarter of 2005, capital requirements for property additions
are
expected to be about $26 million. Penelec has no additional requirements
for
maturing long-term debt during the remainder of 2005. These cash requirements
are expected to be satisfied from internal cash and short-term credit
arrangements.
Market
Risk Information
Penelec
uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations.
FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
provides general management oversight to risk management
activities.
Commodity
Price
Risk
Penelec
is exposed
to price risk primarily due to fluctuating electricity and natural
gas prices.
To manage the volatility relating to these exposures, it uses a variety
of
non-derivative and derivative instruments, including options and futures
contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge
derivative contracts represent non-trading positions that do not qualify
for
hedge treatment under SFAS 133. As of September 30, 2005, Penelec’s
commodity derivatives contract was an embedded option with a fair value
of $14
million. A decrease of $1 million in the value of this asset was recorded
in the
first nine months of 2005 as a decrease in regulatory liabilities,
and
therefore, had no impact on net income.
The
valuation of
derivative commodity contracts is based on observable market information
to the
extent that such information is available. In cases where such information
is
not available, Penelec relies on model-based information. The model
provides
estimates of future regional prices for electricity and an estimate
of related
price volatility. Penelec uses these results to develop estimates of
fair value
for financial reporting purposes and for internal management decision
making.
Sources of information for valuation of derivative contracts as of
September 30, 2005 are summarized by year in the following
table:
Sources
of Information
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value by Contract Year
|
|
|
|
2005(1)
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
Thereafter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
based
on external sources(2)
|
|
|
|
|
$
|
3
|
|
$
|
3
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
8
|
|
Prices
based
on models
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
6
|
|
Total
|
|
|
|
|
$
|
3
|
|
$
|
3
|
|
$
|
2
|
|
$
|
2
|
|
$
|
2
|
|
$
|
2
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) For
the
last quarter of 2005.
(2) Broker
quote sheets.
|
Penelec
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 both its trading and nontrading derivative instruments would not
have had a
material effect on its consolidated financial position or cash flows
as of
September 30, 2005.
Equity
Price
Risk
Included
in nuclear
decommissioning trusts are marketable equity securities carried at
their current
fair value of approximately $61 million and $60 million as of September 30,
2005 and December 31, 2004, respectively. A hypothetical 10%
decrease in
prices quoted by stock exchanges would result in a $6 million reduction
in fair
value as of September 30, 2005.
Regulatory
Matters
Regulatory
assets
are costs which have been authorized by the PPUC and the FERC for recovery
from
customers in future periods and, without such authorization, would
have been
charged to income when incurred. Penelec's regulatory assets as of
September 30, 2005 and December 31, 2004 were $99 million
and $200
million, respectively.
In
accordance with
PPUC directives, Met-Ed and Penelec have been negotiating with interested
parties in an attempt to resolve the merger savings issues that are
the subject
of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion
of total merger savings is estimated to be approximately $31.5 million.
On
April 13, 2005, the Commonwealth Court issued an interim order
in the
remand proceeding that the parties should report the status of the
negotiations
to the PPUC with a copy to the ALJ. The parties exchanged settlement
proposals
in May and June 2005 and continue to have settlement discussions.
In
an
October 16, 2003 order, the PPUC approved September 30,
2004 as the
date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order
also
denied their accounting treatment request regarding the CTC rate/shopping
credit
swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates
that were
in effect from January 1, 2002 on a retroactive basis. On October 22,
2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court
asking
that the Court reverse this PPUC finding; a Commonwealth Court judge
subsequently denied their Objection on October 27, 2003 without
explanation. On October 31, 2003, Met-Ed and Penelec filed an
Application
for Clarification of the Court order with the judge, a Petition for
Review of
the PPUC's October 2 and October 16, 2003 Orders, and
an application
for reargument, if the judge, in his clarification order, indicates
that
Met-Ed's and Penelec's Objection was intended to be denied on the merits.
The
Reargument Brief before the Commonwealth Court was filed on January 28,
2005.
Penelec
purchases a
portion of its PLR requirements from FES through a wholesale power
sales
agreement. The PLR sale is automatically extended for each successive
calendar
year unless either party elects to cancel the agreement by November 1
of
the preceding year. Under the terms of the wholesale agreement, FES
retains the
supply obligation and the supply profit and loss risk, for the portion
of power
supply requirements not self-supplied by Penelec under its NUG contracts
and
other power contracts with nonaffiliated third party suppliers. This
arrangement
reduces Penelec's exposure to high wholesale power prices by providing
power at
a fixed price for its uncommitted PLR energy costs during the term
of the
agreement with FES. Penelec is authorized to defer differences between
NUG
contract costs and current market prices. On
November 1,
2005, FES and the other parties to the wholesale power agreement amended
the
agreement to provide FES the right over the next year to terminate
the agreement
at any time upon 60 days notice. If
the wholesale
power agreement were terminated, Met-Ed and Penelec would need to satisfy
the
applicable portion of their PLR obligations from other sources at prevailing
prices, which are likely to be higher than the current price charged
by FES
under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power
costs could materially increase.
On
January 12,
2005, Penelec filed a request with the PPUC to defer transmission-related
costs
beginning January 1, 2005, estimated to be approximately $4
million per
month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative
and
Pennsylvania Rural Electric Association have all intervened in the
case. To date
no hearing schedule has been established, and Penelec has not yet implemented
deferral accounting for these costs.
On
January 31,
2005, certain PJM transmission owners made three filings pursuant to
a
settlement agreement previously approved by the FERC. Penelec was party
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. Second, the FERC approved the proposed Schedule
12 rate
harmonization. Third, the FERC accepted the proposed formula rate,
subject to
referral and hearing procedures. On June 30, 2005, the PJM transmission
owners filed a request for rehearing of the May 31, 2005 order.
The rate
design and formula rate filings continue to be litigated before the
FERC. The
outcome of these two cases cannot be predicted.
See
Note 14 to the
consolidated financial statements for further details and a complete
discussion
of regulatory matters in Pennsylvania, including a more detailed discussion
of
reliability initiatives, including actions by the PPUC that impact
Penelec.
Environmental
Matters
Penelec
accrues
environmental liabilities when it concludes that it is probable that
it has an
obligation for such costs and can reasonably estimate the amount of
such costs.
Unasserted claims are reflected in Penelec's determination of environmental
liabilities and are accrued in the period that they are both probable
and
reasonably estimable.
Penelec
has been
named a PRP at waste disposal sites, which may require cleanup under
the
Comprehensive Environmental Response, Compensation and Liability Act
of 1980.
Allegations of disposal of hazardous substances at historical sites
and the
liability involved are often unsubstantiated and subject to dispute;
however,
federal law provides that all PRPs for a particular site are liable
on a joint
and several basis.
FirstEnergy
plans
to issue a report regarding its response to air emission requirements.
FirstEnergy expects to complete the report by December 1,
2005.
See
Note 13(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.
Other
Legal Proceedings
There
are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to Penelec's normal business operations pending against Penelec.
The
other material items not otherwise discussed above are described
below.
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 concludes, 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 website (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 also is proceeding
with the
implementation of the recommendations regarding enhancements to regional
reliability 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, and therefore FirstEnergy has not accrued a liability as
of
September 30, 2005 for any expenditures in excess of those actually
incurred through that date. 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. Finally, the PUCO is continuing
to
review FirstEnergy’s filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the
proceeding.
One
complaint was
filed on August 25, 2004 against FirstEnergy in the New York State
Supreme
Court. In this case, several plaintiffs in the New York City metropolitan
area
allege that they suffered damages as a result of the August 14,
2003 power
outages. None of the plaintiffs are customers of any FirstEnergy affiliate.
FirstEnergy's motion to dismiss the case was granted on September 26,
2005.
Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan
State
Court by an individual who is not a customer of any FirstEnergy company.
A
responsive pleading to this matter is not due until on or about December
1,
2005. No estimate of potential liability has been undertaken in this
matter.
FirstEnergy
is
vigorously defending these actions, but cannot predict the outcome
of any of
these proceedings or whether any further regulatory proceedings or
legal actions
may be initiated against the Companies. In particular, if FirstEnergy
or its
subsidiaries were ultimately determined to have legal liability in
connection
with these proceedings, it could have a material adverse effect on
FirstEnergy's
or its subsidiaries' financial condition, results of operations and
cash
flows.
See
Note 13(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.
New
Accounting Standards and Interpretations
EITF
Issue
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty"
In
September 2005,
the EITF reached a final consensus on Issue 04-13 concluding that two
or more
legally separate exchange transactions with the same counterparty should
be
combined and considered as a single arrangement for purposes of applying
APB 29,
when the transactions were entered into "in contemplation" of one another.
If
two transactions are combined and considered a single arrangement,
the EITF
reached a consensus that an exchange of inventory should be accounted
for at
fair value. Although electric power is not capable of being held in
inventory,
there is no substantive conceptual distinction between exchanges involving
power
and other storable inventory. Therefore, Penelec will adopt this EITF
effective
for new arrangements entered into, or modifications or renewals of
existing
arrangements, in interim or annual periods beginning after March 15,
2006.
|
EITF
Issue No. 05-6, "Determining the Amortization Period for
Leasehold
Improvements Purchased after Lease Inception or Acquired
in a Business
Combination"
|
In
June 2005, the
EITF reached a consensus on the application guidance for Issue 05-6.
EITF 05-6
addresses the amortization period for leasehold improvements that were
either
acquired in a business combination or placed in service significantly
after and
not contemplated at or near the beginning of the initial lease term.
For
leasehold improvements acquired in a business combination, the amortization
period is the shorter of the useful life of the assets or a term that
includes
required lease periods and renewals that are deemed to be reasonably
assured at
the date of acquisition. Leasehold improvements that are placed in
service
significantly after and not contemplated at or near the beginning of
the lease
term should be amortized over the shorter of the useful life of the
assets or a
term that includes required lease periods and renewals that are deemed
to be
reasonably assured at the date the leasehold improvements are purchased.
This
EITF was effective July 1, 2005 and is consistent with Penelec's
current
accounting.
FIN
47,
“Accounting for Conditional Asset Retirement Obligations - an interpretation
of
FASB Statement No. 143”
On
March 30,
2005, the FASB issued FIN 47 to clarify the scope and timing of liability
recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for
the fair
value of an asset retirement obligation that is conditional on a future
event,
if the fair value of the liability can be reasonably estimated. In
instances
where there is insufficient information to estimate the liability,
the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair
value
cannot be reasonably estimated, that fact and the reasons why must
be disclosed.
This Interpretation is effective for Penelec in the fourth quarter
of 2005.
Penelec is currently evaluating the effect this Interpretation will
have on its
financial statements.
|
SFAS
154
- “Accounting Changes and Error Corrections - a replacement
of APB Opinion
No. 20 and FASB Statement No.
3”
|
In
May 2005, the
FASB issued SFAS 154 to change the requirements for accounting and
reporting a
change in accounting principle. It applies to all voluntary changes
in
accounting principle and to changes required by an accounting pronouncement
when
that pronouncement does not include specific transition provisions.
This
Statement requires retrospective application to prior periods’ financial
statements of changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect
of the
change. In those instances, this Statement requires that the new accounting
principle be applied to the balances of assets and liabilities as of
the
beginning of the earliest period for which retrospective application
is
practicable and that a corresponding adjustment be made to the opening
balance
of retained earnings (or other appropriate components of equity or
net assets in
the statement of financial position) for that period rather than being
reported
in the Consolidated Statements of Income. This Statement also requires
that a
change in depreciation, amortization, or depletion method for long-lived,
nonfinancial assets be accounted for as a change in accounting estimate
affected
by a change in accounting principle. The provisions of this Statement
are
effective for accounting changes and corrections of errors made in
fiscal years
beginning after December 15, 2005. Penelec will adopt this Statement
effective January 1, 2006.
|
SFAS
153,
“Exchanges of Nonmonetary Assets - an amendment of APB Opinion
No.
29”
|
In
December 2004,
the FASB issued SFAS 153 amending APB 29, which was based on the principle
that
nonmonetary assets should be measured based on the fair value of the
assets
exchanged. The guidance in APB 29 included certain exceptions to that
principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception
for
exchanges that do not have commercial substance. This Statement specifies
that a
nonmonetary exchange has commercial substance if the future cash flows
of the
entity are expected to change significantly as a result of the exchange.
The
provisions of this Statement are effective January 1, 2006 for
Penelec.
This FSP is not expected to have a material impact on Penelec's financial
statements.
SFAS
151,
“Inventory Costs - an amendment of ARB No. 43, Chapter 4”
In
November 2004,
the FASB issued SFAS 151 to clarify the accounting for abnormal amounts
of idle
facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may
be “so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as
current
period costs. In addition, this Statement requires that allocation
of fixed
production overheads to the cost of conversion be based on the normal
capacity
of the production facilities. The provisions of this statement are
effective for
inventory costs incurred by Penelec beginning January 1, 2006.
Penelec is
currently evaluating this Standard and does not expect it to have a
material
impact on the financial statements.
FSP
FAS 115-1,
"The Meaning of Other-Than-Temporary Impairment and its Application
to Certain
Investments"
In
September 2005,
the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1.
FSP FAS
115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition
of
Other Than Temporary Impairment upon the Planned Sale of a Security
Whose Cost
Exceeds Fair Value," (2) clarify that an investor should recognize
an impairment
loss no later than when the impairment is deemed other than temporary,
even if a
decision to sell has not been made, and (3) be effective for
other-than-temporary impairment and analyses conducted in periods beginning
after September 15, 2005. The FASB expects to issue this FSP
in the fourth
quarter of 2005, which would require prospective application with an
effective
date for reporting periods beginning after December 15, 2005. Penelec
is
currently evaluating this FSP and any impact on its
investments.
ITEM
3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
See
“Management’s
Discussion and Analysis of Results of Operation and Financial Condition
- Market
Risk Information” in Item 2 above.
ITEM
4.
CONTROLS AND PROCEDURES
(a) EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
The
applicable
registrant's chief executive officer and chief financial officer have
reviewed
and evaluated the registrant's disclosure controls and procedures,
as defined in
the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e),
as of the end
of the date covered by the report. Based on that evaluation, those
officers have
concluded that the registrant's disclosure controls and procedures
are effective
in timely alerting them to any information relating to the registrants
and their
consolidated subsidiaries that is required to be included in the registrants’
periodic reports and in ensuring that information required in the reports
filed
under the Securities Exchange Act of 1934 is recorded, processed, summarized
and
reported within the time period specified by the SEC's rules and
forms.
(b) CHANGES
IN
INTERNAL CONTROLS
During
the quarter
ended September 30, 2005, 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 13 and 14 to the Consolidated Financial Statements in Part I,
Item 1 of
this Form 10-Q.
ITEM
2. CHANGES
IN
SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES
(e) FirstEnergy
The
table below
includes information on a monthly basis regarding purchases made by
FirstEnergy
of its common stock.
|
|
|
|
|
|
|
|
Maximum
Number
|
|
|
|
|
|
|
|
|
|
(or
Approximate
|
|
|
|
|
|
|
|
Total
Number of
|
|
Dollar
Value) of
|
|
|
|
|
|
|
|
Shares
Purchased
|
|
Shares
that May
|
|
|
|
Total
Number
|
|
|
|
As
Part of Publicly
|
|
Yet
Be Purchased
|
|
|
|
of
Shares
|
|
Average
Price
|
|
Announced
Plans
|
|
Under
the Plans
|
|
Period
|
|
Purchased
(a)
|
|
Paid
per Share
|
|
or
Programs (b)
|
|
or
Programs
|
|
|
|
|
|
|
|
|
|
|
|
July
1-31,
2005
|
|
|
219,344
|
|
$
|
49.40
|
|
|
-
|
|
|
-
|
|
August
1-31,
2005
|
|
|
698,858
|
|
$
|
49.46
|
|
|
-
|
|
|
-
|
|
September
1-30, 2005
|
|
|
489,705
|
|
$
|
51.69
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
quarter
2005
|
|
|
1,407,907
|
|
$
|
50.23
|
|
|
-
|
|
|
-
|
|
|
(a)
|
Share
amounts
reflect purchases on the open market to satisfy FirstEnergy's
obligations
to deliver common stock under its Executive and Director
Incentive
Compensation Plan, Deferred Compensation Plan for Outside
Directors,
Executive Deferred Compensation Plan, Savings Plan and Stock
Investment
Plan. In addition, such amounts reflect shares tendered by
employees to
pay the exercise price or withholding taxes upon exercise
of stock options
granted under the Executive and Director Incentive Compensation
Plan.
|
|
(b)
|
FirstEnergy
does not currently have any publicly announced plan or program
for share
purchases.
|
ITEM
5.
OTHER
INFORMATION
On
November 1, 2005,
the Restated Partial Requirements Agreement, dated as of January
1, 2003, as
amended August 29, 2003 and June 8, 2004 (as so amended, the “Agreement”), among
FES, Met-Ed, Penelec and Waverly was amended by the parties to provide
FES the
right over the next year to terminate the Agreement at any time upon
60 days
written notice. Otherwise, the agreement remains automatically extended
as to
each operating company for each successive calendar year unless FES
or such
operating company elects to cancel the agreement by November 1 of
the preceding
year.
Under
the Agreement,
Met-Ed and Penelec currently purchase a portion of their PLR requirements
from
FES at fixed prices. The remainder of PLR requirements are currently
sourced
from existing NUG contracts or other power contracts with non-affiliated
third
party suppliers. If the Agreement were terminated, Met-Ed and Penelec
would need
to satisfy the applicable portion of their PLR obligations from other
sources at
prevailing prices, which are likely to be higher than the current
price charged
by FES under the Agreement, and as a result, Met-Ed’s and Penelec’s purchased
power costs could materially increase.
Met-Ed,
Penelec and
FES are all wholly owned subsidiaries of FirstEnergy and Waverly
is a wholly
owned subsidiary of Penelec. A copy of the November 1, 2005 amendment
is filed
as Exhibit 10.1 to this Quarterly Report on Form 10-Q.
ITEM
6. EXHIBITS
(a) Exhibits
Exhibit
|
|
Number
|
|
|
|
|
JCP&L
|
|
|
|
|
|
12
|
Fixed
charge
ratios
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.3
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.2
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
Met-Ed
|
|
|
|
|
|
10.1 |
Notice
of
Termination Tolling Agreement, Restated Partial Requirements
Agreement |
|
12
|
Fixed
charge
ratios
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
Penelec
|
|
|
|
|
|
10.1 |
Notice
of
Termination Tolling Agreement, Restated Partial Requirements
Agreement |
|
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-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
FirstEnergy
|
|
|
|
|
|
10.1 |
Notice
of
Termination Tolling Agreement, Restated Partial Requirements
Agreement |
|
10.2
|
Agreement
by
and between FirstEnergy Generation Corp. and Bechtel Power
Corporation
dated August 26, 2005.*
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
OE
|
|
|
|
|
|
15
|
Letter
from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
Penn
|
|
|
|
|
|
15
|
Letter
from
independent registered public accounting firm.
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
CEI
|
|
|
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
|
|
|
TE
|
|
|
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
32.1
|
Certification
of chief executive officer and chief financial officer, pursuant
to 18
U.S.C. Section 1350.
|
*
Confidential
Treatment has been requested with respect to certain portions of this
exhibit.
Omitted portions have been filed separately with the Securities and
Exchange
Commission.
Pursuant
to
reporting requirements of respective financings, JCP&L, Met-Ed and Penelec
are required to file fixed charge ratios as an exhibit to this Form
10-Q.
FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting
requirements and have not filed their respective fixed charge
ratios.
Pursuant
to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
OE,
CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this
Form 10-Q any instrument with respect to long-term debt if the
respective
total amount of securities authorized thereunder does not exceed 10%
of their
respective total assets of FirstEnergy and its subsidiaries on a consolidated
basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec, but
hereby agree to furnish to the Commission on request any such
documents.
SIGNATURE
Pursuant
to the
requirements of the Securities Exchange Act of 1934, each Registrant
has duly
caused this report to be signed on its behalf by the undersigned thereunto
duly
authorized.
November
2,
2005
|
FIRSTENERGY
CORP.
|
|
Registrant
|
|
|
|
OHIO
EDISON COMPANY
|
|
Registrant
|
|
|
|
THE
CLEVELAND ELECTRIC
|
|
ILLUMINATING
COMPANY
|
|
Registrant
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
POWER COMPANY
|
|
Registrant
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
Registrant
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
Registrant
|
|
/s/ Harvey
L.
Wagner
|
|
Harvey L. Wagner
|
|
Vice President, Controller
|
|
and
Chief Accounting Officer
|