main_10q.htm
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D. C. 20549
FORM
10-Q
(Mark
One)
[X] QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the quarterly period ended March 31, 2009
OR
[ ] TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the transition period from
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to
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Commission
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Registrant;
State of Incorporation;
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I.R.S.
Employer
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Address; and Telephone
Number
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333-21011
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FIRSTENERGY
CORP.
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34-1843785
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(An
Ohio Corporation)
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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333-145140-01
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FIRSTENERGY
SOLUTIONS CORP.
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31-1560186
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone
(800)736-3402
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1-2578
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OHIO
EDISON COMPANY
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34-0437786
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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1-2323
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THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
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34-0150020
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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1-3583
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THE
TOLEDO EDISON COMPANY
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34-4375005
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(An
Ohio Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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1-3141
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JERSEY
CENTRAL POWER & LIGHT COMPANY
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21-0485010
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(A
New Jersey Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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1-446
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METROPOLITAN
EDISON COMPANY
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23-0870160
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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1-3522
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PENNSYLVANIA
ELECTRIC COMPANY
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25-0718085
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(A
Pennsylvania Corporation)
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c/o
FirstEnergy Corp.
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76
South Main Street
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Akron,
OH 44308
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Telephone (800)736-3402
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Indicate by check
mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes (X) No ( )
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FirstEnergy
Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company,
The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric
Company
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Yes ( ) No (X)
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FirstEnergy
Solutions Corp.
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Indicate by check
mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted
and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the registrant
was required to submit and post such files).
Yes ( )
No ( )
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FirstEnergy
Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland
Electric Illuminating Company, The Toledo Edison Company, Jersey Central
Power & Light Company, Metropolitan Edison Company, and Pennsylvania
Electric Company
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Indicate by check
mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of
"large accelerated filer,” “accelerated filer” and “smaller reporting company"
in Rule 12b-2 of the Exchange Act.
Large
Accelerated Filer
(X)
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FirstEnergy
Corp.
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Accelerated
Filer
( )
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N/A
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Non-accelerated
Filer (Do
not check if a
smaller
reporting
company)
(X)
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FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light
Company, Metropolitan Edison Company and Pennsylvania Electric
Company
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Smaller
Reporting Company
( )
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N/A
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Indicate by check
mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act).
Yes ( )
No (X)
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FirstEnergy
Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland
Electric Illuminating Company, The Toledo Edison Company, Jersey Central
Power & Light Company, Metropolitan Edison Company and Pennsylvania
Electric Company
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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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FirstEnergy
Corp., $0.10 par value
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304,835,407
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FirstEnergy
Solutions Corp., no par value
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7
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Ohio Edison
Company, no par value
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60
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The Cleveland
Electric Illuminating Company, no par value
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67,930,743
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The Toledo
Edison Company, $5 par value
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29,402,054
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Jersey Central
Power & Light Company, $10 par value
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13,628,447
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Metropolitan
Edison Company, no par value
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859,500
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Pennsylvania
Electric Company, $20 par value
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4,427,577
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FirstEnergy Corp. is
the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The
Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey
Central Power & Light Company, Metropolitan Edison Company and Pennsylvania
Electric Company common stock.
This combined Form
10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio
Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison
Company, Jersey Central Power & Light Company, Metropolitan Edison Company
and Pennsylvania Electric Company. Information contained herein relating to any
individual registrant is filed by such registrant on its own behalf. No
registrant makes any representation as to information relating to any other
registrant, except that information relating to any of the FirstEnergy
subsidiary registrants is also attributed to FirstEnergy Corp.
OMISSION OF CERTAIN
INFORMATION
FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.
Forward-Looking Statements:
This Form 10-Q includes forward-looking statements based on information
currently available to management. Such statements are subject to certain risks
and uncertainties. These statements include declarations regarding management’s
intents, beliefs and current expectations. These statements typically contain,
but are not limited to, the terms “anticipate,” “potential,” “expect,”
“believe,” “estimate” and similar words. Forward-looking statements involve
estimates, assumptions, known and unknown risks, uncertainties and other factors
that may cause actual results, performance or achievements to be materially
different from any future results, performance or achievements expressed or
implied by such forward-looking statements.
Actual results may
differ materially due to:
·
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the speed and
nature of increased competition in the electric utility industry and
legislative and regulatory changes affecting how generation rates will be
determined following the expiration of existing rate plans in Ohio and
Pennsylvania,
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·
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the impact of
the PUCO’s regulatory process on the Ohio Companies associated with the
distribution rate case or implementing the recently-approved ESP,
including the outcome of any competitive generation procurement process in
Ohio,
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·
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economic or
weather conditions affecting future sales and
margins,
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·
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changes in
markets for energy services,
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·
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changing
energy and commodity market prices and
availability,
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·
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replacement
power costs being higher than anticipated or inadequately
hedged,
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·
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the continued
ability of FirstEnergy’s regulated utilities to collect transition and
other charges or to recover increased transmission
costs,
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·
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maintenance
costs being higher than
anticipated,
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·
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other
legislative and regulatory changes, revised environmental requirements,
including possible GHG emission
regulations,
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·
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the potential
impact of the U.S. Court of Appeals’ July 11, 2008 decision requiring
revisions to the CAIR rules and the scope of any laws, rules or
regulations that may ultimately take their
place,
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·
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the
uncertainty of the timing and amounts of the capital expenditures needed
to, among other things, implement the Air Quality Compliance Plan
(including that such amounts could be higher than anticipated or that
certain generating units may need to be shut down) or levels of emission
reductions related to the Consent Decree resolving the NSR litigation or
other potential regulatory
initiatives,
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·
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adverse
regulatory or legal decisions and outcomes (including, but not limited to,
the revocation of necessary licenses or operating permits and oversight)
by the NRC (including, but not limited to, the Demand for Information
issued to FENOC on May 14,
2007),
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·
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Met-Ed’s and
Penelec’s transmission service charge filings with the
PPUC,
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·
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the continuing
availability of generating units and their ability to operate at or near
full capacity,
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·
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the ability to
comply with applicable state and federal reliability
standards,
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·
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the ability to
accomplish or realize anticipated benefits from strategic goals (including
employee workforce initiatives),
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·
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the ability to
improve electric commodity margins and to experience growth in the
distribution business,
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·
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the changing
market conditions that could affect the value of assets held in the
registrants’ nuclear decommissioning trusts, pension trusts and other
trust funds, and cause FirstEnergy to make additional contributions
sooner, or in an amount that is larger than currently
anticipated,
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·
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the ability to
access the public securities and other capital and credit markets in
accordance with FirstEnergy’s financing plan and the cost of such
capital,
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·
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changes in
general economic conditions affecting the
registrants,
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·
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the state of
the capital and credit markets affecting the
registrants,
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·
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interest rates
and any actions taken by credit rating agencies that could negatively
affect the registrants’ access to financing or its costs and increase
requirements to post additional collateral to support outstanding
commodity positions, LOCs and other financial
guarantees,
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·
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the continuing
decline of the national and regional economy and its impact on the
registrants’ major industrial and commercial
customers,
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·
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issues
concerning the soundness of financial institutions and counterparties with
which the registrants do business,
and
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·
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the risks and
other factors discussed from time to time in the registrants’ SEC filings,
and other similar factors.
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The foregoing review
of factors should not be construed as exhaustive. New factors emerge from time
to time, and it is not possible for management to predict all such factors, nor
assess the impact of any such factor on the registrants’ business or the extent
to which any factor, or combination of factors, may cause results to differ
materially from those contained in any forward-looking statements. The
registrants expressly disclaim any current intention to update any
forward-looking statements contained herein as a result of new information,
future events or otherwise.
TABLE
OF CONTENTS
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Pages
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Glossary of Terms
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iii-v
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Part
I. Financial Information
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Items 1. and 2. - Financial
Statements and Management’s Discussion and Analysis ofFinancial Condition
and Results of Operations.
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FirstEnergy Corp.
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Management's
Discussion and Analysis of Financial Condition and
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1-35
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Results of Operations
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Report of
Independent Registered Public Accounting Firm
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36
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Consolidated
Statements of Income
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37
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Consolidated
Statements of Comprehensive Income
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38
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Consolidated
Balance Sheets
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39
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Consolidated
Statements of Cash Flows
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40
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FirstEnergy Solutions
Corp.
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Management's
Narrative Analysis of Results of Operations
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41-43
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Report of
Independent Registered Public Accounting Firm
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44
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Consolidated
Statements of Income and Comprehensive Income
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45
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Consolidated
Balance Sheets
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46
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Consolidated
Statements of Cash Flows
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47
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Ohio Edison
Company
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Management's
Narrative Analysis of Results of Operations
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48-49
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Report of
Independent Registered Public Accounting Firm
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50
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Consolidated
Statements of Income and Comprehensive Income
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51
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Consolidated
Balance Sheets
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52
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Consolidated
Statements of Cash Flows
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53
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The Cleveland Electric
Illuminating Company
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Management's
Narrative Analysis of Results of Operations
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54-55
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Report of
Independent Registered Public Accounting Firm
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56
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Consolidated
Statements of Income and Comprehensive Income
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57
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Consolidated
Balance Sheets
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58
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Consolidated
Statements of Cash Flows
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59
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The Toledo Edison
Company
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Management's
Narrative Analysis of Results of Operations
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60-61
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Report of
Independent Registered Public Accounting Firm
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62
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Consolidated
Statements of Income and Comprehensive Income
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63
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Consolidated
Balance Sheets
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64
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Consolidated
Statements of Cash Flows
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65
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TABLE
OF CONTENTS (Cont'd)
Jersey Central Power & Light
Company
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Pages
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Management's
Narrative Analysis of Results of Operations
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66-67
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Report of
Independent Registered Public Accounting Firm
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68
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Consolidated
Statements of Income and Comprehensive Income
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69
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Consolidated
Balance Sheets
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70
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Consolidated
Statements of Cash Flows
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71
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Metropolitan Edison
Company
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Management's
Narrative Analysis of Results of Operations
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72-73
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Report of
Independent Registered Public Accounting Firm
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74
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Consolidated
Statements of Income and Comprehensive Income
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75
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Consolidated
Balance Sheets
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76
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Consolidated
Statements of Cash Flows
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77
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Pennsylvania Electric
Company
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Management's
Narrative Analysis of Results of Operations
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78-79
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Report of
Independent Registered Public Accounting Firm
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80
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Consolidated
Statements of Income and Comprehensive Income
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81
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Consolidated
Balance Sheets
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82
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Consolidated
Statements of Cash Flows
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83
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Combined Management’s Discussion
and Analysis of Registrant Subsidiaries
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84-97
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Combined Notes to Consolidated
Financial Statements
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98-127
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Item
3. Quantitative
and Qualitative Disclosures About Market Risk.
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128
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Item
4. Controls
and Procedures – FirstEnergy.
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128
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Item
4T.
Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and
Penelec.
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128
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Part
II. Other Information
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Item
1. Legal
Proceedings.
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129
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Item
1A. Risk
Factors.
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129
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Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds.
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129
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Item
6. Exhibits.
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130-131
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GLOSSARY
OF TERMS
The
following abbreviations and acronyms are used in this report to identify
FirstEnergy Corp. and our current and former subsidiaries:
ATSI
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American
Transmission Systems, Inc., owns and operates transmission
facilities
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CEI
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The Cleveland
Electric Illuminating Company, an Ohio electric utility operating
subsidiary
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FENOC
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FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
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FES
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FirstEnergy
Solutions Corp., provides energy-related products and
services
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FESC
|
FirstEnergy
Service Company, provides legal, financial and other corporate support
services
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FEV
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FirstEnergy
Ventures Corp., invests in certain unregulated enterprises and business
ventures
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FGCO
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FirstEnergy
Generation Corp., owns and operates non-nuclear generating
facilities
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FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
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GPU
|
GPU, Inc.,
former parent of JCP&L, Met-Ed and Penelec, which merged with
FirstEnergy on
November 7,
2001
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JCP&L
|
Jersey Central
Power & Light Company, a New Jersey electric utility operating
subsidiary
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JCP&L
Transition
Funding
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JCP&L
Transition Funding LLC, a Delaware limited liability company and issuer of
transition bonds
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JCP&L
Transition
Funding
II
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JCP&L
Transition Funding II LLC, a Delaware limited liability company and issuer
of transition bonds
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Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
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NGC
|
FirstEnergy
Nuclear Generation Corp., owns nuclear generating
facilities
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OE
|
Ohio Edison
Company, an Ohio electric utility operating subsidiary
|
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
|
Pennsylvania
Companies
|
Met-Ed,
Penelec and Penn
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PNBV
|
PNBV Capital
Trust, a special purpose entity created by OE in 1996
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Shelf
Registrants
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OE, CEI, TE,
JCP&L, Met-Ed and Penelec
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Shippingport
|
Shippingport
Capital Trust, a special purpose entity created by CEI and TE in
1997
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Signal Peak
|
A joint
venture between FirstEnergy Ventures Corp. and Boich Companies, that owns
mining and
coal
transportation operations near Roundup, Montana
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TE
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The Toledo
Edison Company, an Ohio electric utility operating
subsidiary
|
Utilities
|
OE, CEI, TE,
Penn, JCP&L, Met-Ed and Penelec
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Waverly
|
The Waverly
Power and Light Company, a wholly owned subsidiary of
Penelec
|
|
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The
following abbreviations and acronyms are used to identify frequently used
terms in this report:
|
|
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AEP
|
American
Electric Power Company, Inc.
|
ALJ
|
Administrative
Law Judge
|
AOCL
|
Accumulated
Other Comprehensive Loss
|
AQC
|
Air Quality
Control
|
BGS
|
Basic
Generation Service
|
CAA
|
Clean Air
Act
|
CAIR
|
Clean Air
Interstate Rule
|
CAMR
|
Clean Air
Mercury Rule
|
CBP
|
Competitive
Bid Process
|
CO2
|
Carbon
Dioxide
|
CTC
|
Competitive
Transition Charge
|
DOJ
|
United States
Department of Justice
|
DPA
|
Department of
the Public Advocate, Division of Rate Counsel
|
EITF
|
Emerging
Issues Task Force
|
EMP
|
Energy Master
Plan
|
EPA
|
United States
Environmental Protection Agency
|
EPACT
|
Energy Policy
Act of 2005
|
ESP
|
Electric
Security Plan
|
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
48
|
FIN 48,
“Accounting for Uncertainty in Income Taxes-an interpretation of FASB
Statement No. 109”
|
GLOSSARY
OF TERMS Cont’d.
FMB
|
First Mortgage
Bond
|
FSP
|
FASB Staff
Position
|
FSP FAS 107-1
and
APB
28-1
|
FSP FAS 107-1
and APB 28-1, “Interim Disclosures about Fair Value of Financial
Instruments”
|
FSP FAS
115-1
and
SFAS 124-1
|
FSP FAS 115-1
and SFAS 124-1, “The Meaning of Other-Than-Temporary Impairment and
its
Application
to Certain Investments”
|
FSP FAS 115-2
and
FAS
124-2
|
FSP FAS 115-2
and FAS 124-2, “Recognition and Presentation of
Other-Than-Temporary
Impairments”
|
FSP FAS
132(R)-1
|
FSP FAS
132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan
Assets”
|
FSP FAS
157-4
|
FSP FAS 157-4,
“Determining Fair Value When the Volume and Level of Activity for the
Asset or
Liability
Have Significantly Decreased and Identifying Transactions That Are Not
Orderly”
|
FTR
|
Financial
Transmission Rights
|
GAAP
|
Accounting
Principles Generally Accepted in the United States
|
GHG
|
Greenhouse
Gases
|
ICE
|
Intercontinental
Exchange
|
IRS
|
Internal
Revenue Service
|
kV
|
Kilovolt
|
KWH
|
Kilowatt-hours
|
LED
|
Light-emitting
Diode
|
LIBOR
|
London
Interbank Offered Rate
|
LOC
|
Letter of
Credit
|
MEIUG
|
Met-Ed
Industrial Users Group
|
MISO
|
Midwest
Independent Transmission System Operator, Inc.
|
Moody’s
|
Moody’s
Investors Service, Inc.
|
MRO
|
Market Rate
Offer
|
MW
|
Megawatts
|
MWH
|
Megawatt-hours
|
NAAQS
|
National
Ambient Air Quality Standards
|
NERC
|
North American
Electric Reliability Corporation
|
NJBPU
|
New Jersey
Board of Public Utilities
|
NOV
|
Notice of
Violation
|
NOX
|
Nitrogen
Oxide
|
NRC
|
Nuclear
Regulatory Commission
|
NSR
|
New Source
Review
|
NUG
|
Non-Utility
Generation
|
NUGC
|
Non-Utility
Generation Charge
|
NYMEX
|
New York
Mercantile Exchange
|
OPEB
|
Other
Post-Employment Benefits
|
OVEC
|
Ohio Valley
Electric Corporation
|
PCRB
|
Pollution
Control Revenue Bond
|
PICA
|
Penelec
Industrial Customer Alliance
|
PJM
|
PJM
Interconnection L. L. C.
|
PLR
|
Provider of
Last Resort; an electric utility’s obligation to provide generation
service to customers
whose
alternative supplier fails to deliver service
|
PPUC
|
Pennsylvania
Public Utility Commission
|
PSA
|
Power Supply
Agreement
|
PUCO
|
Public
Utilities Commission of Ohio
|
PUHCA
|
Public Utility
Holding Company Act of 1935
|
RCP
|
Rate Certainty
Plan
|
RECB
|
Regional
Expansion Criteria and Benefits
|
RFP
|
Request for
Proposal
|
RSP
|
Rate
Stabilization Plan
|
RTC
|
Regulatory
Transition Charge
|
RTO
|
Regional
Transmission Organization
|
S&P
|
Standard &
Poor’s Ratings Service
|
SB221
|
Amended
Substitute Senate Bill 221
|
SBC
|
Societal
Benefits Charge
|
SEC
|
U.S.
Securities and Exchange Commission
|
SECA
|
Seams
Elimination Cost Adjustment
|
SFAS
|
Statement of
Financial Accounting Standards
|
GLOSSARY
OF TERMS Cont’d.
SFAS
115
|
SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity
Securities"
|
SFAS
133
|
SFAS No. 133,
“Accounting for Derivative Instruments and Hedging
Activities”
|
SFAS
157
|
SFAS No. 157,
“Fair Value Measurements”
|
SFAS
160
|
SFAS No. 160,
“Noncontrolling Interests in Consolidated Financial Statements – an
Amendment
of
ARB No. 51”
|
SIP
|
State
Implementation Plan(s) Under the Clean Air Act
|
SNCR
|
Selective
Non-Catalytic Reduction
|
SO2
|
Sulfur
Dioxide
|
TBC
|
Transition
Bond Charge
|
TMI-1
|
Three Mile
Island Unit 1
|
TMI-2
|
Three Mile
Island Unit 2
|
TSC
|
Transmission
Service Charge
|
VIE
|
Variable
Interest Entity
|
PART I. FINANCIAL
INFORMATION
ITEMS
1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
FIRSTENERGY
CORP.
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE
SUMMARY
Net income in the
first quarter of 2009 was $115 million, or basic and diluted earnings of
$0.39 per share of common stock, compared with net income of $277 million,
or basic earnings of $0.91 per share of common stock ($0.90 diluted) in the
first quarter of 2008. The decrease in FirstEnergy’s earnings resulted
principally from regulatory charges ($168 million after-tax) recognized in the
first quarter of 2009 primarily related to the implementation of the Ohio
Companies’ Amended ESP.
Change
in Basic Earnings Per Share
From
Prior Year First Quarter
|
|
|
|
Basic Earnings
Per Share – First Quarter 2008
|
$
0.91
|
Regulatory
charges – 2009
|
(0.55)
|
Income tax
resolution – 2009
|
0.04
|
Organizational
restructuring – 2009
|
(0.05)
|
Gain on
non-core asset sales – 2008
|
(0.06)
|
Trust
securities impairment
|
(0.04)
|
Revenues
|
0.18
|
Fuel and
purchased power
|
(0.24)
|
Amortization /
deferral of regulatory assets
|
0.13
|
Other
expenses
|
0.07
|
Basic Earnings
Per Share – First Quarter 2009
|
$
0.39
|
Regulatory
Matters - Ohio
Ohio
Regulatory Proceedings
On March 25, 2009,
the PUCO issued an order approving the Ohio Companies’ Amended ESP, which
includes provisions for establishing a competitive bid process for generation
supply and pricing for a two-year period beginning June 1, 2009, freezing
distribution rates through December 31, 2011, subject to limited exceptions, and
reducing CEI’s recoverable Extended RTC balance as of
May 31, 2009 by 50 percent ($216 million). On March 4, 2009, the PUCO
issued an order allowing the Ohio Companies to provide electric generation
service to their customers from April 1, 2009, through May 31, 2009, from FES at
the average rate resulting from the Ohio Companies’ December 31, 2008, RFP. The
PUCO also approved the continuation of CEI’s purchased power cost deferral and
the process under which the Ohio Companies conducted their December RFP. The
Amended ESP resulted from a stipulated agreement reached with the PUCO Staff and
nearly all of the intervening parties to the case.
Regulatory
Matters - Pennsylvania
Pennsylvania
Legislative Process
The Governor of
Pennsylvania signed Act 129 of 2008 into law in October 2008, which became
effective November 14, 2008, to create an energy efficiency and
conservation program with requirements to adopt and implement cost-effective
plans to reduce energy consumption and peak demand. On March 26, 2009, the PPUC
approved the company-specific energy consumption and peak demand reductions that
must be achieved under Act 129, which requires electric distribution companies
to reduce electricity consumption by 1% by May 31, 2011 and by 3% by May 31,
2013, and an annual system peak demand reduction of 4.5% by May 31, 2013.
Costs associated with achieving the reduction will be recovered from customers.
Under Act 129, electric distribution companies must develop and file their
energy efficiency and peak load reduction plans for compliance with these
requirements by July 1, 2009.
Act 129 also
requires electric distribution companies to submit by August 14, 2009, a plan to
deploy smart metering technology over a time period not to exceed fifteen
years. The costs of developing and implementing the plan as
ultimately approved by the PPUC will be recovered from customers.
Met-Ed
and Penelec Transmission Rider Filings
On April 15, 2009,
Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009
through May 31, 2010, as required in connection with the PPUC’s January
2007 rate order. For Penelec’s customers, the new TSC would result in an
approximate 1% decrease in monthly bills, reflecting projected PJM transmission
costs as well as a reconciliation for costs already incurred. The TSC for
Met-Ed’s customers would increase to recover the additional PJM charges paid by
Met-Ed in the previous year and to reflect updated projected costs. In order to
gradually transition customers to the higher rate, Met-Ed is proposing to
continue to recover the prior period deferrals allowed in the PPUC’s May 2008
Order and defer $57.5 million of projected costs into a future TSC to be fully
recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s
customers would increase approximately 9.4% for the period June 2009 through May
2010.
On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to their TSC for the period
June 1, 2008, through May 31, 2009. The PPUC ordered an investigation
to review the reasonableness of Met-Ed’s TSC which included a transition
approach that would recover past under-recovered costs of $144 million plus
carrying charges over a 31-month period and deferral of a portion ($92 million)
of projected costs for recovery over a 19-month period beginning June 1,
2009, through December 31, 2010. Hearings and briefing were concluded in
February 2009. On March 4, 2009, MEIUG and PICA filed a Petition to reopen the
record. Met-Ed and Penelec filed objections to MEIUG and PICA’s Petition on
March 13, 2009, resulting in an April 1, 2009, order denying MEIUG
& PICA’s Petition to reopen the record. Met-Ed is awaiting a final PPUC
decision.
Met-Ed
and Penelec Customer Prepayment Plan and Procurement Plan
On September 25,
2008, Met-Ed and Penelec filed a Voluntary Prepayment Plan with the PPUC that
would provide an opportunity for residential and small commercial customers to
prepay about 9.6% of their monthly electric bills during 2009 and 2010, which
would earn interest at 7.5% and be used to reduce electricity charges in 2011
and 2012. Met-Ed, Penelec, the Office of Consumer Advocate and the Office of
Small Business Advocate reached a settlement agreement on the Voluntary
Prepayment Plan, which the PPUC approved on February 26, 2009.
On February 20,
2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan
covering the period January 1, 2011, through May 31, 2013. The plan is
designed to provide adequate and reliable service through a prudent mix of
long-term, short-term and spot market generation supply as required by
Pennsylvania law. The plan proposes a staggered procurement schedule, which
varies by customer class. On March 30, 2009, Met-Ed and Penelec filed written
Direct Testimony; hearings are scheduled for July 15-17, 2009. Met-Ed and
Penelec have requested PPUC approval of their plan by November
2009.
Met-Ed
and Penelec NUG Statement Compliance Filing
On March 31, 2009,
Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the
PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to
reduce its CTC rate for the residential class with a corresponding increase in
the generation rate and the shopping credit, and Penelec proposed to reduce its
CTC rate to zero for all classes with a corresponding increase in the generation
rate and the shopping credit. While these changes would result in additional
annual generation revenue (Met-Ed - $27 million and Penelec - $51 million),
overall rates would remain unchanged. The PPUC must act on this filing within
120 days.
Regulatory
Matters – New Jersey
JCP&L
Solar Renewable Energy Proposal Approved
On March 27, 2009,
the NJBPU approved JCP&L’s proposal to help increase the pace of solar
energy project development in the state by establishing long-term agreements to
purchase and sell Solar Renewable Energy Certificates, which will provide a
stable basis for financing solar generation projects. The plan is expected to
support the phase-in of approximately 42 megawatts of solar generating capacity
over the next three years to help meet the state’s Renewable Portfolio Standards
through 2012.
JCP&L
Selected for Smart Grid Demonstration
JCP&L is one of
three companies selected as a smart grid demonstration host site by the Electric
Power Research Institute to test the integration of smart grid and other
technologies into operations of existing systems. The technologies exhibited
during this project may be one solution to accomplishing the goals of the New
Jersey Energy Master Plan by meeting future electricity demand.
Operational
Matters
Generation
Outages
On February 23,
2009, the Perry Plant began its 12th
scheduled refueling and maintenance outage, in which 280 of the plant’s 748 fuel
assemblies will be exchanged, safety inspections will be conducted, and several
maintenance projects will be completed, including replacement of the plant’s
recirculation pump motor.
On April 20, 2009,
Beaver Valley Unit 1 began a scheduled refueling and maintenance outage. During
the outage, 62 of the 157 fuel assemblies will be exchanged and safety
inspections will be conducted. Also, several projects will be completed to
ensure continued safe and reliable operations, including maintenance on the
cooling tower and the replacement of a pump motor. The unit operated safely and
reliably for 545 consecutive days, beating the previous records of 456 days for
Unit 1 and 537 days for Unit 2 set in 2006 and 2005, respectively.
FirstEnergy expects
generation output for 2009 to be lower than 2008, partly related to three
scheduled nuclear refueling outages in 2009 and a number of planned fossil
outages in the second half of the year, including the tie in of Sammis
Unit 6 as part of FirstEnergy’s air quality control project. FirstEnergy is
also re-evaluating its near-term plans for maintenance and capital work and
outages scheduled over the next several years and may take advantage of the
reduced loads anticipated as a result of economic conditions to undertake
additional work on its facilities, including its largest
units.
R. E. Burger Plant
On April 1, 2009,
FirstEnergy announced plans to retrofit Units 4 and 5 at its R.E. Burger Plant
to repower the units with biomass. Retrofitting the Burger Plant will help meet
the renewable energy goals set forth in Ohio SB221, utilize much of the existing
infrastructure currently in place, preserve approximately 100 jobs and continue
positive economic support to Belmont County, making the Burger Plant one of the
largest biomass facilities in the United States.
OVEC Participation Interest
Sale
On May 1, 2009, FGCO
announced the sale of a 9% interest in the output from OVEC to Buckeye Power
Generating LLC for $252 million. The sale involves the output of 214 MW from
OVEC’s generating facilities in southern Indiana and Ohio. FGCO’s remaining
interest in OVEC was reduced to 11.5%. This transaction is expected to increase
earnings in the second quarter of 2009 by $159 million.
FirstEnergy Reorganization
On March 3, 2009,
FirstEnergy announced it would reduce its management and support staff by 335
employees. This staffing reduction resulted from an effort to enhance
efficiencies in response to the economic downturn. The reduction represents
approximately four percent of FirstEnergy’s non-union workforce. Severance
benefits and career counseling services were provided to eligible employees.
Total one-time charges associated with the reorganization were approximately $22
million, or $0.05 per share of common stock.
Financial
Matters
On January 20, 2009,
Met-Ed issued $300 million of 7.70% Senior Notes due 2019 and used the net
proceeds to repay short-term borrowings. On January 27, 2009, JCP&L issued
$300 million of 7.35% Senior Notes due 2019 and used the net proceeds to repay
short-term borrowings, repurchase equity from FirstEnergy, fund capital
expenditures and for other general corporate purposes. On April 24, 2009,
TE issued $300 million of 7.25% Senior Secured Notes due 2020 and used the net
proceeds to repay short-term borrowings, to fund capital expenditures and for
other general corporate purposes.
On February 12,
2009, $153 million of Wachovia LOCs supporting a like amount of NGC’s PCRBs were
renewed until March 17, 2014, and on March 10, 2009, $100 million of
FGCO’s PCRBs were converted from a variable-rate mode enhanced by Wachovia LOCs
to a fixed-rate mode secured by FMBs.
On March 31, 2009,
FES and FGCO executed a new $100 million, two-year secured term loan facility
with The Royal Bank of Scotland Finance (Ireland) (RBSFI) that replaces an
existing $100 million borrowing facility with RBSFI that was expiring in
November 2009.
FIRSTENERGY’S
BUSINESS
FirstEnergy is a
diversified energy company headquartered in Akron, Ohio, that operates primarily
through three core business segments (see Results of
Operations).
·
|
Energy Delivery Services
transmits and distributes electricity through FirstEnergy’s eight utility
operating companies, serving 4.5 million customers within 36,100
square miles of Ohio, Pennsylvania and New Jersey and purchases power for
its PLR and default service requirements in Pennsylvania and New Jersey.
This business segment derives its revenues principally from the delivery
of electricity within FirstEnergy’s service areas and the sale of electric
generation service to retail customers who have not selected an
alternative supplier (default service) in its Pennsylvania and New Jersey
franchise areas.
|
·
|
Competitive Energy
Services supplies the electric power needs of end-use customers
through retail and wholesale arrangements, including associated company
power sales to meet a portion of the PLR and default service requirements
of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and
competitive retail sales to customers primarily in Ohio, Pennsylvania,
Maryland, Michigan and Illinois. This business segment owns or leases and
operates 19 generating facilities with a net demonstrated capacity of
13,710 MW and also purchases electricity to meet sales obligations.
The segment's net income is primarily derived from affiliated company
power sales and non-affiliated electric generation sales revenues less the
related costs of electricity generation, including purchased power and net
transmission and ancillary costs charged by PJM and MISO to deliver energy
to the segment’s customers.
|
·
|
Ohio Transitional Generation
Services supplies the electric power needs of non-shopping
customers under the default service requirements of FirstEnergy’s Ohio
Companies. The segment's net income is primarily derived from electric
generation sales revenues less the cost of power purchased through the
Ohio Companies’ CBP, including net transmission and ancillary costs
charged by MISO to deliver energy to retail
customers.
|
RESULTS
OF OPERATIONS
The financial
results discussed below include revenues and expenses from transactions among
FirstEnergy's business segments. A reconciliation of segment financial results
is provided in Note 11 to the consolidated financial statements. Net income
by major business segment was as follows:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31
|
|
Increase
|
|
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
Earnings
(Loss)
|
|
(In
millions, except per share data)
|
|
By
Business Segment
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
|
Ohio
transitional generation services
|
|
|
|
|
|
|
|
|
|
|
Other and
reconciling adjustments*
|
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.39
|
|
$
|
0.91
|
|
$
|
(0.52
|
)
|
Diluted
Earnings Per Share
|
|
$
|
0.39
|
|
$
|
0.90
|
|
$
|
(0.51
|
)
|
*
Consists primarily of interest expense related to holding company debt,
corporate support services revenues and expenses, noncontrolling interests and
elimination of intersegment transactions.
Summary of Results of Operations –
First Quarter 2009 Compared with First Quarter 2008
Financial results
for FirstEnergy's major business segments in the first three months of 2009 and
2008 were as follows:
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
First
Quarter 2009 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
1,959 |
|
|
$ |
280 |
|
|
$ |
902 |
|
|
$ |
- |
|
|
$ |
3,141 |
|
Other
|
|
|
150 |
|
|
|
55 |
|
|
|
10 |
|
|
|
(22 |
) |
|
|
193 |
|
Internal
|
|
|
- |
|
|
|
893 |
|
|
|
- |
|
|
|
(893 |
) |
|
|
- |
|
Total
Revenues
|
|
|
2,109 |
|
|
|
1,228 |
|
|
|
912 |
|
|
|
(915 |
) |
|
|
3,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
- |
|
|
|
312 |
|
|
|
- |
|
|
|
- |
|
|
|
312 |
|
Purchased
power
|
|
|
978 |
|
|
|
160 |
|
|
|
898 |
|
|
|
(893 |
) |
|
|
1,143 |
|
Other
operating expenses
|
|
|
480 |
|
|
|
355 |
|
|
|
18 |
|
|
|
(26 |
) |
|
|
827 |
|
Provision for
depreciation
|
|
|
109 |
|
|
|
64 |
|
|
|
- |
|
|
|
4 |
|
|
|
177 |
|
Amortization
of regulatory assets
|
|
|
406 |
|
|
|
- |
|
|
|
5 |
|
|
|
- |
|
|
|
411 |
|
Deferral of
new regulatory assets
|
|
|
(43 |
) |
|
|
- |
|
|
|
(50 |
) |
|
|
- |
|
|
|
(93 |
) |
General
taxes
|
|
|
168 |
|
|
|
32 |
|
|
|
2 |
|
|
|
9 |
|
|
|
211 |
|
Total
Expenses
|
|
|
2,098 |
|
|
|
923 |
|
|
|
873 |
|
|
|
(906 |
) |
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
11 |
|
|
|
305 |
|
|
|
39 |
|
|
|
(9 |
) |
|
|
346 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income (loss)
|
|
|
29 |
|
|
|
(29 |
) |
|
|
1 |
|
|
|
(12 |
) |
|
|
(11 |
) |
Interest
expense
|
|
|
(111 |
) |
|
|
(28 |
) |
|
|
- |
|
|
|
(55 |
) |
|
|
(194 |
) |
Capitalized
interest
|
|
|
1 |
|
|
|
10 |
|
|
|
- |
|
|
|
17 |
|
|
|
28 |
|
Total Other
Expense
|
|
|
(81 |
) |
|
|
(47 |
) |
|
|
1 |
|
|
|
(50 |
) |
|
|
(177 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
(70 |
) |
|
|
258 |
|
|
|
40 |
|
|
|
(59 |
) |
|
|
169 |
|
Income
taxes
|
|
|
(28 |
) |
|
|
103 |
|
|
|
16 |
|
|
|
(37 |
) |
|
|
54 |
|
Net Income
(Loss)
|
|
|
(42 |
) |
|
|
155 |
|
|
|
24 |
|
|
|
(22 |
) |
|
|
115 |
|
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(4 |
) |
|
|
(4 |
) |
Earnings
(Loss) Available To Parent
|
|
$ |
(42 |
) |
|
$ |
155 |
|
|
$ |
24 |
|
|
$ |
(18 |
) |
|
$ |
119 |
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
First
Quarter 2008 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
2,050 |
|
|
$ |
289 |
|
|
$ |
691 |
|
|
$ |
- |
|
|
$ |
3,030 |
|
Other
|
|
|
162 |
|
|
|
40 |
|
|
|
16 |
|
|
|
29 |
|
|
|
247 |
|
Internal
|
|
|
- |
|
|
|
776 |
|
|
|
- |
|
|
|
(776 |
) |
|
|
- |
|
Total
Revenues
|
|
|
2,212 |
|
|
|
1,105 |
|
|
|
707 |
|
|
|
(747 |
) |
|
|
3,277 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
1 |
|
|
|
327 |
|
|
|
- |
|
|
|
- |
|
|
|
328 |
|
Purchased
power
|
|
|
982 |
|
|
|
206 |
|
|
|
588 |
|
|
|
(776 |
) |
|
|
1,000 |
|
Other
operating expenses
|
|
|
445 |
|
|
|
309 |
|
|
|
77 |
|
|
|
(32 |
) |
|
|
799 |
|
Provision for
depreciation
|
|
|
106 |
|
|
|
53 |
|
|
|
- |
|
|
|
5 |
|
|
|
164 |
|
Amortization
of regulatory assets
|
|
|
249 |
|
|
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
258 |
|
Deferral of
new regulatory assets
|
|
|
(100 |
) |
|
|
- |
|
|
|
(5 |
) |
|
|
- |
|
|
|
(105 |
) |
General
taxes
|
|
|
173 |
|
|
|
32 |
|
|
|
1 |
|
|
|
9 |
|
|
|
215 |
|
Total
Expenses
|
|
|
1,856 |
|
|
|
927 |
|
|
|
670 |
|
|
|
(794 |
) |
|
|
2,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
356 |
|
|
|
178 |
|
|
|
37 |
|
|
|
47 |
|
|
|
618 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
45 |
|
|
|
(6 |
) |
|
|
1 |
|
|
|
(23 |
) |
|
|
17 |
|
Interest
expense
|
|
|
(103 |
) |
|
|
(34 |
) |
|
|
- |
|
|
|
(42 |
) |
|
|
(179 |
) |
Capitalized
interest
|
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
1 |
|
|
|
8 |
|
Total Other
Expense
|
|
|
(58 |
) |
|
|
(33 |
) |
|
|
1 |
|
|
|
(64 |
) |
|
|
(154 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
298 |
|
|
|
145 |
|
|
|
38 |
|
|
|
(17 |
) |
|
|
464 |
|
Income
taxes
|
|
|
119 |
|
|
|
58 |
|
|
|
15 |
|
|
|
(5 |
) |
|
|
187 |
|
Net
Income
|
|
|
179 |
|
|
|
87 |
|
|
|
23 |
|
|
|
(12 |
) |
|
|
277 |
|
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
Earnings
Available To Parent
|
|
$ |
179 |
|
|
$ |
87 |
|
|
$ |
23 |
|
|
$ |
(13 |
) |
|
$ |
276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between First Quarter 2009 and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter 2008 Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
(91 |
) |
|
$ |
(9 |
) |
|
$ |
211 |
|
|
$ |
- |
|
|
$ |
111 |
|
Other
|
|
|
(12 |
) |
|
|
15 |
|
|
|
(6 |
) |
|
|
(51 |
) |
|
|
(54 |
) |
Internal
|
|
|
- |
|
|
|
117 |
|
|
|
- |
|
|
|
(117 |
) |
|
|
- |
|
Total
Revenues
|
|
|
(103 |
) |
|
|
123 |
|
|
|
205 |
|
|
|
(168 |
) |
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
(1 |
) |
|
|
(15 |
) |
|
|
- |
|
|
|
- |
|
|
|
(16 |
) |
Purchased
power
|
|
|
(4 |
) |
|
|
(46 |
) |
|
|
310 |
|
|
|
(117 |
) |
|
|
143 |
|
Other
operating expenses
|
|
|
35 |
|
|
|
46 |
|
|
|
(59 |
) |
|
|
6 |
|
|
|
28 |
|
Provision for
depreciation
|
|
|
3 |
|
|
|
11 |
|
|
|
- |
|
|
|
(1 |
) |
|
|
13 |
|
Amortization
of regulatory assets
|
|
|
157 |
|
|
|
- |
|
|
|
(4 |
) |
|
|
- |
|
|
|
153 |
|
Deferral of
new regulatory assets
|
|
|
57 |
|
|
|
- |
|
|
|
(45 |
) |
|
|
- |
|
|
|
12 |
|
General
taxes
|
|
|
(5 |
) |
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
(4 |
) |
Total
Expenses
|
|
|
242 |
|
|
|
(4 |
) |
|
|
203 |
|
|
|
(112 |
) |
|
|
329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(345 |
) |
|
|
127 |
|
|
|
2 |
|
|
|
(56 |
) |
|
|
(272 |
) |
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income (loss)
|
|
|
(16 |
) |
|
|
(23 |
) |
|
|
- |
|
|
|
11 |
|
|
|
(28 |
) |
Interest
expense
|
|
|
(8 |
) |
|
|
6 |
|
|
|
- |
|
|
|
(13 |
) |
|
|
(15 |
) |
Capitalized
interest
|
|
|
1 |
|
|
|
3 |
|
|
|
- |
|
|
|
16 |
|
|
|
20 |
|
Total Other
Income (Expense)
|
|
|
(23 |
) |
|
|
(14 |
) |
|
|
- |
|
|
|
14 |
|
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
(368 |
) |
|
|
113 |
|
|
|
2 |
|
|
|
(42 |
) |
|
|
(295 |
) |
Income
taxes
|
|
|
(147 |
) |
|
|
45 |
|
|
|
1 |
|
|
|
(32 |
) |
|
|
(133 |
) |
Net
Income
|
|
|
(221 |
) |
|
|
68 |
|
|
|
1 |
|
|
|
(10 |
) |
|
|
(162 |
) |
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(5 |
) |
|
|
(5 |
) |
Earnings
Available To Parent
|
|
$ |
(221 |
) |
|
$ |
68 |
|
|
$ |
1 |
|
|
$ |
(5 |
) |
|
$ |
(157 |
) |
Energy Delivery Services – First
Quarter 2009 Compared with First Quarter 2008
This segment
recognized a net loss of $42 million in the first three months of 2009
compared to net income of $179 million in the first three months of 2008,
primarily due to CEI’s $216 million regulatory asset impairment related to
the implementation of the Ohio Companies’ Amended ESP and other regulatory
charges.
Revenues –
The
decrease in total revenues of $103 million resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
The
change in distribution deliveries by customer class is summarized in the
following table:
Electric
Distribution KWH Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Distribution KWH Deliveries
|
|
|
|
The lower revenues
from distribution deliveries were driven by the reductions in sales volume. The
decrease in electric distribution deliveries to commercial and industrial
customers was primarily due to economic conditions in FirstEnergy’s service
territory. In the industrial sector, KWH deliveries declined to major automotive
(28.4%), steel (40.1%), and refinery customers (15.1%). Transition charges for
OE and TE that ceased effective January 1, 2009, with the full recovery of
related costs, were offset by PUCO-approved distribution rate increases (see
Regulatory Matters – Ohio).
The following table
summarizes the price and volume factors contributing to the $9 million
decrease in generation revenues in the first quarter of 2009 compared to the
first quarter of 2008:
Sources
of Change in Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 3.5% decrease in sales volumes
|
|
$
|
(27
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
|
Wholesale:
|
|
|
|
|
Effect
of 11.6% decrease in sales volumes
|
|
|
(25
|
)
|
Change
in prices
|
|
|
|
)
|
|
|
|
|
)
|
Net Decrease
in Generation Revenues
|
|
|
|
)
|
The decrease in
retail generation sales volumes was primarily due to weakened economic
conditions partially offset by increased weather-related usage (heating degree
days increased by 3.3% in the first quarter of 2009). The increase in retail
generation prices during the first three months of 2009 reflected increased
generation rates for JCP&L resulting from the New Jersey BGS auction and for
Penn under its RFP process. Wholesale generation sales decreased principally as
a result of JCP&L selling less power from NUGs. The decrease in prices
reflected lower spot market prices for PJM market participants.
Transmission
revenues increased $11 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the annual update to their TSC riders in
mid-2008. Met-Ed and Penelec defer the difference between revenues from their
transmission rider and transmission costs incurred, resulting in no material
effect to current period earnings (see Regulatory Matters –
Pennsylvania).
Expenses –
The
$242 million increase in total expenses was due to the
following:
|
·
|
Purchased
power costs were $4 million lower in the
first three months of 2009 due to reduced volumes and an increase in the
amount of NUG costs deferred, partially offset by increased unit costs.
The increased unit costs reflected higher JCP&L costs resulting from
the BGS auction. JCP&L is permitted to defer for future collection
from customers the amounts by which its costs of supplying BGS to
non-shopping customers and costs incurred under NUG agreements exceed
amounts collected through BGS and NUGC rates and market sales of NUG
energy and capacity. The following table summarizes the sources of changes
in purchased power costs:
|
Source
of Change in Purchased Power
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Purchases from
non-affiliates:
|
|
|
|
|
Change due to increased unit
costs
|
|
$
|
120
|
|
Change due to decreased
volumes
|
|
|
(103
|
)
|
|
|
|
17
|
|
Purchases from
FES:
|
|
|
|
|
Change due to decreased unit
costs
|
|
|
(9
|
)
|
Change due to increased
volumes
|
|
|
22
|
|
|
|
|
13
|
|
|
|
|
|
|
Increase in
NUG costs deferred
|
|
|
(34
|
)
|
Net Decrease
in Purchased Power Costs
|
|
$
|
(4
|
)
|
|
·
|
An increase in
other operating expenses of $34 million resulted from economic
development obligations, in accordance with the PUCO-approved ESP, and
energy efficiency obligations.
|
·
|
An increase in
employee benefit costs of $30 million and
organizational restructuring costs of $5 million were offset by
reductions in contractor costs of $19 million, transmission expense of
$11 million and materials and supplies costs of
$5 million.
|
|
·
|
An increase of
$157 million in amortization of regulatory assets in 2009 was due to
the ESP-related impairment of CEI’s regulatory assets ($216 million),
partially offset by the cessation of transition cost amortization for OE
and TE ($68 million).
|
|
·
|
The deferral
of new regulatory assets decreased by $57 million during the first
three months of 2009 primarily due to lower PJM transmission cost
deferrals ($25 million) and the cessation in 2009 of RCP distribution cost
deferrals by the Ohio Companies
($35 million).
|
·
|
Depreciation
expense increased $3 million due to property additions since the first
quarter of 2008.
|
·
|
General taxes
decreased $5 million primarily due to lower gross receipts taxes on
reduced revenues.
|
Other Expense –
Other expense
increased $23 million
in 2009 compared to the first three months of 2008, due to lower investment
income of $16 million
resulting from the repayment of notes receivable from affiliates and higher
interest expense (net of capitalized interest) of $7 million due to $600 million
of senior notes issued by JCP&L and Met-Ed in January 2009.
Competitive Energy Services – First
Quarter 2009 Compared with First Quarter 2008
Net income for this
segment was $155 million in the first three
months of 2009 compared to $87 million in the same period
in 2008. The $68 million increase in net income reflected an increase in
gross generation margin, partially offset by higher operating
costs.
Revenues –
Total revenues
increased $123 million
in the first three months of 2009 compared to the same period in 2008. This
increase primarily resulted from higher unit prices on affiliated generation
sales to the Ohio Companies and increased non-affiliated wholesale sales,
partially offset by lower retail sales.
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
)
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The lower retail
revenues reflect reduced commercial and industrial contract renewals in the PJM
market and the termination of certain government aggregation programs in Ohio.
Higher non-affiliated wholesale revenues resulted from higher PJM capacity
prices and increased sales volumes in the MISO market, partially offset by lower
unit prices and volumes in PJM.
The increased
affiliated company generation revenues were due to higher unit prices for sales
to the Ohio Companies under their CBP, partially offset by lower unit prices to
the Pennsylvania Companies and an overall decrease in affiliated sales volumes.
While unit prices for each of the Pennsylvania Companies did not change, the mix
of sales among the companies caused the composite price to decline. FES supplied
less power to the Ohio Companies in the first quarter of 2009 as one of four
winning bidders in the Ohio Companies’ RFP process. The amount of power FES will
supply to the Ohio Companies for periods beginning on or after June 1, 2009 will
be determined by the extent to which FES is successful in bidding in the
upcoming CBP, which is currently scheduled to begin on May 13,
2009.
The following tables
summarize the price and volume factors contributing to changes in revenues from
generation sales:
|
|
|
|
Source
of Change in Non-Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect of 57.0% decrease in sales
volumes
|
|
$
|
(91
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect of 33.9% increase in sales
volumes
|
|
|
44
|
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Net Decrease
in Non-Affiliated Generation Revenues
|
|
|
|
)
|
Source
of Change in Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect of 24.6% decrease in sales
volumes
|
|
$
|
(142
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect of 11.1% increase in sales
volumes
|
|
|
22
|
|
Change in prices
|
|
|
|
)
|
|
|
|
|
|
Net Increase
in Affiliated Generation Revenues
|
|
|
|
|
Transmission
revenues decreased $8 million due to decreased retail load in the MISO
market ($14 million) partially offset by higher PJM congestion revenue ($6
million). Increased lease revenue represents NGC’s acquisition of the equity
interests in the OE and TE Beaver Valley and Perry sale and leaseback
transactions.
Expenses -
Total expenses
decreased $4 million in the first three months of 2009 due to the following
factors:
|
·
|
Purchased
power costs decreased $46 million due primarily to lower unit costs
($15 million) and reduced volume requirements
($31 million).
|
·
|
Fossil fuel
costs decreased $15 million due to decreased generation volumes
($53 million) partially offset by higher unit prices
($38 million). The increased unit prices primarily reflect increased
fuel rates on existing coal contracts in the first quarter of
2009.
|
·
|
Fossil
operating costs decreased $4 million due to a $6 million decrease in
contractor costs as a result of reduced maintenance activities, partially
offset by organizational restructuring costs of
$2 million.
|
·
|
Other
operating expenses increased $27 million due primarily to increased
intersegment billings for leasehold costs from the Ohio
Companies.
|
·
|
Nuclear
operating costs increased $16 million due to higher expenses
associated with the 2009 Perry refueling outage than incurred with the
2008 Davis-Besse refueling outage.
|
|
·
|
Higher
depreciation expense of $11 million was due to property additions
since the first quarter of 2008.
|
·
|
Transmission
expense increased $7 million due to increased PJM
charges.
|
Other Expense –
Total other expense
in the first three months of 2009 was $14 million higher than the
first quarter of 2008, primarily due to a $23 million decrease in earnings
from nuclear decommissioning trust investments reflecting impairments in the
value of securities. This impact was partially offset by a decline in interest
expense (net of capitalized interest) of $9 million.
Ohio Transitional Generation Services –
First Quarter 2009 Compared with First Quarter 2008
Net income for this
segment increased to $24 million in the first three
months of 2009 from $23 million in the same period of 2008. Higher
operating revenues were almost entirely offset by higher operating expenses,
primarily for purchased power.
Revenues –
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months Ended
|
|
|
|
|
|
March
31
|
|
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The following table
summarizes the price and volume factors contributing to the increase in sales
revenues from retail customers:
Source
of Change in Retail Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Effect of 5.0% increase in sales
volumes
|
|
$
|
30
|
|
Change in prices
|
|
|
|
|
Total
Increase in Retail Generation Revenues
|
|
|
|
|
The increase in
generation sales was primarily due to reduced customer shopping as most of the
Ohio Companies’ customers returned to PLR service in December 2008 due to the
termination of certain government aggregation programs in Ohio. Average prices
increased primarily due to an increase in the Ohio Companies’ fuel cost recovery
rider that became effective in January 2009.
Increased
transmission revenue of $17 million resulted from higher sales volumes and a
PUCO-approved transmission tariff increase that was effective in mid-2008. The
difference between transmission revenues accrued and transmission expenses
incurred is deferred, resulting in no material impact to current period
earnings.
Expenses -
Purchased power
costs were $310 million higher due
primarily to higher unit costs and volumes. The factors contributing to the
higher costs are summarized in the following table:
Source
of Change in Purchased Power
|
|
Increase
|
|
|
|
(In
millions)
|
|
Purchases:
|
|
|
|
|
Change due to increased unit
costs
|
|
$
|
284
|
|
Change due to increased
volumes
|
|
|
26
|
|
|
|
$
|
310
|
|
The increase in
purchased volumes was due to the higher retail generation sales requirements
described above. The higher unit costs reflect the implementation of the Ohio
Companies’ CBP for their power supply for retail customers.
Other operating
expenses decreased $59 million due to lower MISO transmission-related
expenses and increased intersegment credits related to the Ohio Companies’
generation leasehold interests. The deferral of regulatory assets increased by
$45 million due to CEI’s deferral of purchased power costs as approved by
the PUCO, partially offset by reduced MISO transmission cost deferrals. The
difference between transmission revenues accrued and transmission expenses
incurred is deferred or amortized, resulting in no material impact to current
period earnings.
Other – First Quarter 2009 Compared
with First Quarter 2008
FirstEnergy’s
financial results from other operating segments and reconciling items, including
interest expense on holding company debt and corporate support services revenues
and expenses, resulted in a $10 million decrease in FirstEnergy’s net
income in the first three months of 2009 compared to the same period in 2008.
The decrease resulted primarily from the absence of the gain on the 2008 sale of
telecommunication assets ($19 million, net of taxes), partially offset by
the favorable resolution in 2009 of income tax issues relating to prior years
($13 million).
CAPITAL
RESOURCES AND LIQUIDITY
FirstEnergy expects
its existing sources of liquidity to remain sufficient to meet its anticipated
obligations and those of its subsidiaries. FirstEnergy’s business is capital
intensive, requiring significant resources to fund operating expenses,
construction expenditures, scheduled debt maturities and interest and dividend
payments. During 2009 and in subsequent years, FirstEnergy expects to satisfy
these requirements with a combination of cash from operations and funds from the
capital markets as market conditions warrant. FirstEnergy also expects that
borrowing capacity under credit facilities will continue to be available to
manage working capital requirements during those periods.
As of March 31,
2009, FirstEnergy’s net deficit in working capital (current assets less current
liabilities) was principally due to short-term borrowings ($2.4 billion)
and the classification of certain variable interest rate PCRBs as currently
payable long-term debt. Currently payable long-term debt as of March 31,
2009, included the following (in millions):
Currently
Payable Long-term Debt
|
|
|
|
|
|
PCRBs
supported by bank LOCs(1)
|
|
$
|
1,636
|
|
|
FGCO and NGC
unsecured PCRBs(1)
|
|
|
82
|
|
|
Penelec
unsecured notes(2)
|
|
|
100
|
|
|
CEI secured
notes(3)
|
|
|
150
|
|
|
Met-Ed secured
notes(4)
|
|
|
100
|
|
|
NGC
collateralized lease obligation bonds
|
|
|
36
|
|
|
Sinking fund
requirements
|
|
|
40
|
|
|
|
|
$
|
2,144
|
|
|
|
|
|
|
|
|
(1)
Interest rate mode permits individual debt holders to put the
respective debt back to the issuer prior to maturity.
(2)
Matured in April 2009.
(3)
Mature in November 2009.
(4)
Mature in March
2010.
|
Short-Term
Borrowings
FirstEnergy had
approximately $2.4 billion of short-term borrowings as of March 31,
2009, and December 31, 2008. FirstEnergy, along with certain of its
subsidiaries, have access to $2.75 billion of short-term financing under a
revolving credit facility that expires in August 2012. A total of 25 banks
participate in the facility, with no one bank having more than 7.3% of the total
commitment. As of May 1, 2009, FirstEnergy had $720 million of bank
credit facilities in addition to the $2.75 billion revolving credit
facility. Also, an aggregate of $550 million of accounts receivable
financing facilities through the Ohio and Pennsylvania Companies may be accessed
to meet working capital requirements and for other general corporate purposes.
FirstEnergy’s available liquidity as of May 1, 2009, is summarized in the
following table:
Company
|
|
Type
|
|
Maturity
|
|
Commitment
|
|
Available
Liquidity
as of
May
1, 2009
|
|
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy(1)
|
|
Revolving
|
|
Aug.
2012
|
|
$
|
2,750
|
|
$
|
227
|
|
FirstEnergy
and FES
|
|
Revolving
|
|
May
2009
|
|
|
300
|
|
|
300
|
|
FirstEnergy
|
|
Bank
lines
|
|
Various(2)
|
|
|
120
|
|
|
20
|
|
FGCO
|
|
Term
loan
|
|
Oct. 2009(3)
|
|
|
300
|
|
|
300
|
|
Ohio and
Pennsylvania Companies
|
|
Receivables
financing
|
|
Various(4)
|
|
|
550
|
|
|
416
|
|
|
|
|
|
Subtotal
|
|
$
|
4,020
|
|
$
|
1,263
|
|
|
|
|
|
Cash
|
|
|
-
|
|
|
698
|
|
|
|
|
|
Total
|
|
$
|
4,020
|
|
$
|
1,961
|
|
(1) FirstEnergy
Corp. and subsidiary borrowers.
(2) $100 million
matures March 31, 2011; $20 million uncommitted line of credit has no
maturity date.
(3) Drawn amounts
are payable within 30 days and may not be re-borrowed.
(4) $180 million
expires December 18, 2009, $370 million expires
February 22, 2010.
|
|
Revolving Credit Facility
FirstEnergy has the
capability to request an increase in the total commitments available under the
$2.75 billion revolving credit facility (included in the borrowing
capability table above) up to a maximum of $3.25 billion, subject to the
discretion of each lender to provide additional commitments. Commitments under
the facility are available until August 24, 2012, unless the lenders agree,
at the request of the borrowers, to an unlimited number of additional one-year
extensions. Generally, borrowings under the facility must be repaid within 364
days. Available amounts for each borrower are subject to a specified sub-limit,
as well as applicable regulatory and other limitations.
The following table
summarizes the borrowing sub-limits for each borrower under the facility, as
well as the limitations on short-term indebtedness applicable to each borrower
under current regulatory approvals and applicable statutory and/or charter
limitations as of March 31, 2009:
|
|
Revolving
|
|
Regulatory
and
|
|
|
|
Credit
Facility
|
|
Other
Short-Term
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
$
|
2,750
|
|
$
|
-
|
(1)
|
FES
|
|
|
1,000
|
|
|
-
|
(1)
|
OE
|
|
|
500
|
|
|
500
|
|
Penn
|
|
|
50
|
|
|
39
|
(2)
|
CEI
|
|
|
250
|
(3)
|
|
500
|
|
TE
|
|
|
250
|
(3)
|
|
500
|
|
JCP&L
|
|
|
425
|
|
|
428
|
(2)
|
Met-Ed
|
|
|
250
|
|
|
300
|
(2)
|
Penelec
|
|
|
250
|
|
|
300
|
(2)
|
ATSI
|
|
|
-
|
(4)
|
|
50
|
|
|
|
|
|
|
|
|
|
(1)No
regulatory approvals, statutory or charter limitations
applicable.
(2)Excluding
amounts which may be borrowed under the regulated companies’ money
pool.
(3)Borrowing
sub-limits for CEI and TE may be increased to up to $500 million by
delivering notice to the administrative agent that such borrower has
senior unsecured debt ratings of at least BBB by S&P and Baa2 by
Moody’s.
(4)The
borrowing sub-limit for ATSI may be increased up to $100 million by
delivering notice to the administrative agent that either (i) ATSI has
senior unsecured debt ratings of at least BBB- by S&P and Baa3 by
Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such
borrower under the facility.
|
Under the revolving
credit facility, borrowers may request the issuance of LOCs expiring up to one
year from the date of issuance. The stated amount of outstanding LOCs will count
against total commitments available under the facility and against the
applicable borrower’s borrowing sub-limit.
The revolving credit
facility contains financial covenants requiring each borrower to maintain a
consolidated debt to total capitalization ratio of no more than 65%, measured at
the end of each fiscal quarter. As of March 31, 2009, FirstEnergy’s and its
subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy(1)
|
|
60.8
|
%
|
FES
|
|
57.3
|
%
|
OE
|
|
44.8
|
%
|
Penn
|
|
19.5
|
%
|
CEI
|
|
54.4
|
%
|
TE
|
|
44.6
|
%
|
JCP&L
|
|
36.3
|
%
|
Met-Ed
|
|
50.0
|
%
|
Penelec
|
|
52.0
|
%
|
(1) As of March 31,
2009, FirstEnergy could issue additional debt of approximately
$3.0 billion, or recognize a reduction in
equity of approximately $1.6 billion, and
remain within the limitations of the financial
covenants required by its revolving
credit facility.
The revolving credit
facility does not contain provisions that either restrict the ability to borrow
or accelerate repayment of outstanding advances as a result of any change in
credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds
borrowed under the facility is related to the credit ratings of the company
borrowing the funds.
FirstEnergy Money Pools
FirstEnergy's
regulated companies also have the ability to borrow from each other and the
holding company to meet their short-term working capital requirements. A similar
but separate arrangement exists among FirstEnergy's unregulated companies. FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money pool
agreements must repay the principal amount of the loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from their respective pool and is based
on the average cost of funds available through the pool. The average interest
rate for borrowings in the first three months of 2009 was 0.97% for the
regulated companies’ money pool and 1.01% for the unregulated companies’ money
pool.
Pollution Control Revenue
Bonds
As of March 31,
2009, FirstEnergy’s currently payable long-term debt includes approximately $1.6
billion (FES - $1.6 billion, Met-Ed - $29 million and Penelec - $45
million) of variable interest rate PCRBs, the bondholders of which are entitled
to the benefit of irrevocable direct pay bank LOCs. The interest rates on the
PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for
mandatory purchase prior to maturity with the purchase price payable from
remarketing proceeds or; if the PCRBs are not successfully remarketed, by
drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required
to reimburse the applicable LOC bank for any such drawings or, if the LOC bank
fails to honor its LOC for any reason, must itself pay the purchase
price.
The LOCs for
FirstEnergy variable interest rate PCRBs were issued by the following
banks:
|
|
Aggregate
LOC
|
|
|
|
Reimbursements
of
|
LOC
Bank
|
|
Amount(4)
|
|
LOC
Termination Date
|
|
LOC
Draws Due
|
|
|
(In
millions)
|
|
|
|
|
Barclays
Bank
|
|
$
|
149
|
|
June
2009
|
|
June
2009
|
Bank of
America(1)
|
|
101
|
|
June
2009
|
|
June
2009
|
The Bank of
Nova Scotia
|
|
255
|
|
Beginning June
2010
|
|
Shorter of 6
months or
LOC termination date
|
The Royal Bank
of Scotland
|
|
131
|
|
June
2012
|
|
6
months
|
KeyBank(2)
|
|
266
|
|
June
2010
|
|
6
months
|
Wachovia
Bank
|
|
153
|
|
March
2014
|
|
March
2014
|
Barclays
Bank(3)
|
|
528
|
|
Beginning
December 2010
|
|
30
days
|
PNC
Bank
|
|
70
|
|
Beginning
December 2010
|
|
180
days
|
Total
|
|
$
|
1,653
|
|
|
|
|
|
|
|
|
|
|
|
(1) Supported by
two participating banks, with each having 50% of the total
commitment.
(2) Supported by
four participating banks, with the LOC bank having 62% of the total
commitment.
(3) Supported by
18 participating banks, with no one bank having more than 14% of the total
commitment.
(4) Includes
approximately $16 million of applicable interest
coverage.
|
In February 2009,
holders of approximately $434 million principal of LOC-supported PCRBs of
OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire
on March 18, 2009. As a result, these PCRBs were subject to mandatory
purchase at a price equal to the principal amount, plus accrued and unpaid
interest, which OE and NGC funded through short-term borrowings. In March 2009,
FGCO remarketed $100 million of those PCRBs, which were previously held by OE.
In addition, approximately $250 million of FirstEnergy’s PCRBs that are
currently supported by LOCs are expected to be remarketed or refinanced in fixed
interest rate modes and secured by FMBs, thereby eliminating or reducing the
need for third-party credit support.
Long-Term Debt Capacity
As of March 31,
2009, the Ohio Companies and Penn had the aggregate capability to issue
approximately $2.7 billion of additional FMBs on the basis of property
additions and retired bonds under the terms of their respective mortgage
indentures. As a result of the issuance of senior secured notes by TE referred
to below and related amendments to the TE mortgage indenture’s bonding ratio,
that capacity decreased to $2.3 billion. The issuance of FMBs by the Ohio
Companies is also subject to provisions of their senior note indentures
generally limiting the incurrence of additional secured debt, subject to certain
exceptions that would permit, among other things, the issuance of secured debt
(including FMBs) supporting pollution control notes or similar obligations, or
as an extension, renewal or replacement of previously outstanding secured debt.
In addition, these provisions would permit OE, CEI and TE to incur additional
secured debt not otherwise permitted by a specified exception of up to $171
million, $164 million and $117 million, respectively, as of March 31, 2009.
In April 2009, TE issued $300 million of new senior secured notes backed by
FMBs. Concurrently with that issuance and in order to satisfy the limitation on
secured debt under its senior note indenture, TE issued an additional
$300 million of FMBs to secure $300 million of its outstanding unsecured
senior notes originally issued in November 2006. Based upon FGCO’s FMB
indenture, net earnings and available bondable property additions as of
March 31, 2009, FGCO had the capability to issue $2.7 billion of
additional FMBs under the terms of that indenture. Met-Ed and Penelec had the
capability to issue secured debt of approximately $423 million and $321 million,
respectively, under provisions of their senior note indentures as of
March 31, 2009.
FirstEnergy’s access
to capital markets and costs of financing are influenced by the ratings of its
securities. On March 2, 2009, Moody’s assigned a Baa1 senior secured rating
to FES-related secured issuances. The following table displays FirstEnergy’s,
FES’ and the Utilities’ securities ratings as of April 30, 2009. S&P’s
and Moody’s outlook for FirstEnergy and its subsidiaries remains
“stable.”
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
Senior
unsecured
|
|
BBB-
|
|
Baa3
|
|
|
|
|
|
|
|
FES
|
|
Senior
secured
|
|
BBB
|
|
Baa1
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
OE
|
|
Senior
secured
|
|
BBB+
|
|
Baa1
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
Penn
|
|
Senior
secured
|
|
A-
|
|
Baa1
|
|
|
|
|
|
|
|
CEI
|
|
Senior
secured
|
|
BBB+
|
|
Baa2
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa3
|
|
|
|
|
|
|
|
TE
|
|
Senior
secured
|
|
BBB+
|
|
Baa2
|
|
|
Senior
unsecured
|
|
BBB
|
|
Baa3
|
|
|
|
|
|
|
|
JCP&L
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
Met-Ed
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
|
|
|
|
|
|
|
Penelec
|
|
Senior
unsecured
|
|
BBB
|
|
Baa2
|
On September 22,
2008, FirstEnergy, along with the Shelf Registrants, filed an automatically
effective shelf registration statement with the SEC for an unspecified number
and amount of securities to be offered thereon. The shelf registration provides
FirstEnergy the flexibility to issue and sell various types of securities,
including common stock, preferred stock, debt securities, warrants, share
purchase contracts, and share purchase units. The Shelf Registrants have
utilized, and may in the future utilize, the shelf registration statement to
offer and sell unsecured, and in some cases, secured debt
securities.
Changes in Cash Position
As of March 31,
2009, FirstEnergy had $399 million in cash and cash equivalents compared to $545
million as of December 31, 2008. Cash and cash equivalents consist of
unrestricted, highly liquid instruments with an original or remaining maturity
of three months or less. As of March 31, 2009, approximately
$311 million of cash and cash equivalents represented temporary overnight
deposits.
During the first
quarter of 2009, FirstEnergy received $248 million of cash from dividends
and equity repurchases from its subsidiaries and paid $168 million in cash
dividends to common shareholders. With the exception of Met-Ed, which is
currently in an accumulated deficit position, there are no material restrictions
on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to
paying dividends from retained earnings, each of FirstEnergy’s electric utility
subsidiaries has authorization from the FERC to pay cash dividends from paid-in
capital accounts, as long as the subsidiary’s debt to total capitalization ratio
(without consideration of retained earnings) remains below 65%.
Cash Flows From Operating
Activities
FirstEnergy's
consolidated net cash from operating activities is provided primarily by its
energy delivery services and competitive energy services businesses (see Results
of Operations above). Net cash provided from operating activities was $462 million in the first
three months of 2009 compared to $359 million in the first three months of
2008, as summarized in the following table:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
115
|
|
$
|
277
|
|
Non-cash
charges
|
|
|
375
|
|
|
211
|
|
Working
capital and other
|
|
|
(28
|
)
|
|
(129
|
)
|
|
|
$
|
462
|
|
$
|
359
|
|
Net cash provided
from operating activities increased by $103 million in the first
three months of 2009 compared to the first three months of 2008 primarily due to
a $164 million increase in non-cash charges and a $101 million
increase from working capital and other changes, partially offset by a $162 million decrease in net
income (see Results of Operations above). The increase in non-cash charges is
primarily due to higher amortization of regulatory assets, including CEI’s $216
million regulatory asset impairment, and changes in accrued compensation and
retirement benefits. The change in accrued compensation and retirement benefits
resulted primarily from higher non-cash retirement benefit expenses recognized
in the first quarter of 2009. The changes in working capital and other primarily
resulted from a $52 million increase in the collection of receivables,
lower net tax payments of $20 million and an increase in other accrued
expenses principally associated with the implementation of the Ohio Companies’
Amended ESP.
Cash Flows From Financing
Activities
In the first three
months of 2009, cash provided from financing activities was $70 million
compared to $224 million in the first three months of 2008. The decrease
was primarily due to lower short-term borrowings, partially offset by long-term
debt issuances in the first quarter of 2009. The following table summarizes
security issuances and redemptions.
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
Securities
Issued or Redeemed
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
New
issues
|
|
|
|
|
|
Pollution
control notes
|
|
$
|
100
|
|
$
|
-
|
|
Unsecured
notes
|
|
|
600
|
|
|
-
|
|
|
|
$
|
700
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
Redemptions
|
|
|
|
|
|
|
|
Pollution
control notes(1)
|
|
$
|
437
|
|
$
|
362
|
|
Senior secured
notes
|
|
|
7
|
|
|
6
|
|
|
|
$
|
444
|
|
$
|
368
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
-
|
|
$
|
746
|
|
|
|
|
|
|
|
|
|
(1) Includes the
mandatory purchase of certain auction rate PCRBs described
above.
|
|
On January 20, 2009,
Met-Ed issued $300 million of 7.70% Senior Notes due 2019 and used the net
proceeds to repay short-term borrowings. On January 27, 2009, JCP&L issued
$300 million of 7.35% Senior Notes due 2019 and used the net proceeds to repay
short-term borrowings, to fund capital expenditures and for other general
corporate purposes. On April 24, 2009, TE issued $300 million of 7.25%
Senior Secured Notes due 2020 and used the net proceeds to repay short-term
borrowings, to fund capital expenditures and for other general corporate
purposes. Each of these issuances was sold off the shelf registration referenced
above.
Cash Flows From Investing
Activities
Net cash flows used
in investing activities resulted principally from property additions. Additions
for the energy delivery services segment primarily include expenditures related
to transmission and distribution facilities. Capital spending by the competitive
energy services segment is principally generation-related. The following table
summarizes investing activities for the three months ended March 31, 2009, and
2008 by business segment:
Summary
of Cash Flows
|
|
Property
|
|
|
|
|
|
|
|
Provided
from (Used for) Investing Activities
|
|
Additions
|
|
Investments
|
|
Other
|
|
Total
|
|
Sources
(Uses)
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
Inter-segment
reconciling items
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-segment
reconciling items
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for
investing activities in the first quarter of 2009 increased by $36 million
compared to the first quarter of 2008. The increase was primarily due to the
absence in 2009 of cash proceeds from the sale of telecommunication assets in
the first quarter of 2008 and higher cash investments for the Signal Peak mining
operations in 2009, partially offset by lower property additions. Property
additions decreased as a result of lower AQC system expenditures in the first
quarter of 2009 and the absence in 2009 of acquisition costs for the Fremont
Plant in the first quarter of 2008.
During the remaining
three quarters of 2009, capital requirements for property additions and capital
leases are expected to be approximately $1.4 billion, including
approximately $225 million for nuclear fuel. FirstEnergy has additional
requirements of approximately $316 million for maturing long-term debt
during the remainder of 2009, of which $100 million was redeemed in April 2009.
These cash requirements are expected to be satisfied from a combination of
internal cash, short-term credit arrangements and funds raised in the capital
markets.
FirstEnergy's
capital spending for the period 2009-2013 is expected to be approximately
$8.1 billion (excluding nuclear fuel), of which approximately
$1.6 billion applies to 2009. Investments for additional nuclear fuel
during the 2009-2013 period are estimated to be approximately $1.3 billion,
of which about $338 million applies to 2009. During the same period,
FirstEnergy's nuclear fuel investments are expected to be reduced by
approximately $1.0 billion and $136 million, respectively, as the
nuclear fuel is consumed.
GUARANTEES
AND OTHER ASSURANCES
As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. Some of the
guaranteed contracts contain collateral provisions that are contingent upon
FirstEnergy’s credit ratings.
As of March 31,
2009, FirstEnergy’s maximum exposure to potential future payments under
outstanding guarantees and other assurances approximated $4.5 billion, as
summarized below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees on Behalf of its Subsidiaries
|
|
|
|
Energy and
Energy-Related Contracts (1)
|
|
$
|
433
|
|
LOC (long-term
debt) – interest coverage (2)
|
|
|
6
|
|
Other (3)
|
|
|
742
|
|
|
|
|
1,181
|
|
|
|
|
|
|
Subsidiaries’
Guarantees
|
|
|
|
|
Energy and
Energy-Related Contracts
|
|
|
77
|
|
LOC (long-term
debt) – interest coverage (2)
|
|
|
9
|
|
FES’ guarantee
of FGCO’s sale and leaseback obligations
|
|
|
2,552
|
|
|
|
|
2,638
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
111
|
|
LOC (long-term
debt) – interest coverage (2)
|
|
|
2
|
|
LOC (non-debt)
(4)(5)
|
|
|
570
|
|
|
|
|
683
|
|
Total
Guarantees and Other Assurances
|
|
$
|
4,502
|
|
|
(1)
|
Issued for
open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
(2)
|
Reflects the
interest coverage portion of LOCs issued in support of floating rate PCRBs
with various maturities. The principal amount of floating-rate PCRBs of
$1.6 billion is reflected in currently payable long-term debt on
FirstEnergy’s consolidated balance
sheets.
|
|
(3)
|
Includes
guarantees of $300 million for OVEC obligations and $80 million
for nuclear decommissioning funding assurances. Also includes $300 million
for a Credit Suisse credit facility for FGCO that is guaranteed by both
FirstEnergy and FES.
|
|
(4)
|
Includes
$145 million issued for various terms pursuant to LOC capacity
available under FirstEnergy’s revolving credit
facility.
|
|
(5)
|
Includes
approximately $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. A
$236 million LOC relating to the sale-leaseback of Beaver Valley
Unit 2 by OE expires in May 2009 and is expected to be
replaced by a $161 million
LOC.
|
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity activities principally to facilitate or hedge normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of credit support for
the financing or refinancing by its subsidiaries of costs related to the
acquisition of property, plant and equipment. These agreements legally obligate
FirstEnergy to fulfill the obligations of those subsidiaries directly involved
in energy and energy-related transactions or 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 assets. FirstEnergy believes the likelihood is remote that such
parental guarantees will increase amounts otherwise paid by FirstEnergy to meet
its obligations incurred in connection with ongoing energy and energy-related
activities.
While these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade to below investment grade or a “material adverse event,” the immediate
posting of cash collateral, provision of an LOC or accelerated payments may be
required of the subsidiary. As of March 31, 2009, FirstEnergy’s maximum
exposure under these collateral provisions was $761 million as shown
below:
Collateral
Provisions
|
|
FES
|
|
Utilities
|
|
Total
|
|
|
|
(In
millions)
|
|
Credit rating
downgrade to
below
investment grade
|
|
$
|
315
|
|
$
|
170
|
|
$
|
485
|
|
Acceleration
of payment or
funding
obligation
|
|
|
80
|
|
|
141
|
|
|
221
|
|
Material
adverse event
|
|
|
50
|
|
|
5
|
|
|
55
|
|
Total
|
|
$
|
445
|
|
$
|
316
|
|
$
|
761
|
|
Stress case
conditions of a credit rating downgrade or “material adverse event” and
hypothetical adverse price movements in the underlying commodity markets would
increase the total potential amount to $830 million, consisting of
$54 million due to “material adverse event” contractual clauses and $776
million due to a below investment grade credit rating.
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.
In addition to
guarantees and surety bonds, FES’ contracts, including power contracts with
affiliates awarded through competitive bidding processes, typically contain
margining provisions which require the posting of cash or LOCs in amounts
determined by future power price movements. Based on FES’ power portfolio as of
March 31, 2009, and forward prices as of that date, FES had $205 million of
outstanding collateral payments. Under a hypothetical adverse change in forward
prices (15% decrease in the first 12 months and 20% decrease thereafter in
prices), FES would be required to post an additional $77 million. Depending
on the volume of forward contracts entered and future price movements, FES could
be required to post significantly higher amounts for margining.
OFF-BALANCE
SHEET ARRANGEMENTS
FES and the Ohio
Companies have obligations that are not included on their Consolidated Balance
Sheets related to sale and leaseback arrangements involving the Bruce Mansfield
Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied
through operating lease payments. The total present value of these sale and
leaseback operating lease commitments, net of trust investments is
$1.7 billion as of March 31, 2009.
FirstEnergy has
equity ownership interests in certain businesses that are accounted for using
the equity method of accounting for investments. There are no undisclosed
material contingencies related to these investments. Certain guarantees that
FirstEnergy does not expect to have a material current or future effect on its
financial condition, liquidity or results of operations are disclosed under
“Guarantees and Other Assurances” above.
MARKET
RISK INFORMATION
FirstEnergy uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations.
FirstEnergy's Risk Policy Committee, comprised of members of senior management,
provides general oversight for risk management activities throughout the
company.
Commodity Price Risk
FirstEnergy is
exposed to financial and market risks resulting from the fluctuation of interest
rates and commodity prices -- electricity, energy transmission, natural gas,
coal, nuclear fuel and emission allowances. To manage the volatility relating to
these exposures, FirstEnergy uses a variety of non-derivative and derivative
instruments, including forward contracts, options, futures contracts and swaps.
The derivatives are used principally for hedging purposes. Derivatives that fall
within the scope of SFAS 133 must be recorded at their fair value and
marked to market. The majority of FirstEnergy’s derivative hedging contracts
qualify for the normal purchase and normal sale exception under SFAS 133
and are therefore excluded from the tables below. Contracts that are not exempt
from such treatment include certain power purchase agreements with NUG entities
that were structured pursuant to the Public Utility Regulatory Policies Act of
1978. These non-trading contracts are adjusted to fair value at the end of each
quarter, with a corresponding regulatory asset recognized for above-market costs
or regulatory liability for below-market costs. The change in the fair value of
commodity derivative contracts related to energy production during the first
quarter of 2009 is summarized in the following table:
Fair
Value of Commodity Derivative Contracts
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
(In
millions)
|
Change
in the Fair Value of
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
Outstanding
net liability as of January 1, 2009
|
$
|
(304
|
)
|
$
|
(41
|
)
|
$
|
(345
|
)
|
Additions/change
in value of existing contracts
|
|
(227
|
)
|
|
(10
|
)
|
|
(237
|
)
|
Settled
contracts
|
|
74
|
|
|
22
|
|
|
96
|
|
Outstanding
net liability as of March 31, 2009 (1)
|
$
|
(457
|
)
|
$
|
(29
|
)
|
$
|
(486
|
)
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Liabilities as of March 31, 2009:
|
|
|
|
|
|
|
|
|
|
Interest rate
swaps (2)
|
|
-
|
|
|
(4
|
)
|
|
(4
|
)
|
Net
Liabilities - Derivative Contracts
as
of March 31, 2009
|
$
|
(457
|
)
|
$
|
(33
|
)
|
$
|
(490
|
)
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
Income
Statement effects (pre-tax)
|
$
|
1
|
|
$
|
-
|
|
$
|
1
|
|
Balance Sheet
effects:
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
$
|
-
|
|
$
|
12
|
|
$
|
12
|
|
Regulatory
assets (net)
|
$
|
154
|
|
$
|
-
|
|
$
|
154
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes $457 million in non-hedge commodity derivative
contracts (primarily with NUGs), which are offset by a regulatory
asset.
(2)
Interest rate swaps are treated as cash flow or fair value
hedges.
(3)
Represents the change in value of existing contracts, settled
contracts and changes in techniques/assumptions.
|
|
Derivatives are
included on the Consolidated Balance Sheet as of March 31, 2009 as
follows:
Balance
Sheet Classification
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
non-current liabilities
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, FirstEnergy relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. FirstEnergy uses these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making (see Note 4 to the consolidated financial statements). Sources of
information for the valuation of commodity derivative contracts as of
March 31, 2009 are summarized by year in the following table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Fair Value by Contract Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
Prices
actively quoted(2)
|
|
$
|
(17
|
)
|
$
|
(13
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(30
|
)
|
Other external
sources(3)
|
|
|
(296
|
)
|
|
(241
|
)
|
|
(195
|
)
|
|
(107
|
)
|
|
-
|
|
|
-
|
|
|
(839
|
)
|
Prices based
on models
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(4)
|
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
|
|
|
|
|
|
)
|
(1) For
the last three quarters of 2009.
(2) Represents
exchange traded NYMEX futures and options.
(3) Primarily
represents contracts based on broker and ICE quotes.
|
(4)
|
Includes
$457 million in non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
FirstEnergy performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of March 31, 2009. Based on derivative contracts held as of
March 31, 2009, an adverse 10% change in commodity prices would decrease
net income by approximately $1 million during the next 12
months.
Forward Starting Swap Agreements -
Cash Flow Hedges
FirstEnergy utilizes
forward starting swap agreements in order to hedge a portion of the consolidated
interest rate risk associated with anticipated future issuances of fixed-rate,
long-term debt securities for one or more of its consolidated subsidiaries in
2009 and 2010, and anticipated variable-rate, short-term debt. 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 and
LIBOR rates between the date of hedge inception and the date of the debt
issuance. During the first three months of 2009, FirstEnergy terminated forward
swaps with an aggregate notional value of $100 million. FirstEnergy
paid $1.3 million in cash related to the terminations, $0.3 million of
which was deemed ineffective and recognized in current period earnings. The
remaining effective portion ($1.0 million) will be recognized over the
terms of the associated future debt. As of March 31, 2009, FirstEnergy had
outstanding forward swaps with an aggregate notional amount of $200 million
and an aggregate fair value of $(4) million.
|
|
March
31, 2009
|
|
December
31, 2008
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
|
|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
Cash flow
hedges
|
|
$
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Price Risk
FirstEnergy provides
a noncontributory qualified defined benefit pension plan that covers
substantially all of its employees and non-qualified pension plans that cover
certain employees. The plan provides defined benefits based on years of service
and compensation levels. FirstEnergy also provides health care benefits, which
include certain employee contributions, deductibles, and co-payments, upon
retirement to employees hired prior to January 1, 2005, their dependents, and
under certain circumstances, their survivors. The benefit plan assets and
obligations are remeasured annually using a December 31 measurement date.
Reductions in plan assets from investment losses during 2008 resulted in a
decrease to the plans’ funded status of $1.7 billion and an after-tax
decrease to common stockholders’ equity of $1.2 billion. As of December 31,
2008, the pension plan was underfunded and FirstEnergy currently estimates that
additional cash contributions will be required in 2011 for the 2010 plan year.
The overall actual investment result during 2008 was a loss of 23.8% compared to
an assumed 9% positive return. Based on an assumed 7% discount rate,
FirstEnergy’s pre-tax net periodic pension and OPEB expense was $43 million
in the first quarter of 2009.
Nuclear
decommissioning trust funds have been established to satisfy NGC’s and our
Utilities’ nuclear decommissioning obligations. As of March 31, 2009,
approximately 31% of the funds were invested in equity securities and 69% were
invested in fixed income securities, with limitations related to concentration
and investment grade ratings. The equity securities are carried at their market
value of approximately $507 million as of March 31, 2009. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$51 million reduction in fair value as of March 31, 2009. The
decommissioning trusts of JCP&L and the Pennsylvania Companies are subject
to regulatory accounting, with unrealized gains and losses recorded as
regulatory assets or liabilities, since the difference between investments held
in trust and the decommissioning liabilities will be recovered from or refunded
to customers. NGC, OE and TE recognize in earnings the unrealized losses on
available-for-sale securities held in their nuclear decommissioning trusts based
on the guidance for other-than-temporary impairments provided in SFAS 115,
FSP SFAS 115-1 and SFAS 124-1. On March 27, 2009, FENOC submitted
to the NRC a biennial evaluation of the funding status of these trusts and
concluded that the amounts in the trusts as of December 31, 2008, when coupled
with the rates of return allowable by the NRC (over a safe store period for
certain units) and the existing parental guarantee, would provide reasonable
assurance of funding for decommissioning cost estimates under current NRC
regulations. FirstEnergy does not expect to make additional cash contributions
to the nuclear decommissioning trusts in 2009, other than the required annual
TMI-2 trust contribution that is collected through customer rates. However,
should the trust funds continue to experience declines in market value,
FirstEnergy may be required to take measures, such as providing financial
guarantees through LOCs or parental guarantees or making additional
contributions to the trusts to ensure that the trusts are adequately funded and
meet minimum NRC funding requirements.
CREDIT
RISK
Credit risk is the
risk of an obligor's failure to meet the terms of any investment contract, loan
agreement or otherwise perform as agreed. Credit risk arises from all activities
in which success depends on issuer, borrower or counterparty performance,
whether reflected on or off the balance sheet. FirstEnergy engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.
FirstEnergy
maintains credit policies with respect to its counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of its credit program, FirstEnergy aggressively
manages the quality of its portfolio of energy contracts, evidenced by a current
weighted average risk rating for energy contract counterparties of BBB+
(S&P). As of March 31, 2009, the largest credit concentration was with JP
Morgan, which is currently rated investment grade, representing 9.6% of
FirstEnergy’s total approved credit risk.
OUTLOOK
State Regulatory Matters
In Ohio, New Jersey
and Pennsylvania, laws applicable to electric industry restructuring contain
similar provisions that are reflected in the Utilities' respective state
regulatory plans. These provisions include:
·
|
restructuring
the electric generation business and allowing the Utilities' customers to
select a competitive electric generation supplier other than the
Utilities;
|
|
|
·
|
establishing
or defining the PLR obligations to customers in the Utilities' service
areas;
|
|
|
·
|
providing the
Utilities 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 Utilities' transmission and distribution systems;
and
|
|
|
·
|
requiring
corporate separation of regulated and unregulated business
activities.
|
The Utilities and
ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC
and the NJBPU have authorized for recovery from customers in future periods or
for which authorization is probable. Without the probability of such
authorization, costs currently recorded as regulatory assets would have been
charged to income as incurred. Regulatory assets that do not earn a current
return totaled approximately $130 million as of March 31, 2009
(JCP&L - $54 million and Met-Ed - $76 million). Regulatory assets
not earning a current return (primarily for certain regulatory transition costs
and employee postretirement benefits) are expected to be recovered by 2014 for
JCP&L and by 2020 for Met-Ed. The following table discloses regulatory
assets by company:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
545
|
|
$
|
575
|
|
$
|
(30
|
)
|
CEI
|
|
|
618
|
|
|
784
|
|
|
(166
|
)
|
TE
|
|
|
96
|
|
|
109
|
|
|
(13
|
)
|
JCP&L
|
|
|
1,162
|
|
|
1,228
|
|
|
(66
|
)
|
Met-Ed
|
|
|
490
|
|
|
413
|
|
|
77
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
)
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec had
net regulatory liabilities of approximately $49 million
and
$137 million as of March 31, 2009 and December 31, 2008,
respectively.
These net regulatory liabilities are included in Other
Non-current
Liabilities on the Consolidated Balance
Sheets.
|
Regulatory assets by
source are as follows:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
1,437
|
|
$
|
1,452
|
|
$
|
(15
|
)
|
Customer
shopping incentives
|
|
|
211
|
|
|
420
|
|
|
(209
|
)
|
Customer
receivables for future income taxes
|
|
|
220
|
|
|
245
|
|
|
(25
|
)
|
Loss on
reacquired debt
|
|
|
50
|
|
|
51
|
|
|
(1
|
)
|
Employee
postretirement benefits
|
|
|
29
|
|
|
31
|
|
|
(2
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and spent fuel
disposal costs
|
|
|
(56
|
)
|
|
(57
|
)
|
|
1
|
|
Asset removal
costs
|
|
|
(225
|
)
|
|
(215
|
)
|
|
(10
|
)
|
MISO/PJM
transmission costs
|
|
|
342
|
|
|
389
|
|
|
(47
|
)
|
Purchased
power costs
|
|
|
305
|
|
|
214
|
|
|
91
|
|
Distribution
costs
|
|
|
478
|
|
|
475
|
|
|
3
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
Reliability Initiatives
In 2005, Congress
amended the Federal Power Act to provide for federally-enforceable mandatory
reliability standards. The mandatory reliability standards apply to the bulk
power system and impose certain operating, record-keeping and reporting
requirements on the Utilities and ATSI. The NERC is charged with establishing
and enforcing these reliability standards, although it has delegated day-to-day
implementation and enforcement of its responsibilities to eight regional
entities, including ReliabilityFirst Corporation. All of
FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy
actively participates in the NERC and ReliabilityFirst stakeholder processes,
and otherwise monitors and manages its companies in response to the ongoing
development, implementation and enforcement of the reliability
standards.
FirstEnergy believes
that it is in compliance with all currently-effective and enforceable
reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will
continue to refine existing reliability standards as well as to develop and
adopt new reliability standards. The financial impact of complying with new or
amended standards cannot be determined at this time. However, the 2005
amendments to the Federal Power Act provide that all prudent costs incurred to
comply with the new reliability standards be recovered in rates. Still, any
future inability on FirstEnergy’s part to comply with the reliability standards
for its bulk power system could result in the imposition of financial penalties
and thus have a material adverse effect on its financial condition, results of
operations and cash flows.
In April 2007,
ReliabilityFirst
performed a routine compliance audit of FirstEnergy’s bulk-power system within
the MISO region and found it to be in full compliance with all audited
reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine
compliance audit of FirstEnergy’s bulk-power system within the PJM region and
found it to be in full compliance with all audited reliability
standards.
On December 9, 2008,
a transformer at JCP&L’s Oceanview substation failed, resulting in an outage
on certain bulk electric system (transmission voltage) lines out of the
Oceanview and Atlantic substations, with customers in the affected area losing
power. Power was restored to most customers within a few hours and to all
customers within eleven hours. On December 16, 2008, JCP&L provided
preliminary information about the event to certain regulatory agencies,
including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation
Investigation in order to determine JCP&L’s contribution to the electrical
event and to review any potential violation of NERC Reliability Standards
associated with the event. The initial phase of the investigation requires
JCP&L to respond to NERC’s request for factual data about the outage.
JCP&L submitted its written response on May 1, 2009. JCP&L is not
able at this time to predict what actions, if any, that NERC will take upon
receipt of JCP&L’s response to NERC’s data request.
Ohio
On June 7, 2007, the
Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO and, on August 6, 2007, updated their filing to support
a distribution rate increase of $332 million. On December 4, 2007, the
PUCO Staff issued its Staff Reports containing the results of its investigation
into the distribution rate request. On January 21, 2009, the PUCO granted the
Ohio Companies’ application to increase electric distribution rates by $136.6
million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These
increases went into effect for OE and TE on January 23, 2009, and will go into
effect for CEI on May 1, 2009. Applications for rehearing of this order were
filed by the Ohio Companies and one other party on February 20, 2009. The PUCO
granted these applications for rehearing on March 18, 2009.
SB221, which became
effective on July 31, 2008, required all electric utilities to file an ESP,
and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies
filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the
MRO application; however, the PUCO later granted the Ohio Companies’ application
for rehearing for the purpose of further consideration of the matter. The ESP
proposed to phase in new generation rates for customers beginning in 2009 for up
to a three-year period and resolve the Ohio Companies’ collection of fuel costs
deferred in 2006 and 2007, and the distribution rate request described above. In
response to the PUCO’s December 19, 2008 order, which significantly modified and
approved the ESP as modified, the Ohio Companies notified the PUCO that they
were withdrawing and terminating the ESP application in addition to continuing
their current rate plan in effect as allowed by the terms of SB221. On
December 31, 2008, the Ohio Companies conducted a CBP for the procurement
of electric generation for retail customers from January 5, 2009 through March
31, 2009. The average winning bid price was equivalent to a retail rate of 6.98
cents per kwh. The power supply obtained through this process provides
generation service to the Ohio Companies’ retail customers who choose not to
shop with alternative suppliers. On January 9, 2009, the Ohio Companies
requested the implementation of a new fuel rider to recover the costs resulting
from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’
request for a new fuel rider to recover increased costs resulting from the CBP
but did not authorize OE and TE to continue collecting RTC or allow the Ohio
Companies to continue collections pursuant to the two existing fuel riders. The
new fuel rider allows for current recovery of the increased purchased power
costs for OE and TE, and authorizes CEI to collect a portion of those costs
currently and defer the remainder for future recovery.
On January 29, 2009,
the PUCO ordered its Staff to develop a proposal to establish an ESP for the
Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended
ESP application, including an attached Stipulation and Recommendation that was
signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening
parties. Specifically, the Amended ESP provides that generation will be provided
by FES at the average wholesale rate of the CBP process described above for
April and May 2009 to the Ohio Companies for their non-shopping customers; for
the period of June 1, 2009 through May 31, 2011, retail generation
prices will be based upon the outcome of a descending clock CBP on a
slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of
any increase resulting from this CBP process by authorizing deferral of related
purchased power costs, subject to specified limits. The Amended ESP further
provides that the Ohio Companies will not seek a base distribution rate
increase, subject to certain exceptions, with an effective date of such increase
before January 1, 2012, that CEI will agree to write-off approximately
$216 million of its Extended RTC balance, and that the Ohio Companies will
collect a delivery service improvement rider at an overall average rate of $.002
per kWh for the period of April 1, 2009 through December 31, 2011. The
Amended ESP also addresses a number of other issues, including but not limited
to, rate design for various customer classes, resolution of the prudence review
and the collection of deferred costs that were approved in prior proceedings. On
February 26, 2009, the Ohio Companies filed a Supplemental Stipulation,
which was signed or not opposed by virtually all of the parties to the
proceeding, that supplemented and modified certain provisions of the
February 19 Stipulation and Recommendation. Specifically, the Supplemental
Stipulation modified the provision relating to governmental aggregation and the
Generation Service Uncollectible Rider, provided further detail on the
allocation of the economic development funding contained in the Stipulation and
Recommendation, and proposed additional provisions related to the collaborative
process for the development of energy efficiency programs, among other
provisions. The PUCO adopted and approved certain aspects of the Stipulation and
Recommendation on March 4, 2009, and adopted and approved the remainder of the
Stipulation and Recommendation and Supplemental Stipulation without modification
on March 25, 2009. Certain aspects of the Stipulation and Recommendation
and Supplemental Stipulation take effect on April 1, 2009 while the
remaining provisions take effect on June 1, 2009. The CBP auction is
currently scheduled to begin on May 13, 2009. The bidding will occur for a
single, two-year product and there will not be a load cap for the
bidders. FES may participate without limitation.
SB221 also requires
electric distribution utilities to implement energy efficiency programs that
achieve an energy savings equivalent of approximately 166,000 MWH in 2009,
290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in
2013. Utilities are also required to reduce peak demand in 2009 by one percent,
with an additional seventy-five hundredths of one percent reduction each year
thereafter through 2018. Costs associated with compliance are
recoverable from customers.
Pennsylvania
Met-Ed and Penelec
purchase a portion of their PLR and default service requirements from FES
through a fixed-price partial requirements wholesale power sales agreement. The
agreement allows Met-Ed and Penelec to sell the output of NUG energy to the
market and requires FES to provide energy at fixed prices to replace any NUG
energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and
default service obligations. If Met-Ed and Penelec were to replace the entire
FES supply at current market power prices without corresponding regulatory
authorization to increase their generation prices to customers, each company
would likely incur a significant increase in operating expenses and experience a
material deterioration in credit quality metrics. Under such a scenario, each
company's credit profile would no longer be expected to support an investment
grade rating for their fixed income securities. If FES ultimately determines to
terminate, reduce, or significantly modify the agreement prior to the expiration
of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief
is not likely to be granted by the PPUC. See FERC Matters below for a
description of the Third Restated Partial Requirements Agreement, executed by
the parties on October 31, 2008, that limits the amount of energy and
capacity FES must supply to Met-Ed and Penelec. In the event of a third party
supplier default, the increased costs to Met-Ed and Penelec could be
material.
On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. Various intervenors filed
complaints against those filings. In addition, the PPUC ordered an investigation
to review the reasonableness of Met-Ed’s TSC, while at the same time allowing
Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15,
2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed
with its investigation and a litigation schedule was adopted. Hearings and
briefing for both Met-Ed and Penelec have concluded and the companies are
awaiting a Recommended Decision from the ALJ. The TSCs include a component from
under-recovery of actual transmission costs incurred during the prior period
(Met-Ed - $144 million and Penelec - $4 million) and future transmission
cost projections for June 2008 through May 2009 (Met-Ed - $258 million and
Penelec - $92 million). Met-Ed received PPUC approval for a transition
approach that would recover past under-recovered costs plus carrying charges
through the new TSC over thirty-one months and defer a portion of the projected
costs ($92 million) plus carrying charges for recovery through future TSCs
by December 31, 2010.
On April 15, 2009,
Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009
through May 31, 2010, as required in connection with the PPUC’s January
2007 rate order. For Penelec’s customers, the new TSC would result in an
approximate 1% decrease in monthly bills, reflecting projected PJM transmission
costs as well as a reconciliation for costs already incurred. The TSC for
Met-Ed’s customers would increase to recover the additional PJM charges paid by
Met-Ed in the previous year and to reflect updated projected costs. In order to
gradually transition customers to the higher rate, Met-Ed is proposing to
continue to recover the prior period deferrals allowed in the PPUC’s May 2008
Order and defer $57.5 million of projected costs into a future TSC to be fully
recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s
customers would increase approximately 9.4% for the period June 2009 through May
2010.
On October 15, 2008,
the Governor of Pennsylvania signed House Bill 2200 into law which became
effective on November 14, 2008 as Act 129 of 2008. The bill addresses
issues such as: energy efficiency and peak load reduction; generation
procurement; time-of-use rates; smart meters and alternative energy. Act 129
requires utilities to file with the PPUC an energy efficiency and peak load
reduction plan by July 1, 2009 and a smart meter procurement and
installation plan by August 14, 2009. On January 15, 2009, in compliance
with Act 129, the PPUC issued its proposed guidelines for the filing of
utilities’ energy efficiency and peak load reduction plans. Similar guidelines
related to Smart Meter deployment were issued for comment on March 30,
2009.
Major provisions of
the legislation include:
·
|
power acquired
by utilities to serve customers after rate caps expire will be procured
through a competitive procurement process that must include a mix of
long-term and short-term contracts and spot market
purchases;
|
·
|
the
competitive procurement process must be approved by the PPUC and may
include auctions, RFPs, and/or bilateral
agreements;
|
·
|
utilities must
provide for the installation of smart meter technology within 15
years;
|
·
|
a minimum
reduction in peak demand of 4.5% by May 31,
2013;
|
·
|
minimum
reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
2013, respectively; and
|
·
|
an expanded
definition of alternative energy to include additional types of
hydroelectric and biomass
facilities.
|
Legislation
addressing rate mitigation and the expiration of rate caps was not enacted in
2008; however, several bills addressing these issues have been introduced in the
current legislative session, which began in January 2009. The final
form and impact of such legislation is uncertain.
On February 26,
2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and
Penelec that provides an opportunity for residential and small commercial
customers to prepay an amount on their monthly electric bills during 2009 and
2010. Customer prepayments earn interest at 7.5% and will be used to reduce
electricity charges in 2011 and 2012.
On February 20,
2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan
covering the period January 1, 2011 through May 31, 2013. The
companies’ plan is designed to provide adequate and reliable service via a
prudent mix of long-term, short-term and spot market generation supply, as
required by Act 129. The plan proposes a staggered procurement schedule,
which varies by customer class, through the use of a descending clock auction.
Met-Ed and Penelec have requested PPUC approval of their plan by November
2009.
On March 31, 2009,
Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the
PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to
reduce its CTC rate for the residential class with a corresponding increase in
the generation rate and the shopping credit, and Penelec proposed to reduce its
CTC rate to zero for all classes with a corresponding increase in the generation
rate and the shopping credit. While these changes would result in additional
annual generation revenue (Met-Ed - $27 million and Penelec - $51 million),
overall rates would remain unchanged. The PPUC must act on this filing within
120 days.
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, costs incurred under NUG
agreements, and certain other stranded costs, exceed amounts collected through
BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31,
2009, the accumulated deferred cost balance totaled approximately
$165 million.
In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004, supporting 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 DPA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. JCP&L responded to additional
NJBPU staff discovery requests in May and November 2007 and also submitted
comments in the proceeding in November 2007. A schedule for further NJBPU
proceedings has not yet been set. On March 13, 2009, JCP&L filed its
annual SBC Petition with the NJBPU that includes a request for a reduction in
the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2
decommissioning cost analysis dated January 2009. This matter is currently
pending before the NJBPU.
On August 1, 2005,
the NJBPU established a proceeding to determine whether additional ratepayer
protections are required at the state level in light of the repeal of the PUHCA
pursuant to the EPACT. The NJBPU approved regulations effective October 2,
2006 that prevent a holding company that owns a gas or electric public utility
from investing more than 25% of the combined assets of its utility and
utility-related subsidiaries into businesses unrelated to the utility industry.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional
draft proposal on March 31, 2006 addressing various issues including access
to books and records, ring-fencing, cross subsidization, corporate governance
and related matters. Following public hearing and consideration of comments from
interested parties, the NJBPU approved final regulations effective April 6,
2009. These regulations are not expected to materially impact FirstEnergy or
JCP&L.
New Jersey statutes
require that the state periodically undertake a planning process, known as the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President and
includes representatives of several State departments.
The EMP was issued
on October 22, 2008, establishing five major goals:
·
|
maximize
energy efficiency to achieve a 20% reduction in energy consumption by
2020;
|
·
|
reduce peak
demand for electricity by 5,700 MW by
2020;
|
·
|
meet 30% of
the state’s electricity needs with renewable energy by
2020;
|
·
|
examine smart
grid technology and develop additional cogeneration and other generation
resources consistent with the state’s greenhouse gas targets;
and
|
·
|
invest in
innovative clean energy technologies and businesses to stimulate the
industry’s growth in New Jersey.
|
On January 28, 2009,
the NJBPU adopted an order establishing the general process and contents of
specific EMP plans that must be filed by December 31, 2009 by New Jersey
electric and gas utilities in order to achieve the goals of the EMP. At this
time, FirstEnergy cannot determine the impact, if any, the EMP may have on its
operations or those of JCP&L.
In support of the
New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced
its intent to spend approximately $98 million on infrastructure and energy
efficiency projects in 2009. An estimated $40 million will be spent on
infrastructure projects, including substation upgrades, new transformers,
distribution line re-closers and automated breaker operations. Approximately
$34 million will be spent implementing new demand response programs as well
as expanding on existing programs. Another $11 million will be spent on
energy efficiency, specifically replacing transformers and capacitor control
systems and installing new LED street lights. The remaining $13 million
will be spent on energy efficiency programs that will complement those currently
being offered. Completion of the projects is dependent upon resolution of
regulatory issues including recovery of the costs associated with plan
implementation.
FERC Matters
Transmission Service between MISO and
PJM
On November 18,
2004, the FERC issued an order eliminating the through and out rate for
transmission service between the MISO and PJM regions. The FERC’s intent was to
eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM, and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. Briefs addressing the initial decision were filed on
September 11, 2006 and October 20, 2006. A final order is pending before
the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and
entering into settlement agreements with other parties in the docket to mitigate
the risk of lower transmission revenue collection associated with an adverse
order. On September 26, 2008, the MISO and PJM transmission owners filed a
motion requesting that the FERC approve the pending settlements and act on the
initial decision. On November 20, 2008, FERC issued an order approving
uncontested settlements, but did not rule on the initial decision. On December
19, 2008, an additional order was issued approving two contested
settlements.
PJM Transmission Rate
On January 31, 2005,
certain PJM transmission owners made filings with the FERC pursuant to a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. Hearings were
held and numerous parties appeared and litigated various issues concerning PJM
rate design; notably AEP, which proposed to create a "postage stamp", or average
rate for all high voltage transmission facilities across PJM and a zonal
transmission rate for facilities below 345 kV. This proposal would have the
effect of shifting recovery of the costs of high voltage transmission lines to
other transmission zones, including those where JCP&L, Met-Ed, and Penelec
serve load. On April 19, 2007, the FERC issued an order finding that the PJM
transmission owners’ existing “license plate” or zonal rate design was just and
reasonable and ordered that the current license plate rates for existing
transmission facilities be retained. On the issue of rates for new transmission
facilities, the FERC directed that costs for new transmission facilities that
are rated at 500 kV or higher are to be collected from all transmission zones
throughout the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to be
allocated on a “beneficiary pays” basis. The FERC found that PJM’s current
beneficiary-pays cost allocation methodology is not sufficiently detailed and,
in a related order that also was issued on April 19, 2007, directed that
hearings be held for the purpose of establishing a just and reasonable cost
allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007 order. On
January 31, 2008, the requests for rehearing were denied. On February 11, 2008,
AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the
federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission,
the PUCO and Dayton Power & Light have also appealed these orders to the
Seventh Circuit Court of Appeals. The appeals of these parties and others have
been consolidated for argument in the Seventh Circuit. Oral argument was held on
April 13, 2009, and a decision is expected this summer.
The FERC’s orders on
PJM rate design will prevent the allocation of a portion of the revenue
requirement of existing transmission facilities of other utilities to JCP&L,
Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce the
costs of future transmission to be recovered from the JCP&L, Met-Ed and
Penelec zones. A partial settlement agreement addressing the “beneficiary pays”
methodology for below 500 kV facilities, but excluding the issue of allocating
new facilities costs to merchant transmission entities, was filed on September
14, 2007. The agreement was supported by the FERC’s Trial Staff, and was
certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued
an order conditionally approving the settlement subject to the submission of a
compliance filing. The compliance filing was submitted on August 29, 2008,
and the FERC issued an order accepting the compliance filing on October 15,
2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate
cost responsibility assignments for below 500 kV upgrades included in
PJM’s Regional Transmission Expansion Planning process in accordance with
the settlement. The FERC conditionally accepted the compliance filing on
January 28, 2009. PJM submitted a further compliance filing on March 2,
2009, which was accepted by the FERC on April 10, 2009. The remaining
merchant transmission cost allocation issues were the subject of a hearing at
the FERC in May 2008. An initial decision was issued by the Presiding Judge on
September 18, 2008. PJM and FERC trial staff each filed a Brief on
Exceptions to the initial decision on October 20, 2008. Briefs Opposing
Exceptions were filed on November 10, 2008.
Post
Transition Period Rate Design
The FERC had
directed MISO, PJM, and the respective transmission owners to make filings on or
before August 1, 2007 to reevaluate transmission rate design within MISO, and
between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the
vast majority of transmission owners, including FirstEnergy affiliates, which
proposed to retain the existing transmission rate design. These filings were
approved by the FERC on January 31, 2008. As a result of the FERC’s approval,
the rates charged to FirstEnergy’s load-serving affiliates for transmission
service over existing transmission facilities in MISO and PJM are unchanged. In
a related filing, MISO and MISO transmission owners requested that the current
MISO pricing for new transmission facilities that spreads 20% of the cost of new
345 kV and higher transmission facilities across the entire MISO footprint
(known as the RECB methodology) be retained.
On September 17,
2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act
seeking to have the entire transmission rate design and cost allocation methods
used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory,
and to have the FERC fix a uniform regional transmission rate design and cost
allocation method for the entire MISO and PJM “Super Region” that recovers the
average cost of new and existing transmission facilities operated at voltages of
345 kV and above from all transmission customers. Lower voltage facilities would
continue to be recovered in the local utility transmission rate zone through a
license plate rate. AEP requested a refund effective October 1, 2007, or
alternatively, February 1, 2008. On January 31, 2008, the FERC issued an
order denying the complaint. The effect of this order is to prevent the shift of
significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request
by AEP was denied by the FERC on December 19, 2008. On February 17, 2009,
AEP appealed the FERC’s January 31, 2008, and December 19, 2008,
orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of
its affiliated operating utility companies, filed a motion to intervene on March
10, 2009.
Duquesne’s
Request to Withdraw from PJM
On November 8, 2007,
Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and
to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy
interests, including but not limited to the terms under which FirstEnergy’s
Beaver Valley Plant would continue to participate in PJM’s energy markets.
FirstEnergy, therefore, intervened and participated fully in all of the FERC
dockets that were related to Duquesne’s proposed move.
In November, 2008,
Duquesne and other parties, including FirstEnergy, negotiated a settlement that
would, among other things, allow for Duquesne to remain in PJM and provide for a
methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012
auction that excluded the Duquesne load. The settlement agreement was filed on
December 10, 2008 and approved by the FERC in an order issued on January 29,
2009. MISO opposed the settlement agreement pending resolution of exit fees
alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in
its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January
29, 2009 order approving the settlement. Thereafter, FirstEnergy and other
parties filed in opposition to the rehearing request. The PPUC's rehearing
request, and the pleadings in opposition thereto, are pending before the
FERC.
Changes
ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30,
2008, a group of PJM load-serving entities, state commissions, consumer
advocates, and trade associations (referred to collectively as the RPM Buyers)
filed a complaint at the FERC against PJM alleging that three of the
four transitional RPM auctions yielded prices that are unjust and
unreasonable under the Federal Power Act. On September 19, 2008, the FERC
denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’
request for a technical conference to review aspects of the RPM. The FERC also
ordered PJM to file on or before December 15, 2008, a report on potential
adjustments to the RPM program as suggested in a Brattle Group report. On
December 12, 2008, PJM filed proposed tariff amendments that would adjust
slightly the RPM program. PJM also requested that the FERC conduct a settlement
hearing to address changes to the RPM and suggested that the FERC should rule on
the tariff amendments only if settlement could not be reached in January, 2009.
The request for settlement hearings was granted. Settlement had not been reached
by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted
comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief
Judge issued an order terminating settlement talks. On February 9, 2009,
PJM and a group of stakeholders submitted an offer of settlement, which used the
PJM December 12, 2008 filing as its starting point, and stated that unless
otherwise specified, provisions filed by PJM on December 12, 2008,
apply.
On March 26, 2009,
the FERC accepted in part, and rejected in part, tariff provisions submitted by
PJM, revising certain parts of its RPM. Ordered changes included making
incremental improvements to RPM; however, the basic construct of RPM remains
intact. On April 3, 2009, PJM filed with the FERC requesting clarification on
certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM
submitted a compliance filing addressing the changes the FERC ordered in the
March 26, 2009 Order; numerous parties have filed requests for rehearing of
the March 26, 2009 Order. In addition, the FERC has indefinitely
postponed the technical conference on RPM granted in the FERC order of
September 19, 2008.
MISO
Resource Adequacy Proposal
MISO made a filing
on December 28, 2007 that would create an enforceable planning reserve
requirement in the MISO tariff for load-serving entities such as the Ohio
Companies, Penn Power, and FES. This requirement is proposed to become effective
for the planning year beginning June 1, 2009. The filing would permit MISO to
establish the reserve margin requirement for load-serving entities based upon a
one day loss of load in ten years standard, unless the state utility regulatory
agency establishes a different planning reserve for load-serving entities in its
state. FirstEnergy believes the proposal promotes a mechanism that will result
in commitments from both load-serving entities and resources, including both
generation and demand side resources that are necessary for reliable resource
adequacy and planning in the MISO footprint. Comments on the filing were
submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource
Adequacy proposal on March 26, 2008, requiring MISO to submit to further
compliance filings. Rehearing requests are pending on the FERC’s March 26 Order.
On May 27, 2008, MISO submitted a compliance filing to address issues associated
with planning reserve margins. On June 17, 2008, various parties submitted
comments and protests to MISO’s compliance filing. FirstEnergy submitted
comments identifying specific issues that must be clarified and addressed. On
June 25, 2008, MISO submitted a second compliance filing establishing the
enforcement mechanism for the reserve margin requirement which establishes
deficiency payments for load-serving entities that do not meet the resource
adequacy requirements. Numerous parties, including FirstEnergy, protested this
filing.
On October 20, 2008,
the FERC issued three orders essentially permitting the MISO Resource Adequacy
program to proceed with some modifications. First, the FERC accepted MISO's
financial settlement approach for enforcement of Resource Adequacy subject to a
compliance filing modifying the cost of new entry penalty. Second, the FERC
conditionally accepted MISO's compliance filing on the qualifications for
purchased power agreements to be capacity resources, load forecasting, loss of
load expectation, and planning reserve zones. Additional compliance filings were
directed on accreditation of load modifying resources and price responsive
demand. Finally, the FERC largely denied rehearing of its March 26 order with
the exception of issues related to behind the meter resources and certain
ministerial matters. On November 19, 2008, MISO made various compliance
filings pursuant to these orders. Issuance of orders on rehearing and two of the
compliance filings occurred on February 19, 2009. No material changes were made
to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an
additional order on rehearing and compliance, approving MISO’s proposed
financial settlement provision for Resource Adequacy. The MISO Resource Adequacy
process is expected to start as planned effective June 1, 2009, the beginning of
the MISO planning year.
FES Sales to Affiliates
On October 24, 2008,
FES, on its own behalf and on behalf of its generation-controlling subsidiaries,
filed an application with the FERC seeking a waiver of the affiliate sales
restrictions between FES and the Ohio Companies. The purpose of the waiver is to
ensure that FES will be able to continue supplying a material portion of the
electric load requirements of the Ohio Companies after January 1, 2009
pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained
a similar waiver for electricity sales to its affiliates in New Jersey, New
York, and Pennsylvania. On December 23, 2008, the FERC issued an order
granting the waiver request and the Ohio Companies made the required compliance
filing on December 30, 2008. In January 2009,
several parties filed for rehearing of the FERC’s December 23, 2008 order. In
response, FES filed an answer to requests for rehearing on February 5, 2009. The
requests and responses are pending before the FERC.
FES supplied all of
the power requirements for the Ohio Companies pursuant to a Power Supply
Agreement that ended on December 31, 2008. On January 2, 2009, FES
signed an agreement to provide 75% of the Ohio Companies’ power requirements for
the period January 5, 2009 through March 31, 2009. Subsequently, FES
signed an agreement to provide 100% of the Ohio Companies’ power requirements
for the period April 1, 2009 through May 31, 2009. On March 4,
2009, the PUCO issued an order approving these two affiliate sales agreements.
FERC authorization for these affiliate sales was by means of the
December 23, 2008 waiver.
On October 31, 2008,
FES executed a Third Restated Partial Requirements Agreement with Met-Ed,
Penelec, and Waverly effective November 1, 2008. The Third Restated Partial
Requirements Agreement limits the amount of capacity and energy required to be
supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’
power supply requirements. Met-Ed, Penelec, and Waverly have committed resources
in place for the balance of their expected power supply during 2009 and 2010.
Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and
Waverly are responsible for obtaining additional power supply requirements
created by the default or failure of supply of their committed resources. Prices
for the power provided by FES were not changed in the Third Restated Partial
Requirements Agreement.
Environmental
Matters
Various federal,
state and local authorities regulate FirstEnergy with regard to air and water
quality and other environmental matters. The effects of compliance on
FirstEnergy with regard to environmental matters could have a material adverse
effect on FirstEnergy's earnings and competitive position to the extent that it
competes with companies that are not subject to such regulations and, therefore,
do not bear the risk of costs associated with compliance, or failure to comply,
with such regulations. FirstEnergy estimates capital expenditures for
environmental compliance of approximately $808 million for the period
2009-2013.
FirstEnergy accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably estimate the amount of such
costs. Unasserted claims are reflected in FirstEnergy’s determination of
environmental liabilities and are accrued in the period that they become both
probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is
required to meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in the shutdown of the
generating unit involved and/or civil or criminal penalties of up to $37,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. FirstEnergy believes it is currently in compliance with this policy, but
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.
The EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006, alleging violations to various sections of the CAA. FirstEnergy has
disputed those alleged violations based on its CAA permit, the Ohio SIP and
other information provided to the EPA at an August 2006 meeting with the EPA.
The EPA has several enforcement options (administrative compliance order,
administrative penalty order, and/or judicial, civil or criminal action) and has
indicated that such option may depend on the time needed to achieve and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding emission limits applicable to
the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies
with SO2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX reductions
required by the 1990 Amendments are being achieved through combustion controls,
the generation of more electricity at lower-emitting plants, and/or using
emission allowances. In September 1998, the EPA finalized regulations requiring
additional NOX reductions
at FirstEnergy's facilities. The EPA's NOX Transport
Rule imposes uniform reductions of NOX emissions
(an approximate 85% reduction in utility plant NOX emissions
from projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX budgets
established under SIPs through combustion controls and post-combustion controls,
including Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.
In 1999 and 2000,
the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn
based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR
Litigation) and filed similar complaints involving 44 other U.S. power plants.
This case and seven other similar cases are referred to as the NSR cases. OE’s
and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New
Jersey and New York) that resolved all issues related to the Sammis NSR
litigation was approved by the Court on July 11, 2005. This settlement
agreement, in the form of a consent decree, requires reductions of NOX and
SO2
emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants
through the installation of pollution control devices or repowering and provides
for stipulated penalties for failure to install and operate such pollution
controls or complete repowering in accordance with that agreement. Capital
expenditures necessary to complete requirements of the Sammis NSR Litigation
consent decree, including repowering Burger Units 4 and 5 for biomass fuel
consumption, are currently estimated to be $706 million for 2009-2012 (with
$414 million expected to be spent in 2009).
On May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal CAA, alleging violations of air
pollution laws at the Bruce Mansfield Plant, including opacity limitations.
Prior to the receipt of this notice, the Plant was subject to a Consent Order
and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with the
applicable laws will continue. On October 18, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed
a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the
Court denied the motion to dismiss, but also ruled that monetary damages could
not be recovered under the public nuisance claim. In July 2008, three additional
complaints were filed against FGCO in the United States District Court for the
Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant
air emissions. In addition to seeking damages, two of the complaints seek to
enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible,
prudent and proper manner”, one being a complaint filed on behalf of twenty-one
individuals and the other being a class action complaint, seeking certification
as a class action with the eight named plaintiffs as the class representatives.
On October 14, 2008, the Court granted FGCO’s motion to consolidate
discovery for all four complaints pending against the Bruce Mansfield Plant.
FGCO believes the claims are without merit and intends to defend itself against
the allegations made in these complaints. The Pennsylvania Department of Health
and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed
their intention to conduct additional air monitoring in the vicinity of the
Mansfield plant.
On December 18,
2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations
at the Portland Generation Station against Reliant (the current owner and
operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in
1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that
"modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without
preconstruction NSR or permitting under the CAA's prevention of significant
deterioration program, and seeks injunctive relief, penalties, attorney fees and
mitigation of the harm caused by excess emissions. On March 14, 2008,
Met-Ed filed a motion to dismiss the citizen suit claims against it and a
stipulation in which the parties agreed that GPU, Inc. should be dismissed from
this case. On March 26, 2008, GPU, Inc. was dismissed by the United States
District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe
Energy is disputed. On October 30, 2008, the state of Connecticut filed a
Motion to Intervene, which the Court granted on March 24, 2009. On
December 5, 2008, New Jersey filed an amended complaint, adding claims with
respect to alleged modifications that occurred after GPU’s sale of the plant.
Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on
February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant
alleging new source review violations at the Portland Generation Station based
on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome
of this matter. The EPA’s January 14, 2009, NOV also alleged new source
review violations at the Keystone and Shawville Stations based on
“modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of
Keystone Station and Penelec, as former owner and operator of the Shawville
Station, are unable to predict the outcome of this matter.
On June 11, 2008,
the EPA issued a Notice and Finding of Violation to Mission Energy Westside,
Inc. alleging that "modifications" at the Homer City Power Station occurred
since 1988 to the present without preconstruction NSR or permitting under the
CAA's prevention of significant deterioration program. Mission Energy is seeking
indemnification from Penelec, the co-owner (along with New York State Electric
and Gas Company) and operator of the Homer City Power Station prior to its sale
in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy
is disputed. Penelec is unable to predict the outcome of this
matter.
On May 16, 2008,
FGCO received a request from the EPA for information pursuant to Section 114(a)
of the CAA for certain operating and maintenance information regarding the
Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA
to determine whether these generating sources are complying with the NSR
provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an
Administrative Consent Order modifying that request and setting forth a schedule
for FGCO’s response. On October 27, 2008, FGCO received a second request from
the EPA for information pursuant to Section 114(a) of the CAA for additional
operating and maintenance information regarding the Eastlake, Lakeshore, Bay
Shore and Ashtabula generating plants. FGCO intends to fully comply with the
EPA’s information requests, but, at this time, is unable to predict the outcome
of this matter.
On August 18, 2008,
FirstEnergy received a request from the EPA for information pursuant to Section
114(a) of the CAA for certain operating and maintenance information regarding
its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a
nearly identical request directed to the current owner, Reliant Energy, to allow
the EPA to determine whether these generating sources are complying with the NSR
provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s
information request, but, at this time, is unable to predict the outcome of this
matter.
National Ambient Air Quality
Standards
In March 2005,
the EPA finalized the CAIR covering a total of 28 states (including Michigan,
New Jersey, Ohio and Pennsylvania) and the District of Columbia based on
proposed findings that air emissions from 28 eastern states and the District of
Columbia significantly contribute to non-attainment of the NAAQS for fine
particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires
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),
ultimately capping SO2 emissions
in affected states to just 2.5 million tons annually and NOX emissions
to just 1.3 million tons annually. CAIR was challenged in the United States
Court of Appeals for the District of Columbia and on July 11, 2008, the Court
vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from
the ground up.” On September 24, 2008, the EPA, utility, mining and certain
environmental advocacy organizations petitioned the Court for a rehearing to
reconsider its ruling vacating CAIR. On December 23, 2008, the Court
reconsidered its prior ruling and allowed CAIR to remain in effect to
“temporarily preserve its environmental values” until the EPA replaces CAIR with
a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of
compliance with these regulations may be substantial and will depend, in part,
on the action taken by the EPA in response to the Court’s ruling.
Mercury Emissions
In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases; initially, capping national mercury
emissions at 38 tons by 2010 (as a "co-benefit" from implementation of
SO2
and NOX emission
caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states
and environmental groups appealed the CAMR to the United States Court of Appeals
for the District of Columbia. On February 8, 2008, the Court vacated the
CAMR, ruling that the EPA failed to take the necessary steps to “de-list”
coal-fired power plants from its hazardous air pollutant program and, therefore,
could not promulgate a cap-and-trade program. The EPA petitioned for rehearing
by the entire Court, which denied the petition on May 20, 2008. On
October 17, 2008, the EPA (and an industry group) petitioned the United
States Supreme Court for review of the Court’s ruling vacating CAMR. On February
6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23,
2009, the Supreme Court dismissed the EPA’s petition and denied the industry
group’s petition. The EPA is developing new mercury emission standards for
coal-fired power plants. FGCO’s future cost of compliance with mercury
regulations may be substantial and will depend on the action taken by the EPA
and on how they are ultimately implemented.
Pennsylvania has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. On January 30, 2009,
the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule
“unlawful, invalid and unenforceable” and enjoined the Commonwealth from
continued implementation or enforcement of that rule. It is anticipated that
compliance with these regulations, if the Commonwealth Court’s rulings were
reversed on appeal and Pennsylvania’s mercury rule was implemented, would not
require the addition of mercury controls at the Bruce Mansfield Plant,
FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at
all.
Climate Change
In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG, including CO2, emitted
by developed countries by 2012. The United States signed the Kyoto Protocol in
1998 but it was never submitted for ratification by the United States Senate.
However, the Bush administration had committed the United States to a voluntary
climate change strategy to reduce domestic GHG intensity – the ratio of
emissions to economic output – by 18% through 2012. Also, in an April 16,
2008 speech, former President Bush set a policy goal of stopping the growth of
GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition,
the EPACT established a Committee on Climate Change Technology to coordinate
federal climate change activities and promote the development and deployment of
GHG reducing technologies. President Obama has announced his Administration’s
“New Energy for America Plan” that includes, among other provisions, ensuring
that 10% of electricity in the United States comes from renewable sources by
2012, and increasing to 25% by 2025; and implementing an economy-wide
cap-and-trade program to reduce GHG emissions 80% by 2050.
There are a number
of initiatives to reduce GHG emissions under consideration at the federal, state
and international level. At the international level, efforts to reach a new
global agreement to reduce GHG emissions post-2012 have begun with the Bali
Roadmap, which outlines a two-year process designed to lead to an agreement in
2009. At the federal level, members of Congress have introduced several bills
seeking to reduce emissions of GHG in the United States, and the Senate
Environment and Public Works Committee has passed one such bill. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states, led by California, have
coordinated efforts to develop regional strategies to control emissions of
certain GHGs.
On April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2
emissions from automobiles as “air pollutants” under the CAA. Although this
decision did not address CO2 emissions
from electric generating plants, the EPA has similar authority under the CAA to
regulate “air pollutants” from those and other facilities. On April 17,
2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings
for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding
concludes that the atmospheric concentrations of several key greenhouse gases
threaten the health and welfare of future generations and that the combined
emissions of these gases by motor vehicles contribute to the atmospheric
concentrations of these key greenhouse gases and hence to the threat of climate
change. Although the EPA’s proposed finding, if finalized, does not establish
emission requirements for motor vehicles, such requirements would be expected to
occur through further rulemakings. Additionally, while the EPA’s proposed
findings do not specifically address stationary sources, including electric
generating plants, those findings, if finalized, would be expected to support
the establishment of future emission requirements by the EPA for stationary
sources.
FirstEnergy cannot
currently estimate the financial impact of climate change policies, although
potential legislative or regulatory programs restricting CO2 emissions
could require significant capital and other expenditures. The CO2 emissions
per KWH of electricity generated by FirstEnergy is lower than many regional
competitors due to its diversified generation sources, which include low or
non-CO2 emitting
gas-fired and nuclear generators.
Clean Water Act
Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio,
New Jersey and Pennsylvania have water quality standards applicable to
FirstEnergy's operations. As provided in the Clean Water Act, authority to grant
federal National Pollutant Discharge Elimination System water discharge permits
can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.
On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality (when aquatic organisms
are pinned against screens or other parts of a cooling water intake system) and
entrainment (which occurs when aquatic life is drawn into a facility's cooling
water system). On January 26, 2007, the United States Court of Appeals for the
Second Circuit remanded portions of the rulemaking dealing with impingement
mortality and entrainment back to the EPA for further rulemaking and eliminated
the restoration option from the EPA’s regulations. On July 9, 2007, the EPA
suspended this rule, noting that until further rulemaking occurs, permitting
authorities should continue the existing practice of applying their best
professional judgment to minimize impacts on fish and shellfish from cooling
water intake structures. On April 1, 2009, the Supreme Court of the United
States reversed one significant aspect of the Second Circuit Court’s opinion and
decided that Section 316(b) of the Clean Water Act authorizes the EPA to
compare costs with benefits in determining the best technology available for
minimizing adverse environmental impact at cooling water intake structures.
FirstEnergy is studying various control options and their costs and
effectiveness. Depending on the results of such studies and the EPA’s further
rulemaking and any action taken by the states exercising best professional
judgment, the future costs of compliance with these standards may require
material capital expenditures.
The U.S. Attorney's
Office in Cleveland, Ohio has advised FGCO that it is considering prosecution
under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum
spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on
November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to
predict the outcome of this matter.
Regulation of Waste
Disposal
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 non-hazardous waste. In
February 2009, the EPA requested comments from the states on options for
regulating coal combustion wastes, including regulation as non-hazardous waste
or regulation as a hazardous waste. The future cost of compliance with coal
combustion waste regulations may be substantial and will depend, in part, on the
regulatory action taken by the EPA and implementation by the
states.
Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had
approximately $1.6 billion invested in external trusts to be used for the
decommissioning and environmental remediation of Davis-Besse, Beaver Valley,
Perry and TMI-2. As part of the application to the NRC to transfer the ownership
of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to
contribute another $80 million to these trusts by 2010. Consistent with NRC
guidance, utilizing a “real” rate of return on these funds of approximately 2%
over inflation, these trusts are expected to exceed the minimum decommissioning
funding requirements set by the NRC. Conservatively, these estimates do not
include any return that the trusts may earn over the 20-year plant useful life
extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of
the decommissioning of TMI-2) seeks for these facilities.
The Utilities have
been named as potentially responsible parties 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 potentially
responsible parties for a particular site may be liable on a joint and several
basis. Environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of March 31, 2009, based on
estimates of the total costs of cleanup, the Utilities' proportionate
responsibility for such costs and the financial ability of other unaffiliated
entities to pay. Total liabilities of approximately $91 million have been
accrued through March 31, 2009. Included in the total are accrued
liabilities of approximately $56 million for environmental remediation of
former manufactured gas plants and gas holder facilities in New Jersey, which
are being recovered by JCP&L through a non-bypassable SBC.
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, the Muise class action) 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.
After various
motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common
law fraud, negligent misrepresentation, strict product liability, and punitive
damages were dismissed, leaving only the negligence and breach of contract
causes of actions. The class was decertified twice by the trial court, and
appealed both times by the Plaintiffs, with the results being that: (1) the
Appellate Division limited the class only to those customers directly impacted
by the outages of JCP&L transformers in Red Bank, NJ, based on a common
incident involving the failure of the bushings of two large transformers in the
Red Bank substation which resulted in planned and unplanned outages in the area
during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded
this matter back to the Trial Court to allow plaintiffs sufficient time to
establish a damage model or individual proof of damages. Proceedings then
continued at the trial court level and a case management conference with the
presiding Judge was held on June 13, 2008. At that conference, counsel for
the Plaintiffs stated his intent to drop his efforts to create a class-wide
damage model and, instead of dismissing the class action, expressed his desire
for a bifurcated trial on liability and damages. In response, JCP&L filed an
objection to the plaintiffs’ proposed trial plan and another motion to decertify
the class. On March 31, 2009, the trial court granted JCP&L’s motion to
decertify the class. On April 20, 2009, the Plaintiffs filed their appeal
to the trial court's decision to decertify the class.
Nuclear Plant Matters
On May 14, 2007, the
Office of Enforcement of the NRC issued a Demand for Information to FENOC,
following FENOC’s reply to an April 2, 2007 NRC request for information about
two reports prepared by expert witnesses for an insurance arbitration (the
insurance claim was subsequently withdrawn by FirstEnergy in December 2007)
related to Davis-Besse. The NRC indicated that this information was needed for
the NRC “to determine whether an Order or other action should be taken pursuant
to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to
operate its licensed facilities in accordance with the terms of its licenses and
the Commission’s regulations.” FENOC was directed to submit the information to
the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s
Demand for Information reaffirming that it accepts full responsibility for the
mistakes and omissions leading up to the damage to the reactor vessel head and
that it remains committed to operating Davis-Besse and FirstEnergy’s other
nuclear plants safely and responsibly. FENOC submitted a supplemental response
clarifying certain aspects of the response to the NRC on July 16, 2007. The
NRC issued a Confirmatory Order imposing these commitments on FENOC. In an
April 23, 2009 Inspection Report, the NRC concluded that FENOC had
completed all necessary actions required by the Confirmatory Order.
In August 2007,
FENOC submitted an application to the NRC to renew the operating licenses for
the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The
NRC is required by statute to provide an opportunity for members of the public
to request a hearing on the application. No members of the public, however,
requested a hearing on the Beaver Valley license renewal application. On
September 24, 2008, the NRC issued a draft supplemental Environmental Impact
Statement for Beaver Valley. FENOC will continue to work with the NRC Staff
as it completes its environmental and technical reviews of the license renewal
application, and expects to obtain renewed licenses for the Beaver Valley Power
Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley
Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and
2, respectively.
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.
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. On September 9, 2005, the arbitration panel issued an opinion to
award approximately $16 million to the bargaining unit employees. A final order
identifying the individual damage amounts was issued on October 31, 2007
and the award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. On February 25, 2009, the federal district court denied JCP&L’s motion
to vacate the arbitration decision and granted the union’s motion to confirm the
award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to
Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take
as long as 24 months. JCP&L recognized a liability for the potential
$16 million award in 2005. Post-judgment interest began to accrue as of
February 25, 2009, and the liability will be adjusted accordingly.
The union employees
at the Bruce Mansfield Plant have been working without a labor contract since
February 15, 2008. The parties are continuing to bargain with the
assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready
in the event of a strike.
The union employees
at Met-Ed have been working without a labor contract since May 1, 2009. The
parties are continuing to bargain and FirstEnergy has a work continuation plan
ready in the event of a strike.
FirstEnergy accrues
legal 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.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal
liability or are otherwise made subject to liability based on the above matters,
it could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition, results of operations and cash flows.
NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP
FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for
the Asset or Liability Have Significantly Decreased and Identifying Transactions
That Are Not Orderly”
In April 2009, the
FASB issued Staff Position FAS 157-4, which provides additional guidance to
consider in estimating fair value when there has been a significant decrease in
market activity for a financial asset. The FSP establishes a two-step process
requiring a reporting entity to first determine if a market is not active in
relation to normal market activity for the asset. If evidence indicates the
market is not active, an entity would then need to determine whether a quoted
price in the market is associated with a distressed transaction. An entity will
need to further analyze the transactions or quoted prices, and an adjustment to
the transactions or quoted prices may be necessary to estimate fair value.
Additional disclosures related to the inputs and valuation techniques used in
the fair value measurements are also required. The FSP is effective for interim
and annual periods ending after June 15, 2009, with early adoption permitted for
periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its
interim period ending June 30, 2009. While the FSP will expand disclosure
requirements, FirstEnergy does not expect the FSP to have a material effect upon
its financial statements.
|
FSP
FAS 115-2 and FAS 124-2 - “Recognition and Presentation of
Other-Than-Temporary Impairments”
|
In April 2009, the
FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to
determine whether an other-than-temporary impairment exists for debt securities
and the amount of impairment to be recorded in earnings. Under the FSP,
management will be required to assert it does not have the intent to sell the
debt security, and it is more likely than not it will not have to sell the debt
security before recovery of its cost basis. If management is unable to make
these assertions, the debt security will be deemed other-than-temporarily
impaired and the security will be written down to fair value with the full
charge recorded through earnings. If management is able to make the assertions,
but there are credit losses associated with the debt security, the portion of
impairment related to credit losses will be recognized in earnings while the
remaining impairment will be recognized through other comprehensive income. The
FSP is effective for interim and annual reporting periods ending after June 15,
2009, with early adoption permitted for periods ending after March 15, 2009.
FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and
does not expect the FSP to have a material effect upon its financial
statements.
|
FSP
FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of
Financial Instruments”
|
In April 2009, the
FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of
the fair value of financial instruments in interim financial statements, as well
as in annual financial statements. The FSP also requires entities to disclose
the methods and significant assumptions used to estimate the fair value of
financial instruments in both interim and annual financial statements. The FSP
is effective for interim and annual reporting periods ending after June 15,
2009, with early adoption permitted for periods ending after March 15, 2009.
FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and
expects to expand its disclosures regarding the fair value of financial
instruments.
FSP FAS 132 (R)-1 – “Employers’
Disclosures about Postretirement Benefit Plan Assets”
In December 2008,
the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. Requirements of this FSP include disclosures about
investment policies and strategies, categories of plan assets, fair value
measurements of plan assets, and significant categories of risk. This FSP is
effective for fiscal years ending after December 15, 2009. FirstEnergy will
expand its disclosures related to postretirement benefit plan assets as a result
of this FSP.
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 March 31, 2009 and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2009 and 2008. These interim financial statements
are the responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, common
stockholders’ equity, and cash flows for the year then ended (not presented
herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. As discussed in
Note 6 to the accompanying consolidated financial statements, the Company
changed its reporting related to noncontrolling interest. The accompanying
December 31, 2008 consolidated balance sheet reflects this
change.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
March
31
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
(In
millions, except
|
|
|
per
share amounts)
|
|
REVENUES:
|
|
|
|
|
|
Electric
utilities
|
$ |
3,020 |
|
|
$ |
2,913 |
|
Unregulated
businesses
|
|
314 |
|
|
|
364 |
|
Total
revenues*
|
|
3,334 |
|
|
|
3,277 |
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
Fuel
|
|
312 |
|
|
|
328 |
|
Purchased
power
|
|
1,143 |
|
|
|
1,000 |
|
Other
operating expenses
|
|
827 |
|
|
|
799 |
|
Provision for
depreciation
|
|
177 |
|
|
|
164 |
|
Amortization
of regulatory assets
|
|
411 |
|
|
|
258 |
|
Deferral of
new regulatory assets
|
|
(93 |
) |
|
|
(105 |
) |
General
taxes
|
|
211 |
|
|
|
215 |
|
Total
expenses
|
|
2,988 |
|
|
|
2,659 |
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
346 |
|
|
|
618 |
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Investment
income (loss), net
|
|
(11 |
) |
|
|
17 |
|
Interest
expense
|
|
(194 |
) |
|
|
(179 |
) |
Capitalized
interest
|
|
28 |
|
|
|
8 |
|
Total other
expense
|
|
(177 |
) |
|
|
(154 |
) |
|
|
|
|
|
|
|
|
INCOME BEFORE
INCOME TAXES
|
|
169 |
|
|
|
464 |
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
54 |
|
|
|
187 |
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
115 |
|
|
|
277 |
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income (loss)
|
|
(4 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
EARNINGS
AVAILABLE TO PARENT
|
$ |
119 |
|
|
$ |
276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK
|
$ |
0.39 |
|
|
$ |
0.91 |
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
304 |
|
|
|
304 |
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK
|
$ |
0.39 |
|
|
$ |
0.90 |
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
306 |
|
|
|
307 |
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
$ |
0.55 |
|
|
$ |
0.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Includes
$109 million and $114 million of excise tax collections in the first
quarter of 2009 and 2008, respectively.
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
FirstEnergy Corp. are an integral part of these
statements.
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
March
31
|
|
|
2009
|
|
|
2008
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
NET
INCOME
|
$ |
115 |
|
|
$ |
277 |
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
35 |
|
|
|
(20 |
) |
Unrealized
gain (loss) on derivative hedges
|
|
15 |
|
|
|
(13 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
(5 |
) |
|
|
(58 |
) |
Other
comprehensive income (loss)
|
|
45 |
|
|
|
(91 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
15 |
|
|
|
(33 |
) |
Other
comprehensive income (loss), net of tax
|
|
30 |
|
|
|
(58 |
) |
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
145 |
|
|
|
219 |
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
|
|
(4 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO PARENT
|
$ |
149 |
|
|
$ |
218 |
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
FirstEnergy Corp. are an integral part of these
statements.
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
March
31,
|
|
|
December
31,
|
|
|
2009
|
|
|
2008
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
Cash and cash
equivalents
|
$ |
399 |
|
|
$ |
545 |
|
Receivables-
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $27 million and $28
million,
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
1,266 |
|
|
|
1,304 |
|
Other (less
accumulated provisions of $9 million for uncollectible
accounts)
|
|
159 |
|
|
|
167 |
|
Materials and
supplies, at average cost
|
|
657 |
|
|
|
605 |
|
Prepaid
taxes
|
|
318 |
|
|
|
283 |
|
Other
|
|
205 |
|
|
|
149 |
|
|
|
3,004 |
|
|
|
3,053 |
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
In
service
|
|
26,757 |
|
|
|
26,482 |
|
Less -
Accumulated provision for depreciation
|
|
10,947 |
|
|
|
10,821 |
|
|
|
15,810 |
|
|
|
15,661 |
|
Construction
work in progress
|
|
2,397 |
|
|
|
2,062 |
|
|
|
18,207 |
|
|
|
17,723 |
|
INVESTMENTS:
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
1,649 |
|
|
|
1,708 |
|
Investments in
lease obligation bonds
|
|
561 |
|
|
|
598 |
|
Other
|
|
689 |
|
|
|
711 |
|
|
|
2,899 |
|
|
|
3,017 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
Goodwill
|
|
5,575 |
|
|
|
5,575 |
|
Regulatory
assets
|
|
2,938 |
|
|
|
3,140 |
|
Power purchase
contract asset
|
|
340 |
|
|
|
434 |
|
Other
|
|
594 |
|
|
|
579 |
|
|
|
9,447 |
|
|
|
9,728 |
|
|
$ |
33,557 |
|
|
$ |
33,521 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
$ |
2,144 |
|
|
$ |
2,476 |
|
Short-term
borrowings
|
|
2,397 |
|
|
|
2,397 |
|
Accounts
payable
|
|
704 |
|
|
|
794 |
|
Accrued
taxes
|
|
281 |
|
|
|
333 |
|
Other
|
|
1,169 |
|
|
|
1,098 |
|
|
|
6,695 |
|
|
|
7,098 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
Common
stockholders’ equity-
|
|
|
|
|
|
|
|
Common stock,
$0.10 par value, authorized 375,000,000 shares-
|
|
31 |
|
|
|
31 |
|
304,835,407
shares outstanding
|
|
|
|
|
|
|
|
Other paid-in
capital
|
|
5,459 |
|
|
|
5,473 |
|
Accumulated
other comprehensive loss
|
|
(1,350 |
) |
|
|
(1,380 |
) |
Retained
earnings
|
|
4,110 |
|
|
|
4,159 |
|
Total common
stockholders' equity
|
|
8,250 |
|
|
|
8,283 |
|
Noncontrolling
interest
|
|
34 |
|
|
|
32 |
|
Total
equity
|
|
8,284 |
|
|
|
8,315 |
|
Long-term debt
and other long-term obligations
|
|
9,697 |
|
|
|
9,100 |
|
|
|
17,981 |
|
|
|
17,415 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
2,130 |
|
|
|
2,163 |
|
Asset
retirement obligations
|
|
1,356 |
|
|
|
1,335 |
|
Deferred gain
on sale and leaseback transaction
|
|
1,018 |
|
|
|
1,027 |
|
Power purchase
contract liability
|
|
816 |
|
|
|
766 |
|
Retirement
benefits
|
|
1,896 |
|
|
|
1,884 |
|
Lease market
valuation liability
|
|
296 |
|
|
|
308 |
|
Other
|
|
1,369 |
|
|
|
1,525 |
|
|
|
8,881 |
|
|
|
9,008 |
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
$ |
33,557 |
|
|
$ |
33,521 |
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements are an integral
part of these balance sheets.
|
|
|
|
|
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
March
31
|
|
|
2009
|
|
|
2008
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
Income
|
$ |
115 |
|
|
$ |
277 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
177 |
|
|
|
164 |
|
Amortization
of regulatory assets
|
|
411 |
|
|
|
258 |
|
Deferral of
new regulatory assets
|
|
(93 |
) |
|
|
(105 |
) |
Nuclear fuel
and lease amortization
|
|
27 |
|
|
|
26 |
|
Deferred
purchased power and other costs
|
|
(62 |
) |
|
|
(43 |
) |
Deferred
income taxes and investment tax credits, net
|
|
(28 |
) |
|
|
89 |
|
Investment
impairment
|
|
36 |
|
|
|
16 |
|
Deferred rents
and lease market valuation liability
|
|
(14 |
) |
|
|
4 |
|
Stock-based
compensation
|
|
(13 |
) |
|
|
(35 |
) |
Accrued
compensation and retirement benefits
|
|
(66 |
) |
|
|
(142 |
) |
Gain on asset
sales
|
|
(5 |
) |
|
|
(37 |
) |
Electric
service prepayment programs
|
|
(8 |
) |
|
|
(19 |
) |
Cash
collateral received (paid)
|
|
(15 |
) |
|
|
8 |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
Receivables
|
|
46 |
|
|
|
(6 |
) |
Materials and
supplies
|
|
(7 |
) |
|
|
(17 |
) |
Prepaid
taxes
|
|
(34 |
) |
|
|
(100 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
Accounts
payable
|
|
(90 |
) |
|
|
(23 |
) |
Accrued
taxes
|
|
(51 |
) |
|
|
(5 |
) |
Accrued
interest
|
|
118 |
|
|
|
91 |
|
Other
|
|
18 |
|
|
|
(42 |
) |
Net cash
provided from operating activities
|
|
462 |
|
|
|
359 |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
700 |
|
|
|
- |
|
Short-term
borrowings, net
|
|
- |
|
|
|
746 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
Long-term
debt
|
|
(444 |
) |
|
|
(368 |
) |
Net controlled
disbursement activity
|
|
(10 |
) |
|
|
6 |
|
Common stock
dividend payments
|
|
(168 |
) |
|
|
(168 |
) |
Other
|
|
(8 |
) |
|
|
8 |
|
Net cash
provided from financing activities
|
|
70 |
|
|
|
224 |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Property
additions
|
|
(654 |
) |
|
|
(711 |
) |
Proceeds from
asset sales
|
|
8 |
|
|
|
50 |
|
Sales of
investment securities held in trusts
|
|
567 |
|
|
|
361 |
|
Purchases of
investment securities held in trusts
|
|
(584 |
) |
|
|
(384 |
) |
Cash
investments
|
|
17 |
|
|
|
58 |
|
Other
|
|
(32 |
) |
|
|
(16 |
) |
Net cash used
for investing activities
|
|
(678 |
) |
|
|
(642 |
) |
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
(146 |
) |
|
|
(59 |
) |
Cash and cash
equivalents at beginning of period
|
|
545 |
|
|
|
129 |
|
Cash and cash
equivalents at end of period
|
$ |
399 |
|
|
$ |
70 |
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
FirstEnergy Corp. are an integral
|
|
part of these
statements.
|
|
|
|
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
ANALYSIS
OF RESULTS OF OPERATIONS
FES is a wholly
owned subsidiary of FirstEnergy. FES provides energy-related products and
services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its
subsidiaries, FGCO and NGC, owns or leases and operates and maintains
FirstEnergy’s fossil and hydroelectric generation facilities and owns
FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned
subsidiary of FirstEnergy, operates and maintains the nuclear generating
facilities.
FES’ revenues have
been primarily derived from the sale of electricity (provided from FES’
generating facilities and through purchased power arrangements) to affiliated
utility companies to meet all or a portion of their PLR and default service
requirements. These affiliated power sales included a full-requirements PSA with
OE, CEI and TE to supply each of their default service obligations through
December 31, 2008, at prices that considered their respective PUCO-authorized
billing rates. See Regulatory Matters – Ohio below for a discussion of Ohio
power supply procurement issues for 2009 and beyond. FES continues to have a
partial requirements wholesale power sales agreement with its affiliates, Met-Ed
and Penelec, to supply a portion of each of their respective default service
obligations at fixed prices through 2009. This sales agreement is renewed
annually unless cancelled by either party with at least a sixty-day written
notice prior to the end of the calendar year. FES also supplies, through
May 31, 2009, a portion of Penn’s default service requirements at
market-based rates as a result of Penn’s 2008 competitive solicitations. FES’
revenues also include competitive retail and wholesale sales to non-affiliated
customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois.
These sales may provide a greater portion of revenues in future years depending
upon FES’ participation in its Ohio and Pennsylvania utility affiliates’ power
procurement arrangements.
Results of
Operations
In the first three
months of 2009, net income increased to $171 million from $90 million in the same
period in 2008. The increase in net income was primarily due to higher revenues
and lower fuel and purchased power costs, partially offset by higher other
operating expenses, depreciation and other miscellaneous expenses.
Revenues
Revenues increased
by $127 million in the
first three months of 2009 compared to the same period in 2008 due to increases
in revenues from non-affiliated and affiliated wholesale generation sales,
partially offset by lower retail generation sales. The increase in revenues
resulted from the following sources:
|
|
Three Months
Ended
|
|
|
|
|
|
March
31
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
)
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail generation
sales revenues decreased due to reduced commercial and industrial contract
renewals in the PJM market and the termination of certain government aggregation
programs in the MISO market that were supplied by FES. Non-affiliated wholesale
revenues increased due to higher PJM capacity prices and increased sales volumes
in the MISO market, partially offset by lower unit prices and volumes in
PJM.
Increased affiliated
company wholesale revenues resulted from higher unit prices for sales to the
Ohio Companies, under their CBP, partially offset by lower composite prices to
the Pennsylvania Companies and an overall decrease in affiliated sales volumes.
While unit prices for each of the Pennsylvania Companies did not change, the mix
of sales among the companies caused the overall composite price to
decline. FES supplied less power to the Ohio Companies in the first
quarter of 2009 as one of four winning bidders in the Ohio Companies’ RFP
process.
The following tables
summarize the price and volume factors contributing to changes in revenues from
non-affiliated and affiliated generation sales in the first three months of 2009
compared to the same period last year:
|
|
Increase
|
|
Source
of Change in Non-Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect of 57.0% decrease in sales
volumes
|
|
$
|
(91
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect of 33.9% increase in sales
volumes
|
|
|
44
|
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Net Decrease
in Non-Affiliated Generation Revenues
|
|
|
|
)
|
|
|
Increase
|
|
Source
of Change in Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect of 24.6% decrease in sales
volumes
|
|
$
|
(142
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect of 11.1% increase in sales
volumes
|
|
|
22
|
|
Change in prices
|
|
|
|
)
|
|
|
|
|
|
Net Increase
in Affiliated Generation Revenues
|
|
|
|
|
Transmission revenue
decreased $8 million due to decreased retail load in the MISO market
($14 million), partially offset by higher PJM congestion revenues ($6
million). Other revenue increased $27 million primarily due to NGC’s lease
revenue received from its equity interests in the Beaver Valley Unit 2 and Perry
sale and leaseback transactions acquired during the second quarter of
2008.
Expenses
Total expenses
decreased by $1 million in the first three months of 2009 compared with the
same period of 2008. The following table summarizes the factors contributing to
the changes in fuel and purchased power costs in the first three months of 2009
from the same period last year:
Source
of Change in Fuel and Purchased Power
|
|
|
|
|
|
(In
millions)
|
|
Fossil
Fuel:
|
|
|
|
|
Change due to increased unit
costs
|
|
$
|
36
|
|
Change due to volume
consumed
|
|
|
(52
|
)
|
|
|
|
(16
|
)
|
Nuclear
Fuel:
|
|
|
|
|
Change due to increased unit
costs
|
|
|
1
|
|
Change due to volume
consumed
|
|
|
-
|
|
|
|
|
1
|
|
Non-affiliated
Purchased Power:
|
|
|
|
|
Change due to decreased unit
costs
|
|
|
(15
|
)
|
Change due to volume
purchased
|
|
|
(31
|
)
|
|
|
|
(46
|
)
|
Affiliated
Purchased Power:
|
|
|
|
|
Change due to increased unit
costs
|
|
|
40
|
|
Change due to volume
purchased
|
|
|
(3
|
)
|
|
|
|
37
|
|
Net Decrease
in Fuel and Purchased Power Costs
|
|
|
|
)
|
Fossil fuel costs
decreased $16 million in the first
three months of 2009 primarily as a result of decreased coal consumption,
reflecting lower generation. Higher unit prices were due to increased fuel rates
on existing coal contracts in the first quarter of 2009. Nuclear fuel costs were
relatively unchanged in the first quarter of 2009 from last year.
Purchased power
costs from non-affiliates decreased primarily as a result of lower market rates
and reduced volume requirements. Purchases from affiliated companies
increased as a result of higher unit costs on purchases from the Ohio Companies’
leasehold interests in Beaver Valley Unit 2 and Perry.
Other operating
expenses increased by $11 million in the first
three months of 2009 from the same period of 2008. The increase was primarily
due to 2009 organizational restructuring costs ($4 million) and nuclear
operating costs as a result of higher expenses associated with the 2009 Perry
refueling outage than incurred with the 2008 Davis-Besse refueling outage
($11 million). Transmission expenses increased as a result of higher
congestion charges ($7 million). Partially offsetting the increases were
lower fossil contractor costs as a result of rescheduled maintenance activities
($7 million) and lower lease expenses relating to CEI’s and TE’s leasehold
improvements in the Mansfield Plant that were transferred to FGCO during the
first quarter of 2008 ($5 million).
Depreciation expense
increased by $12 million in the first three months of 2009 primarily due to
NGC’s acquisition of certain lessor equity interests in the sale and leaseback
of Perry and Beaver Valley Unit 2 ($7 million) and property additions since the
first quarter of 2008.
Other Expense
Other expense
increased by $14 million in the first
three months of 2009 from the same period of 2008 primarily due to a greater
loss in value of nuclear decommissioning trust investments ($23 million)
during the first quarter of 2009. Partially offsetting the higher securities
impairments was a $10 million decline in interest expense as a result of higher
capitalized interest ($3 million) and lower interest expense to affiliates due
to lower rates on loans from the unregulated moneypool ($4
million).
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to FES.
New Accounting Standards and
Interpretations
See
the “New Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to FES.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of
FirstEnergy Solutions Corp.:
We have reviewed the
accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its
subsidiaries as of March 31, 2009 and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2009 and 2008. These interim financial statements
are the responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated balance sheet
information as of December 31, 2008, is fairly stated in all material
respects in relation to the consolidated balance sheet from which it has been
derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric sales
to affiliates
|
|
$ |
892,690 |
|
|
$ |
776,307 |
|
Electric sales
to non-affiliates
|
|
|
279,746 |
|
|
|
288,341 |
|
Other
|
|
|
53,670 |
|
|
|
34,468 |
|
Total
revenues
|
|
|
1,226,106 |
|
|
|
1,099,116 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
306,158 |
|
|
|
321,689 |
|
Purchased
power from non-affiliates
|
|
|
160,342 |
|
|
|
206,724 |
|
Purchased
power from affiliates
|
|
|
63,207 |
|
|
|
25,485 |
|
Other
operating expenses
|
|
|
307,356 |
|
|
|
296,546 |
|
Provision for
depreciation
|
|
|
61,373 |
|
|
|
49,742 |
|
General
taxes
|
|
|
23,376 |
|
|
|
23,197 |
|
Total
expenses
|
|
|
921,812 |
|
|
|
923,383 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
304,294 |
|
|
|
175,733 |
|
|
|
|
|
|
|
|
|
|
OTHER
EXPENSE:
|
|
|
|
|
|
|
|
|
Miscellaneous
expense
|
|
|
(26,363 |
) |
|
|
(2,904 |
) |
Interest
expense to affiliates
|
|
|
(2,979 |
) |
|
|
(7,210 |
) |
Interest
expense - other
|
|
|
(22,527 |
) |
|
|
(24,535 |
) |
Capitalized
interest
|
|
|
10,078 |
|
|
|
6,663 |
|
Total other
expense
|
|
|
(41,791 |
) |
|
|
(27,986 |
) |
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
262,503 |
|
|
|
147,747 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
91,822 |
|
|
|
57,763 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
170,681 |
|
|
|
89,984 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
2,568 |
|
|
|
(1,820 |
) |
Unrealized
gain on derivative hedges
|
|
|
11,016 |
|
|
|
5,718 |
|
Change in
unrealized gain on available-for-sale securities
|
|
|
(1,477 |
) |
|
|
(51,852 |
) |
Other
comprehensive income (loss)
|
|
|
12,107 |
|
|
|
(47,954 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
4,709 |
|
|
|
(17,403 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
7,398 |
|
|
|
(30,551 |
) |
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
178,079 |
|
|
$ |
59,433 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
FirstEnergy Solutions Corp. are an
|
|
integral part
of these statements.
|
|
|
|
|
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
34 |
|
|
$ |
39 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,994,000 and $5,899,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
54,554 |
|
|
|
86,123 |
|
Associated
companies
|
|
|
287,935 |
|
|
|
378,100 |
|
Other (less
accumulated provisions of $6,702,000 and $6,815,000
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
66,293 |
|
|
|
24,626 |
|
Notes
receivable from associated companies
|
|
|
433,137 |
|
|
|
129,175 |
|
Materials and
supplies, at average cost
|
|
|
567,687 |
|
|
|
521,761 |
|
Prepayments
and other
|
|
|
112,162 |
|
|
|
112,535 |
|
|
|
|
1,521,802 |
|
|
|
1,252,359 |
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
9,912,603 |
|
|
|
9,871,904 |
|
Less -
Accumulated provision for depreciation
|
|
|
4,327,241 |
|
|
|
4,254,721 |
|
|
|
|
5,585,362 |
|
|
|
5,617,183 |
|
Construction
work in progress
|
|
|
2,114,831 |
|
|
|
1,747,435 |
|
|
|
|
7,700,193 |
|
|
|
7,364,618 |
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
995,476 |
|
|
|
1,033,717 |
|
Long-term
notes receivable from associated companies
|
|
|
62,900 |
|
|
|
62,900 |
|
Other
|
|
|
31,898 |
|
|
|
61,591 |
|
|
|
|
1,090,274 |
|
|
|
1,158,208 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income tax benefits
|
|
|
241,607 |
|
|
|
267,762 |
|
Lease
assignment receivable from associated companies
|
|
|
71,356 |
|
|
|
71,356 |
|
Goodwill
|
|
|
24,248 |
|
|
|
24,248 |
|
Property
taxes
|
|
|
50,104 |
|
|
|
50,104 |
|
Unamortized
sale and leaseback costs
|
|
|
86,302 |
|
|
|
69,932 |
|
Other
|
|
|
87,141 |
|
|
|
96,434 |
|
|
|
|
560,758 |
|
|
|
579,836 |
|
|
|
$ |
10,873,027 |
|
|
$ |
10,355,021 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
1,690,942 |
|
|
$ |
2,024,898 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
786,116 |
|
|
|
264,823 |
|
Other
|
|
|
1,100,000 |
|
|
|
1,000,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
409,160 |
|
|
|
472,338 |
|
Other
|
|
|
144,837 |
|
|
|
154,593 |
|
Accrued
taxes
|
|
|
122,734 |
|
|
|
79,766 |
|
Other
|
|
|
239,984 |
|
|
|
248,439 |
|
|
|
|
4,493,773 |
|
|
|
4,244,857 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 750 shares,
|
|
|
|
|
|
|
|
|
7 shares
outstanding
|
|
|
1,462,133 |
|
|
|
1,464,229 |
|
Accumulated
other comprehensive loss
|
|
|
(84,473 |
) |
|
|
(91,871 |
) |
Retained
earnings
|
|
|
1,742,746 |
|
|
|
1,572,065 |
|
Total common
stockholder's equity
|
|
|
3,120,406 |
|
|
|
2,944,423 |
|
Long-term debt
and other long-term obligations
|
|
|
670,061 |
|
|
|
571,448 |
|
|
|
|
3,790,467 |
|
|
|
3,515,871 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Deferred gain
on sale and leaseback transaction
|
|
|
1,018,156 |
|
|
|
1,026,584 |
|
Accumulated
deferred investment tax credits
|
|
|
61,645 |
|
|
|
62,728 |
|
Asset
retirement obligations
|
|
|
877,073 |
|
|
|
863,085 |
|
Retirement
benefits
|
|
|
198,803 |
|
|
|
194,177 |
|
Property
taxes
|
|
|
50,104 |
|
|
|
50,104 |
|
Lease market
valuation liability
|
|
|
296,376 |
|
|
|
307,705 |
|
Other
|
|
|
86,630 |
|
|
|
89,910 |
|
|
|
|
2,588,787 |
|
|
|
2,594,293 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
10,873,027 |
|
|
$ |
10,355,021 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
FirstEnergy Solutions Corp. are an integral part
|
|
of these
balance sheets.
|
|
|
|
|
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
170,681 |
|
|
$ |
89,984 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
61,373 |
|
|
|
49,742 |
|
Nuclear fuel
and lease amortization
|
|
|
27,169 |
|
|
|
25,426 |
|
Deferred rents
and lease market valuation liability
|
|
|
(37,522 |
) |
|
|
(34,887 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
24,866 |
|
|
|
30,781 |
|
Investment
impairment
|
|
|
33,535 |
|
|
|
14,943 |
|
Accrued
compensation and retirement benefits
|
|
|
(3,439 |
) |
|
|
(11,042 |
) |
Commodity
derivative transactions, net
|
|
|
15,817 |
|
|
|
8,086 |
|
Gain on asset
sales
|
|
|
(5,209 |
) |
|
|
(4,964 |
) |
Cash
collateral, net
|
|
|
(5,492 |
) |
|
|
1,601 |
|
Decrease
(increase) in operating assets:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
80,067 |
|
|
|
69,533 |
|
Materials and
supplies
|
|
|
(865 |
) |
|
|
(12,948 |
) |
Prepayments
and other current assets
|
|
|
(3,456 |
) |
|
|
(12,260 |
) |
Increase
(decrease) in operating liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(61,419 |
) |
|
|
(17,149 |
) |
Accrued
taxes
|
|
|
39,846 |
|
|
|
(28,652 |
) |
Accrued
interest
|
|
|
10,338 |
|
|
|
(728 |
) |
Other
|
|
|
1,577 |
|
|
|
(7,514 |
) |
Net cash
provided from operating activities
|
|
|
347,867 |
|
|
|
159,952 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
100,000 |
|
|
|
- |
|
Short-term
borrowings, net
|
|
|
621,294 |
|
|
|
1,281,896 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(335,916 |
) |
|
|
(288,603 |
) |
Common stock
dividend payments
|
|
|
- |
|
|
|
(10,000 |
) |
Net cash
provided from financing activities
|
|
|
385,378 |
|
|
|
983,293 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(412,805 |
) |
|
|
(476,529 |
) |
Proceeds from
asset sales
|
|
|
7,573 |
|
|
|
5,088 |
|
Sales of
investment securities held in trusts
|
|
|
351,414 |
|
|
|
173,123 |
|
Purchases of
investment securities held in trusts
|
|
|
(356,904 |
) |
|
|
(181,079 |
) |
Loans to
associated companies, net
|
|
|
(303,963 |
) |
|
|
(644,604 |
) |
Other
|
|
|
(18,565 |
) |
|
|
(19,244 |
) |
Net cash used
for investing activities
|
|
|
(733,250 |
) |
|
|
(1,143,245 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
(5 |
) |
|
|
- |
|
Cash and cash
equivalents at beginning of period
|
|
|
39 |
|
|
|
2 |
|
Cash and cash
equivalents at end of period
|
|
$ |
34 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
FirstEnergy Solutions Corp. are an integral part of
|
|
these
statements.
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
ANALYSIS
OF RESULTS OF OPERATIONS
OE is a wholly owned
electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary,
Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated
electric distribution services. They provide generation services to those
franchise customers electing to retain OE and Penn as their power supplier.
Until December 31, 2008, OE purchased power for delivery and resale from a
full requirements power sale agreement with its affiliate FES at a fixed price
that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio
below for a discussion of Ohio power supply procurement issues for 2009 and
beyond.
Results of
Operations
In the first three
months of 2009, net income decreased to $12 million from $44 million in the same
period of 2008. The decrease primarily resulted from the completion of the
recovery of transition costs at the end of 2008 and accrued obligations
principally associated with the implementation of the ESP in 2009. OE’s financial
statements include certain immaterial adjustments that relate to prior periods
that reduced net income by $3 million for the first quarter of
2009.
Revenues
Revenues increased
by $96 million, or 14.8%, in the first three months of 2009 compared with the
same period in 2008, primarily due to increases in retail generation revenues
($114 million) and wholesale revenues ($35 million), partially offset by
decreases in distribution throughput revenues ($53 million).
Retail generation
revenues increased primarily due to higher average prices across all customer
classes and increased KWH sales to residential and commercial customers,
reflecting a decrease in customer shopping for those sectors as most of OE’s
franchise customers returned to PLR service in December 2008. Reduced industrial
KWH sales reflected weakened economic conditions in OE’s and Penn’s service
territories. Additional generation revenues from OE’s fuel rider effective in
January 2009 contributed to the rate variances (see Regulatory Matters – Ohio).
Changes in retail
generation sales and revenues in the first three months of 2009 from the same
period in 2008 are summarized in the following tables:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
11.8
|
%
|
Commercial
|
|
|
17.3
|
%
|
Industrial
|
|
|
(8.2
|
)%
|
Net
Increase in Generation Sales
|
|
|
7.2
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
55
|
|
Commercial
|
|
|
41
|
|
Industrial
|
|
|
18
|
|
Increase
in Generation Revenues
|
|
$
|
114
|
|
Revenues from
distribution throughput decreased by $53 million in the first three months of
2009 compared to the same period in 2008 due to lower average unit prices and
lower KWH deliveries to all customer classes. Reduced deliveries to commercial
and industrial customers were a result of the weakened economy. Transition
charges that ceased effective January 1, 2009, with the full recovery of
related costs, were partially offset by a July 2008 increase to a PUCO-approved
transmission rider and a January 2009 distribution rate increase (see Regulatory
Matters – Ohio).
Changes in
distribution KWH deliveries and revenues in the first three months of 2009 from
the same period in 2008 are summarized in the following tables.
Distribution
KWH Deliveries |
|
Decrease |
|
|
|
|
|
|
Residential
|
|
|
(1.0
|
)%
|
Commercial
|
|
|
(4.7
|
)%
|
Industrial
|
|
|
(22.9 |
)%
|
Decrease
in Distribution Deliveries
|
|
|
(9.2 |
)%
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(8
|
)
|
Commercial
|
|
|
(22
|
)
|
Industrial
|
|
|
(23
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(53
|
)
|
Expenses
Total expenses
increased by $143 million in the first three months of 2009 from the same period
of 2008. The following table presents changes from the prior year by expense
category.
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
130
|
|
Other
operating costs
|
|
|
17
|
|
Amortization
of regulatory assets, net
|
|
|
(3
|
)
|
General
taxes
|
|
|
(1
|
)
|
Net
Increase in Expenses
|
|
$
|
143
|
|
Higher purchased
power costs are primarily due to the results of the CBP used for the procurement
of electric generation for retail customers during the first quarter of 2009 and
higher volumes due to increased retail generation KWH sales. The increase in
other operating costs for the first three months of 2009 was primarily due to
accruals for economic development programs, in accordance with the PUCO-approved
ESP, and energy efficiency obligations. Lower amortization of net regulatory
assets was primarily due to the conclusion of transition cost amortization in
2008, partially offset by lower MISO transmission cost deferrals and lower RCP
distribution deferrals.
Other Expenses
Other expenses
increased by $8 million in the first
three months of 2009 compared to the same period in 2008 primarily due to higher
interest expense associated with the issuance of OE’s $300 million of FMBs
in October 2008.
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to OE.
New Accounting Standards and
Interpretations
See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to OE.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of Ohio
Edison Company:
We have reviewed the
accompanying consolidated balance sheet of Ohio Edison Company and its
subsidiaries as of March 31, 2009 and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2009 and 2008. These interim financial statements are
the responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed
an unqualified opinion on those consolidated financial statements. As discussed
in Note 6 to the accompanying consolidated financial statements, the
Company changed its reporting related to noncontrolling interest. The
accompanying December 31, 2008 consolidated balance sheet reflects this
change.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
STATEMENTS OF INCOME
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
720,011 |
|
|
$ |
622,271 |
|
Excise and
gross receipts tax collections
|
|
|
28,980 |
|
|
|
30,378 |
|
Total
revenues
|
|
|
748,991 |
|
|
|
652,649 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
332,336 |
|
|
|
319,711 |
|
Purchased
power from non-affiliates
|
|
|
137,813 |
|
|
|
20,475 |
|
Other
operating costs
|
|
|
157,830 |
|
|
|
140,326 |
|
Provision for
depreciation
|
|
|
21,513 |
|
|
|
21,493 |
|
Amortization
of regulatory assets, net
|
|
|
20,211 |
|
|
|
23,127 |
|
General
taxes
|
|
|
49,120 |
|
|
|
50,453 |
|
Total
expenses
|
|
|
718,823 |
|
|
|
575,585 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
30,168 |
|
|
|
77,064 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
9,362 |
|
|
|
15,055 |
|
Miscellaneous
expense
|
|
|
(810 |
) |
|
|
(3,652 |
) |
Interest
expense
|
|
|
(23,287 |
) |
|
|
(17,641 |
) |
Capitalized
interest
|
|
|
220 |
|
|
|
110 |
|
Total other
expense
|
|
|
(14,515 |
) |
|
|
(6,128 |
) |
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
15,653 |
|
|
|
70,936 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
4,005 |
|
|
|
26,873 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
11,648 |
|
|
|
44,063 |
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income
|
|
|
146 |
|
|
|
154 |
|
|
|
|
|
|
|
|
|
|
EARNINGS
AVAILABLE TO PARENT
|
|
$ |
11,502 |
|
|
$ |
43,909 |
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
11,648 |
|
|
$ |
44,063 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
5,738 |
|
|
|
(3,994 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
|
(2,709 |
) |
|
|
(7,571 |
) |
Other
comprehensive income (loss)
|
|
|
3,029 |
|
|
|
(11,565 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
529 |
|
|
|
(4,262 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
2,500 |
|
|
|
(7,303 |
) |
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
14,148 |
|
|
|
36,760 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
|
|
|
146 |
|
|
|
154 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO PARENT
|
|
$ |
14,002 |
|
|
$ |
36,606 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Ohio Edison Company are an integral part
|
|
of these
statements.
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
311,192 |
|
|
$ |
146,343 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $6,621,000 and $6,065,000,
respectively,
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
292,159 |
|
|
|
277,377 |
|
Associated
companies
|
|
|
217,455 |
|
|
|
234,960 |
|
Other (less
accumulated provisions of $8,000 and $7,000, respectively,
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
19,492 |
|
|
|
14,492 |
|
Notes
receivable from associated companies
|
|
|
77,264 |
|
|
|
222,861 |
|
Prepayments
and other
|
|
|
22,544 |
|
|
|
5,452 |
|
|
|
|
940,106 |
|
|
|
901,485 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,915,643 |
|
|
|
2,903,290 |
|
Less -
Accumulated provision for depreciation
|
|
|
1,120,219 |
|
|
|
1,113,357 |
|
|
|
|
1,795,424 |
|
|
|
1,789,933 |
|
Construction
work in progress
|
|
|
47,022 |
|
|
|
37,766 |
|
|
|
|
1,842,446 |
|
|
|
1,827,699 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
256,473 |
|
|
|
256,974 |
|
Investment in
lease obligation bonds
|
|
|
239,501 |
|
|
|
239,625 |
|
Nuclear plant
decommissioning trusts
|
|
|
112,778 |
|
|
|
116,682 |
|
Other
|
|
|
98,729 |
|
|
|
100,792 |
|
|
|
|
707,481 |
|
|
|
714,073 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
544,782 |
|
|
|
575,076 |
|
Property
taxes
|
|
|
60,542 |
|
|
|
60,542 |
|
Unamortized
sale and leaseback costs
|
|
|
38,880 |
|
|
|
40,130 |
|
Other
|
|
|
32,418 |
|
|
|
33,710 |
|
|
|
|
676,622 |
|
|
|
709,458 |
|
|
|
$ |
4,166,655 |
|
|
$ |
4,152,715 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
2,697 |
|
|
$ |
101,354 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
79,810 |
|
|
|
- |
|
Other
|
|
|
1,540 |
|
|
|
1,540 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
115,778 |
|
|
|
131,725 |
|
Other
|
|
|
54,237 |
|
|
|
26,410 |
|
Accrued
taxes
|
|
|
72,736 |
|
|
|
77,592 |
|
Accrued
interest
|
|
|
23,717 |
|
|
|
25,673 |
|
Other
|
|
|
124,871 |
|
|
|
85,209 |
|
|
|
|
475,386 |
|
|
|
449,503 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 175,000,000 shares -
|
|
|
|
|
|
|
|
|
60 shares
outstanding
|
|
|
1,224,347 |
|
|
|
1,224,416 |
|
Accumulated
other comprehensive loss
|
|
|
(181,885 |
) |
|
|
(184,385 |
) |
Retained
earnings
|
|
|
265,525 |
|
|
|
254,023 |
|
Total common
stockholder's equity
|
|
|
1,307,987 |
|
|
|
1,294,054 |
|
Noncontrolling
interest
|
|
|
7,252 |
|
|
|
7,106 |
|
Total
equity
|
|
|
1,315,239 |
|
|
|
1,301,160 |
|
Long-term debt
and other long-term obligations
|
|
|
1,123,966 |
|
|
|
1,122,247 |
|
|
|
|
2,439,205 |
|
|
|
2,423,407 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
650,601 |
|
|
|
653,475 |
|
Accumulated
deferred investment tax credits
|
|
|
12,700 |
|
|
|
13,065 |
|
Asset
retirement obligations
|
|
|
81,944 |
|
|
|
80,647 |
|
Retirement
benefits
|
|
|
305,943 |
|
|
|
308,450 |
|
Other
|
|
|
200,876 |
|
|
|
224,168 |
|
|
|
|
1,252,064 |
|
|
|
1,279,805 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
4,166,655 |
|
|
$ |
4,152,715 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Ohio Edison Company are an integral part of
|
|
these balance
sheets.
|
|
|
|
|
|
|
|
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
11,648 |
|
|
$ |
44,063 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
21,513 |
|
|
|
21,493 |
|
Amortization
of regulatory assets, net
|
|
|
20,211 |
|
|
|
23,127 |
|
Purchased
power cost recovery reconciliation
|
|
|
2,978 |
|
|
|
- |
|
Amortization
of lease costs
|
|
|
32,934 |
|
|
|
32,934 |
|
Deferred
income taxes and investment tax credits, net
|
|
|
(7,272 |
) |
|
|
6,866 |
|
Accrued
compensation and retirement benefits
|
|
|
(1,746 |
) |
|
|
(19,482 |
) |
Accrued
regulatory obligations
|
|
|
18,350 |
|
|
|
- |
|
Electric
service prepayment programs
|
|
|
(3,944 |
) |
|
|
(10,028 |
) |
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
1,435 |
|
|
|
(27,496 |
) |
Prepayments
and other current assets
|
|
|
(9,806 |
) |
|
|
(7,451 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
11,880 |
|
|
|
(3,939 |
) |
Accrued
taxes
|
|
|
(26,222 |
) |
|
|
2,991 |
|
Accrued
interest
|
|
|
(1,956 |
) |
|
|
(5,919 |
) |
Other
|
|
|
6,708 |
|
|
|
(2,220 |
) |
Net cash
provided from operating activities
|
|
|
76,711 |
|
|
|
54,939 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
79,810 |
|
|
|
- |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(100,393 |
) |
|
|
(75 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
- |
|
|
|
(15,000 |
) |
Other
|
|
|
(69 |
) |
|
|
(5 |
) |
Net cash used
for financing activities
|
|
|
(20,652 |
) |
|
|
(15,080 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(37,523 |
) |
|
|
(49,011 |
) |
Sales of
investment securities held in trusts
|
|
|
9,417 |
|
|
|
62,344 |
|
Purchases of
investment securities held in trusts
|
|
|
(10,422 |
) |
|
|
(63,797 |
) |
Loan
repayments from associated companies, net
|
|
|
146,098 |
|
|
|
6,534 |
|
Cash
investments
|
|
|
(243 |
) |
|
|
147 |
|
Other
|
|
|
1,463 |
|
|
|
3,924 |
|
Net cash
provided from (used for) investing activities
|
|
|
108,790 |
|
|
|
(39,859 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
164,849 |
|
|
|
- |
|
Cash and cash
equivalents at beginning of period
|
|
|
146,343 |
|
|
|
732 |
|
Cash and cash
equivalents at end of period
|
|
$ |
311,192 |
|
|
$ |
732 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Ohio Edison Company are an integral part
|
|
of these
statements.
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
ANALYSIS
OF RESULTS OF OPERATIONS
CEI is a wholly
owned, electric utility subsidiary of FirstEnergy. CEI conducts business in
northeastern Ohio, providing regulated electric distribution services. CEI also
provides generation services to those customers electing to retain CEI as their
power supplier. Until December 31, 2008, CEI purchased power for delivery and
resale from a full requirements power sale agreement with its affiliate FES at a
fixed price that was reflected in rates approved by the PUCO. See Regulatory
Matters – Ohio below for a discussion of Ohio power supply procurement issues
for 2009 and beyond.
Results
of Operations
CEI recognized a net
loss of $105 million in the first three months of 2009 compared to net income of
$58 million in the same period of 2008. The decrease resulted primarily
from CEI’s $216 million regulatory asset impairment related to the
implementation of its ESP and increased purchased power costs, partially offset
by higher deferrals of new regulatory assets.
Revenues
Revenues increased
by $12 million, or 2.8%, in the first three months of 2009 compared to the
same period of 2008 primarily due to an increase in retail generation revenues
($18 million), partially offset by decreases in distribution revenues ($4
million) and other miscellaneous revenues ($2 million).
Retail generation
revenues increased in the first three months of 2009 due to higher average unit
prices across all customer classes and increased sales volume to residential and
commercial customers, compared to the same period of 2008. Generation rate
increases under CEI’s CBP contributed to the increased rate variances (see
Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major
automotive and steel customers, reflected weakened economic conditions. The
increase in sales volume for residential and commercial customers primarily
reflected a decrease in customer shopping, as most of CEI’s customers returned
to PLR service in December 2008.
Changes in retail
generation sales and revenues in the first three months of 2009 compared to the
same period in 2008 are summarized in the following tables:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
Residential
|
|
|
8.0
|
%
|
Commercial
|
|
|
12.5
|
%
|
Industrial
|
|
|
(9.8
|
)%
|
Net
Increase in Retail Generation Sales
|
|
|
1.4
|
%
|
Retail
Generation Revenues
|
|
Increase
(Decrease)
|
|
|
|
(in
millions)
|
|
Residential
|
|
$
|
8
|
|
Commercial
|
|
|
12
|
|
Industrial
|
|
|
(2
|
)
|
Net
Increase in Generation Revenues
|
|
$
|
18
|
|
Revenues from
distribution throughput decreased by $4 million in the first three months
of 2009 compared to the same period of 2008 primarily due lower KWH deliveries
to commercial and industrial customers as a result of the economic downturn in
CEI’s service territory.
Decreases in
distribution KWH deliveries and revenues in the first three months of 2009
compared to the same period of 2008 are summarized in the following
tables.
Distribution
KWH Deliveries
|
|
Decrease
|
|
Residential
|
|
|
(0.6
|
)%
|
Commercial
|
|
|
(5.1
|
)%
|
Industrial
|
|
|
(19.8
|
)%
|
Decrease
in Distribution Deliveries
|
|
|
(10.0
|
)%
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(1
|
)
|
Commercial
|
|
|
(1
|
)
|
Industrial
|
|
|
(2
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(4
|
)
|
Expenses
Total expenses
increased by $267 million in the first three months of 2009 compared to the
same period of 2008. The following table presents the change from the prior year
by expense category:
Expenses -
Changes
|
|
Increase
(Decrease)
|
|
|
|
(in
millions)
|
|
Purchased
power costs
|
|
$
|
117
|
|
Amortization
of regulatory assets
|
|
|
218
|
|
Deferral of
new regulatory assets
|
|
|
(66
|
)
|
General
taxes
|
|
|
(2
|
)
|
Net
Increase in Expenses
|
|
$
|
267
|
|
Higher purchased
power costs are primarily due to the results of the CBP used for the procurement
of electric generation for retail customers in the first quarter of 2009.
Increased amortization of regulatory assets was primarily due to the impairment
of CEI’s Extended RTC balance in accordance with the PUCO-approved ESP. The
increase in the deferral of new regulatory assets was primarily due to CEI’s
deferral of purchased power costs as approved by the PUCO, partially offset by
lower deferred MISO transmission expenses and the absence of RCP distribution
deferrals that ceased at the end of 2008. While other operating costs were
unchanged from the previous year, cost increases associated with the ESP for
economic development and energy efficiency programs, higher pension expense and
restructuring costs were completely offset by reduced transmission expense,
labor, contractor costs and general business expense. The decrease in general
taxes is primarily due to lower property taxes.
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to CEI.
New Accounting Standards and
Interpretations
See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to CEI.
.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of Directors of
The Cleveland
Electric Illuminating Company:
We have reviewed the
accompanying consolidated balance sheet of The Cleveland Electric Illuminating
Company and its subsidiaries as of March 31, 2009 and the related consolidated
statements of income, comprehensive income and cash flows for each of the
three-month periods ended March 31, 2009 and 2008. These interim financial
statements are the responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. As discussed in
Note 6 to the accompanying consolidated financial statements, the Company
changed its reporting related to noncontrolling interest. The accompanying
December 31, 2008 consolidated balance sheet reflects this change.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
STATEMENTS OF INCOME
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
431,405 |
|
|
$ |
418,708 |
|
Excise tax
collections
|
|
|
18,320 |
|
|
|
18,600 |
|
Total
revenues
|
|
|
449,725 |
|
|
|
437,308 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
238,872 |
|
|
|
190,196 |
|
Purchased
power from non-affiliates
|
|
|
71,746 |
|
|
|
3,048 |
|
Other
operating costs
|
|
|
64,830 |
|
|
|
65,118 |
|
Provision for
depreciation
|
|
|
18,280 |
|
|
|
19,076 |
|
Amortization
of regulatory assets
|
|
|
256,737 |
|
|
|
38,256 |
|
Deferral of
new regulatory assets
|
|
|
(94,816 |
) |
|
|
(29,248 |
) |
General
taxes
|
|
|
38,141 |
|
|
|
40,083 |
|
Total
expenses
|
|
|
593,790 |
|
|
|
326,529 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
(144,065 |
) |
|
|
110,779 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
8,420 |
|
|
|
9,188 |
|
Miscellaneous
income
|
|
|
1,994 |
|
|
|
1,118 |
|
Interest
expense
|
|
|
(33,322 |
) |
|
|
(32,520 |
) |
Capitalized
interest
|
|
|
67 |
|
|
|
196 |
|
Total other
expense
|
|
|
(22,841 |
) |
|
|
(22,018 |
) |
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
(166,906 |
) |
|
|
88,761 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAX EXPENSE (BENEFIT)
|
|
|
(61,506 |
) |
|
|
30,326 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
(105,400 |
) |
|
|
58,435 |
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income
|
|
|
458 |
|
|
|
584 |
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) AVAILABLE TO PARENT
|
|
$ |
(105,858 |
) |
|
$ |
57,851 |
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
$ |
(105,400 |
) |
|
$ |
58,435 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
3,967 |
|
|
|
(213 |
) |
Income tax
expense related to other comprehensive income
|
|
|
1,370 |
|
|
|
281 |
|
Other
comprehensive income (loss), net of tax
|
|
|
2,597 |
|
|
|
(494 |
) |
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME (LOSS)
|
|
|
(102,803 |
) |
|
|
57,941 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
|
|
|
458 |
|
|
|
584 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME (LOSS) ATTRIBUTABLE TO PARENT
|
|
$ |
(103,261 |
) |
|
$ |
57,357 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
The Cleveland Electric Illuminating
|
|
Company are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
233 |
|
|
$ |
226 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $6,199,000 and
|
|
|
|
|
|
|
|
|
$5,916,000,
respectively, for uncollectible accounts)
|
|
|
283,967 |
|
|
|
276,400 |
|
Associated
companies
|
|
|
159,819 |
|
|
|
113,182 |
|
Other
|
|
|
4,438 |
|
|
|
13,834 |
|
Notes
receivable from associated companies
|
|
|
22,744 |
|
|
|
19,060 |
|
Prepayments
and other
|
|
|
2,002 |
|
|
|
2,787 |
|
|
|
|
473,203 |
|
|
|
425,489 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,240,065 |
|
|
|
2,221,660 |
|
Less -
Accumulated provision for depreciation
|
|
|
852,393 |
|
|
|
846,233 |
|
|
|
|
1,387,672 |
|
|
|
1,375,427 |
|
Construction
work in progress
|
|
|
40,545 |
|
|
|
40,651 |
|
|
|
|
1,428,217 |
|
|
|
1,416,078 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Investment in
lessor notes
|
|
|
388,647 |
|
|
|
425,715 |
|
Other
|
|
|
10,239 |
|
|
|
10,249 |
|
|
|
|
398,886 |
|
|
|
435,964 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521 |
|
|
|
1,688,521 |
|
Regulatory
assets
|
|
|
617,967 |
|
|
|
783,964 |
|
Property
taxes
|
|
|
71,500 |
|
|
|
71,500 |
|
Other
|
|
|
10,629 |
|
|
|
10,818 |
|
|
|
|
2,388,617 |
|
|
|
2,554,803 |
|
|
|
$ |
4,688,923 |
|
|
$ |
4,832,334 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
150,704 |
|
|
$ |
150,688 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
242,065 |
|
|
|
227,949 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
94,824 |
|
|
|
106,074 |
|
Other
|
|
|
26,914 |
|
|
|
7,195 |
|
Accrued
taxes
|
|
|
76,130 |
|
|
|
87,810 |
|
Accrued
interest
|
|
|
41,546 |
|
|
|
13,932 |
|
Other
|
|
|
44,021 |
|
|
|
40,095 |
|
|
|
|
676,204 |
|
|
|
633,743 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
|
67,930,743
shares outstanding
|
|
|
878,680 |
|
|
|
878,785 |
|
Accumulated
other comprehensive loss
|
|
|
(132,260 |
) |
|
|
(134,857 |
) |
Retained
earnings
|
|
|
754,096 |
|
|
|
859,954 |
|
Total common
stockholder's equity
|
|
|
1,500,516 |
|
|
|
1,603,882 |
|
Noncontrolling
interest
|
|
|
20,173 |
|
|
|
22,555 |
|
Total
equity
|
|
|
1,520,689 |
|
|
|
1,626,437 |
|
Long-term debt
and other long-term obligations
|
|
|
1,573,241 |
|
|
|
1,591,586 |
|
|
|
|
3,093,930 |
|
|
|
3,218,023 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
644,547 |
|
|
|
704,270 |
|
Accumulated
deferred investment tax credits
|
|
|
12,731 |
|
|
|
13,030 |
|
Retirement
benefits
|
|
|
129,537 |
|
|
|
128,738 |
|
Lease
assignment payable to associated companies
|
|
|
40,827 |
|
|
|
40,827 |
|
Other
|
|
|
91,147 |
|
|
|
93,703 |
|
|
|
|
918,789 |
|
|
|
980,568 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
4,688,923 |
|
|
$ |
4,832,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
The Cleveland Electric Illuminating
|
|
Company are an
integral part of these balance sheets.
|
|
|
|
|
|
|
|
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net income
(loss)
|
|
$ |
(105,400 |
) |
|
$ |
58,435 |
|
Adjustments to
reconcile net income (loss) to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
18,280 |
|
|
|
19,076 |
|
Amortization
of regulatory assets
|
|
|
256,737 |
|
|
|
38,256 |
|
Deferral of
new regulatory assets
|
|
|
(94,816 |
) |
|
|
(29,248 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(61,525 |
) |
|
|
(4,965 |
) |
Accrued
compensation and retirement benefits
|
|
|
1,828 |
|
|
|
(3,507 |
) |
Accrued
regulatory obligations
|
|
|
12,057 |
|
|
|
- |
|
Electric
service prepayment programs
|
|
|
(2,695 |
) |
|
|
(5,847 |
) |
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(44,808 |
) |
|
|
90,280 |
|
Prepayments
and other current assets
|
|
|
785 |
|
|
|
604 |
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
18,470 |
|
|
|
1,111 |
|
Accrued
taxes
|
|
|
(16,274 |
) |
|
|
23,196 |
|
Accrued
interest
|
|
|
27,614 |
|
|
|
23,831 |
|
Other
|
|
|
346 |
|
|
|
2,308 |
|
Net cash
provided from operating activities
|
|
|
10,599 |
|
|
|
213,530 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(181 |
) |
|
|
(165 |
) |
Short-term
borrowings, net
|
|
|
(4,086 |
) |
|
|
(177,960 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(10,000 |
) |
|
|
(30,000 |
) |
Other
|
|
|
(2,840 |
) |
|
|
(2,955 |
) |
Net cash used
for financing activities
|
|
|
(17,107 |
) |
|
|
(211,080 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(24,900 |
) |
|
|
(37,203 |
) |
Loans to
associated companies, net
|
|
|
(3,683 |
) |
|
|
(2,373 |
) |
Redemptions of
lessor notes
|
|
|
37,068 |
|
|
|
37,709 |
|
Other
|
|
|
(1,970 |
) |
|
|
(574 |
) |
Net cash
provided from (used for) investing activities
|
|
|
6,515 |
|
|
|
(2,441 |
) |
|
|
|
|
|
|
|
|
|
Net increase
in cash and cash equivalents
|
|
|
7 |
|
|
|
9 |
|
Cash and cash
equivalents at beginning of period
|
|
|
226 |
|
|
|
232 |
|
Cash and cash
equivalents at end of period
|
|
$ |
233 |
|
|
$ |
241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
The Cleveland Electric Illuminating
|
|
Company are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
ANALYSIS
OF RESULTS OF OPERATIONS
TE is a wholly owned
electric utility subsidiary of FirstEnergy. TE conducts business in northwestern
Ohio, providing regulated electric distribution services. TE also provides
generation services to those customers electing to retain TE as their power
supplier. Until December 31, 2008, TE purchased power for delivery and resale
from a full requirements power sale agreement with its affiliate FES at a fixed
price that was reflected in rates approved by the PUCO. See Regulatory Matters –
Ohio below for a discussion of Ohio power supply procurement issues for 2009 and
beyond.
Results of
Operations
Net income in the
first three months of 2009 decreased to $1 million from $17 million in the same
period of 2008. The decrease resulted primarily from the completion of
transition cost recovery in 2008.
Revenues
Revenues increased
$33 million, or
15.6%, in the first three months of 2009 compared to the same period of 2008
primarily due to increased retail generation revenues ($67 million), partially
offset by lower distribution revenues ($33 million) and wholesale
generation revenues ($1 million).
Retail generation
revenues increased in the first three months of 2009 due to higher average
prices across all customer classes and increased KWH sales to residential and
commercial customers, compared to the same period of 2008. TE’s implementation
of a fuel rider in January 2009 produced the rate variances (see Regulatory
Matters – Ohio). Reduced industrial KWH sales, principally to major automotive
and steel customers, reflected weakened economic conditions. The increase in
sales volume for residential and commercial customers resulted principally from
a decrease in customer shopping. Most of TE’s franchise customers
returned to PLR service in December 2008.
Changes in retail
electric generation KWH sales and revenues in the first three months of 2009
from the same period of 2008 are summarized in the following
tables.
|
|
Increase
|
|
Retail
KWH Sales
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
6.5
|
%
|
Commercial
|
|
|
39.3
|
%
|
Industrial
|
|
|
(11.5
|
)%
|
Net
Increase in Retail KWH Sales
|
|
|
3.9
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
16
|
|
Commercial
|
|
|
26
|
|
Industrial
|
|
|
25
|
|
Increase
in Retail Generation Revenues
|
|
$
|
67
|
|
Revenues from
distribution throughput decreased by $33 million in the first three months of
2009 compared to the same period in 2008 due to lower average unit prices and
lower KWH deliveries for all customer classes. Transition charges that ceased
effective January 1, 2009, with the full recovery of related costs, were
partially offset by a PUCO-approved distribution rate increase (see Regulatory
Matters – Ohio).
Changes in
distribution KWH deliveries and revenues in the first three months of 2009 from
the same period of 2008 are summarized in the following tables.
Distribution
KWH Deliveries
|
|
Decrease
|
|
|
|
|
|
|
Residential
|
|
|
(2.8
|
)%
|
Commercial
|
|
|
(10.0
|
)%
|
Industrial
|
|
|
(13.5
|
)%
|
Decrease
in Distribution Deliveries
|
|
|
(9.6
|
)%
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(8
|
)
|
Commercial
|
|
|
(17
|
)
|
Industrial
|
|
|
(8
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(33
|
)
|
Expenses
Total expenses
increased $57 million in the first three months of 2009 from the same
period of 2008. The following table presents changes from the prior year by
expense category.
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
$
|
|
|
Provision for
depreciation
|
|
|
|
)
|
Amortization
of regulatory assets, net
|
|
|
|
|
|
|
|
|
|
Higher purchased
power costs are primarily due to the results of the CBP used for the procurement
of electric generation for retail customers during the first quarter of 2009.
While other operating costs were unchanged from the first quarter of 2008, cost
increases associated with the regulatory obligations for economic development
and energy efficiency programs, higher pension and other expenses were
completely offset by reduced transmission, labor and other employee benefit
expenses. Depreciation expense decreased due to the transfer of leasehold
improvements for the Bruce Mansfield Plant and Beaver Valley Unit 2 to FGCO and
NGC, respectively, during 2008. The decrease in the net amortization of
regulatory assets is primarily due to the cessation of transition cost
amortization, partially offset by a reduction in transmission deferrals and the
absence of RCP distribution cost deferrals in 2009.
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to TE.
New Accounting Standards and
Interpretations
See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to TE.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of The
Toledo Edison Company:
We have reviewed the
accompanying consolidated balance sheet of The Toledo Edison Company and its
subsidiary as of March 31, 2009 and the related consolidated statements of
income, comprehensive income and cash flows for each of the three-month periods
ended March 31, 2009 and 2008. These interim financial statements are the
responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. As discussed in
Note 6 to the accompanying consolidated financial statements, the Company
changed its reporting related to noncontrolling interest. The accompanying
December 31, 2008 consolidated balance sheet reflects this change.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
STATEMENTS OF INCOME
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
237,085 |
|
|
$ |
203,669 |
|
Excise tax
collections
|
|
|
7,729 |
|
|
|
8,025 |
|
Total
revenues
|
|
|
244,814 |
|
|
|
211,694 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
125,324 |
|
|
|
99,494 |
|
Purchased
power from non-affiliates
|
|
|
40,537 |
|
|
|
1,804 |
|
Other
operating costs
|
|
|
45,004 |
|
|
|
45,329 |
|
Provision for
depreciation
|
|
|
7,572 |
|
|
|
9,025 |
|
Amortization
of regulatory assets, net
|
|
|
9,897 |
|
|
|
15,531 |
|
General
taxes
|
|
|
14,250 |
|
|
|
14,377 |
|
Total
expenses
|
|
|
242,584 |
|
|
|
185,560 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
2,230 |
|
|
|
26,134 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
5,484 |
|
|
|
6,481 |
|
Miscellaneous
expense
|
|
|
(1,340 |
) |
|
|
(1,512 |
) |
Interest
expense
|
|
|
(5,533 |
) |
|
|
(6,035 |
) |
Capitalized
interest
|
|
|
42 |
|
|
|
37 |
|
Total other
expense
|
|
|
(1,347 |
) |
|
|
(1,029 |
) |
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
883 |
|
|
|
25,105 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAX EXPENSE (BENEFIT)
|
|
|
(109 |
) |
|
|
8,088 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
992 |
|
|
|
17,017 |
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
EARNINGS
AVAILABLE TO PARENT
|
|
$ |
990 |
|
|
$ |
17,015 |
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
992 |
|
|
$ |
17,017 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
133 |
|
|
|
(63 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
|
(809 |
) |
|
|
1,961 |
|
Other
comprehensive income (loss)
|
|
|
(676 |
) |
|
|
1,898 |
|
Income tax
expense (benefit) related to other comprehensive income
|
|
|
(19 |
) |
|
|
728 |
|
Other
comprehensive income (loss), net of tax
|
|
|
(657 |
) |
|
|
1,170 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
335 |
|
|
|
18,187 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE TO PARENT
|
|
$ |
333 |
|
|
$ |
18,185 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
The Toledo Edison Company
|
|
are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
15 |
|
|
$ |
14 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
|
|
|
438 |
|
|
|
751 |
|
Associated
companies
|
|
|
70,444 |
|
|
|
61,854 |
|
Other (less
accumulated provisions of $193,000 and $203,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
23,693 |
|
|
|
23,336 |
|
Notes
receivable from associated companies
|
|
|
133,186 |
|
|
|
111,579 |
|
Prepayments
and other
|
|
|
4,481 |
|
|
|
1,213 |
|
|
|
|
232,257 |
|
|
|
198,747 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
880,315 |
|
|
|
870,911 |
|
Less -
Accumulated provision for depreciation
|
|
|
413,030 |
|
|
|
407,859 |
|
|
|
|
467,285 |
|
|
|
463,052 |
|
Construction
work in progress
|
|
|
10,957 |
|
|
|
9,007 |
|
|
|
|
478,242 |
|
|
|
472,059 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Investment in
lessor notes
|
|
|
124,329 |
|
|
|
142,687 |
|
Long-term
notes receivable from associated companies
|
|
|
37,154 |
|
|
|
37,233 |
|
Nuclear plant
decommissioning trusts
|
|
|
73,235 |
|
|
|
73,500 |
|
Other
|
|
|
1,646 |
|
|
|
1,668 |
|
|
|
|
236,364 |
|
|
|
255,088 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576 |
|
|
|
500,576 |
|
Regulatory
assets
|
|
|
96,351 |
|
|
|
109,364 |
|
Property
taxes
|
|
|
22,970 |
|
|
|
22,970 |
|
Other
|
|
|
62,004 |
|
|
|
51,315 |
|
|
|
|
681,901 |
|
|
|
684,225 |
|
|
|
$ |
1,628,764 |
|
|
$ |
1,610,119 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
222 |
|
|
$ |
34 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
59,462 |
|
|
|
70,455 |
|
Other
|
|
|
14,823 |
|
|
|
4,812 |
|
Notes payable
to associated companies
|
|
|
107,265 |
|
|
|
111,242 |
|
Accrued
taxes
|
|
|
23,259 |
|
|
|
24,433 |
|
Lease market
valuation liability
|
|
|
36,900 |
|
|
|
36,900 |
|
Other
|
|
|
54,397 |
|
|
|
22,489 |
|
|
|
|
296,328 |
|
|
|
270,365 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
$5 par value, authorized 60,000,000 shares -
|
|
|
|
|
|
|
|
|
29,402,054
shares outstanding
|
|
|
147,010 |
|
|
|
147,010 |
|
Other paid-in
capital
|
|
|
175,866 |
|
|
|
175,879 |
|
Accumulated
other comprehensive loss
|
|
|
(34,029 |
) |
|
|
(33,372 |
) |
Retained
earnings
|
|
|
191,523 |
|
|
|
190,533 |
|
Total common
stockholder's equity
|
|
|
480,370 |
|
|
|
480,050 |
|
Noncontrolling
interest
|
|
|
2,676 |
|
|
|
2,675 |
|
Total
equity
|
|
|
483,046 |
|
|
|
482,725 |
|
Long-term debt
and other long-term obligations
|
|
|
303,021 |
|
|
|
299,626 |
|
|
|
|
786,067 |
|
|
|
782,351 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
77,016 |
|
|
|
78,905 |
|
Accumulated
deferred investment tax credits
|
|
|
6,695 |
|
|
|
6,804 |
|
Lease market
valuation liability
|
|
|
263,875 |
|
|
|
273,100 |
|
Retirement
benefits
|
|
|
74,911 |
|
|
|
73,106 |
|
Asset
retirement obligations
|
|
|
30,719 |
|
|
|
30,213 |
|
Lease
assignment payable to associated companies
|
|
|
30,529 |
|
|
|
30,529 |
|
Other
|
|
|
62,624 |
|
|
|
64,746 |
|
|
|
|
546,369 |
|
|
|
557,403 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
1,628,764 |
|
|
$ |
1,610,119 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
The Toledo Edison Company are an integral
|
|
part of these
balance sheets.
|
|
|
|
|
|
|
|
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
992 |
|
|
$ |
17,017 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
|
7,572 |
|
|
|
9,025 |
|
Amortization
of regulatory assets, net
|
|
|
9,897 |
|
|
|
15,531 |
|
Purchased
power cost recovery reconciliation
|
|
|
2,912 |
|
|
|
- |
|
Deferred rents
and lease market valuation liability
|
|
|
6,141 |
|
|
|
6,099 |
|
Deferred
income taxes and investment tax credits, net
|
|
|
(2,151 |
) |
|
|
(3,404 |
) |
Accrued
compensation and retirement benefits
|
|
|
397 |
|
|
|
(1,813 |
) |
Accrued
regulatory obligations
|
|
|
4,450 |
|
|
|
- |
|
Electric
service prepayment programs
|
|
|
(1,240 |
) |
|
|
(2,670 |
) |
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(8,395 |
) |
|
|
45,738 |
|
Prepayments
and other current assets
|
|
|
492 |
|
|
|
181 |
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
9,018 |
|
|
|
(174,243 |
) |
Accrued
taxes
|
|
|
(4,904 |
) |
|
|
6,840 |
|
Accrued
interest
|
|
|
4,613 |
|
|
|
4,663 |
|
Other
|
|
|
1,465 |
|
|
|
989 |
|
Net cash
provided from (used for) operating activities
|
|
|
31,259 |
|
|
|
(76,047 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
- |
|
|
|
52,821 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(181 |
) |
|
|
(9 |
) |
Short-term
borrowings, net
|
|
|
(3,977 |
) |
|
|
- |
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(10,000 |
) |
|
|
(15,000 |
) |
Other
|
|
|
(39 |
) |
|
|
- |
|
Net cash
provided from (used for) financing activities
|
|
|
(14,197 |
) |
|
|
37,812 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(12,233 |
) |
|
|
(19,435 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(21,528 |
) |
|
|
46,789 |
|
Redemption of
lessor notes
|
|
|
18,358 |
|
|
|
11,989 |
|
Sales of
investment securities held in trusts
|
|
|
44,270 |
|
|
|
3,908 |
|
Purchases of
investment securities held in trusts
|
|
|
(44,856 |
) |
|
|
(4,715 |
) |
Other
|
|
|
(1,072 |
) |
|
|
(110 |
) |
Net cash
provided from (used for) investing activities
|
|
|
(17,061 |
) |
|
|
38,426 |
|
|
|
|
|
|
|
|
|
|
Net change
in cash and cash equivalents
|
|
|
1 |
|
|
|
191 |
|
Cash and cash
equivalents at beginning of period
|
|
|
14 |
|
|
|
22 |
|
Cash and cash
equivalents at end of period
|
|
$ |
15 |
|
|
$ |
213 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
The Toledo Edison Company are an
|
|
integral part
of these statements.
|
|
|
|
|
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
JCP&L is a
wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
business in New Jersey, providing regulated electric transmission and
distribution services. JCP&L also provides generation services to franchise
customers electing to retain JCP&L as their power supplier. JCP&L
procures electric supply to serve its BGS customers through a statewide auction
process approved by the NJBPU.
Results of
Operations
Net income for the
first three months of 2009 decreased to $28 million from $34 million in the same
period in 2008. The decrease was primarily due to lower revenues and higher
other operating costs, partially offset by lower purchased power costs and
reduced amortization of regulatory assets.
Revenues
In the first three
months of 2009, revenues decreased by $21 million, or 3%, compared
to the same period of 2008. A $31 million increase in retail generation revenues
was more than offset by a $47 million decrease in wholesale revenues in the
first three months of 2009.
Retail generation
revenues from all customer classes increased in the first three months of 2009
compared to the same period of 2008 due to higher unit prices resulting from the
BGS auction effective June 1, 2008, partially offset by a decrease in
retail generation KWH sales to commercial customers. Sales volume to the
commercial sector decreased primarily due to an increase in the number of
customers procuring generation from other suppliers.
Wholesale generation
revenues decreased $47 million in the first
three months of 2009 due to lower market prices and a decrease in sales volume
(from NUG purchases) as compared to the first three months of 2008.
Changes in retail
generation KWH sales and revenues by customer class in the first three months of
2009 compared to the same period of 2008 are summarized in the following
tables:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
0.1
|
%
|
Commercial
|
|
|
(7.0
|
)%
|
Industrial
|
|
|
2.9
|
%
|
Net
Decrease in Generation Sales
|
|
|
(2.7
|
)%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
30
|
|
Commercial
|
|
|
1
|
|
Industrial
|
|
|
-
|
|
Increase
in Generation Revenues
|
|
$
|
31
|
|
Distribution
revenues decreased by $1 million in the first three months of 2009 compared to
the same period of 2008, reflecting lower KWH deliveries to commercial and
industrial customers as a result of weakened economic conditions in JCP&L’s
service territory. The decrease in KWH deliveries was partially offset by an
increase in composite unit prices.
Changes in
distribution KWH deliveries and revenues by customer class in the first three
months of 2009 compared to the same period in 2008 are summarized in the
following tables:
|
|
Increase
|
|
Distribution
KWH Deliveries
|
|
(Decrease)
|
|
|
|
|
|
|
|
Residential
|
|
|
|
-
|
%
|
Commercial
|
|
|
|
(2.4
|
)%
|
Industrial
|
|
|
|
(11.4
|
)%
|
Decrease
in Distribution Deliveries
|
|
|
|
(2.5
|
)%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
Commercial
|
|
|
(2
|
)
|
Industrial
|
|
|
(1
|
)
|
Net
Decrease in Distribution Revenues
|
|
$
|
(1
|
)
|
Expenses
Total expenses
decreased by $11 million in the first three months of 2009 compared to the
same period of 2008. The following table presents changes from the prior year
period by expense category:
Expenses -
Changes
|
|
|
Increase
(Decrease)
|
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
|
$
|
(15
|
)
|
Other
operating costs
|
|
|
|
7
|
|
Provision for
depreciation
|
|
|
|
2
|
|
Amortization
of regulatory assets
|
|
|
|
(5
|
)
|
Net
Decrease in Expenses
|
|
|
$
|
(11
|
)
|
Purchased power
costs decreased in the first three months of 2009 primarily due to lower KWH
purchases to meet the lower demand, partially offset by higher unit prices from
the BGS auction effective June 1, 2008. Other operating costs increased in
the first three months of 2009 primarily due to higher expenses related to
employee benefits and customer assistance programs, partially offset by lower
contracting and labor expenses. Depreciation expense increased primarily due to
an increase in depreciable property since the first quarter of 2008.
Amortization of regulatory assets decreased in the first three months of 2009
primarily due to the full recovery of certain regulatory assets in June
2008.
Other Expenses
Other expenses
increased by $2 million in the first
three months of 2009 compared to the same period in 2008 primarily due to
interest expense associated with JCP&L’s $300 million Senior Notes
issuance in January 2009.
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of other legal proceedings applicable to JCP&L.
New Accounting Standards and
Interpretations
See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
JCP&L.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of Jersey
Central Power & Light Company:
We have reviewed the
accompanying consolidated balance sheet of Jersey Central Power & Light
Company and its subsidiaries as of March 31, 2009 and the related consolidated
statements of income, comprehensive income and cash flows for each of the
three-month periods ended March 31, 2009 and 2008. These interim financial
statements are the responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated balance sheet
information as of December 31, 2008, is fairly stated in all material respects
in relation to the consolidated balance sheet from which it has been
derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
760,920 |
|
|
$ |
781,433 |
|
Excise tax
collections
|
|
|
12,731 |
|
|
|
12,795 |
|
Total
revenues
|
|
|
773,651 |
|
|
|
794,228 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
481,241 |
|
|
|
496,681 |
|
Other
operating costs
|
|
|
85,870 |
|
|
|
78,784 |
|
Provision for
depreciation
|
|
|
25,103 |
|
|
|
23,282 |
|
Amortization
of regulatory assets
|
|
|
86,831 |
|
|
|
91,519 |
|
General
taxes
|
|
|
17,496 |
|
|
|
17,028 |
|
Total
expenses
|
|
|
696,541 |
|
|
|
707,294 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
77,110 |
|
|
|
86,934 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense)
|
|
|
805 |
|
|
|
(389 |
) |
Interest
expense
|
|
|
(27,868 |
) |
|
|
(24,464 |
) |
Capitalized
interest
|
|
|
62 |
|
|
|
276 |
|
Total other
expense
|
|
|
(27,001 |
) |
|
|
(24,577 |
) |
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
50,109 |
|
|
|
62,357 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
22,551 |
|
|
|
28,403 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
27,558 |
|
|
|
33,954 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
4,121 |
|
|
|
(3,449 |
) |
Unrealized
gain on derivative hedges
|
|
|
69 |
|
|
|
69 |
|
Other
comprehensive income (loss)
|
|
|
4,190 |
|
|
|
(3,380 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
1,430 |
|
|
|
(1,470 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
2,760 |
|
|
|
(1,910 |
) |
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
30,318 |
|
|
$ |
32,044 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company
|
|
are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
4 |
|
|
$ |
66 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,415,000 and $3,230,000
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
315,084 |
|
|
|
340,485 |
|
Associated
companies
|
|
|
116 |
|
|
|
265 |
|
Other
|
|
|
35,941 |
|
|
|
37,534 |
|
Notes
receivable - associated companies
|
|
|
91,362 |
|
|
|
16,254 |
|
Prepaid
taxes
|
|
|
4,243 |
|
|
|
10,492 |
|
Other
|
|
|
21,006 |
|
|
|
18,066 |
|
|
|
|
467,756 |
|
|
|
423,162 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
4,337,711 |
|
|
|
4,307,556 |
|
Less -
Accumulated provision for depreciation
|
|
|
1,562,417 |
|
|
|
1,551,290 |
|
|
|
|
2,775,294 |
|
|
|
2,756,266 |
|
Construction
work in progress
|
|
|
69,806 |
|
|
|
77,317 |
|
|
|
|
2,845,100 |
|
|
|
2,833,583 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear fuel
disposal trust
|
|
|
189,784 |
|
|
|
181,468 |
|
Nuclear plant
decommissioning trusts
|
|
|
136,783 |
|
|
|
143,027 |
|
Other
|
|
|
2,154 |
|
|
|
2,145 |
|
|
|
|
328,721 |
|
|
|
326,640 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,810,936 |
|
|
|
1,810,936 |
|
Regulatory
assets
|
|
|
1,162,132 |
|
|
|
1,228,061 |
|
Other
|
|
|
28,487 |
|
|
|
29,946 |
|
|
|
|
3,001,555 |
|
|
|
3,068,943 |
|
|
|
$ |
6,643,132 |
|
|
$ |
6,652,328 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
29,465 |
|
|
$ |
29,094 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
- |
|
|
|
121,380 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
22,562 |
|
|
|
12,821 |
|
Other
|
|
|
158,972 |
|
|
|
198,742 |
|
Accrued
taxes
|
|
|
53,998 |
|
|
|
20,561 |
|
Accrued
interest
|
|
|
30,446 |
|
|
|
9,197 |
|
Other
|
|
|
129,745 |
|
|
|
133,091 |
|
|
|
|
425,188 |
|
|
|
524,886 |
|
CAPITALIZATION
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
$10 par value, authorized 16,000,000 shares-
|
|
|
|
|
|
|
|
|
13,628,447
shares outstanding
|
|
|
136,284 |
|
|
|
144,216 |
|
Other paid-in
capital
|
|
|
2,502,594 |
|
|
|
2,644,756 |
|
Accumulated
other comprehensive loss
|
|
|
(213,778 |
) |
|
|
(216,538 |
) |
Retained
earnings
|
|
|
121,134 |
|
|
|
156,576 |
|
Total common
stockholder's equity
|
|
|
2,546,234 |
|
|
|
2,729,010 |
|
Long-term debt
and other long-term obligations
|
|
|
1,824,851 |
|
|
|
1,531,840 |
|
|
|
|
4,371,085 |
|
|
|
4,260,850 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Power purchase
contract liability
|
|
|
530,538 |
|
|
|
531,686 |
|
Accumulated
deferred income taxes
|
|
|
664,388 |
|
|
|
689,065 |
|
Nuclear fuel
disposal costs
|
|
|
196,260 |
|
|
|
196,235 |
|
Asset
retirement obligations
|
|
|
96,839 |
|
|
|
95,216 |
|
Retirement
benefits
|
|
|
185,265 |
|
|
|
190,182 |
|
Other
|
|
|
173,569 |
|
|
|
164,208 |
|
|
|
|
1,846,859 |
|
|
|
1,866,592 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
6,643,132 |
|
|
$ |
6,652,328 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company are an integral
|
|
part of these
balance sheets.
|
|
|
|
|
|
|
|
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
27,558 |
|
|
$ |
33,954 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
25,103 |
|
|
|
23,282 |
|
Amortization
of regulatory assets
|
|
|
86,831 |
|
|
|
91,519 |
|
Deferred
purchased power and other costs
|
|
|
(28,369 |
) |
|
|
(23,893 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(6,408 |
) |
|
|
723 |
|
Accrued
compensation and retirement benefits
|
|
|
(7,481 |
) |
|
|
(15,113 |
) |
Cash
collateral returned to suppliers
|
|
|
(209 |
) |
|
|
(502 |
) |
Decrease
(increase) in operating assets:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
27,143 |
|
|
|
48,733 |
|
Materials and
supplies
|
|
|
- |
|
|
|
255 |
|
Prepaid
taxes
|
|
|
6,249 |
|
|
|
(290 |
) |
Other current
assets
|
|
|
(1,457 |
) |
|
|
(1,305 |
) |
Increase
(decrease) in operating liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(30,029 |
) |
|
|
(14,511 |
) |
Accrued
taxes
|
|
|
33,114 |
|
|
|
29,844 |
|
Accrued
interest
|
|
|
21,249 |
|
|
|
17,338 |
|
Other
|
|
|
7,890 |
|
|
|
(3,098 |
) |
Net cash
provided from operating activities
|
|
|
161,184 |
|
|
|
186,936 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
299,619 |
|
|
|
- |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(150,000 |
) |
|
|
- |
|
Long-term
debt
|
|
|
(6,402 |
) |
|
|
(5,872 |
) |
Short-term
borrowings, net
|
|
|
(121,380 |
) |
|
|
(48,001 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(63,000 |
) |
|
|
(70,000 |
) |
Other
|
|
|
(2,152 |
) |
|
|
(68 |
) |
Net cash used
for financing activities
|
|
|
(43,315 |
) |
|
|
(123,941 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(37,372 |
) |
|
|
(56,047 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(75,108 |
) |
|
|
18 |
|
Sales of
investment securities held in trusts
|
|
|
115,483 |
|
|
|
56,506 |
|
Purchases of
investment securities held in trusts
|
|
|
(120,062 |
) |
|
|
(61,290 |
) |
Other
|
|
|
(872 |
) |
|
|
(2,236 |
) |
Net cash used
for investing activities
|
|
|
(117,931 |
) |
|
|
(63,049 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
(62 |
) |
|
|
(54 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
66 |
|
|
|
94 |
|
Cash and cash
equivalents at end of period
|
|
$ |
4 |
|
|
$ |
40 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company
|
|
are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
ANALYSIS
OF RESULTS OF OPERATIONS
Met-Ed is a wholly
owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in
eastern Pennsylvania, providing regulated electric transmission and distribution
services. Met-Ed also provides generation service to those customers electing to
retain Met-Ed as their power supplier. Met-Ed has a partial requirements
wholesale power sales agreement with FES, to supply a portion of each of its
default service obligations at fixed prices through 2009. This sales agreement
is renewed annually unless cancelled by either party with at least a sixty day
written notice prior to the end of the calendar year.
Results of
Operations
Net income decreased
to $17 million in the first quarter of 2009, compared to $22 million in the same
period of 2008. The decrease was primarily due to higher purchased power costs
and lower deferrals of new regulatory assets, partially offset by higher
revenues.
Revenues
Revenues increased
by $29 million, or 7.3%, in the first quarter of 2009, compared to the same
period of 2008, primarily due to higher distribution throughput revenues and
wholesale generation revenues, partially offset by a decrease in retail
generation revenues. Wholesale revenues increased by $8 million in the first
quarter of 2009, compared to the same period of 2008, due to higher capacity
prices for PJM market participants; wholesale KWH sales volume was lower in
2009.
In the first quarter
of 2009, retail generation revenues decreased $5 million due to lower KWH sales
to the commercial and industrial customer classes, partially offset by higher
KWH sales to the residential customer class with a slight increase in composite
unit prices in all customer classes. Higher KWH sales in the residential sector
were due to increased weather- related usage, reflecting an 8.1% increase in
heating degree days in the first quarter of 2009. Lower KWH sales to commercial
and industrial customers were principally due to economic conditions in Met-Ed’s
service territory.
Changes in retail
generation sales and revenues in the first quarter of 2009 compared to the same
period of 2008 are summarized in the following tables:
|
|
Increase
|
|
Retail
Generation KWH Sales
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
2.9
|
%
|
Commercial
|
|
|
(2.5
|
)%
|
Industrial
|
|
|
(12.9
|
)%
|
Net
Decrease in Retail Generation Sales
|
|
|
(2.9
|
)%
|
|
|
Increase
|
|
Retail
Generation Revenues
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
2
|
|
Commercial
|
|
|
(1
|
)
|
Industrial
|
|
|
(6
|
)
|
Net
Decrease in Retail Generation Revenues
|
|
$
|
(5
|
)
|
In the first quarter
of 2009, distribution throughput revenues increased $22 million primarily due to
higher transmission rates, resulting from the annual update of Met-Ed’s TSC
rider effective June 1, 2008. Decreased deliveries to commercial and industrial
customers, reflecting the weakened economy, were partially offset by increased
deliveries to residential customers as a result of the weather conditions
described above.
Changes in
distribution KWH deliveries and revenues in the first quarter of 2009 compared
to the same period of 2008 are summarized in the following tables:
|
|
Increase
|
|
Distribution
KWH Deliveries
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
2.9
|
%
|
Commercial
|
|
|
(2.5
|
)%
|
Industrial
|
|
|
(12.9
|
)%
|
Net
Decrease in Distribution Deliveries
|
|
|
(2.9
|
)%
|
Distribution
Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
14
|
|
Commercial
|
|
|
5
|
|
Industrial
|
|
|
3
|
|
Increase
in Distribution Revenues
|
|
$
|
22
|
|
PJM transmission
revenues increased by $4 million in the first
quarter of 2009 compared to the same period of 2008, primarily due to increased
revenues related to Met-Ed’s Auction Revenue Rights and Financial Transmission
Rights. Met-Ed defers the difference between transmission revenues and
transmission costs incurred, resulting in no material effect to current period
earnings.
Operating Expenses
Total operating
expenses increased by $37 million in the first quarter of 2009 compared to
the same period of 2008. The following table presents changes from the prior
year by expense category:
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
7
|
|
Other
operating costs
|
|
|
(1
|
)
|
Provision for
depreciation
|
|
|
1
|
|
Deferral of
new regulatory assets
|
|
|
30
|
|
Net
Increase in Expenses
|
|
$
|
37
|
|
Purchased power
costs increased by $7 million in the first quarter of 2009, primarily due to
higher composite unit prices partially offset by decreased KWH purchases due to
lower generation sales requirements. The deferral of new regulatory assets
decreased in the first quarter of 2009 primarily due to decreased transmission
cost deferrals reflecting lower PJM transmission service expenses and the
increased transmission revenues described above.
Other Expense
Other expense
increased in the first quarter of 2009 primarily due to a decrease in interest
deferred on regulatory assets, reflecting a lower regulatory asset base, and an
increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in
January 2009.
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to Met-Ed.
New Accounting Standards and
Interpretations
See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
Met-Ed.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of
Metropolitan Edison Company:
We have reviewed the
accompanying consolidated balance sheet of Metropolitan Edison Company and its
subsidiary as of March 31, 2009 and the related consolidated statements of
income, comprehensive income and cash flows for each of the three-month periods
ended March 31, 2009 and 2008. These interim financial statements are the
responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated balance sheet
information as of December 31, 2008, is fairly stated in all material respects
in relation to the consolidated balance sheet from which it has been
derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
409,686 |
|
|
$ |
379,608 |
|
Gross receipts
tax collections
|
|
|
19,983 |
|
|
|
20,718 |
|
Total
revenues
|
|
|
429,669 |
|
|
|
400,326 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
100,077 |
|
|
|
83,442 |
|
Purchased
power from non-affiliates
|
|
|
123,911 |
|
|
|
133,540 |
|
Other
operating costs
|
|
|
106,357 |
|
|
|
107,017 |
|
Provision for
depreciation
|
|
|
12,139 |
|
|
|
11,112 |
|
Amortization
of regulatory assets
|
|
|
35,432 |
|
|
|
35,575 |
|
Deferral of
new regulatory assets
|
|
|
(7,841 |
) |
|
|
(37,772 |
) |
General
taxes
|
|
|
21,935 |
|
|
|
21,781 |
|
Total
expenses
|
|
|
392,010 |
|
|
|
354,695 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
37,659 |
|
|
|
45,631 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
3,186 |
|
|
|
5,479 |
|
Miscellaneous
income (expense)
|
|
|
856 |
|
|
|
(309 |
) |
Interest
expense
|
|
|
(13,359 |
) |
|
|
(11,672 |
) |
Capitalized
interest
|
|
|
15 |
|
|
|
(219 |
) |
Total other
expense
|
|
|
(9,302 |
) |
|
|
(6,721 |
) |
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
28,357 |
|
|
|
38,910 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
11,735 |
|
|
|
16,675 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
16,622 |
|
|
|
22,235 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
4,553 |
|
|
|
(2,233 |
) |
Unrealized
gain on derivative hedges
|
|
|
84 |
|
|
|
84 |
|
Other
comprehensive income (loss)
|
|
|
4,637 |
|
|
|
(2,149 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
1,793 |
|
|
|
(970 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
2,844 |
|
|
|
(1,179 |
) |
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
19,466 |
|
|
$ |
21,056 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company
|
|
are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
127 |
|
|
$ |
144 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,867,000 and $3,616,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
161,613 |
|
|
|
159,975 |
|
Associated
companies
|
|
|
27,349 |
|
|
|
17,034 |
|
Other
|
|
|
17,521 |
|
|
|
19,828 |
|
Notes
receivable from associated companies
|
|
|
229,614 |
|
|
|
11,446 |
|
Prepaid
taxes
|
|
|
57,115 |
|
|
|
6,121 |
|
Other
|
|
|
5,238 |
|
|
|
1,621 |
|
|
|
|
498,577 |
|
|
|
216,169 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,093,792 |
|
|
|
2,065,847 |
|
Less -
Accumulated provision for depreciation
|
|
|
784,064 |
|
|
|
779,692 |
|
|
|
|
1,309,728 |
|
|
|
1,286,155 |
|
Construction
work in progress
|
|
|
19,087 |
|
|
|
32,305 |
|
|
|
|
1,328,815 |
|
|
|
1,318,460 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
217,476 |
|
|
|
226,139 |
|
Other
|
|
|
975 |
|
|
|
976 |
|
|
|
|
218,451 |
|
|
|
227,115 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
416,499 |
|
|
|
416,499 |
|
Regulatory
assets
|
|
|
489,680 |
|
|
|
412,994 |
|
Power purchase
contract asset
|
|
|
248,762 |
|
|
|
300,141 |
|
Other
|
|
|
37,231 |
|
|
|
31,031 |
|
|
|
|
1,192,172 |
|
|
|
1,160,665 |
|
|
|
$ |
3,238,015 |
|
|
$ |
2,922,409 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
128,500 |
|
|
$ |
28,500 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
- |
|
|
|
15,003 |
|
Other
|
|
|
250,000 |
|
|
|
250,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
29,764 |
|
|
|
28,707 |
|
Other
|
|
|
46,216 |
|
|
|
55,330 |
|
Accrued
taxes
|
|
|
8,489 |
|
|
|
16,238 |
|
Accrued
interest
|
|
|
11,557 |
|
|
|
6,755 |
|
Other
|
|
|
29,506 |
|
|
|
30,647 |
|
|
|
|
504,032 |
|
|
|
431,180 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
|
859,500 shares
outstanding
|
|
|
1,196,090 |
|
|
|
1,196,172 |
|
Accumulated
other comprehensive loss
|
|
|
(138,140 |
) |
|
|
(140,984 |
) |
Accumulated
deficit
|
|
|
(34,502 |
) |
|
|
(51,124 |
) |
Total common
stockholder's equity
|
|
|
1,023,448 |
|
|
|
1,004,064 |
|
Long-term debt
and other long-term obligations
|
|
|
713,782 |
|
|
|
513,752 |
|
|
|
|
1,737,230 |
|
|
|
1,517,816 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
390,448 |
|
|
|
387,757 |
|
Accumulated
deferred investment tax credits
|
|
|
7,653 |
|
|
|
7,767 |
|
Nuclear fuel
disposal costs
|
|
|
44,334 |
|
|
|
44,328 |
|
Asset
retirement obligations
|
|
|
171,561 |
|
|
|
170,999 |
|
Retirement
benefits
|
|
|
144,459 |
|
|
|
145,218 |
|
Power purchase
contract liability
|
|
|
172,520 |
|
|
|
150,324 |
|
Other
|
|
|
65,778 |
|
|
|
67,020 |
|
|
|
|
996,753 |
|
|
|
973,413 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
3,238,015 |
|
|
$ |
2,922,409 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are an integral
|
|
part of these
balance sheets.
|
|
|
|
|
|
|
|
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
16,622 |
|
|
$ |
22,235 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
12,139 |
|
|
|
11,112 |
|
Amortization
of regulatory assets
|
|
|
35,432 |
|
|
|
35,575 |
|
Deferred costs
recoverable as regulatory assets
|
|
|
(19,633 |
) |
|
|
(10,628 |
) |
Deferral of
new regulatory assets
|
|
|
(7,841 |
) |
|
|
(37,772 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
4,657 |
|
|
|
17,307 |
|
Accrued
compensation and retirement benefits
|
|
|
1,029 |
|
|
|
(9,655 |
) |
Cash
collateral to suppliers
|
|
|
(9,500 |
) |
|
|
- |
|
Increase in
operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(9,860 |
) |
|
|
(30,863 |
) |
Prepayments
and other current assets
|
|
|
(50,422 |
) |
|
|
(41,088 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(8,058 |
) |
|
|
(14,196 |
) |
Accrued
taxes
|
|
|
(7,749 |
) |
|
|
(14,519 |
) |
Accrued
interest
|
|
|
4,803 |
|
|
|
281 |
|
Other
|
|
|
2,460 |
|
|
|
3,892 |
|
Net cash used
for operating activities
|
|
|
(35,921 |
) |
|
|
(68,319 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
300,000 |
|
|
|
- |
|
Short-term
borrowings, net
|
|
|
- |
|
|
|
131,743 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
(28,500 |
) |
Short-term
borrowings, net
|
|
|
(15,003 |
) |
|
|
- |
|
Other
|
|
|
(2,150 |
) |
|
|
(15 |
) |
Net cash
provided from financing activities
|
|
|
282,847 |
|
|
|
103,228 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(25,922 |
) |
|
|
(31,296 |
) |
Sales of
investment securities held in trusts
|
|
|
27,800 |
|
|
|
40,513 |
|
Purchases of
investment securities held in trusts
|
|
|
(29,821 |
) |
|
|
(43,391 |
) |
Loans to
associated companies, net
|
|
|
(218,168 |
) |
|
|
(254 |
) |
Other
|
|
|
(832 |
) |
|
|
(484 |
) |
Net cash used
for investing activities
|
|
|
(246,943 |
) |
|
|
(34,912 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
(17 |
) |
|
|
(3 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
144 |
|
|
|
135 |
|
Cash and cash
equivalents at end of period
|
|
$ |
127 |
|
|
$ |
132 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are
|
|
an integral
part of these statements.
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
ANALYSIS
OF RESULTS OF OPERATIONS
Penelec is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts business in
northern and south central Pennsylvania, providing regulated transmission and
distribution services. Penelec also provides generation services to those
customers electing to retain Penelec as their power supplier. Penelec has a
partial requirements wholesale power sales agreement with FES, to supply a
portion of each of its default service obligations at fixed prices through 2009.
This sales agreement is renewed annually unless cancelled by either party with
at least a sixty day written notice prior to the end of the calendar
year.
Results of
Operations
Net income decreased
to $19 million in the first quarter of 2009, compared to $21 million in the same
period of 2008. The decrease was primarily due to lower revenues, partially
offset by an increase in the deferral of new regulatory assets.
Revenues
Revenues decreased
by $7 million, or 1.7%, in the first quarter of 2009 as compared to the same
period of 2008, primarily due to lower retail generation revenues and PJM
transmission revenues, partially offset by increased distribution throughput
revenues and wholesale generation revenues. Wholesale generation revenues
increased $7 million in the first quarter of 2009 as compared to the same period
of 2008, primarily reflecting higher PJM capacity prices.
In the first quarter
of 2009, retail generation revenues decreased $8 million primarily due to lower
KWH sales to the commercial and industrial customer classes due to weakened
economic conditions, partially offset by a slight increase in KWH sales to the
residential customer class.
Changes in retail
generation sales and revenues in the first quarter of 2009 compared to the same
period of 2008 are summarized in the following tables:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
0.4
|
%
|
Commercial
|
|
|
(3.2
|
)
%
|
Industrial
|
|
|
(13.9
|
)
%
|
Net
Decrease in Retail Generation Sales
|
|
|
(4.9
|
)
%
|
Retail
Generation Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
-
|
|
Commercial
|
|
|
(2
|
)
|
Industrial
|
|
|
(6
|
)
|
Decrease
in Retail Generation Revenues
|
|
$
|
(8
|
)
|
Revenues from
distribution throughput increased $5 million in the first quarter of 2009
compared to the same period of 2008, primarily due to an increase in
transmission rates, resulting from the annual update of Penelec’s TSC rider
effective June 1, 2008, and a slight increase in usage in the residential
sector. Partially offsetting this increase was lower usage in the commercial and
industrial sectors, reflecting economic conditions in Penelec’s service
territory.
Changes in
distribution KWH deliveries and revenues in the first quarter of 2009 compared
to the same period of 2008 are summarized in the following tables:
Distribution
KWH Deliveries
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
0.4
|
%
|
Commercial
|
|
|
(3.2
|
)
%
|
Industrial
|
|
|
(12.0
|
)
%
|
Net
Decrease in Distribution Deliveries
|
|
|
(4.6
|
)
%
|
Distribution
Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
4
|
|
Commercial
|
|
|
1
|
|
Industrial
|
|
|
-
|
|
Increase
in Distribution Revenues
|
|
$
|
5
|
|
PJM transmission
revenues decreased by $13 million in the first quarter of 2009 compared to the
same period of 2008, primarily due to lower revenues related to Penelec’s
Financial Transmission Rights. Penelec defers the difference between
transmission revenues and transmission costs incurred, resulting in no material
effect to current period earnings.
Operating Expenses
Total operating
expenses increased by $5 million in the first quarter of 2009 as compared with
the same period of 2008. The following table presents changes from the prior
year by expense category:
Expenses
– Changes
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Purchased
power costs
|
|
$
|
2
|
|
Other
operating costs
|
|
|
6
|
|
Provision for
depreciation
|
|
|
2
|
|
Deferral of
new regulatory assets
|
|
|
(4
|
)
|
General
taxes
|
|
|
(1
|
)
|
Net
Increase in Expenses
|
|
$
|
5
|
|
Purchased power
costs increased by $2 million, or 0.9%, in the first quarter of 2009 compared to
the same period of 2008, primarily due to increased composite unit prices,
partially offset by reduced volume as a result of lower KWH sales requirements.
Other operating costs increased by $6 million in the first quarter of 2009
primarily due to higher employee benefit expenses. Depreciation expense
increased $2 million in the first quarter of 2009 primarily due to an increase
in depreciable property in service since the first quarter of
2008. The deferral of new regulatory assets increased $4 million in
the first quarter of 2009 primarily due to an increase in transmission cost
deferrals as a result of increased net congestion costs.
Other Income
In the first quarter
of 2009, other income increased primarily due to lower interest expense on
reduced borrowings from the regulated money pool.
Legal
Proceedings
See the “Regulatory
Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within
the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for
discussion of legal proceedings applicable to Penelec.
New Accounting Standards and
Interpretations
See the “New
Accounting Standards and Interpretations” section within the Combined
Management’s Discussion and Analysis of Registrant Subsidiaries for discussion
of new accounting standards and interpretations applicable to
Penelec.
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of
Pennsylvania Electric Company:
We have reviewed the
accompanying consolidated balance sheet of Pennsylvania Electric Company and its
subsidiaries as of March 31, 2009 and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2009 and 2008. These interim financial statements are
the responsibility of the Company’s management.
We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of December
31, 2008, and the related consolidated statements of income, capitalization,
common stockholder's equity, and cash flows for the year then ended (not
presented herein), and in our report dated February 24, 2009, we expressed an
unqualified opinion on those consolidated financial statements. In our opinion,
the information set forth in the accompanying consolidated balance sheet
information as of December 31, 2008, is fairly stated in all material respects
in relation to the consolidated balance sheet from which it has been
derived.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
May 7,
2009
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
371,293 |
|
|
$ |
376,028 |
|
Gross receipts
tax collections
|
|
|
17,292 |
|
|
|
19,464 |
|
Total
revenues
|
|
|
388,585 |
|
|
|
395,492 |
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
96,081 |
|
|
|
83,464 |
|
Purchased
power from non-affiliates
|
|
|
127,166 |
|
|
|
137,770 |
|
Other
operating costs
|
|
|
77,289 |
|
|
|
71,077 |
|
Provision for
depreciation
|
|
|
14,455 |
|
|
|
12,516 |
|
Amortization
of regulatory assets
|
|
|
16,141 |
|
|
|
16,346 |
|
Deferral of
new regulatory assets
|
|
|
(7,365 |
) |
|
|
(3,526 |
) |
General
taxes
|
|
|
20,593 |
|
|
|
21,855 |
|
Total
expenses
|
|
|
344,360 |
|
|
|
339,502 |
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
44,225 |
|
|
|
55,990 |
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense)
|
|
|
798 |
|
|
|
(191 |
) |
Interest
expense
|
|
|
(13,233 |
) |
|
|
(15,322 |
) |
Capitalized
interest
|
|
|
22 |
|
|
|
(806 |
) |
Total other
expense
|
|
|
(12,413 |
) |
|
|
(16,319 |
) |
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
31,812 |
|
|
|
39,671 |
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
13,122 |
|
|
|
18,279 |
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
18,690 |
|
|
|
21,392 |
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
2,955 |
|
|
|
(3,473 |
) |
Unrealized
gain on derivative hedges
|
|
|
16 |
|
|
|
16 |
|
Change in
unrealized gain on available-for-sale securities
|
|
|
(22 |
) |
|
|
11 |
|
Other
comprehensive income (loss)
|
|
|
2,949 |
|
|
|
(3,446 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
1,055 |
|
|
|
(1,506 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
1,894 |
|
|
|
(1,940 |
) |
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
20,584 |
|
|
$ |
19,452 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Pennsylvania Electric Company
|
|
are an
integral part of these statements.
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
March
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
13 |
|
|
$ |
23 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,285,000 and $3,121,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
140,783 |
|
|
|
146,831 |
|
Associated
companies
|
|
|
80,387 |
|
|
|
65,610 |
|
Other
|
|
|
19,493 |
|
|
|
26,766 |
|
Notes
receivable from associated companies
|
|
|
15,198 |
|
|
|
14,833 |
|
Prepaid
taxes
|
|
|
66,392 |
|
|
|
16,310 |
|
Other
|
|
|
1,142 |
|
|
|
1,517 |
|
|
|
|
323,408 |
|
|
|
271,890 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,345,475 |
|
|
|
2,324,879 |
|
Less -
Accumulated provision for depreciation
|
|
|
873,677 |
|
|
|
868,639 |
|
|
|
|
1,471,798 |
|
|
|
1,456,240 |
|
Construction
work in progress
|
|
|
25,042 |
|
|
|
25,146 |
|
|
|
|
1,496,840 |
|
|
|
1,481,386 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
113,265 |
|
|
|
115,292 |
|
Non-utility
generation trusts
|
|
|
117,899 |
|
|
|
116,687 |
|
Other
|
|
|
289 |
|
|
|
293 |
|
|
|
|
231,453 |
|
|
|
232,272 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
768,628 |
|
|
|
768,628 |
|
Power purchase
contract asset
|
|
|
78,226 |
|
|
|
119,748 |
|
Other
|
|
|
15,308 |
|
|
|
18,658 |
|
|
|
|
862,162 |
|
|
|
907,034 |
|
|
|
$ |
2,913,863 |
|
|
$ |
2,892,582 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
145,000 |
|
|
$ |
145,000 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
112,034 |
|
|
|
31,402 |
|
Other
|
|
|
250,000 |
|
|
|
250,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
49,981 |
|
|
|
63,692 |
|
Other
|
|
|
42,004 |
|
|
|
48,633 |
|
Accrued
taxes
|
|
|
4,053 |
|
|
|
13,264 |
|
Accrued
interest
|
|
|
13,730 |
|
|
|
13,131 |
|
Other
|
|
|
26,591 |
|
|
|
31,730 |
|
|
|
|
643,393 |
|
|
|
596,852 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
$20 par value, authorized 5,400,000 shares-
|
|
|
|
|
|
|
|
|
4,427,577
shares outstanding
|
|
|
88,552 |
|
|
|
88,552 |
|
Other paid-in
capital
|
|
|
912,380 |
|
|
|
912,441 |
|
Accumulated
other comprehensive loss
|
|
|
(126,103 |
) |
|
|
(127,997 |
) |
Retained
earnings
|
|
|
94,803 |
|
|
|
76,113 |
|
Total common
stockholder's equity
|
|
|
969,632 |
|
|
|
949,109 |
|
Long-term debt
and other long-term obligations
|
|
|
633,355 |
|
|
|
633,132 |
|
|
|
|
1,602,987 |
|
|
|
1,582,241 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
48,847 |
|
|
|
136,579 |
|
Accumulated
deferred income taxes
|
|
|
183,906 |
|
|
|
169,807 |
|
Retirement
benefits
|
|
|
172,544 |
|
|
|
172,718 |
|
Asset
retirement obligations
|
|
|
87,395 |
|
|
|
87,089 |
|
Power purchase
contract liability
|
|
|
112,462 |
|
|
|
83,600 |
|
Other
|
|
|
62,329 |
|
|
|
63,696 |
|
|
|
|
667,483 |
|
|
|
713,489 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
2,913,863 |
|
|
$ |
2,892,582 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Pennsylvania Electric Company
|
|
are an
integral part of these balance sheets.
|
|
|
|
|
|
|
|
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
March
31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
18,690 |
|
|
$ |
21,392 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
14,455 |
|
|
|
12,516 |
|
Amortization
of regulatory assets
|
|
|
16,141 |
|
|
|
16,346 |
|
Deferral of
new regulatory assets
|
|
|
(7,365 |
) |
|
|
(3,526 |
) |
Deferred costs
recoverable as regulatory assets
|
|
|
(20,022 |
) |
|
|
(8,403 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
11,833 |
|
|
|
10,541 |
|
Accrued
compensation and retirement benefits
|
|
|
431 |
|
|
|
(10,488 |
) |
Cash
collateral
|
|
|
- |
|
|
|
301 |
|
Increase in
operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(1,709 |
) |
|
|
(13,701 |
) |
Prepayments
and other current assets
|
|
|
(49,707 |
) |
|
|
(40,591 |
) |
Increase
(Decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(5,340 |
) |
|
|
(3,144 |
) |
Accrued
taxes
|
|
|
(9,065 |
) |
|
|
(5,809 |
) |
Accrued
interest
|
|
|
599 |
|
|
|
510 |
|
Other
|
|
|
(988 |
) |
|
|
4,991 |
|
Net cash used
for operating activities
|
|
|
(32,047 |
) |
|
|
(19,065 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
80,632 |
|
|
|
118,209 |
|
Redemptions
and Repayments
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
(45,112 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(15,000 |
) |
|
|
(20,000 |
) |
Net cash
provided from financing activities
|
|
|
65,632 |
|
|
|
53,097 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(28,190 |
) |
|
|
(28,902 |
) |
Sales of
investment securities held in trusts
|
|
|
18,800 |
|
|
|
24,407 |
|
Purchases of
investment securities held in trusts
|
|
|
(22,108 |
) |
|
|
(29,083 |
) |
Loan
repayments to associated companies, net
|
|
|
(365 |
) |
|
|
(610 |
) |
Other
|
|
|
(1,732 |
) |
|
|
153 |
|
Net cash used
for investing activities
|
|
|
(33,595 |
) |
|
|
(34,035 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
(10 |
) |
|
|
(3 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
23 |
|
|
|
46 |
|
Cash and cash
equivalents at end of period
|
|
$ |
13 |
|
|
$ |
43 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they relate to
Pennsylvania Electric Company are
|
|
an integral
part of these statements.
|
|
|
|
|
|
|
|
|
COMBINED
MANAGEMENT’S DISCUSSION
AND
ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a
combined presentation of certain disclosures referenced in Management’s
Narrative Analysis of Results of Operations of FES and the Utilities. This
information should be read in conjunction with (i) FES’ and the Utilities’
respective Consolidated Financial Statements and Management’s Narrative Analysis
of Results of Operations; (ii) the Combined Notes to Consolidated Financial
Statements as they relate to FES and the Utilities; and (iii) FES’ and the
Utilities’ respective 2008 Annual Reports on Form 10-K.
Regulatory
Matters (Applicable to each of
the Utilities)
In Ohio, New Jersey
and Pennsylvania, laws applicable to electric industry restructuring contain
similar provisions that are reflected in the Utilities' respective state
regulatory plans. These provisions include:
·
|
restructuring
the electric generation business and allowing the Utilities' customers to
select a competitive electric generation supplier other than the
Utilities;
|
|
|
·
|
establishing
or defining the PLR obligations to customers in the Utilities' service
areas;
|
|
|
·
|
providing the
Utilities 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 Utilities' transmission and distribution systems;
and
|
|
|
·
|
requiring
corporate separation of regulated and unregulated business
activities.
|
The Utilities
recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and
the NJBPU have authorized for recovery from customers in future periods or for
which authorization is probable. Without the probability of such authorization,
costs currently recorded as regulatory assets would have been charged to income
as incurred. Regulatory assets that do not earn a current return totaled
approximately $130 million as of March 31, 2009 (JCP&L -
$54 million and Met-Ed - $76 million). Regulatory assets not earning a
current return (primarily for certain regulatory transition costs and employee
postretirement benefits) are expected to be recovered by 2014 for JCP&L and
by 2020 for Met-Ed. The following table discloses regulatory assets by
company:
|
|
March
31,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets*
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
545
|
|
$
|
575
|
|
$
|
(30
|
)
|
CEI
|
|
|
618
|
|
|
784
|
|
|
(166
|
)
|
TE
|
|
|
96
|
|
|
109
|
|
|
(13
|
)
|
JCP&L
|
|
|
1,162
|
|
|
1,228
|
|
|
(66
|
)
|
Met-Ed
|
|
|
490
|
|
|
413
|
|
|
77
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
)
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec had
net regulatory liabilities of approximately $49 million
and
$137 million as of March 31, 2009 and December 31, 2008,
respectively.
These net regulatory liabilities are included in Other
Non-current
Liabilities on the Consolidated Balance
Sheets.
|
Ohio
(Applicable to OE, CEI, TE and FES)
On June 7, 2007, the
Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO and, on August 6, 2007, updated their filing to support
a distribution rate increase of $332 million. On December 4, 2007, the
PUCO Staff issued its Staff Reports containing the results of its investigation
into the distribution rate request. On January 21, 2009, the PUCO granted the
Ohio Companies’ application to increase electric distribution rates by $136.6
million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These
increases went into effect for OE and TE on January 23, 2009, and will go into
effect for CEI on May 1, 2009. Applications for rehearing of this order were
filed by the Ohio Companies and one other party on February 20, 2009. The PUCO
granted these applications for rehearing on March 18, 2009.
SB221, which became
effective on July 31, 2008, required all electric utilities to file an ESP,
and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies
filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the
MRO application; however, the PUCO later granted the Ohio Companies’ application
for rehearing for the purpose of further consideration of the matter. The ESP
proposed to phase in new generation rates for customers beginning in 2009 for up
to a three-year period and resolve the Ohio Companies’ collection of fuel costs
deferred in 2006 and 2007, and the distribution rate request described above. In
response to the PUCO’s December 19, 2008 order, which significantly modified and
approved the ESP as modified, the Ohio Companies notified the PUCO that they
were withdrawing and terminating the ESP application in addition to continuing
their current rate plan in effect as allowed by the terms of SB221. On
December 31, 2008, the Ohio Companies conducted a CBP for the procurement
of electric generation for retail customers from January 5, 2009 through March
31, 2009. The average winning bid price was equivalent to a retail rate of 6.98
cents per kwh. The power supply obtained through this process provides
generation service to the Ohio Companies’ retail customers who choose not to
shop with alternative suppliers. On January 9, 2009, the Ohio Companies
requested the implementation of a new fuel rider to recover the costs resulting
from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’
request for a new fuel rider to recover increased costs resulting from the CBP
but did not authorize OE and TE to continue collecting RTC or allow the Ohio
Companies to continue collections pursuant to the two existing fuel riders. The
new fuel rider allows for current recovery of the increased purchased power
costs for OE and TE, and authorizes CEI to collect a portion of those costs
currently and defer the remainder for future recovery.
On January 29, 2009,
the PUCO ordered its Staff to develop a proposal to establish an ESP for the
Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended
ESP application, including an attached Stipulation and Recommendation that was
signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening
parties. Specifically, the Amended ESP provides that generation will be provided
by FES at the average wholesale rate of the CBP process described above for
April and May 2009 to the Ohio Companies for their non-shopping customers; for
the period of June 1, 2009 through May 31, 2011, retail generation
prices will be based upon the outcome of a descending clock CBP on a
slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of
any increase resulting from this CBP process by authorizing deferral of related
purchased power costs, subject to specified limits. The Amended ESP further
provides that the Ohio Companies will not seek a base distribution rate
increase, subject to certain exceptions, with an effective date of such increase
before January 1, 2012, that CEI will agree to write-off approximately
$216 million of its Extended RTC balance, and that the Ohio Companies will
collect a delivery service improvement rider at an overall average rate of $.002
per kWh for the period of April 1, 2009 through December 31, 2011. The
Amended ESP also addresses a number of other issues, including but not limited
to, rate design for various customer classes, resolution of the prudence review
and the collection of deferred costs that were approved in prior proceedings. On
February 26, 2009, the Ohio Companies filed a Supplemental Stipulation,
which was signed or not opposed by virtually all of the parties to the
proceeding, that supplemented and modified certain provisions of the
February 19 Stipulation and Recommendation. Specifically, the Supplemental
Stipulation modified the provision relating to governmental aggregation and the
Generation Service Uncollectible Rider, provided further detail on the
allocation of the economic development funding contained in the Stipulation and
Recommendation, and proposed additional provisions related to the collaborative
process for the development of energy efficiency programs, among other
provisions. The PUCO adopted and approved certain aspects of the Stipulation and
Recommendation on March 4, 2009, and adopted and approved the remainder of the
Stipulation and Recommendation and Supplemental Stipulation without modification
on March 25, 2009. Certain aspects of the Stipulation and Recommendation
and Supplemental Stipulation take effect on April 1, 2009 while the
remaining provisions take effect on June 1, 2009. The CBP auction is
currently scheduled to begin on May 13, 2009. The bidding will occur for a
single, two-year product and there will not be a load cap for the
bidders. FES may participate without limitation.
SB221 also requires
electric distribution utilities to implement energy efficiency programs that
achieve an energy savings equivalent of approximately 166,000 MWH in 2009,
290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in
2013. Utilities are also required to reduce peak demand in 2009 by one percent,
with an additional seventy-five hundredths of one percent reduction each year
thereafter through 2018. Costs associated with compliance are
recoverable from customers.
Pennsylvania
(Applicable to FES, Met-Ed, Penelec, OE and Penn)
Met-Ed and Penelec
purchase a portion of their PLR and default service requirements from FES
through a fixed-price partial requirements wholesale power sales agreement. The
agreement allows Met-Ed and Penelec to sell the output of NUG energy to the
market and requires FES to provide energy at fixed prices to replace any NUG
energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and
default service obligations. If Met-Ed and Penelec were to replace the entire
FES supply at current market power prices without corresponding regulatory
authorization to increase their generation prices to customers, each company
would likely incur a significant increase in operating expenses and experience a
material deterioration in credit quality metrics. Under such a scenario, each
company's credit profile would no longer be expected to support an investment
grade rating for their fixed income securities. If FES ultimately determines to
terminate, reduce, or significantly modify the agreement prior to the expiration
of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief
is not likely to be granted by the PPUC. See FERC Matters below for a
description of the Third Restated Partial Requirements Agreement, executed by
the parties on October 31, 2008, that limits the amount of energy and
capacity FES must supply to Met-Ed and Penelec. In the event of a third party
supplier default, the increased costs to Met-Ed and Penelec could be
material.
On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. Various intervenors filed
complaints against those filings. In addition, the PPUC ordered an investigation
to review the reasonableness of Met-Ed’s TSC, while at the same time allowing
Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15,
2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed
with its investigation and a litigation schedule was adopted. Hearings and
briefing for both Met-Ed and Penelec have concluded and the companies are
awaiting a Recommended Decision from the ALJ. The TSCs include a component from
under-recovery of actual transmission costs incurred during the prior period
(Met-Ed - $144 million and Penelec - $4 million) and future transmission
cost projections for June 2008 through May 2009 (Met-Ed - $258 million and
Penelec - $92 million). Met-Ed received PPUC approval for a transition
approach that would recover past under-recovered costs plus carrying charges
through the new TSC over thirty-one months and defer a portion of the projected
costs ($92 million) plus carrying charges for recovery through future TSCs
by December 31, 2010.
On April 15, 2009,
Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009
through May 31, 2010, as required in connection with the PPUC’s January
2007 rate order. For Penelec’s customers, the new TSC would result in an
approximate 1% decrease in monthly bills, reflecting projected PJM transmission
costs as well as a reconciliation for costs already incurred. The TSC for
Met-Ed’s customers would increase to recover the additional PJM charges paid by
Met-Ed in the previous year and to reflect updated projected costs. In order to
gradually transition customers to the higher rate, Met-Ed is proposing to
continue to recover the prior period deferrals allowed in the PPUC’s May 2008
Order and defer $57.5 million of projected costs into a future TSC to be fully
recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s
customers would increase approximately 9.4% for the period June 2009 through May
2010.
On October 15, 2008,
the Governor of Pennsylvania signed House Bill 2200 into law which became
effective on November 14, 2008 as Act 129 of 2008. The bill addresses
issues such as: energy efficiency and peak load reduction; generation
procurement; time-of-use rates; smart meters and alternative energy. Act 129
requires utilities to file with the PPUC an energy efficiency and peak load
reduction plan by July 1, 2009 and a smart meter procurement and
installation plan by August 14, 2009. On January 15, 2009, in compliance
with Act 129, the PPUC issued its proposed guidelines for the filing of
utilities’ energy efficiency and peak load reduction plans. Similar guidelines
related to Smart Meter deployment were issued for comment on March 30,
2009.
Major provisions of
the legislation include:
·
|
power acquired
by utilities to serve customers after rate caps expire will be procured
through a competitive procurement process that must include a mix of
long-term and short-term contracts and spot market
purchases;
|
·
|
the
competitive procurement process must be approved by the PPUC and may
include auctions, RFPs, and/or bilateral
agreements;
|
·
|
utilities must
provide for the installation of smart meter technology within 15
years;
|
·
|
a minimum
reduction in peak demand of 4.5% by May 31,
2013;
|
·
|
minimum
reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
2013, respectively; and
|
·
|
an expanded
definition of alternative energy to include additional types of
hydroelectric and biomass
facilities.
|
Legislation
addressing rate mitigation and the expiration of rate caps was not enacted in
2008; however, several bills addressing these issues have been introduced in the
current legislative session, which began in January 2009. The final
form and impact of such legislation is uncertain.
On February 26,
2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and
Penelec that provides an opportunity for residential and small commercial
customers to prepay an amount on their monthly electric bills during 2009 and
2010. Customer prepayments earn interest at 7.5% and will be used to reduce
electricity charges in 2011 and 2012.
On February 20,
2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan
covering the period January 1, 2011 through May 31, 2013. The
companies’ plan is designed to provide adequate and reliable service via a
prudent mix of long-term, short-term and spot market generation supply, as
required by Act 129. The plan proposes a staggered procurement schedule,
which varies by customer class, through the use of a descending clock auction.
Met-Ed and Penelec have requested PPUC approval of their plan by November
2009.
On March 31, 2009,
Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the
PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to
reduce its CTC rate for the residential class with a corresponding increase in
the generation rate and the shopping credit, and Penelec proposed to reduce its
CTC rate to zero for all classes with a corresponding increase in the generation
rate and the shopping credit. While these changes would result in additional
annual generation revenue (Met-Ed - $27 million and Penelec - $51 million),
overall rates would remain unchanged. The PPUC must act on this filing within
120 days.
New Jersey
(Applicable to JCP&L)
JCP&L is
permitted to defer for future collection from customers the amounts by which its
costs of supplying BGS to non-shopping customers, costs incurred under NUG
agreements, and certain other stranded costs, exceed amounts collected through
BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31,
2009, the accumulated deferred cost balance totaled approximately
$165 million.
In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004, supporting 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 DPA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. JCP&L responded to additional
NJBPU staff discovery requests in May and November 2007 and also submitted
comments in the proceeding in November 2007. A schedule for further NJBPU
proceedings has not yet been set. On March 13, 2009, JCP&L filed its
annual SBC Petition with the NJBPU that includes a request for a reduction in
the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2
decommissioning cost analysis dated January 2009. This matter is currently
pending before the NJBPU.
On August 1, 2005,
the NJBPU established a proceeding to determine whether additional ratepayer
protections are required at the state level in light of the repeal of the PUHCA
pursuant to the EPACT. The NJBPU approved regulations effective October 2,
2006 that prevent a holding company that owns a gas or electric public utility
from investing more than 25% of the combined assets of its utility and
utility-related subsidiaries into businesses unrelated to the utility industry.
These regulations are not expected to materially impact JCP&L. Also, in the
same proceeding, the NJBPU Staff issued an additional draft proposal on
March 31, 2006 addressing various issues including access to books and
records, ring-fencing, cross subsidization, corporate governance and related
matters. Following public hearing and consideration of comments from interested
parties, the NJBPU approved final regulations effective April 6, 2009. These
regulations are not expected to materially impact JCP&L.
New Jersey statutes
require that the state periodically undertake a planning process, known as the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President and
includes representatives of several State departments.
The EMP was issued
on October 22, 2008, establishing five major goals:
·
|
maximize
energy efficiency to achieve a 20% reduction in energy consumption by
2020;
|
·
|
reduce peak
demand for electricity by 5,700 MW by
2020;
|
·
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meet 30% of
the state’s electricity needs with renewable energy by
2020;
|
·
|
examine smart
grid technology and develop additional cogeneration and other generation
resources consistent with the state’s greenhouse gas targets;
and
|
·
|
invest in
innovative clean energy technologies and businesses to stimulate the
industry’s growth in New Jersey.
|
On January 28, 2009,
the NJBPU adopted an order establishing the general process and contents of
specific EMP plans that must be filed by December 31, 2009 by New Jersey
electric and gas utilities in order to achieve the goals of the EMP. At this
time, JCP&L cannot determine the impact, if any, the EMP may have on its
operations.
In support of the
New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced
its intent to spend approximately $98 million on infrastructure and energy
efficiency projects in 2009. An estimated $40 million will be spent on
infrastructure projects, including substation upgrades, new transformers,
distribution line re-closers and automated breaker operations. Approximately
$34 million will be spent implementing new demand response programs as well
as expanding on existing programs. Another $11 million will be spent on
energy efficiency, specifically replacing transformers and capacitor control
systems and installing new LED street lights. The remaining $13 million
will be spent on energy efficiency programs that will complement those currently
being offered. Completion of the projects is dependent upon resolution of
regulatory issues including recovery of the costs associated with plan
implementation.
FERC Matters
(Applicable to FES and each of the Utilities)
Transmission Service between MISO and
PJM
On November 18,
2004, the FERC issued an order eliminating the through and out rate for
transmission service between the MISO and PJM regions. The FERC’s intent was to
eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM, and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. Briefs addressing the initial decision were filed on
September 11, 2006 and October 20, 2006. A final order is pending before
the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and
entering into settlement agreements with other parties in the docket to mitigate
the risk of lower transmission revenue collection associated with an adverse
order. On September 26, 2008, the MISO and PJM transmission owners filed a
motion requesting that the FERC approve the pending settlements and act on the
initial decision. On November 20, 2008, FERC issued an order approving
uncontested settlements, but did not rule on the initial decision. On December
19, 2008, an additional order was issued approving two contested
settlements.
PJM Transmission Rate
On January 31, 2005,
certain PJM transmission owners made filings with the FERC pursuant to a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. Hearings were
held and numerous parties appeared and litigated various issues concerning PJM
rate design; notably AEP, which proposed to create a "postage stamp", or average
rate for all high voltage transmission facilities across PJM and a zonal
transmission rate for facilities below 345 kV. This proposal would have the
effect of shifting recovery of the costs of high voltage transmission lines to
other transmission zones, including those where JCP&L, Met-Ed, and Penelec
serve load. On April 19, 2007, the FERC issued an order finding that the PJM
transmission owners’ existing “license plate” or zonal rate design was just and
reasonable and ordered that the current license plate rates for existing
transmission facilities be retained. On the issue of rates for new transmission
facilities, the FERC directed that costs for new transmission facilities that
are rated at 500 kV or higher are to be collected from all transmission zones
throughout the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to be
allocated on a “beneficiary pays” basis. The FERC found that PJM’s current
beneficiary-pays cost allocation methodology is not sufficiently detailed and,
in a related order that also was issued on April 19, 2007, directed that
hearings be held for the purpose of establishing a just and reasonable cost
allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007 order. On
January 31, 2008, the requests for rehearing were denied. On February 11, 2008,
AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the
federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission,
the PUCO and Dayton Power & Light have also appealed these orders to the
Seventh Circuit Court of Appeals. The appeals of these parties and others have
been consolidated for argument in the Seventh Circuit. Oral argument was held on
April 13, 2009, and a decision is expected this summer.
The FERC’s orders on
PJM rate design will prevent the allocation of a portion of the revenue
requirement of existing transmission facilities of other utilities to JCP&L,
Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce the
costs of future transmission to be recovered from the JCP&L, Met-Ed and
Penelec zones. A partial settlement agreement addressing the “beneficiary pays”
methodology for below 500 kV facilities, but excluding the issue of allocating
new facilities costs to merchant transmission entities, was filed on September
14, 2007. The agreement was supported by the FERC’s Trial Staff, and was
certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued
an order conditionally approving the settlement subject to the submission of a
compliance filing. The compliance filing was submitted on August 29, 2008,
and the FERC issued an order accepting the compliance filing on October 15,
2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate
cost responsibility assignments for below 500 kV upgrades included in
PJM’s Regional Transmission Expansion Planning process in accordance with
the settlement. The FERC conditionally accepted the compliance filing on
January 28, 2009. PJM submitted a further compliance filing on March 2,
2009, which was accepted by the FERC on April 10, 2009. The remaining
merchant transmission cost allocation issues were the subject of a hearing at
the FERC in May 2008. An initial decision was issued by the Presiding Judge on
September 18, 2008. PJM and FERC trial staff each filed a Brief on
Exceptions to the initial decision on October 20, 2008. Briefs Opposing
Exceptions were filed on November 10, 2008.
Post
Transition Period Rate Design
The FERC had
directed MISO, PJM, and the respective transmission owners to make filings on or
before August 1, 2007 to reevaluate transmission rate design within MISO, and
between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the
vast majority of transmission owners, including FirstEnergy affiliates, which
proposed to retain the existing transmission rate design. These filings were
approved by the FERC on January 31, 2008. As a result of the FERC’s approval,
the rates charged to FirstEnergy’s load-serving affiliates for transmission
service over existing transmission facilities in MISO and PJM are unchanged. In
a related filing, MISO and MISO transmission owners requested that the current
MISO pricing for new transmission facilities that spreads 20% of the cost of new
345 kV and higher transmission facilities across the entire MISO footprint
(known as the RECB methodology) be retained.
On September 17,
2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act
seeking to have the entire transmission rate design and cost allocation methods
used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory,
and to have the FERC fix a uniform regional transmission rate design and cost
allocation method for the entire MISO and PJM “Super Region” that recovers the
average cost of new and existing transmission facilities operated at voltages of
345 kV and above from all transmission customers. Lower voltage facilities would
continue to be recovered in the local utility transmission rate zone through a
license plate rate. AEP requested a refund effective October 1, 2007, or
alternatively, February 1, 2008. On January 31, 2008, the FERC issued an
order denying the complaint. The effect of this order is to prevent the shift of
significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request
by AEP was denied by the FERC on December 19, 2008. On February 17, 2009,
AEP appealed the FERC’s January 31, 2008, and December 19, 2008,
orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of
its affiliated operating utility companies, filed a motion to intervene on March
10, 2009.
Duquesne’s
Request to Withdraw from PJM
On November 8, 2007,
Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and
to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy
interests, including but not limited to the terms under which FirstEnergy’s
Beaver Valley Plant would continue to participate in PJM’s energy markets.
FirstEnergy, therefore, intervened and participated fully in all of the FERC
dockets that were related to Duquesne’s proposed move.
In November, 2008,
Duquesne and other parties, including FirstEnergy, negotiated a settlement that
would, among other things, allow for Duquesne to remain in PJM and provide for a
methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012
auction that excluded the Duquesne load. The settlement agreement was filed on
December 10, 2008 and approved by the FERC in an order issued on January 29,
2009. MISO opposed the settlement agreement pending resolution of exit fees
alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in
its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January
29, 2009 order approving the settlement. Thereafter, FirstEnergy and other
parties filed in opposition to the rehearing request. The PPUC's rehearing
request, and the pleadings in opposition thereto, are pending before the
FERC.
Changes
ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30,
2008, a group of PJM load-serving entities, state commissions, consumer
advocates, and trade associations (referred to collectively as the RPM Buyers)
filed a complaint at the FERC against PJM alleging that three of the
four transitional RPM auctions yielded prices that are unjust and
unreasonable under the Federal Power Act. On September 19, 2008, the FERC
denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’
request for a technical conference to review aspects of the RPM. The FERC also
ordered PJM to file on or before December 15, 2008, a report on potential
adjustments to the RPM program as suggested in a Brattle Group report. On
December 12, 2008, PJM filed proposed tariff amendments that would adjust
slightly the RPM program. PJM also requested that the FERC conduct a settlement
hearing to address changes to the RPM and suggested that the FERC should rule on
the tariff amendments only if settlement could not be reached in January, 2009.
The request for settlement hearings was granted. Settlement had not been reached
by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted
comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief
Judge issued an order terminating settlement talks. On February 9, 2009,
PJM and a group of stakeholders submitted an offer of settlement, which used the
PJM December 12, 2008 filing as its starting point, and stated that unless
otherwise specified, provisions filed by PJM on December 12, 2008,
apply.
On March 26, 2009,
the FERC accepted in part, and rejected in part, tariff provisions submitted by
PJM, revising certain parts of its RPM. Ordered changes included making
incremental improvements to RPM; however, the basic construct of RPM remains
intact. On April 3, 2009, PJM filed with the FERC requesting clarification on
certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM
submitted a compliance filing addressing the changes the FERC ordered in the
March 26, 2009 Order; numerous parties have filed requests for rehearing of
the March 26, 2009 Order. In addition, the FERC has indefinitely postponed
the technical conference on RPM granted in the FERC order of September 19,
2008.
MISO
Resource Adequacy Proposal
MISO made a filing
on December 28, 2007 that would create an enforceable planning reserve
requirement in the MISO tariff for load-serving entities such as the Ohio
Companies, Penn Power, and FES. This requirement is proposed to become effective
for the planning year beginning June 1, 2009. The filing would permit MISO to
establish the reserve margin requirement for load-serving entities based upon a
one day loss of load in ten years standard, unless the state utility regulatory
agency establishes a different planning reserve for load-serving entities in its
state. FirstEnergy believes the proposal promotes a mechanism that will result
in commitments from both load-serving entities and resources, including both
generation and demand side resources that are necessary for reliable resource
adequacy and planning in the MISO footprint. Comments on the filing were
submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource
Adequacy proposal on March 26, 2008, requiring MISO to submit to further
compliance filings. Rehearing requests are pending on the FERC’s March 26 Order.
On May 27, 2008, MISO submitted a compliance filing to address issues associated
with planning reserve margins. On June 17, 2008, various parties submitted
comments and protests to MISO’s compliance filing. FirstEnergy submitted
comments identifying specific issues that must be clarified and addressed. On
June 25, 2008, MISO submitted a second compliance filing establishing the
enforcement mechanism for the reserve margin requirement which establishes
deficiency payments for load-serving entities that do not meet the resource
adequacy requirements. Numerous parties, including FirstEnergy, protested this
filing.
On October 20, 2008,
the FERC issued three orders essentially permitting the MISO Resource Adequacy
program to proceed with some modifications. First, the FERC accepted MISO's
financial settlement approach for enforcement of Resource Adequacy subject to a
compliance filing modifying the cost of new entry penalty. Second, the FERC
conditionally accepted MISO's compliance filing on the qualifications for
purchased power agreements to be capacity resources, load forecasting, loss of
load expectation, and planning reserve zones. Additional compliance filings were
directed on accreditation of load modifying resources and price responsive
demand. Finally, the FERC largely denied rehearing of its March 26 order with
the exception of issues related to behind the meter resources and certain
ministerial matters. On November 19, 2008, MISO made various compliance
filings pursuant to these orders. Issuance of orders on rehearing and two of the
compliance filings occurred on February 19, 2009. No material changes were made
to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an
additional order on rehearing and compliance, approving MISO’s proposed
financial settlement provision for Resource Adequacy. The MISO Resource Adequacy
process is expected to start as planned effective June 1, 2009, the beginning of
the MISO planning year.
FES Sales to Affiliates
On October 24, 2008,
FES, on its own behalf and on behalf of its generation-controlling subsidiaries,
filed an application with the FERC seeking a waiver of the affiliate sales
restrictions between FES and the Ohio Companies. The purpose of the waiver is to
ensure that FES will be able to continue supplying a material portion of the
electric load requirements of the Ohio Companies after January 1, 2009
pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained
a similar waiver for electricity sales to its affiliates in New Jersey, New
York, and Pennsylvania. On December 23, 2008, the FERC issued an order
granting the waiver request and the Ohio Companies made the required compliance
filing on December 30, 2008. In January 2009,
several parties filed for rehearing of the FERC’s December 23, 2008 order. In
response, FES filed an answer to requests for rehearing on February 5, 2009. The
requests and responses are pending before the FERC.
FES supplied all of
the power requirements for the Ohio Companies pursuant to a Power Supply
Agreement that ended on December 31, 2008. On January 2, 2009, FES
signed an agreement to provide 75% of the Ohio Companies’ power requirements for
the period January 5, 2009 through March 31, 2009. Subsequently, FES
signed an agreement to provide 100% of the Ohio Companies’ power requirements
for the period April 1, 2009 through May 31, 2009. On March 4,
2009, the PUCO issued an order approving these two affiliate sales agreements.
FERC authorization for these affiliate sales was by means of the
December 23, 2008 waiver.
On October 31, 2008,
FES executed a Third Restated Partial Requirements Agreement with Met-Ed,
Penelec, and Waverly effective November 1, 2008. The Third Restated Partial
Requirements Agreement limits the amount of capacity and energy required to be
supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’
power supply requirements. Met-Ed, Penelec, and Waverly have committed resources
in place for the balance of their expected power supply during 2009 and 2010.
Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and
Waverly are responsible for obtaining additional power supply requirements
created by the default or failure of supply of their committed resources. Prices
for the power provided by FES were not changed in the Third Restated Partial
Requirements Agreement.
Environmental
Matters
Various federal,
state and local authorities regulate FES and the Utilities with regard to air
and water quality and other environmental matters. The effects of compliance on
FES and the Utilities with regard to environmental matters could have a material
adverse effect on their earnings and competitive position to the extent that
they compete 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.
FES and the
Utilities accrue environmental liabilities only when they conclude that it is
probable that they have an obligation for such costs and can reasonably estimate
the amount of such costs. Unasserted claims are reflected in FES’ and the
Utilities’ determination of environmental liabilities and are accrued in the
period that they become both probable and reasonably estimable.
Clean Air Act Compliance
(Applicable to FES, OE, JCP&L, Met-Ed and Penelec)
FES is required to
meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in the shutdown of the
generating unit involved and/or civil or criminal penalties of up to $37,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. FES believes it is currently in compliance with this policy, but cannot
predict what action the EPA may take in the future with respect to the interim
enforcement policy.
The EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006, alleging violations to various sections of the CAA. FES has disputed
those alleged violations based on its CAA permit, the Ohio SIP and other
information provided to the EPA at an August 2006 meeting with the EPA. The EPA
has several enforcement options (administrative compliance order, administrative
penalty order, and/or judicial, civil or criminal action) and has indicated that
such option may depend on the time needed to achieve and demonstrate compliance
with the rules alleged to have been violated. On June 5, 2007, the EPA
requested another meeting to discuss “an appropriate compliance program” and a
disagreement regarding emission limits applicable to the common stack for Bay
Shore Units 2, 3 and 4.
FES complies with
SO2
reduction requirements under the Clean Air Act Amendments of 1990 by burning
lower-sulfur fuel, generating more electricity from lower-emitting plants,
and/or using emission allowances. NOX reductions
required by the 1990 Amendments are being achieved through combustion controls,
the generation of more electricity at lower-emitting plants, and/or using
emission allowances. In September 1998, the EPA finalized regulations requiring
additional NOX reductions
at FES' facilities. The EPA's NOX Transport
Rule imposes uniform reductions of NOX emissions
(an approximate 85% reduction in utility plant NOX emissions
from projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are contributing significantly to ozone levels in the eastern United States. FES
believes its facilities are also complying with the NOX budgets
established under SIPs through combustion controls and post-combustion controls,
including Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.
In 1999 and 2000,
the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn
based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR
Litigation) and filed similar complaints involving 44 other U.S. power plants.
This case and seven other similar cases are referred to as the NSR cases. OE’s
and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New
Jersey and New York) that resolved all issues related to the Sammis NSR
litigation was approved by the Court on July 11, 2005. This settlement
agreement, in the form of a consent decree, requires reductions of NOX and
SO2
emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants
through the installation of pollution control devices or repowering and provides
for stipulated penalties for failure to install and operate such pollution
controls or complete repowering in accordance with that agreement. Capital
expenditures necessary to complete requirements of the Sammis NSR Litigation
consent decree, including repowering Burger Units 4 and 5 for biomass fuel
consumption, are currently estimated to be $706 million for 2009-2012 (with
$414 million expected to be spent in 2009).
On May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal CAA, alleging violations of air
pollution laws at the Bruce Mansfield Plant, including opacity limitations.
Prior to the receipt of this notice, the Plant was subject to a Consent Order
and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with the
applicable laws will continue. On October 18, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed
a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the
Court denied the motion to dismiss, but also ruled that monetary damages could
not be recovered under the public nuisance claim. In July 2008, three additional
complaints were filed against FGCO in the United States District Court for the
Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant
air emissions. In addition to seeking damages, two of the complaints seek to
enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible,
prudent and proper manner”, one being a complaint filed on behalf of twenty-one
individuals and the other being a class action complaint, seeking certification
as a class action with the eight named plaintiffs as the class representatives.
On October 14, 2008, the Court granted FGCO’s motion to consolidate
discovery for all four complaints pending against the Bruce Mansfield Plant.
FGCO believes the claims are without merit and intends to defend itself against
the allegations made in these complaints. The Pennsylvania Department of Health
and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed
their intention to conduct additional air monitoring in the vicinity of the
Mansfield plant.
On December 18,
2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations
at the Portland Generation Station against Reliant (the current owner and
operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in
1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that
"modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without
preconstruction NSR or permitting under the CAA's prevention of significant
deterioration program, and seeks injunctive relief, penalties, attorney fees and
mitigation of the harm caused by excess emissions. On March 14, 2008,
Met-Ed filed a motion to dismiss the citizen suit claims against it and a
stipulation in which the parties agreed that GPU, Inc. should be dismissed from
this case. On March 26, 2008, GPU, Inc. was dismissed by the United States
District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe
Energy is disputed. On October 30, 2008, the state of Connecticut filed a
Motion to Intervene, which the Court granted on March 24, 2009. On
December 5, 2008, New Jersey filed an amended complaint, adding claims with
respect to alleged modifications that occurred after GPU’s sale of the plant.
Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on
February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant
alleging new source review violations at the Portland Generation Station based
on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome
of this matter. The EPA’s January 14, 2009, NOV also alleged new source
review violations at the Keystone and Shawville Stations based on
“modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of
Keystone Station and Penelec, as former owner and operator of the Shawville
Station, are unable to predict the outcome of this matter.
On June 11, 2008,
the EPA issued a Notice and Finding of Violation to Mission Energy Westside,
Inc. alleging that "modifications" at the Homer City Power Station occurred
since 1988 to the present without preconstruction NSR or permitting under the
CAA's prevention of significant deterioration program. Mission Energy is seeking
indemnification from Penelec, the co-owner (along with New York State Electric
and Gas Company) and operator of the Homer City Power Station prior to its sale
in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy
is disputed. Penelec is unable to predict the outcome of this
matter.
On May 16, 2008,
FGCO received a request from the EPA for information pursuant to Section 114(a)
of the CAA for certain operating and maintenance information regarding the
Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA
to determine whether these generating sources are complying with the NSR
provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an
Administrative Consent Order modifying that request and setting forth a schedule
for FGCO’s response. On October 27, 2008, FGCO received a second request from
the EPA for information pursuant to Section 114(a) of the CAA for additional
operating and maintenance information regarding the Eastlake, Lakeshore, Bay
Shore and Ashtabula generating plants. FGCO intends to fully comply with the
EPA’s information requests, but, at this time, is unable to predict the outcome
of this matter.
On August 18, 2008,
FirstEnergy received a request from the EPA for information pursuant to Section
114(a) of the CAA for certain operating and maintenance information regarding
its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a
nearly identical request directed to the current owner, Reliant Energy, to allow
the EPA to determine whether these generating sources are complying with the NSR
provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s
information request, but, at this time, is unable to predict the outcome of this
matter.
National Ambient Air Quality
Standards (Applicable to FES)
In March 2005,
the EPA finalized the CAIR covering a total of 28 states (including Michigan,
New Jersey, Ohio and Pennsylvania) and the District of Columbia based on
proposed findings that air emissions from 28 eastern states and the District of
Columbia significantly contribute to non-attainment of the NAAQS for fine
particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires
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),
ultimately capping SO2 emissions
in affected states to just 2.5 million tons annually and NOX emissions
to just 1.3 million tons annually. CAIR was challenged in the United States
Court of Appeals for the District of Columbia and on July 11, 2008, the Court
vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from
the ground up.” On September 24, 2008, the EPA, utility, mining and certain
environmental advocacy organizations petitioned the Court for a rehearing to
reconsider its ruling vacating CAIR. On December 23, 2008, the Court
reconsidered its prior ruling and allowed CAIR to remain in effect to
“temporarily preserve its environmental values” until the EPA replaces CAIR with
a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of
compliance with these regulations may be substantial and will depend, in part,
on the action taken by the EPA in response to the Court’s ruling.
Mercury
Emissions (Applicable to FES)
In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases; initially, capping national mercury
emissions at 38 tons by 2010 (as a "co-benefit" from implementation of
SO2
and NOX emission
caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states
and environmental groups appealed the CAMR to the United States Court of Appeals
for the District of Columbia. On February 8, 2008, the Court vacated the
CAMR, ruling that the EPA failed to take the necessary steps to “de-list”
coal-fired power plants from its hazardous air pollutant program and, therefore,
could not promulgate a cap-and-trade program. The EPA petitioned for rehearing
by the entire Court, which denied the petition on May 20, 2008. On
October 17, 2008, the EPA (and an industry group) petitioned the United
States Supreme Court for review of the Court’s ruling vacating CAMR. On February
6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23,
2009, the Supreme Court dismissed the EPA’s petition and denied the industry
group’s petition. The EPA is developing new mercury emission standards for
coal-fired power plants. FGCO’s future cost of compliance with mercury
regulations may be substantial and will depend on the action taken by the EPA
and on how they are ultimately implemented.
Pennsylvania has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. On January 30, 2009,
the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule
“unlawful, invalid and unenforceable” and enjoined the Commonwealth from
continued implementation or enforcement of that rule. It is anticipated that
compliance with these regulations, if the Commonwealth Court’s rulings were
reversed on appeal and Pennsylvania’s mercury rule was implemented, would not
require the addition of mercury controls at the Bruce Mansfield Plant, FES’ only
Pennsylvania coal-fired power plant, until 2015, if at all.
Climate
Change (Applicable to FES)
In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG, including CO2, emitted
by developed countries by 2012. The United States signed the Kyoto Protocol in
1998 but it was never submitted for ratification by the United States Senate.
However, the Bush administration had committed the United States to a voluntary
climate change strategy to reduce domestic GHG intensity – the ratio of
emissions to economic output – by 18% through 2012. Also, in an April 16,
2008 speech, former President Bush set a policy goal of stopping the growth of
GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition,
the EPACT established a Committee on Climate Change Technology to coordinate
federal climate change activities and promote the development and deployment of
GHG reducing technologies. President Obama has announced his Administration’s
“New Energy for America Plan” that includes, among other provisions, ensuring
that 10% of electricity in the United States comes from renewable sources by
2012, and increasing to 25% by 2025; and implementing an economy-wide
cap-and-trade program to reduce GHG emissions 80% by 2050.
There are a number
of initiatives to reduce GHG emissions under consideration at the federal, state
and international level. At the international level, efforts to reach a new
global agreement to reduce GHG emissions post-2012 have begun with the Bali
Roadmap, which outlines a two-year process designed to lead to an agreement in
2009. At the federal level, members of Congress have introduced several bills
seeking to reduce emissions of GHG in the United States, and the Senate
Environment and Public Works Committee has passed one such bill. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states, led by California, have
coordinated efforts to develop regional strategies to control emissions of
certain GHGs.
On April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2
emissions from automobiles as “air pollutants” under the CAA. Although this
decision did not address CO2 emissions
from electric generating plants, the EPA has similar authority under the CAA to
regulate “air pollutants” from those and other facilities. On April 17,
2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings
for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding
concludes that the atmospheric concentrations of several key greenhouse gases
threaten the health and welfare of future generations and that the combined
emissions of these gases by motor vehicles contribute to the atmospheric
concentrations of these key greenhouse gases and hence to the threat of climate
change. Although the EPA’s proposed finding, if finalized, does not establish
emission requirements for motor vehicles, such requirements would be expected to
occur through further rulemakings. Additionally, while the EPA’s proposed
findings do not specifically address stationary sources, including electric
generating plants, those findings, if finalized, would be expected to support
the establishment of future emission requirements by the EPA for stationary
sources.
FES cannot currently
estimate the financial impact of climate change policies, although potential
legislative or regulatory programs restricting CO2 emissions
could require significant capital and other expenditures. The CO2 emissions
per KWH of electricity generated by FES is lower than many regional competitors
due to its diversified generation sources, which include low or non-CO2 emitting
gas-fired and nuclear generators.
Clean Water Act (Applicable
to FES)
Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FES' plants. In addition, Ohio, New
Jersey and Pennsylvania have water quality standards applicable to FES'
operations. As provided in the Clean Water Act, authority to grant federal
National Pollutant Discharge Elimination System water discharge permits can be
assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.
On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality (when aquatic organisms
are pinned against screens or other parts of a cooling water intake system) and
entrainment (which occurs when aquatic life is drawn into a facility's cooling
water system). On January 26, 2007, the United States Court of Appeals for the
Second Circuit remanded portions of the rulemaking dealing with impingement
mortality and entrainment back to the EPA for further rulemaking and eliminated
the restoration option from the EPA’s regulations. On July 9, 2007, the EPA
suspended this rule, noting that until further rulemaking occurs, permitting
authorities should continue the existing practice of applying their best
professional judgment to minimize impacts on fish and shellfish from cooling
water intake structures. On April 1, 2009, the Supreme Court of the United
States reversed one significant aspect of the Second Circuit Court’s opinion and
decided that Section 316(b) of the Clean Water Act authorizes the EPA to
compare costs with benefits in determining the best technology available for
minimizing adverse environmental impact at cooling water intake structures. FES
is studying various control options and their costs and effectiveness. Depending
on the results of such studies and the EPA’s further rulemaking and any action
taken by the states exercising best professional judgment, the future costs of
compliance with these standards may require material capital
expenditures.
The U.S. Attorney's
Office in Cleveland, Ohio has advised FGCO that it is considering prosecution
under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum
spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on
November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to
predict the outcome of this matter.
Regulation of Waste Disposal
(Applicable to FES and each of the Utilities)
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 non-hazardous waste. In
February 2009, the EPA requested comments from the states on options for
regulating coal combustion wastes, including regulation as non-hazardous waste
or regulation as a hazardous waste. The future cost of compliance with coal
combustion waste regulations may be substantial and will depend, in part, on the
regulatory action taken by the EPA and implementation by the
states.
Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had
approximately $1.6 billion invested in external trusts to be used for the
decommissioning and environmental remediation of Davis-Besse, Beaver Valley,
Perry and TMI-2. As part of the application to the NRC to transfer the ownership
of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to
contribute another $80 million to these trusts by 2010. Consistent with NRC
guidance, utilizing a “real” rate of return on these funds of approximately 2%
over inflation, these trusts are expected to exceed the minimum decommissioning
funding requirements set by the NRC. Conservatively, these estimates do not
include any return that the trusts may earn over the 20-year plant useful life
extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of
the decommissioning of TMI-2) seeks for these facilities.
The Utilities have
been named as potentially responsible parties 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 potentially
responsible parties for a particular site may be liable on a joint and several
basis. Environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of March 31, 2009, based on
estimates of the total costs of cleanup, the Utilities' proportionate
responsibility for such costs and the financial ability of other unaffiliated
entities to pay. Total liabilities of approximately $91 million (JCP&L
- $64 million, TE - $1 million, CEI - $1 million and FirstEnergy
Corp. - $25 million) have been accrued through March 31, 2009.
Included in the total are accrued liabilities of approximately $56 million
for environmental remediation of former manufactured gas plants and gas holder
facilities in New Jersey, which are being recovered by JCP&L through a
non-bypassable SBC.
Other Legal
Proceedings
Power Outages and Related
Litigation (Applicable to JCP&L)
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, the Muise class action) 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.
After various
motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common
law fraud, negligent misrepresentation, strict product liability, and punitive
damages were dismissed, leaving only the negligence and breach of contract
causes of actions. The class was decertified twice by the trial court, and
appealed both times by the Plaintiffs, with the results being that: (1) the
Appellate Division limited the class only to those customers directly impacted
by the outages of JCP&L transformers in Red Bank, NJ, based on a common
incident involving the failure of the bushings of two large transformers in the
Red Bank substation which resulted in planned and unplanned outages in the area
during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded
this matter back to the Trial Court to allow plaintiffs sufficient time to
establish a damage model or individual proof of damages. Proceedings then
continued at the trial court level and a case management conference with the
presiding Judge was held on June 13, 2008. At that conference, counsel for
the Plaintiffs stated his intent to drop his efforts to create a class-wide
damage model and, instead of dismissing the class action, expressed his desire
for a bifurcated trial on liability and damages. In response, JCP&L filed an
objection to the plaintiffs’ proposed trial plan and another motion to decertify
the class. On March 31, 2009, the trial court granted JCP&L’s motion to
decertify the class. On April 20, 2009, the Plaintiffs filed their appeal
to the trial court's decision to decertify the class.
On December 9, 2008,
a transformer at JCP&L’s Oceanview substation failed, resulting in an outage
on certain bulk electric system (transmission voltage) lines out of the
Oceanview and Atlantic substations, with customers in the affected area losing
power. Power was restored to most customers within a few hours and to all
customers within eleven hours. On December 16, 2008, JCP&L provided
preliminary information about the event to certain regulatory agencies,
including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation
Investigation in order to determine JCP&L’s contribution to the electrical
event and to review any potential violation of NERC Reliability Standards
associated with the event. The initial phase of the investigation requires
JCP&L to respond to NERC’s request for factual data about the outage.
JCP&L submitted its written response on May 1, 2009. JCP&L is not
able at this time to predict what actions, if any, that NERC will take upon
receipt of JCP&L’s response to NERC’s data request.
Nuclear Plant
Matters (Applicable to FES)
On May 14, 2007, the
Office of Enforcement of the NRC issued a Demand for Information to FENOC,
following FENOC’s reply to an April 2, 2007 NRC request for information about
two reports prepared by expert witnesses for an insurance arbitration (the
insurance claim was subsequently withdrawn by FirstEnergy in December 2007)
related to Davis-Besse. The NRC indicated that this information was needed for
the NRC “to determine whether an Order or other action should be taken pursuant
to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to
operate its licensed facilities in accordance with the terms of its licenses and
the Commission’s regulations.” FENOC was directed to submit the information to
the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s
Demand for Information reaffirming that it accepts full responsibility for the
mistakes and omissions leading up to the damage to the reactor vessel head and
that it remains committed to operating Davis-Besse and FirstEnergy’s other
nuclear plants safely and responsibly. FENOC submitted a supplemental response
clarifying certain aspects of the response to the NRC on July 16, 2007. The
NRC issued a Confirmatory Order imposing these commitments on FENOC. In an
April 23, 2009 Inspection Report, the NRC concluded that FENOC had
completed all necessary actions required by the Confirmatory Order.
In August 2007,
FENOC submitted an application to the NRC to renew the operating licenses for
the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The
NRC is required by statute to provide an opportunity for members of the public
to request a hearing on the application. No members of the public, however,
requested a hearing on the Beaver Valley license renewal application. On
September 24, 2008, the NRC issued a draft supplemental Environmental Impact
Statement for Beaver Valley. FENOC will continue to work with the NRC Staff
as it completes its environmental and technical reviews of the license renewal
application, and expects to obtain renewed licenses for the Beaver Valley Power
Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley
Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and
2, respectively.
Other Legal
Matters (Applicable to FES and each of the
Utilities)
There are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to FES' and the Utilities’ normal business operations pending against
them. The other potentially material items not otherwise discussed above are
described below.
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. On September 9, 2005, the arbitration panel issued an opinion to
award approximately $16 million to the bargaining unit employees. A final order
identifying the individual damage amounts was issued on October 31, 2007
and the award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. On February 25, 2009, the federal district court denied JCP&L’s motion
to vacate the arbitration decision and granted the union’s motion to confirm the
award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to
Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take
as long as 24 months. JCP&L recognized a liability for the potential
$16 million award in 2005. Post-judgment interest began to accrue as of
February 25, 2009, and the liability will be adjusted accordingly.
The union employees
at the Bruce Mansfield Plant have been working without a labor contract since
February 15, 2008. The parties are continuing to bargain with the
assistance of a federal mediator. FES has a strike mitigation plan ready in the
event of a strike.
The union employees
at Met-Ed have been working without a labor contract since May 1, 2009. The
parties are continuing to bargain and FirstEnergy has a work continuation plan
ready in the event of a strike.
FES and the
Utilities accrue legal 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. If it were ultimately determined that FES and the
Utilities have legal liability or are otherwise made subject to liability based
on the above matters, it could have a material adverse effect on their financial
condition, results of operations and cash flows.
New
Accounting Standards and Interpretations (Applicable to FES and
each of the Utilities)
FSP
FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for
the Asset or Liability Have Significantly Decreased and Identifying Transactions
That Are Not Orderly”
In April 2009, the
FASB issued Staff Position FAS 157-4, which provides additional guidance to
consider in estimating fair value when there has been a significant decrease in
market activity for a financial asset. The FSP establishes a two-step process
requiring a reporting entity to first determine if a market is not active in
relation to normal market activity for the asset. If evidence indicates the
market is not active, an entity would then need to determine whether a quoted
price in the market is associated with a distressed transaction. An entity will
need to further analyze the transactions or quoted prices, and an adjustment to
the transactions or quoted prices may be necessary to estimate fair value.
Additional disclosures related to the inputs and valuation techniques used in
the fair value measurements are also required. The FSP is effective for interim
and annual periods ending after June 15, 2009, with early adoption permitted for
periods ending after March 15, 2009. FES and the Utilities will adopt the FSP
for their interim period ending June 30, 2009. While the FSP will expand
disclosure requirements, FES and the Utilities do not expect the FSP to have a
material effect upon their financial statements.
|
FSP
FAS 115-2 and FAS 124-2 - “Recognition and Presentation of
Other-Than-Temporary Impairments”
|
In April 2009, the
FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to
determine whether an other-than-temporary impairment exists for debt securities
and the amount of impairment to be recorded in earnings. Under the FSP,
management will be required to assert it does not have the intent to sell the
debt security, and it is more likely than not it will not have to sell the debt
security before recovery of its cost basis. If management is unable to make
these assertions, the debt security will be deemed other-than-temporarily
impaired and the security will be written down to fair value with the full
charge recorded through earnings. If management is able to make the assertions,
but there are credit losses associated with the debt security, the portion of
impairment related to credit losses will be recognized in earnings while the
remaining impairment will be recognized through other comprehensive income. The
FSP is effective for interim and annual reporting periods ending after June 15,
2009, with early adoption permitted for periods ending after March 15, 2009. FES
and the Utilities will adopt the FSP for their interim period ending June 30,
2009 and do not expect the FSP to have a material effect upon their financial
statements.
|
FSP
FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of
Financial Instruments”
|
In April 2009, the
FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of
the fair value of financial instruments in interim financial statements, as well
as in annual financial statements. The FSP also requires entities to disclose
the methods and significant assumptions used to estimate the fair value of
financial instruments in both interim and annual financial statements. The FSP
is effective for interim and annual reporting periods ending after June 15,
2009, with early adoption permitted for periods ending after March 15, 2009. FES
and the Utilities will adopt the FSP for their interim period ending June 30,
2009, and expect to expand their disclosures regarding the fair value of
financial instruments.
FSP FAS 132 (R)-1 – “Employers’
Disclosures about Postretirement Benefit Plan Assets”
In December 2008,
the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. Requirements of this FSP include disclosures about
investment policies and strategies, categories of plan assets, fair value
measurements of plan assets, and significant categories of risk. This FSP is
effective for fiscal years ending after December 15, 2009. FES and the Utilities
will expand their disclosures related to postretirement benefit plan assets as a
result of this FSP.
Recent
Developments
(Applicable to FES and each of the Utilities to the
extent indicated)
On April 6, 2009,
Richard H. Marsh, Senior Vice President and Chief Financial Officer (CFO) of
FirstEnergy indicated his intention to step down as CFO on May 1, 2009, and
retire from FirstEnergy effective July 1, 2009. Mr. Marsh was also Senior
Vice President and CFO of FES and each of the Utilities except JCP&L and a
Director of FES, OE, CEI and TE. On April 8, 2009, FirstEnergy’s Board of
Directors elected Mark T. Clark, Executive Vice President and CFO to succeed Mr.
Marsh as CFO of FirstEnergy, effective May 1, 2009. Mr. Clark also became
Executive Vice President and CFO of FES and each of the Utilities except
JCP&L and a Director of FES, OE, CEI and TE, effective May 1,
2009.
COMBINED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1.
ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a
diversified energy company that holds, directly or indirectly, all of the
outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a
wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and
its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its
subsidiaries follow GAAP and comply with the regulations, orders, policies and
practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC
and the 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,
2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited
financial statements of FirstEnergy, FES and each of the Utilities reflect all
normal recurring adjustments that, in the opinion of management, are necessary
to fairly present results of operations for the interim periods. Certain prior
year amounts have been reclassified to conform to the current year presentation.
Unless otherwise indicated, defined terms used herein have the meanings set
forth in the accompanying Glossary of Terms.
FirstEnergy and its
subsidiaries consolidate all majority-owned subsidiaries over which they
exercise control and, when applicable, entities for which they have a
controlling financial interest. Intercompany transactions and balances are
eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 6)
when it is determined to be the VIE's primary beneficiary. Investments in
non-consolidated affiliates over which FirstEnergy and its subsidiaries have the
ability to exercise significant influence, but not control (20-50% owned
companies, joint ventures and partnerships) follow the equity method of
accounting. Under the equity method, the interest in the entity is reported as
an investment in the Consolidated Balance Sheets and the percentage share of the
entity’s earnings is reported in the Consolidated Statements of
Income.
The consolidated
financial statements as of March 31, 2009, and for the three-month periods
ended March 31, 2009 and 2008, have been reviewed by PricewaterhouseCoopers
LLP, an independent registered public accounting firm. Their report (dated
May 7, 2009) is included herein. The report of PricewaterhouseCoopers LLP
states that they did not audit and they do not express an opinion on that
unaudited financial information. Accordingly, the degree of reliance on their
report on such information should be restricted in light of the limited nature
of the review procedures applied. PricewaterhouseCoopers LLP is not subject to
the liability provisions of Section 11 of the Securities Act of 1933 for their
report on the unaudited financial information because that report is not a
“report” or a “part” of a registration statement prepared or certified by
PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the
Securities Act of 1933.
2.
EARNINGS PER SHARE
Basic earnings per
share of common stock is computed using the weighted average of actual common
shares outstanding during the respective period as the denominator. The
denominator for diluted earnings per share of common stock reflects the weighted
average of common shares outstanding plus the potential additional common shares
that could result if dilutive securities and other agreements to issue common
stock were exercised. The following table reconciles basic and diluted earnings
per share of common stock:
Reconciliation
of Basic and Diluted
|
|
Three
Months Ended
March
31
|
|
Earnings
per Share of Common Stock
|
|
2009
|
|
2008
|
|
|
(In
millions, except
per
share amounts)
|
Earnings
available to parent
|
|
$
|
119
|
|
$
|
276
|
|
|
|
|
|
|
|
|
|
Average shares
of common stock outstanding – Basic
|
|
|
304
|
|
|
304
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
2
|
|
|
3
|
|
Average shares
of common stock outstanding – Diluted
|
|
|
306
|
|
|
307
|
|
|
|
|
|
|
|
|
|
Basic earnings
per share of common stock
|
|
$
|
0.39
|
|
$
|
0.91
|
|
Diluted
earnings per share of common stock
|
|
$
|
0.39
|
|
$
|
0.90
|
|
3.
FAIR VALUE MEASURES
FirstEnergy’s
valuation techniques, including the three levels of the fair value hierarchy as
defined by SFAS 157, are disclosed in Note 5 of the Notes to Consolidated
Financial Statements in FirstEnergy’s Annual Report.
The following table
sets forth FirstEnergy’s financial assets and financial liabilities that are
accounted for at fair value by level within the fair value hierarchy as of
March 31, 2009 and December 31, 2008. Assets and liabilities are classified
in their entirety based on the lowest level of input that is significant to the
fair value measurement. FirstEnergy’s assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect
the fair valuation of assets and liabilities and their placement within the fair
value hierarchy levels.
Recurring
Fair Value Measures
|
|
|
|
|
|
|
|
|
|
as
of March 31, 2009
|
|
Level
1
|
|
Level
2
|
|
Level
3
|
|
Total
|
|
|
|
(In
millions)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
-
|
|
$
|
43
|
|
$
|
-
|
|
$
|
43
|
|
Available-for-sale
securities(1)
|
|
|
427
|
|
|
1,533
|
|
|
-
|
|
|
1,960
|
|
NUG
contracts(2)
|
|
|
-
|
|
|
-
|
|
|
340
|
|
|
340
|
|
Other
investments
|
|
|
-
|
|
|
80
|
|
|
-
|
|
|
80
|
|
Total
|
|
$
|
427
|
|
$
|
1,656
|
|
$
|
340
|
|
$
|
2,423
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
30
|
|
$
|
27
|
|
$
|
-
|
|
$
|
57
|
|
NUG
contracts(2)
|
|
|
-
|
|
|
-
|
|
|
816
|
|
|
816
|
|
Total
|
|
$
|
30
|
|
$
|
27
|
|
$
|
816
|
|
$
|
873
|
|
(1)
|
Primarily
consists of investments in nuclear decommissioning trusts, the spent
nuclear fuel trusts and the NUG trusts.
Balance
excludes $3 million of receivables, payables and accrued
income.
|
(2)
|
NUG contracts
are completely offset by regulatory
assets.
|
Recurring
Fair Value Measures
|
|
|
|
|
|
|
|
|
|
as
of December 31, 2008
|
|
Level
1
|
|
Level
2
|
|
Level
3
|
|
Total
|
|
|
|
(In
millions)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
-
|
|
$
|
40
|
|
$
|
-
|
|
$
|
40
|
|
Available-for-sale
securities(1)
|
|
|
537
|
|
|
1,464
|
|
|
-
|
|
|
2,001
|
|
NUG
contracts(2)
|
|
|
-
|
|
|
-
|
|
|
434
|
|
|
434
|
|
Other
investments
|
|
|
-
|
|
|
83
|
|
|
-
|
|
|
83
|
|
Total
|
|
$
|
537
|
|
$
|
1,587
|
|
$
|
434
|
|
$
|
2,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
25
|
|
$
|
31
|
|
$
|
-
|
|
$
|
56
|
|
NUG
contracts(2)
|
|
|
-
|
|
|
-
|
|
|
766
|
|
|
766
|
|
Total
|
|
$
|
25
|
|
$
|
31
|
|
$
|
766
|
|
$
|
822
|
|
|
(1)
|
Primarily
consists of investments in nuclear decommissioning trusts, the spent
nuclear fuel trusts and the NUG trusts.
Balance
excludes $5 million of receivables, payables and accrued
income.
|
(2)
NUG contracts are completely offset by regulatory assets.
The determination of
the above fair value measures takes into consideration various factors required
under SFAS 157. These factors include nonperformance risk, including
counterparty credit risk and the impact of credit enhancements (such as cash
deposits, LOCs and priority interests). The impact of nonperformance risk was
immaterial in the fair value measurements.
The following table
sets forth a reconciliation of changes in the fair value of NUG contracts
classified as Level 3 in the fair value hierarchy for the three months ended
March 31, 2009 and 2008 (in millions):
|
|
Three
Months Ended
March 31
|
|
|
|
2009
|
|
2008
|
|
Balance as of
January 1
|
|
$
|
(332
|
)
|
$
|
(803
|
)
|
Settlements(1)
|
|
|
83
|
|
|
64
|
|
Unrealized
gains (losses)(1)
|
|
|
(227
|
)
|
|
320
|
|
Net
transfers to (from) Level 3
|
|
|
-
|
|
|
-
|
|
Balance as of
March 31, 2009
|
|
$
|
(476
|
)
|
$
|
(419
|
)
|
|
|
|
|
|
|
|
|
Change in
unrealized gains (losses) relating to
|
|
|
|
|
|
|
|
instruments
held as of March 31
|
|
$
|
(227
|
)
|
$
|
320
|
|
|
|
|
|
|
|
|
|
(1) Changes in the
fair value of NUG contracts are completely offset by regulatory
assets and do not impact earnings.
|
|
On January 1, 2009,
FirstEnergy adopted FSP FAS 157-2, for financial assets and financial
liabilities measured at fair value on a non-recurring basis. The impact of SFAS
157 on those financial assets and financial liabilities is
immaterial.
4.
DERIVATIVE INSTRUMENTS
FirstEnergy is
exposed to financial risks resulting from fluctuating interest rates and
commodity prices, including prices for electricity, natural gas, coal and energy
transmission. To manage the volatility relating to these exposures, FirstEnergy
uses a variety of derivative instruments, including forward contracts, options,
futures contracts and swaps. The derivatives are used for risk management
purposes. In addition to derivatives, FirstEnergy also enters into master
netting agreements with certain third parties. FirstEnergy's Risk Policy
Committee, comprised of members of senior management, provides general
management oversight for risk management activities throughout FirstEnergy. They
are responsible for promoting the effective design and implementation of sound
risk management programs. They also oversee compliance with corporate risk
management policies and established risk management practices.
FirstEnergy accounts
for derivative instruments on its Consolidated Balance Sheet at their fair value
unless they meet the normal purchase and normal sales criteria. Derivatives that
meet those criteria are accounted for at cost. The changes in the fair value of
derivative instruments that do not meet the normal purchase and normal sales
criteria are recorded as other expense, as AOCL, or as part of the value of the
hedged item as described below.
Interest Rate Derivatives
Under the revolving
credit facility, FirstEnergy incurs variable interest charges based on LIBOR. In
2008, FirstEnergy entered into swaps with a notional value of $200 million
to hedge against changes in associated interest rates. Hedges with a notional
value of $100 million expire in November 2009 and the remainder expire in
November 2010. The swaps are accounted for as cash flow hedges under SFAS 133.
As of March 31, 2009, the fair value of outstanding swaps was
$(4) million.
FirstEnergy uses
forward starting swap agreements to hedge a portion of the consolidated interest
rate risk associated with issuances of fixed-rate, long-term debt securities of
its subsidiaries. These derivatives are treated as cash flow hedges, protecting
against the risk of changes in future interest payments resulting from changes
in benchmark U.S. Treasury rates between the date of hedge inception and the
date of the debt issuance. During the first quarter of 2009, FirstEnergy
terminated forward swaps with a notional value of $100 million when a
subsidiary issued long term debt. The gain associated with the termination was
$1.3 million, of which $0.3 million was ineffective and recognized as
an adjustment to interest expense. The remaining effective portion will be
amortized to interest expense over the life of the hedged debt. FirstEnergy
currently has no outstanding forward swaps.
As of March 31,
2009 and 2008, the total fair value of outstanding interest rate derivatives was
$(4) million and $(3) million, respectively. Interest rate derivatives are
located in “Other Noncurrent Liabilities” in FirstEnergy’s consolidated balance
sheets. The effect of interest rate derivatives on the statements of income and
comprehensive income during the periods ended March 31, 2009 and 2008
were:
|
Three
Months Ended
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
Effective
Portion
|
|
(in
millions)
|
|
|
|
Loss
Recognized in AOCL
|
$
|
(2
|
)
|
$
|
-
|
|
|
Loss
Reclassified from AOCL into Interest Expense
|
|
(5
|
)
|
|
(4
|
)
|
Ineffective
Portion
|
|
|
|
|
|
|
|
Loss
Recognized in Interest Expense
|
|
-
|
|
|
(1
|
)
|
Total unamortized
losses included in AOCL associated with prior interest rate hedges totaled
$119 million ($70 million net of tax) as of March 31, 2009. Based
on current estimates, approximately $11 million will be amortized to interest
expense during the next twelve months. FirstEnergy’s interest rate swaps do not
include any contingent credit risk related features.
Commodity Derivatives
FirstEnergy uses
both physically and financially settled derivatives to manage its exposure to
volatility in commodity prices. Commodity derivatives are used for risk
management purposes to hedge exposures when it makes economic sense to do so,
including circumstances in which the hedging relationship does not qualify for
hedge accounting. Derivatives that do not qualify under the normal purchase or
sales criteria or for hedge accounting as cash flow hedges are marked to market
through earnings. FirstEnergy’s risk policy does not allow derivatives to be
used for speculative or trading purposes. FirstEnergy hedges forecasted electric
sales and purchases and anticipated natural gas purchases using forwards and
options. Heating oil futures are used to hedge both oil purchases and fuel
surcharges associated with rail transportation contracts. FirstEnergy’s maximum
hedge term is typically two years. The effective portions of all cash flow
hedges are initially recorded in AOCL and are subsequently included in net
income as the underlying hedged commodities are delivered.
The following tables
summarize the location and fair value of commodity derivatives in FirstEnergy’s
consolidated balance sheets:
Derivative
Assets
|
|
Derivative
Liabilities
|
|
|
Fair
Value
|
|
|
|
Fair
Value
|
|
|
March
31,
|
|
December
31,
|
|
|
|
March
31,
|
|
December
31,
|
|
|
2009
|
|
2008
|
|
|
|
2009
|
|
2008
|
Cash
Flow Hedges
|
|
(in
millions)
|
|
Cash
Flow Hedges
|
|
(in
millions)
|
Electricity
Forwards
|
|
|
|
|
|
Electricity
Forwards
|
|
|
|
|
|
Current
Assets
|
$
|
23
|
$
|
11
|
|
|
Current
Liabilities
|
$
|
23
|
$
|
27
|
Natural Gas
Futures
|
|
|
|
|
|
Natural Gas
Futures
|
|
|
|
|
|
Current
Assets
|
|
-
|
|
-
|
|
|
Current
Liabilities
|
|
11
|
|
4
|
|
Long-Term
Deferred Charges
|
|
-
|
|
-
|
|
|
Noncurrent
Liabilities
|
|
5
|
|
5
|
Other
|
|
|
|
|
|
Other
|
|
|
|
|
|
Current
Assets
|
|
-
|
|
-
|
|
|
Current
Liabilities |
|
10
|
|
12
|
|
Long-Term
Deferred Charges
|
|
-
|
|
-
|
|
|
Noncurrent
Liabilities |
|
3
|
|
4
|
|
|
$
|
23
|
$
|
11
|
|
|
$
|
52
|
$
|
52
|
|
|
|
|
|
|
|
|
Derivative
Assets
|
|
Derivative
Liabilities
|
|
|
|
Fair
Value
|
|
|
|
Fair
Value
|
|
|
|
March
31, 2009
|
|
December
31, 2008
|
|
|
|
March
31, 2009
|
|
December
31, 2008
|
Economic
Hedges
|
|
(in
millions)
|
|
Economic
Hedges
|
|
(in
millions)
|
NUG
Contracts
|
|
|
|
NUG
Contracts
|
|
|
|
Power
Purchase
|
$
|
340
|
$
|
434
|
|
|
Power
Purchase
|
$
|
816
|
$
|
766
|
|
Contract
Asset
|
|
|
|
|
|
|
Contract
Liability
|
|
|
|
|
Other
|
|
|
|
|
|
Other
|
|
|
|
|
|
Current
Assets
|
|
1
|
|
1
|
|
|
Current
Liabilities
|
|
1
|
|
1
|
|
Long-Term
Deferred Charges
|
|
19
|
|
28
|
|
|
Noncurrent
Liabilities
|
|
-
|
|
-
|
|
|
$
|
360
|
$
|
463
|
|
|
$
|
817
|
$
|
767
|
Total
Commodity Derivatives
|
$
|
383
|
$
|
474
|
|
Total
Commodity Derivatives
|
$
|
869
|
$
|
819
|
Electricity forwards
are used to balance expected retail and wholesale sales with expected generation
and purchased power. Natural gas futures are entered into based on expected
consumption of natural gas, primarily used in FirstEnergy’s peaking units.
Heating oil futures are entered into based on expected consumption of oil and
the financial risk in FirstEnergy’s transportation contracts. Derivative
instruments are not used in quantities greater than forecasted needs. The
following table summarizes the volume of FirstEnergy’s outstanding derivative
transactions as of March 31, 2009.
|
Purchases
|
|
Sales
|
|
Net
|
|
Units
|
|
|
|
(in
thousands)
|
|
Electricity
Forwards
|
|
772
|
|
|
(1,735
|
)
|
|
(963
|
)
|
|
MWh
|
|
Heating Oil
Futures
|
|
20,496
|
|
|
(2,520
|
)
|
|
17,976
|
|
|
Gallons
|
|
Natural Gas
Futures
|
|
4,850
|
|
|
-
|
|
|
4,850
|
|
|
mmBtu
|
|
The effect of
derivative instruments on the consolidated statements of income and
comprehensive income for the three months ended March 31, 2009 and 2008, for
instruments designated in cash flow hedging relationships and not in hedging
relationships, respectively, are summarized in the following
tables:
Derivatives in Cash Flow Hedging
Relationships
|
Electricity
|
|
|
Natural
Gas
|
|
|
Heating
Oil
|
|
|
|
|
|
|
Forwards
|
|
|
Futures
|
|
|
Futures
|
|
|
Total
|
|
2009
|
|
(in
millions)
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$
|
(2
|
)
|
$
|
(7
|
)
|
$
|
(1
|
)
|
$
|
(10
|
)
|
Effective Gain
(Loss) Reclassified to:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power Expense
|
|
(18
|
)
|
|
-
|
|
|
-
|
|
|
(18
|
)
|
|
Fuel
Expense
|
|
-
|
|
|
-
|
|
|
(4
|
)
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$
|
(14
|
)
|
$
|
3
|
|
$
|
-
|
|
$
|
(11
|
)
|
Effective Gain
(Loss) Reclassified to:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power Expense
|
|
(17
|
)
|
|
-
|
|
|
-
|
|
|
(17
|
)
|
|
Fuel
Expense
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The ineffective portion was immaterial.
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives Not in Hedging
Relationships
|
NUG
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
|
|
Other
|
|
|
Total
|
|
2009
|
|
(in
millions)
|
Unrealized
Gain (Loss) Recognized in:
|
|
|
|
|
|
|
|
|
|
Regulatory Assets(1)
|
$
|
(227
|
)
|
$
|
-
|
|
$
|
(227
|
)
|
Realized Gain
(Loss) Reclassified to:
|
|
|
|
|
|
|
|
|
|
|
Fuel
Expense(2)
|
|
$
|
-
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
Regulatory Assets(3)
|
|
|
(83
|
)
|
|
10
|
|
|
(73
|
)
|
|
|
$
|
(83
|
)
|
$
|
9
|
|
$
|
(74
|
)
|
2008
|
|
|
|
|
|
|
|
|
|
|
Unrealized
Gain (Loss) Recognized in:
|
|
|
|
|
|
|
|
|
|
Regulatory Assets(1)
|
$
|
320
|
|
$
|
-
|
|
$
|
320
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain
(Loss) Reclassified to:
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
Assets(3)
|
$
|
(64
|
)
|
$
|
11
|
|
$
|
(53
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Changes in the
fair value of NUG Contracts are deferred for future recovery from (or
refund to) customers.
|
(2)
|
The realized
gain (loss) is reclassified upon termination of the derivative
instrument
|
(3)
|
The above
market cost of NUG power is deferred for future recovery from (or refund
to)
customers.
|
Total unamortized
losses included in AOCL associated with commodity derivatives were $32 million
($19 million net of tax) as of March 31, 2009, as compared to
$44 million ($27 million net of tax) as of December 31, 2008. The
change (net of tax) resulted from a net $5 million increase related to
current hedging activity and a $13 million decrease due to net hedge losses
reclassified to earnings during the first quarter of 2009. Based on current
estimates, approximately $15 million (after tax) of the net deferred losses
on derivative instruments in AOCL as of March 31, 2009 are expected to be
reclassified to earnings during the next twelve months as hedged transactions
occur. The fair value of these derivative instruments fluctuate from period to
period based on various market factors.
Many of
FirstEnergy’s commodity derivatives contain credit risk features. As of
March 31, 2009, FirstEnergy posted $141 million of collateral related
to net liability positions and held no counterparties’ funds related to asset
positions. The collateral FirstEnergy has posted relates to both derivative and
non-derivative contracts. FirstEnergy’s largest derivative counterparties fully
collateralize all derivative transactions. Certain commodity derivative
contracts include credit-risk-related contingent features that would require
FirstEnergy to post additional collateral if the credit rating for its debt were
to fall below investment grade. The aggregate fair value of derivative
instruments with credit-risk related contingent features that are in a liability
position on March 31, 2009 was $4 million, for which no collateral has been
posted. If FirstEnergy’s credit rating were to fall below investment grade, it
would be required to post $4 million of additional collateral related to
commodity derivatives.
5.
PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides
noncontributory qualified defined benefit pension plans that cover substantially
all of its employees and non-qualified pension plans that cover certain
employees. The plans provide defined benefits based on years of service and
compensation levels. FirstEnergy’s funding policy is based on actuarial
computations using the projected unit credit method. FirstEnergy uses a
December 31 measurement date for its pension and other postretirement
benefit plans. The fair value of the plan assets represents the actual market
value as of December 31. FirstEnergy also provides a minimum amount of
noncontributory life insurance to retired employees in addition to optional
contributory insurance. Health care benefits, which include certain employee
contributions, deductibles and co-payments, are available upon retirement to
employees hired prior to January 1, 2005, their dependents and, under
certain circumstances, their survivors. FirstEnergy recognizes the expected cost
of providing pension benefits and other postretirement benefits from the time
employees are hired until they become eligible to receive those benefits. In
addition, FirstEnergy has obligations to former or inactive employees after
employment, but before retirement, for disability-related benefits.
For the three months
ended March 31, 2009 and 2008, FirstEnergy’s net pension and OPEB expense
(benefit) was $43 million and $(15) million, respectively. The
components of FirstEnergy's net pension and other postretirement benefit cost
(including amounts capitalized) for the three months ended March 31, 2009 and
2008, consisted of the following:
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Pension
Benefits
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Other
Postretirement Benefits
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2009
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2008
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2009
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2008
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(In
millions)
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Expected
return on plan assets
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Amortization
of prior service cost
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Recognized net
actuarial loss
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Net periodic
cost (credit)
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Pension and
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. The Companies capitalize employee benefits
related to construction projects. The net pension and other postretirement
benefit costs (including amounts capitalized) recognized by each of the
Companies for the three months ended March 31, 2009 and 2008 were as
follows:
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Pension
Benefit Cost (Credit)
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Other
Postretirement
Benefit
Cost (Credit)
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2009
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2008
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2009
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2008
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millions)
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Other
FirstEnergy subsidiaries
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6.
VARIABLE INTEREST ENTITIES
FirstEnergy and its
subsidiaries consolidate VIEs when they are determined to be the VIE's primary
beneficiary as defined by FIN 46R. Effective January 1, 2009,
FirstEnergy adopted SFAS 160. As a result, FirstEnergy and its subsidiaries
reflect the portion of VIEs not owned by them in the caption noncontrolling
interest within the consolidated financial statements. The change in
noncontrolling interest within the Consolidated Balance Sheets is the result of
earnings and losses of the noncontrolling interests and distributions to
owners.
Mining
Operations
On July 16, 2008,
FEV entered into a joint venture with the Boich Companies, a Columbus,
Ohio-based coal company, to acquire a majority stake in the Signal Peak mining
and coal transportation operations near Roundup, Montana. FEV made a
$125 million equity investment in the joint venture, which acquired 80% of
the mining operations (Signal Peak Energy, LLC) and 100% of the transportation
operations, with FEV owning a 45% economic interest and an affiliate of the
Boich Companies owning a 55% economic interest in the joint venture. Both
parties have a 50% voting interest in the joint venture. In March 2009, FEV
agreed to pay a total of $8.5 million (of which $1.7 million was paid in March
2009) to affiliates of the Boich Companies to purchase an additional 5% economic
interest in the Signal Peak mining and coal transportation operations. Voting
interests will remain unchanged after the sale is completed in July 2009.
Effective January 16, 2010, the joint venture will have 18 months to exercise an
option to acquire the remaining 20% stake in the mining operations. In
accordance with FIN 46R, FEV consolidates the mining and transportation
operations of this joint venture in its financial statements.
Trusts
FirstEnergy’s
consolidated financial statements include PNBV and Shippingport, VIEs created in
1996 and 1997, respectively, to refinance debt originally issued in connection
with sale and leaseback transactions. PNBV and Shippingport financial data are
included in the consolidated financial statements of OE and CEI,
respectively.
PNBV was established
to purchase a portion of the lease obligation bonds issued in connection with
OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver
Valley Unit 2. OE used debt and available funds to purchase the notes issued by
PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3%
equity interest by an unaffiliated third party and a 3% equity interest held by
OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to
purchase all of the lease obligation bonds issued in connection with CEI’s and
TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE
used debt and available funds to purchase the notes issued by
Shippingport.
Loss
Contingencies
FES and the Ohio
Companies are exposed to losses under their applicable sale-leaseback agreements
upon the occurrence of certain contingent events that each company considers
unlikely to occur. The maximum exposure under these provisions represents the
net amount of casualty value payments due upon the occurrence of specified
casualty events that render the applicable plant worthless. Net discounted lease
payments would not be payable if the casualty loss payments were made. The
following table discloses each company’s net exposure to loss based upon the
casualty value provisions mentioned above:
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Maximum
Exposure
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Discounted
Lease Payments, net(1)
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Net
Exposure
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(In
millions)
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FES
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$
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1,373
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$
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1,202
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$
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171
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OE
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759
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587
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172
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CEI
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740
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73
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667
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TE
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740
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419
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321
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(1) The
net present value of FirstEnergy’s consolidated sale and leaseback
operating
lease commitments is $1.7 billion
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In
October 2007, CEI and TE assigned their leasehold interests in the Bruce
Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising
under those leases. FGCO subsequently transferred the Unit 1 portion of these
leasehold interests, as well as FGCO’s leasehold interests under its
July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly
formed wholly-owned subsidiary in December 2007. The subsidiary assumed all
of the lessee obligations associated with the assigned interests. However, CEI
and TE remain primarily liable on the 1987 leases and related agreements as to
the lessors and other parties to the agreements. FGCO remains primarily liable
on the 2007 leases and related agreements, and FES remains primarily liable as a
guarantor under the related 2007 guarantees, as to the lessors and other parties
to the respective agreements. These assignments terminate automatically upon the
termination of the underlying leases.
During the second
quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987
sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity
interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In
addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI
1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to
lease these MW under their respective sale and leaseback arrangements and the
related lease debt remains outstanding.
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 24 long-term
power purchase agreements with NUG entities. The agreements were entered into
pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was
not involved in the creation of, and has no equity or debt invested in, these
entities.
FirstEnergy has
determined that for all but eight of these entities, neither JCP&L, Met-Ed
nor Penelec have variable interests in the entities or the entities are
governmental or not-for-profit organizations not within the scope of
FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
remaining eight entities, which sell their output at variable prices that
correlate to some extent with the operating costs of the plants. As required by
FIN 46R, FirstEnergy periodically requests from these eight entities the
information necessary to determine whether they are VIEs or whether JCP&L,
Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to
obtain the requested information, which in most cases was deemed by the
requested entity to be proprietary. As such, FirstEnergy applied the scope
exception that exempts enterprises unable to obtain the necessary information to
evaluate entities under FIN 46R.
Since FirstEnergy
has no equity or debt interests in the NUG entities, its maximum exposure to
loss relates primarily to the above-market costs it may incur for power.
FirstEnergy expects any above-market costs it incurs to be recovered from
customers. Purchased power costs from these entities during the three months
ended March 31, 2009 and 2008 are shown in the following
table:
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Three
Months Ended
|
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|
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March
31,
|
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2009
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2008
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(In
millions)
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Transition Bonds
The consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned
limited liability companies of JCP&L. In June 2002, JCP&L Transition
Funding sold $320 million of transition bonds to securitize the recovery of
JCP&L's bondable stranded costs associated with the previously divested
Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition
Funding II sold $182 million of transition bonds to securitize the recovery
of deferred costs associated with JCP&L’s supply of BGS.
JCP&L did not
purchase and does not own any of the transition bonds, which are included as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As
of March 31, 2009, $363 million of the transition bonds were
outstanding. The transition bonds are the sole obligations of JCP&L
Transition Funding and JCP&L Transition Funding II and are collateralized by
each company’s equity and assets, which consists primarily of bondable
transition property.
Bondable transition
property represents the irrevocable right under New Jersey law of a utility
company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on transition bonds and
other fees and expenses associated with their issuance. JCP&L sold its
bondable transition property to JCP&L Transition Funding and JCP&L
Transition Funding II and, as servicer, manages and administers the bondable
transition property, including the billing, collection and remittance of the
TBC, pursuant to separate servicing agreements with JCP&L Transition Funding
and JCP&L Transition Funding II. For the two series of transition bonds,
JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable
from TBC collections.
7.
INCOME TAXES
FirstEnergy accounts
for uncertainty in income taxes recognized in a company’s financial statements
in accordance with FIN 48. This interpretation prescribes a recognition
threshold and measurement attribute for financial statement recognition and
measurement of tax positions taken or expected to be taken on a company’s tax
return. Upon completion of the federal tax examination for the 2007 tax year in
the first quarter of 2009, FirstEnergy recognized $13 million in tax
benefits, which favorably affected FirstEnergy’s effective tax rate. During the
first three months of 2008, there were no material changes to FirstEnergy’s
unrecognized tax benefits. As of March 31, 2009, FirstEnergy expects that
it is reasonably possible that $193 million of the unrecognized benefits
may be resolved within the next twelve months, of which approximately
$148 million, if recognized, would affect FirstEnergy’s effective tax rate.
The potential decrease in the amount of unrecognized tax benefits is primarily
associated with issues related to the capitalization of certain costs, gains and
losses recognized on the disposition of assets and various other tax
items.
FIN 48 also requires
companies to recognize interest expense or income related to uncertain tax
positions. That amount is computed by applying the applicable statutory interest
rate to the difference between the tax position recognized in accordance with
FIN 48 and the amount previously taken or expected to be taken on the tax
return. FirstEnergy includes net interest and penalties in the provision for
income taxes. The net amount of accumulated interest accrued as of
March 31, 2009 was $61 million, as compared to $59 million as of
December 31, 2008. During the first three months of 2009 and 2008, there
were no material changes to the amount of interest accrued.
FirstEnergy has tax
returns that are under review at the audit or appeals level by the IRS and state
tax authorities. All state jurisdictions are open from 2001-2008. The IRS began
reviewing returns for the years 2001-2003 in July 2004 and several items are
under appeal. The federal audits for the years 2004-2006 were completed in 2008
and several items are under appeal. The IRS began auditing the year 2007 in
February 2007 under its Compliance Assurance Process program and was completed
in the first quarter of 2009 with two items under appeal. The IRS began auditing
the year 2008 in February 2008 and the year 2009 in February 2009 under its
Compliance Assurance Process program. Neither audit is expected to close before
December 2009. Management believes that adequate reserves have been recognized
and final settlement of these audits is not expected to have a material adverse
effect on FirstEnergy’s financial condition or results of
operations.
8.
COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND
OTHER ASSURANCES
As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. As of
March 31, 2009, outstanding guarantees and other assurances aggregated
approximately $4.5 billion, consisting of parental guarantees -
$1.2 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds -
$0.1 billion and LOCs - $0.6 billion.
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity activities principally to facilitate or hedge normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of credit support for
the financing or refinancing by subsidiaries of costs related to the acquisition
of property, plant and equipment. These agreements obligate FirstEnergy to
fulfill the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financing where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables
the counterparty's legal claim to be satisfied by other FirstEnergy assets. The
likelihood is remote that such parental guarantees of $0.4 billion
(included in the $1.2 billion discussed above) as of March 31, 2009
would increase amounts otherwise payable by FirstEnergy to meet its obligations
incurred in connection with financings and ongoing energy and energy-related
activities.
While these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or “material adverse event,” the immediate posting of cash collateral,
provision of an LOC or accelerated payments may be required of the subsidiary.
As of March 31, 2009, FirstEnergy's maximum exposure under these collateral
provisions was $761 million, consisting of $55 million due to
“material adverse event” contractual clauses and $706 million due to a
below investment grade credit rating. Additionally, stress case conditions of a
credit rating downgrade or “material adverse event” and hypothetical adverse
price movements in the underlying commodity markets would increase this amount
to $830 million, consisting of $54 million due to “material adverse
event” contractual clauses and $776 million due to a below investment grade
credit rating.
Most of
FirstEnergy's surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related guarantees of $111 million
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.
In addition to
guarantees and surety bonds, FES’ contracts, including power contracts with
affiliates awarded through competitive bidding processes, typically contain
margining provisions which require the posting of cash or LOCs in amounts
determined by future power price movements. Based on FES’ contracts as of March
31, 2009, and forward prices as of that date, FES had $205 million of
outstanding collateral payments. Under a hypothetical adverse change in forward
prices (15% decrease in the first 12 months and 20% decrease in prices
thereafter), FES would be required to post an additional $77 million.
Depending on the volume of forward contracts entered and future price movements,
FES could be required to post significantly higher amounts for
margining.
In July 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1. FES has fully and unconditionally
guaranteed all of FGCO’s obligations under each of the leases (see
Note 12). The related lessor notes and pass through certificates are not
guaranteed by FES or FGCO, but the notes are secured by, among other things,
each lessor trust’s undivided interest in Unit 1, rights and interests under the
applicable lease and rights and interests under other related agreements,
including FES’ lease guaranty.
On October 8, 2008,
to enhance their liquidity position in the face of the turbulent credit and bond
markets, FirstEnergy, FES and FGCO entered into a $300 million secured term loan
facility with Credit Suisse. Under the facility, FGCO is the borrower and FES
and FirstEnergy are guarantors. Generally, the facility is available to FGCO
until October 7, 2009, with a minimum borrowing amount of $100 million and
maturity 30 days from the date of the borrowing. Once repaid, borrowings may not
be re-borrowed.
(B)
|
ENVIRONMENTAL
MATTERS
|
Various federal,
state and local authorities regulate FirstEnergy with regard to air and water
quality and other environmental matters. The effects of compliance on
FirstEnergy with regard to environmental matters could have a material adverse
effect on FirstEnergy's earnings and competitive position to the extent that it
competes with companies that are not subject to such regulations and, therefore,
do not bear the risk of costs associated with compliance, or failure to comply,
with such regulations. FirstEnergy estimates capital expenditures for
environmental compliance of approximately $808 million for the period
2009-2013.
FirstEnergy accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably estimate the amount of such
costs. Unasserted claims are reflected in FirstEnergy’s determination of
environmental liabilities and are accrued in the period that they become both
probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is
required to meet federally-approved SO2 emissions
regulations. Violations of such regulations can result in the shutdown of the
generating unit involved and/or civil or criminal penalties of up to $37,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. FirstEnergy believes it is currently in compliance with this policy, but
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.
The EPA Region 5
issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June
15, 2006, alleging violations to various sections of the CAA. FirstEnergy has
disputed those alleged violations based on its CAA permit, the Ohio SIP and
other information provided to the EPA at an August 2006 meeting with the EPA.
The EPA has several enforcement options (administrative compliance order,
administrative penalty order, and/or judicial, civil or criminal action) and has
indicated that such option may depend on the time needed to achieve and
demonstrate compliance with the rules alleged to have been violated. On
June 5, 2007, the EPA requested another meeting to discuss “an appropriate
compliance program” and a disagreement regarding emission limits applicable to
the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies
with SO2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NOX reductions
required by the 1990 Amendments are being achieved through combustion controls,
the generation of more electricity at lower-emitting plants, and/or using
emission allowances. In September 1998, the EPA finalized regulations requiring
additional NOX reductions
at FirstEnergy's facilities. The EPA's NOX Transport
Rule imposes uniform reductions of NOX emissions
(an approximate 85% reduction in utility plant NOX emissions
from projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NOX emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NOX budgets
established under SIPs through combustion controls and post-combustion controls,
including Selective Catalytic Reduction and SNCR systems, and/or using emission
allowances.
In 1999 and 2000,
the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn
based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR
Litigation) and filed similar complaints involving 44 other U.S. power plants.
This case and seven other similar cases are referred to as the NSR cases. OE’s
and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New
Jersey and New York) that resolved all issues related to the Sammis NSR
litigation was approved by the Court on July 11, 2005. This settlement
agreement, in the form of a consent decree, requires reductions of NOX and
SO2
emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants
through the installation of pollution control devices or repowering and provides
for stipulated penalties for failure to install and operate such pollution
controls or complete repowering in accordance with that agreement. Capital
expenditures necessary to complete requirements of the Sammis NSR Litigation
consent decree, including repowering Burger Units 4 and 5 for biomass fuel
consumption, are currently estimated to be $706 million for 2009-2012 (with
$414 million expected to be spent in 2009).
On May 22, 2007,
FirstEnergy and FGCO received a notice letter, required 60 days prior to the
filing of a citizen suit under the federal CAA, alleging violations of air
pollution laws at the Bruce Mansfield Plant, including opacity limitations.
Prior to the receipt of this notice, the Plant was subject to a Consent Order
and Agreement with the Pennsylvania Department of Environmental Protection
concerning opacity emissions under which efforts to achieve compliance with the
applicable laws will continue. On October 18, 2007, PennFuture filed a
complaint, joined by three of its members, in the United States District Court
for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed
a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the
Court denied the motion to dismiss, but also ruled that monetary damages could
not be recovered under the public nuisance claim. In July 2008, three additional
complaints were filed against FGCO in the United States District Court for the
Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant
air emissions. In addition to seeking damages, two of the complaints seek to
enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible,
prudent and proper manner”, one being a complaint filed on behalf of twenty-one
individuals and the other being a class action complaint, seeking certification
as a class action with the eight named plaintiffs as the class representatives.
On October 14, 2008, the Court granted FGCO’s motion to consolidate
discovery for all four complaints pending against the Bruce Mansfield Plant.
FGCO believes the claims are without merit and intends to defend itself against
the allegations made in these complaints. The Pennsylvania Department of Health
and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed
their intention to conduct additional air monitoring in the vicinity of the
Mansfield plant.
On December 18,
2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations
at the Portland Generation Station against Reliant (the current owner and
operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in
1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that
"modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without
preconstruction NSR or permitting under the CAA's prevention of significant
deterioration program, and seeks injunctive relief, penalties, attorney fees and
mitigation of the harm caused by excess emissions. On March 14, 2008,
Met-Ed filed a motion to dismiss the citizen suit claims against it and a
stipulation in which the parties agreed that GPU, Inc. should be dismissed from
this case. On March 26, 2008, GPU, Inc. was dismissed by the United States
District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe
Energy is disputed. On October 30, 2008, the state of Connecticut filed a
Motion to Intervene, which the Court granted on March 24, 2009. On
December 5, 2008, New Jersey filed an amended complaint, adding claims with
respect to alleged modifications that occurred after GPU’s sale of the plant.
Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on
February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant
alleging new source review violations at the Portland Generation Station based
on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome
of this matter. The EPA’s January 14, 2009, NOV also alleged new source
review violations at the Keystone and Shawville Stations based on
“modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of
Keystone Station and Penelec, as former owner and operator of the Shawville
Station, are unable to predict the outcome of this matter.
On June 11, 2008,
the EPA issued a Notice and Finding of Violation to Mission Energy Westside,
Inc. alleging that "modifications" at the Homer City Power Station occurred
since 1988 to the present without preconstruction NSR or permitting under the
CAA's prevention of significant deterioration program. Mission Energy is seeking
indemnification from Penelec, the co-owner (along with New York State Electric
and Gas Company) and operator of the Homer City Power Station prior to its sale
in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy
is disputed. Penelec is unable to predict the outcome of this
matter.
On May 16, 2008,
FGCO received a request from the EPA for information pursuant to Section 114(a)
of the CAA for certain operating and maintenance information regarding the
Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA
to determine whether these generating sources are complying with the NSR
provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an
Administrative Consent Order modifying that request and setting forth a schedule
for FGCO’s response. On October 27, 2008, FGCO received a second request from
the EPA for information pursuant to Section 114(a) of the CAA for additional
operating and maintenance information regarding the Eastlake, Lakeshore, Bay
Shore and Ashtabula generating plants. FGCO intends to fully comply with the
EPA’s information requests, but, at this time, is unable to predict the outcome
of this matter.
On August 18, 2008,
FirstEnergy received a request from the EPA for information pursuant to Section
114(a) of the CAA for certain operating and maintenance information regarding
its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a
nearly identical request directed to the current owner, Reliant Energy, to allow
the EPA to determine whether these generating sources are complying with the NSR
provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s
information request, but, at this time, is unable to predict the outcome of this
matter.
National Ambient Air Quality
Standards
In March 2005,
the EPA finalized the CAIR covering a total of 28 states (including Michigan,
New Jersey, Ohio and Pennsylvania) and the District of Columbia based on
proposed findings that air emissions from 28 eastern states and the District of
Columbia significantly contribute to non-attainment of the NAAQS for fine
particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires
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),
ultimately capping SO2 emissions
in affected states to just 2.5 million tons annually and NOX emissions
to just 1.3 million tons annually. CAIR was challenged in the United States
Court of Appeals for the District of Columbia and on July 11, 2008, the Court
vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from
the ground up.” On September 24, 2008, the EPA, utility, mining and certain
environmental advocacy organizations petitioned the Court for a rehearing to
reconsider its ruling vacating CAIR. On December 23, 2008, the Court
reconsidered its prior ruling and allowed CAIR to remain in effect to
“temporarily preserve its environmental values” until the EPA replaces CAIR with
a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of
compliance with these regulations may be substantial and will depend, in part,
on the action taken by the EPA in response to the Court’s ruling.
Mercury Emissions
In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. In March 2005, the EPA finalized
the CAMR, which provides a cap-and-trade program to reduce mercury emissions
from coal-fired power plants in two phases; initially, capping national mercury
emissions at 38 tons by 2010 (as a "co-benefit" from implementation of
SO2
and NOX emission
caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states
and environmental groups appealed the CAMR to the United States Court of Appeals
for the District of Columbia. On February 8, 2008, the Court vacated the
CAMR, ruling that the EPA failed to take the necessary steps to “de-list”
coal-fired power plants from its hazardous air pollutant program and, therefore,
could not promulgate a cap-and-trade program. The EPA petitioned for rehearing
by the entire Court, which denied the petition on May 20, 2008. On
October 17, 2008, the EPA (and an industry group) petitioned the United
States Supreme Court for review of the Court’s ruling vacating CAMR. On February
6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23,
2009, the Supreme Court dismissed the EPA’s petition and denied the industry
group’s petition. The EPA is developing new mercury emission standards for
coal-fired power plants. FGCO’s future cost of compliance with mercury
regulations may be substantial and will depend on the action taken by the EPA
and on how they are ultimately implemented.
Pennsylvania has
submitted a new mercury rule for EPA approval that does not provide a
cap-and-trade approach as in the CAMR, but rather follows a command-and-control
approach imposing emission limits on individual sources. On January 30, 2009,
the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule
“unlawful, invalid and unenforceable” and enjoined the Commonwealth from
continued implementation or enforcement of that rule. It is anticipated that
compliance with these regulations, if the Commonwealth Court’s rulings were
reversed on appeal and Pennsylvania’s mercury rule was implemented, would not
require the addition of mercury controls at the Bruce Mansfield Plant,
FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at
all.
Climate Change
In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol, to address global warming by reducing the amount of man-made
GHG, including CO2, emitted
by developed countries by 2012. The United States signed the Kyoto Protocol in
1998 but it was never submitted for ratification by the United States Senate.
However, the Bush administration had committed the United States to a voluntary
climate change strategy to reduce domestic GHG intensity – the ratio of
emissions to economic output – by 18% through 2012. Also, in an April 16,
2008 speech, former President Bush set a policy goal of stopping the growth of
GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition,
the EPACT established a Committee on Climate Change Technology to coordinate
federal climate change activities and promote the development and deployment of
GHG reducing technologies. President Obama has announced his Administration’s
“New Energy for America Plan” that includes, among other provisions, ensuring
that 10% of electricity in the United States comes from renewable sources by
2012, and increasing to 25% by 2025; and implementing an economy-wide
cap-and-trade program to reduce GHG emissions 80% by 2050.
There are a number
of initiatives to reduce GHG emissions under consideration at the federal, state
and international level. At the international level, efforts to reach a new
global agreement to reduce GHG emissions post-2012 have begun with the Bali
Roadmap, which outlines a two-year process designed to lead to an agreement in
2009. At the federal level, members of Congress have introduced several bills
seeking to reduce emissions of GHG in the United States, and the Senate
Environment and Public Works Committee has passed one such bill. State
activities, primarily the northeastern states participating in the Regional
Greenhouse Gas Initiative and western states, led by California, have
coordinated efforts to develop regional strategies to control emissions of
certain GHGs.
On April 2, 2007,
the United States Supreme Court found that the EPA has the authority to regulate
CO2
emissions from automobiles as “air pollutants” under the CAA. Although this
decision did not address CO2 emissions
from electric generating plants, the EPA has similar authority under the CAA to
regulate “air pollutants” from those and other facilities. On April 17,
2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings
for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding
concludes that the atmospheric concentrations of several key greenhouse gases
threaten the health and welfare of future generations and that the combined
emissions of these gases by motor vehicles contribute to the atmospheric
concentrations of these key greenhouse gases and hence to the threat of climate
change. Although the EPA’s proposed finding, if finalized, does not establish
emission requirements for motor vehicles, such requirements would be expected to
occur through further rulemakings. Additionally, while the EPA’s proposed
findings do not specifically address stationary sources, including electric
generating plants, those findings, if finalized, would be expected to support
the establishment of future emission requirements by the EPA for stationary
sources.
FirstEnergy cannot
currently estimate the financial impact of climate change policies, although
potential legislative or regulatory programs restricting CO2 emissions
could require significant capital and other expenditures. The CO2 emissions
per KWH of electricity generated by FirstEnergy is lower than many regional
competitors due to its diversified generation sources, which include low or
non-CO2 emitting
gas-fired and nuclear generators.
Clean Water Act
Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio,
New Jersey and Pennsylvania have water quality standards applicable to
FirstEnergy's operations. As provided in the Clean Water Act, authority to grant
federal National Pollutant Discharge Elimination System water discharge permits
can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.
On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act for reducing impacts on fish and shellfish from cooling water
intake structures at certain existing large electric generating plants. The
regulations call for reductions in impingement mortality (when aquatic organisms
are pinned against screens or other parts of a cooling water intake system) and
entrainment (which occurs when aquatic life is drawn into a facility's cooling
water system). On January 26, 2007, the United States Court of Appeals for the
Second Circuit remanded portions of the rulemaking dealing with impingement
mortality and entrainment back to the EPA for further rulemaking and eliminated
the restoration option from the EPA’s regulations. On July 9, 2007, the EPA
suspended this rule, noting that until further rulemaking occurs, permitting
authorities should continue the existing practice of applying their best
professional judgment to minimize impacts on fish and shellfish from cooling
water intake structures. On April 1, 2009, the Supreme Court of the United
States reversed one significant aspect of the Second Circuit Court’s opinion and
decided that Section 316(b) of the Clean Water Act authorizes the EPA to
compare costs with benefits in determining the best technology available for
minimizing adverse environmental impact at cooling water intake structures.
FirstEnergy is studying various control options and their costs and
effectiveness. Depending on the results of such studies and the EPA’s further
rulemaking and any action taken by the states exercising best professional
judgment, the future costs of compliance with these standards may require
material capital expenditures.
The U.S. Attorney's
Office in Cleveland, Ohio has advised FGCO that it is considering prosecution
under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum
spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on
November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to
predict the outcome of this matter.
Regulation of Waste
Disposal
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 non-hazardous waste. In
February 2009, the EPA requested comments from the states on options for
regulating coal combustion wastes, including regulation as non-hazardous waste
or regulation as a hazardous waste. The future cost of compliance with coal
combustion waste regulations may be substantial and will depend, in part, on the
regulatory action taken by the EPA and implementation by the
states.
Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had
approximately $1.6 billion invested in external trusts to be used for the
decommissioning and environmental remediation of Davis-Besse, Beaver Valley,
Perry and TMI-2. As part of the application to the NRC to transfer the ownership
of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to
contribute another $80 million to these trusts by 2010. Consistent with NRC
guidance, utilizing a “real” rate of return on these funds of approximately 2%
over inflation, these trusts are expected to exceed the minimum decommissioning
funding requirements set by the NRC. Conservatively, these estimates do not
include any return that the trusts may earn over the 20-year plant useful life
extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of
the decommissioning of TMI-2) seeks for these facilities.
The Utilities have
been named as potentially responsible parties 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 potentially
responsible parties for a particular site may be liable on a joint and several
basis. Environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of March 31, 2009, based on
estimates of the total costs of cleanup, the Utilities' proportionate
responsibility for such costs and the financial ability of other unaffiliated
entities to pay. Total liabilities of approximately $91 million (JCP&L
- $64 million, TE - $1 million, CEI - $1 million and FirstEnergy
Corp. - $25 million) have been accrued through March 31, 2009.
Included in the total are accrued liabilities of approximately $56 million
for environmental remediation of former manufactured gas plants and gas holder
facilities in New Jersey, which are being recovered by JCP&L through a
non-bypassable SBC.
(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, the Muise class action) 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.
After various
motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common
law fraud, negligent misrepresentation, strict product liability, and punitive
damages were dismissed, leaving only the negligence and breach of contract
causes of actions. The class was decertified twice by the trial court, and
appealed both times by the Plaintiffs, with the results being that: (1) the
Appellate Division limited the class only to those customers directly impacted
by the outages of JCP&L transformers in Red Bank, NJ, based on a common
incident involving the failure of the bushings of two large transformers in the
Red Bank substation which resulted in planned and unplanned outages in the area
during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded
this matter back to the Trial Court to allow plaintiffs sufficient time to
establish a damage model or individual proof of damages. Proceedings then
continued at the trial court level and a case management conference with the
presiding Judge was held on June 13, 2008. At that conference, counsel for
the Plaintiffs stated his intent to drop his efforts to create a class-wide
damage model and, instead of dismissing the class action, expressed his desire
for a bifurcated trial on liability and damages. In response, JCP&L filed an
objection to the plaintiffs’ proposed trial plan and another motion to decertify
the class. On March 31, 2009, the trial court granted JCP&L’s motion to
decertify the class. On April 20, 2009, the Plaintiffs filed their appeal
to the trial court's decision to decertify the class.
Nuclear Plant Matters
On May 14, 2007, the
Office of Enforcement of the NRC issued a Demand for Information to FENOC,
following FENOC’s reply to an April 2, 2007 NRC request for information about
two reports prepared by expert witnesses for an insurance arbitration (the
insurance claim was subsequently withdrawn by FirstEnergy in December 2007)
related to Davis-Besse. The NRC indicated that this information was needed for
the NRC “to determine whether an Order or other action should be taken pursuant
to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to
operate its licensed facilities in accordance with the terms of its licenses and
the Commission’s regulations.” FENOC was directed to submit the information to
the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s
Demand for Information reaffirming that it accepts full responsibility for the
mistakes and omissions leading up to the damage to the reactor vessel head and
that it remains committed to operating Davis-Besse and FirstEnergy’s other
nuclear plants safely and responsibly. FENOC submitted a supplemental response
clarifying certain aspects of the response to the NRC on July 16, 2007. The
NRC issued a Confirmatory Order imposing these commitments on FENOC. In an
April 23, 2009 Inspection Report, the NRC concluded that FENOC had
completed all necessary actions required by the Confirmatory Order.
In August 2007,
FENOC submitted an application to the NRC to renew the operating licenses for
the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The
NRC is required by statute to provide an opportunity for members of the public
to request a hearing on the application. No members of the public, however,
requested a hearing on the Beaver Valley license renewal application. On
September 24, 2008, the NRC issued a draft supplemental Environmental Impact
Statement for Beaver Valley. FENOC will continue to work with the NRC Staff
as it completes its environmental and technical reviews of the license renewal
application, and expects to obtain renewed licenses for the Beaver Valley Power
Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley
Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and
2, respectively.
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.
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. On September 9, 2005, the arbitration panel issued an opinion to
award approximately $16 million to the bargaining unit employees. A final order
identifying the individual damage amounts was issued on October 31, 2007
and the award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. On February 25, 2009, the federal district court denied JCP&L’s motion
to vacate the arbitration decision and granted the union’s motion to confirm the
award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to
Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take
as long as 24 months. JCP&L recognized a liability for the potential
$16 million award in 2005. Post-judgment interest began to accrue as of
February 25, 2009, and the liability will be adjusted accordingly.
The union employees
at the Bruce Mansfield Plant have been working without a labor contract since
February 15, 2008. The parties are continuing to bargain with the
assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready
in the event of a strike.
The union employees
at Met-Ed have been working without a labor contract since May 1, 2009. The
parties are continuing to bargain and FirstEnergy has a work continuation plan
ready in the event of a strike.
FirstEnergy accrues
legal 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.
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.
9.
REGULATORY MATTERS
(A) RELIABILITY
INITIATIVES
In 2005, Congress
amended the Federal Power Act to provide for federally-enforceable mandatory
reliability standards. The mandatory reliability standards apply to the bulk
power system and impose certain operating, record-keeping and reporting
requirements on the Utilities and ATSI. The NERC is charged with establishing
and enforcing these reliability standards, although it has delegated day-to-day
implementation and enforcement of its responsibilities to eight regional
entities, including ReliabilityFirst Corporation. All of
FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy
actively participates in the NERC and ReliabilityFirst stakeholder processes,
and otherwise monitors and manages its companies in response to the ongoing
development, implementation and enforcement of the reliability
standards.
FirstEnergy believes
that it is in compliance with all currently-effective and enforceable
reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will
continue to refine existing reliability standards as well as to develop and
adopt new reliability standards. The financial impact of complying with new or
amended standards cannot be determined at this time. However, the 2005
amendments to the Federal Power Act provide that all prudent costs incurred to
comply with the new reliability standards be recovered in rates. Still, any
future inability on FirstEnergy’s part to comply with the reliability standards
for its bulk power system could result in the imposition of financial penalties
and thus have a material adverse effect on its financial condition, results of
operations and cash flows.
In April 2007,
ReliabilityFirst
performed a routine compliance audit of FirstEnergy’s bulk-power system within
the MISO region and found it to be in full compliance with all audited
reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine
compliance audit of FirstEnergy’s bulk-power system within the PJM region and
found it to be in full compliance with all audited reliability
standards.
On December 9, 2008,
a transformer at JCP&L’s Oceanview substation failed, resulting in an outage
on certain bulk electric system (transmission voltage) lines out of the
Oceanview and Atlantic substations, with customers in the affected area losing
power. Power was restored to most customers within a few hours and to all
customers within eleven hours. On December 16, 2008, JCP&L provided
preliminary information about the event to certain regulatory agencies,
including the NERC. On March 31, 2009, the NERC initiated a Compliance
Violation Investigation in order to determine JCP&L’s contribution to the
electrical event and to review any potential violation of NERC Reliability
Standards associated with the event. The initial phase of the investigation
requires JCP&L to respond to NERC’s request for factual data about the
outage. JCP&L submitted its written response on May 1, 2009. JCP&L
is not able at this time to predict what actions, if any, that NERC will take
upon receipt of JCP&L’s response to NERC’s data request.
(B) OHIO
On June 7, 2007, the
Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO and, on August 6, 2007, updated their filing to support
a distribution rate increase of $332 million. On December 4, 2007, the
PUCO Staff issued its Staff Reports containing the results of its investigation
into the distribution rate request. On January 21, 2009, the PUCO granted the
Ohio Companies’ application to increase electric distribution rates by $136.6
million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These
increases went into effect for OE and TE on January 23, 2009, and will go into
effect for CEI on May 1, 2009. Applications for rehearing of this order were
filed by the Ohio Companies and one other party on February 20, 2009. The PUCO
granted these applications for rehearing on March 18, 2009.
SB221, which became
effective on July 31, 2008, required all electric utilities to file an ESP,
and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies
filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the
MRO application; however, the PUCO later granted the Ohio Companies’ application
for rehearing for the purpose of further consideration of the matter. The ESP
proposed to phase in new generation rates for customers beginning in 2009 for up
to a three-year period and resolve the Ohio Companies’ collection of fuel costs
deferred in 2006 and 2007, and the distribution rate request described above. In
response to the PUCO’s December 19, 2008 order, which significantly modified and
approved the ESP as modified, the Ohio Companies notified the PUCO that they
were withdrawing and terminating the ESP application in addition to continuing
their current rate plan in effect as allowed by the terms of SB221. On
December 31, 2008, the Ohio Companies conducted a CBP for the procurement
of electric generation for retail customers from January 5, 2009 through March
31, 2009. The average winning bid price was equivalent to a retail rate of 6.98
cents per kwh. The power supply obtained through this process provides
generation service to the Ohio Companies’ retail customers who choose not to
shop with alternative suppliers. On January 9, 2009, the Ohio Companies
requested the implementation of a new fuel rider to recover the costs resulting
from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’
request for a new fuel rider to recover increased costs resulting from the CBP
but did not authorize OE and TE to continue collecting RTC or allow the Ohio
Companies to continue collections pursuant to the two existing fuel riders. The
new fuel rider allows for current recovery of the increased purchased power
costs for OE and TE, and authorizes CEI to collect a portion of those costs
currently and defer the remainder for future recovery.
On January 29, 2009,
the PUCO ordered its Staff to develop a proposal to establish an ESP for the
Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended
ESP application, including an attached Stipulation and Recommendation that was
signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening
parties. Specifically, the Amended ESP provides that generation will be provided
by FES at the average wholesale rate of the CBP process described above for
April and May 2009 to the Ohio Companies for their non-shopping customers; for
the period of June 1, 2009 through May 31, 2011, retail generation
prices will be based upon the outcome of a descending clock CBP on a
slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of
any increase resulting from this CBP process by authorizing deferral of related
purchased power costs, subject to specified limits. The Amended ESP further
provides that the Ohio Companies will not seek a base distribution rate
increase, subject to certain exceptions, with an effective date of such increase
before January 1, 2012, that CEI will agree to write-off approximately
$216 million of its Extended RTC balance, and that the Ohio Companies will
collect a delivery service improvement rider at an overall average rate of $.002
per kWh for the period of April 1, 2009 through December 31, 2011. The
Amended ESP also addresses a number of other issues, including but not limited
to, rate design for various customer classes, resolution of the prudence review
and the collection of deferred costs that were approved in prior proceedings. On
February 26, 2009, the Ohio Companies filed a Supplemental Stipulation,
which was signed or not opposed by virtually all of the parties to the
proceeding, that supplemented and modified certain provisions of the
February 19 Stipulation and Recommendation. Specifically, the Supplemental
Stipulation modified the provision relating to governmental aggregation and the
Generation Service Uncollectible Rider, provided further detail on the
allocation of the economic development funding contained in the Stipulation and
Recommendation, and proposed additional provisions related to the collaborative
process for the development of energy efficiency programs, among other
provisions. The PUCO adopted and approved certain aspects of the Stipulation and
Recommendation on March 4, 2009, and adopted and approved the remainder of the
Stipulation and Recommendation and Supplemental Stipulation without modification
on March 25, 2009. Certain aspects of the Stipulation and Recommendation
and Supplemental Stipulation take effect on April 1, 2009 while the
remaining provisions take effect on June 1, 2009. The CBP auction is currently
scheduled to begin on May 13, 2009. The bidding will occur for a single,
two-year product and there will not be a load cap for the
bidders. FES may participate without limitation.
SB221 also requires
electric distribution utilities to implement energy efficiency programs that
achieve an energy savings equivalent of approximately 166,000 MWH in 2009,
290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in
2013. Utilities are also required to reduce peak demand in 2009 by one percent,
with an additional seventy-five hundredths of one percent reduction each year
thereafter through 2018. Costs associated with compliance are
recoverable from customers.
(C)
PENNSYLVANIA
Met-Ed and Penelec
purchase a portion of their PLR and default service requirements from FES
through a fixed-price partial requirements wholesale power sales agreement. The
agreement allows Met-Ed and Penelec to sell the output of NUG energy to the
market and requires FES to provide energy at fixed prices to replace any NUG
energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and
default service obligations. If Met-Ed and Penelec were to replace the entire
FES supply at current market power prices without corresponding regulatory
authorization to increase their generation prices to customers, each company
would likely incur a significant increase in operating expenses and experience a
material deterioration in credit quality metrics. Under such a scenario, each
company's credit profile would no longer be expected to support an investment
grade rating for their fixed income securities. If FES ultimately determines to
terminate, reduce, or significantly modify the agreement prior to the expiration
of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief
is not likely to be granted by the PPUC. See FERC Matters below for a
description of the Third Restated Partial Requirements Agreement, executed by
the parties on October 31, 2008, that limits the amount of energy and
capacity FES must supply to Met-Ed and Penelec. In the event of a third party
supplier default, the increased costs to Met-Ed and Penelec could be
material.
On May 22, 2008, the
PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. Various intervenors filed
complaints against those filings. In addition, the PPUC ordered an investigation
to review the reasonableness of Met-Ed’s TSC, while at the same time allowing
Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15,
2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed
with its investigation and a litigation schedule was adopted. Hearings and
briefing for both Met-Ed and Penelec have concluded and the companies are
awaiting a Recommended Decision from the ALJ. The TSCs include a component from
under-recovery of actual transmission costs incurred during the prior period
(Met-Ed - $144 million and Penelec - $4 million) and future transmission
cost projections for June 2008 through May 2009 (Met-Ed - $258 million and
Penelec - $92 million). Met-Ed received PPUC approval for a transition
approach that would recover past under-recovered costs plus carrying charges
through the new TSC over thirty-one months and defer a portion of the projected
costs ($92 million) plus carrying charges for recovery through future TSCs
by December 31, 2010.
On April 15, 2009,
Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009
through May 31, 2010, as required in connection with the PPUC’s January
2007 rate order. For Penelec’s customers, the new TSC would result in an
approximate 1% decrease in monthly bills, reflecting projected PJM transmission
costs as well as a reconciliation for costs already incurred. The TSC for
Met-Ed’s customers would increase to recover the additional PJM charges paid by
Met-Ed in the previous year and to reflect updated projected costs. In order to
gradually transition customers to the higher rate, Met-Ed is proposing to
continue to recover the prior period deferrals allowed in the PPUC’s May 2008
Order and defer $57.5 million of projected costs into a future TSC to be fully
recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s
customers would increase approximately 9.4% for the period June 2009 through May
2010.
On October 15, 2008,
the Governor of Pennsylvania signed House Bill 2200 into law which became
effective on November 14, 2008 as Act 129 of 2008. The bill addresses
issues such as: energy efficiency and peak load reduction; generation
procurement; time-of-use rates; smart meters and alternative energy. Act 129
requires utilities to file with the PPUC an energy efficiency and peak load
reduction plan by July 1, 2009 and a smart meter procurement and
installation plan by August 14, 2009. On January 15, 2009, in compliance
with Act 129, the PPUC issued its proposed guidelines for the filing of
utilities’ energy efficiency and peak load reduction plans. Similar guidelines
related to Smart Meter deployment were issued for comment on March 30,
2009.
Major provisions of
the legislation include:
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power acquired
by utilities to serve customers after rate caps expire will be procured
through a competitive procurement process that must include a mix of
long-term and short-term contracts and spot market
purchases;
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the
competitive procurement process must be approved by the PPUC and may
include auctions, RFPs, and/or bilateral
agreements;
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utilities must
provide for the installation of smart meter technology within 15
years;
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a minimum
reduction in peak demand of 4.5% by May 31,
2013;
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minimum
reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31,
2013, respectively; and
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an expanded
definition of alternative energy to include additional types of
hydroelectric and biomass
facilities.
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Legislation
addressing rate mitigation and the expiration of rate caps was not enacted in
2008; however, several bills addressing these issues have been introduced in the
current legislative session, which began in January 2009. The final
form and impact of such legislation is uncertain.
On February 26,
2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and
Penelec that provides an opportunity for residential and small commercial
customers to prepay an amount on their monthly electric bills during 2009 and
2010. Customer prepayments earn interest at 7.5% and will be used to reduce
electricity charges in 2011 and 2012.
On February 20,
2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan
covering the period January 1, 2011 through May 31, 2013. The
companies’ plan is designed to provide adequate and reliable service via a
prudent mix of long-term, short-term and spot market generation supply, as
required by Act 129. The plan proposes a staggered procurement schedule,
which varies by customer class, through the use of a descending clock auction.
Met-Ed and Penelec have requested PPUC approval of their plan by November
2009.
On March 31, 2009,
Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the
PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to
reduce its CTC rate for the residential class with a corresponding increase in
the generation rate and the shopping credit, and Penelec proposed to reduce its
CTC rate to zero for all classes with a corresponding increase in the generation
rate and the shopping credit. While these changes would result in additional
annual generation revenue (Met-Ed - $27 million and Penelec - $51 million),
overall rates would remain unchanged. The PPUC must act on this filing within
120 days.
(D) NEW
JERSEY
JCP&L is
permitted to defer for future collection from customers the amounts by which its
costs of supplying BGS to non-shopping customers, costs incurred under NUG
agreements, and certain other stranded costs, exceed amounts collected through
BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31,
2009, the accumulated deferred cost balance totaled approximately
$165 million.
In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004, supporting 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 DPA filed comments on February 28, 2005
requesting that decommissioning funding be suspended. On March 18, 2005,
JCP&L filed a response to those comments. JCP&L responded to additional
NJBPU staff discovery requests in May and November 2007 and also submitted
comments in the proceeding in November 2007. A schedule for further NJBPU
proceedings has not yet been set. On March 13, 2009, JCP&L filed its
annual SBC Petition with the NJBPU that includes a request for a reduction in
the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2
decommissioning cost analysis dated January 2009. This matter is currently
pending before the NJBPU.
On August 1, 2005,
the NJBPU established a proceeding to determine whether additional ratepayer
protections are required at the state level in light of the repeal of the PUHCA
pursuant to the EPACT. The NJBPU approved regulations effective October 2,
2006 that prevent a holding company that owns a gas or electric public utility
from investing more than 25% of the combined assets of its utility and
utility-related subsidiaries into businesses unrelated to the utility industry.
These regulations are not expected to materially impact FirstEnergy or
JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional
draft proposal on March 31, 2006 addressing various issues including access
to books and records, ring-fencing, cross subsidization, corporate governance
and related matters. Following public hearing and consideration of comments from
interested parties, the NJBPU approved final regulations effective April 6,
2009. These regulations are not expected to materially impact FirstEnergy or
JCP&L.
New Jersey statutes
require that the state periodically undertake a planning process, known as the
EMP, to address energy related issues including energy security, economic
growth, and environmental impact. The EMP is to be developed with involvement of
the Governor’s Office and the Governor’s Office of Economic Growth, and is to be
prepared by a Master Plan Committee, which is chaired by the NJBPU President and
includes representatives of several State departments.
The EMP was issued
on October 22, 2008, establishing five major goals:
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maximize
energy efficiency to achieve a 20% reduction in energy consumption by
2020;
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reduce peak
demand for electricity by 5,700 MW by
2020;
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meet 30% of
the state’s electricity needs with renewable energy by
2020;
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examine smart
grid technology and develop additional cogeneration and other generation
resources consistent with the state’s greenhouse gas targets;
and
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invest in
innovative clean energy technologies and businesses to stimulate the
industry’s growth in New Jersey.
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On January 28, 2009,
the NJBPU adopted an order establishing the general process and contents of
specific EMP plans that must be filed by December 31, 2009 by New Jersey
electric and gas utilities in order to achieve the goals of the EMP. At this
time, FirstEnergy cannot determine the impact, if any, the EMP may have on its
operations or those of JCP&L.
In support of the
New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced
its intent to spend approximately $98 million on infrastructure and energy
efficiency projects in 2009. An estimated $40 million will be spent on
infrastructure projects, including substation upgrades, new transformers,
distribution line re-closers and automated breaker operations. Approximately
$34 million will be spent implementing new demand response programs as well
as expanding on existing programs. Another $11 million will be spent on
energy efficiency, specifically replacing transformers and capacitor control
systems and installing new LED street lights. The remaining $13 million
will be spent on energy efficiency programs that will complement those currently
being offered. Completion of the projects is dependent upon resolution of
regulatory issues including recovery of the costs associated with plan
implementation.
(E) FERC
MATTERS
Transmission Service between MISO and
PJM
On November 18,
2004, the FERC issued an order eliminating the through and out rate for
transmission service between the MISO and PJM regions. The FERC’s intent was to
eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM, and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. Briefs addressing the initial decision were filed on
September 11, 2006 and October 20, 2006. A final order is pending before
the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and
entering into settlement agreements with other parties in the docket to mitigate
the risk of lower transmission revenue collection associated with an adverse
order. On September 26, 2008, the MISO and PJM transmission owners filed a
motion requesting that the FERC approve the pending settlements and act on the
initial decision. On November 20, 2008, FERC issued an order approving
uncontested settlements, but did not rule on the initial decision. On December
19, 2008, an additional order was issued approving two contested
settlements.
PJM Transmission Rate
On January 31, 2005,
certain PJM transmission owners made filings with the FERC pursuant to a
settlement agreement previously approved by the FERC. JCP&L, Met-Ed and
Penelec were parties to that proceeding and joined in two of the filings. In the
first filing, the settling transmission owners submitted a filing justifying
continuation of their existing rate design within the PJM RTO. Hearings were
held and numerous parties appeared and litigated various issues concerning PJM
rate design; notably AEP, which proposed to create a "postage stamp", or average
rate for all high voltage transmission facilities across PJM and a zonal
transmission rate for facilities below 345 kV. This proposal would have the
effect of shifting recovery of the costs of high voltage transmission lines to
other transmission zones, including those where JCP&L, Met-Ed, and Penelec
serve load. On April 19, 2007, the FERC issued an order finding that the PJM
transmission owners’ existing “license plate” or zonal rate design was just and
reasonable and ordered that the current license plate rates for existing
transmission facilities be retained. On the issue of rates for new transmission
facilities, the FERC directed that costs for new transmission facilities that
are rated at 500 kV or higher are to be collected from all transmission zones
throughout the PJM footprint by means of a postage-stamp rate. Costs for new
transmission facilities that are rated at less than 500 kV, however, are to be
allocated on a “beneficiary pays” basis. The FERC found that PJM’s current
beneficiary-pays cost allocation methodology is not sufficiently detailed and,
in a related order that also was issued on April 19, 2007, directed that
hearings be held for the purpose of establishing a just and reasonable cost
allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007,
certain parties filed for rehearing of the FERC’s April 19, 2007 order. On
January 31, 2008, the requests for rehearing were denied. On February 11, 2008,
AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the
federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission,
the PUCO and Dayton Power & Light have also appealed these orders to the
Seventh Circuit Court of Appeals. The appeals of these parties and others have
been consolidated for argument in the Seventh Circuit. Oral argument was held on
April 13, 2009, and a decision is expected this summer.
The FERC’s orders on
PJM rate design will prevent the allocation of a portion of the revenue
requirement of existing transmission facilities of other utilities to JCP&L,
Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new
500 kV and above transmission facilities on a PJM-wide basis will reduce the
costs of future transmission to be recovered from the JCP&L, Met-Ed and
Penelec zones. A partial settlement agreement addressing the “beneficiary pays”
methodology for below 500 kV facilities, but excluding the issue of allocating
new facilities costs to merchant transmission entities, was filed on September
14, 2007. The agreement was supported by the FERC’s Trial Staff, and was
certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued
an order conditionally approving the settlement subject to the submission of a
compliance filing. The compliance filing was submitted on August 29, 2008,
and the FERC issued an order accepting the compliance filing on October 15,
2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate
cost responsibility assignments for below 500 kV upgrades included in
PJM’s Regional Transmission Expansion Planning process in accordance with
the settlement. The FERC conditionally accepted the compliance filing on
January 28, 2009. PJM submitted a further compliance filing on March 2,
2009, which was accepted by the FERC on April 10, 2009. The remaining
merchant transmission cost allocation issues were the subject of a hearing at
the FERC in May 2008. An initial decision was issued by the Presiding Judge on
September 18, 2008. PJM and FERC trial staff each filed a Brief on
Exceptions to the initial decision on October 20, 2008. Briefs Opposing
Exceptions were filed on November 10, 2008.
Post
Transition Period Rate Design
The FERC had
directed MISO, PJM, and the respective transmission owners to make filings on or
before August 1, 2007 to reevaluate transmission rate design within MISO, and
between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the
vast majority of transmission owners, including FirstEnergy affiliates, which
proposed to retain the existing transmission rate design. These filings were
approved by the FERC on January 31, 2008. As a result of the FERC’s approval,
the rates charged to FirstEnergy’s load-serving affiliates for transmission
service over existing transmission facilities in MISO and PJM are unchanged. In
a related filing, MISO and MISO transmission owners requested that the current
MISO pricing for new transmission facilities that spreads 20% of the cost of new
345 kV and higher transmission facilities across the entire MISO footprint
(known as the RECB methodology) be retained.
On September 17,
2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act
seeking to have the entire transmission rate design and cost allocation methods
used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory,
and to have the FERC fix a uniform regional transmission rate design and cost
allocation method for the entire MISO and PJM “Super Region” that recovers the
average cost of new and existing transmission facilities operated at voltages of
345 kV and above from all transmission customers. Lower voltage facilities would
continue to be recovered in the local utility transmission rate zone through a
license plate rate. AEP requested a refund effective October 1, 2007, or
alternatively, February 1, 2008. On January 31, 2008, the FERC issued an
order denying the complaint. The effect of this order is to prevent the shift of
significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request
by AEP was denied by the FERC on December 19, 2008. On February 17, 2009,
AEP appealed the FERC’s January 31, 2008, and December 19, 2008,
orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of
its affiliated operating utility companies, filed a motion to intervene on March
10, 2009.
Duquesne’s
Request to Withdraw from PJM
On November 8, 2007,
Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and
to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy
interests, including but not limited to the terms under which FirstEnergy’s
Beaver Valley Plant would continue to participate in PJM’s energy markets.
FirstEnergy, therefore, intervened and participated fully in all of the FERC
dockets that were related to Duquesne’s proposed move.
In November, 2008,
Duquesne and other parties, including FirstEnergy, negotiated a settlement that
would, among other things, allow for Duquesne to remain in PJM and provide for a
methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012
auction that excluded the Duquesne load. The settlement agreement was filed on
December 10, 2008 and approved by the FERC in an order issued on January 29,
2009. MISO opposed the settlement agreement pending resolution of exit fees
alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in
its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January
29, 2009 order approving the settlement. Thereafter, FirstEnergy and other
parties filed in opposition to the rehearing request. The PPUC's rehearing
request, and the pleadings in opposition thereto, are pending before the
FERC.
Changes
ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30,
2008, a group of PJM load-serving entities, state commissions, consumer
advocates, and trade associations (referred to collectively as the RPM Buyers)
filed a complaint at the FERC against PJM alleging that three of the
four transitional RPM auctions yielded prices that are unjust and
unreasonable under the Federal Power Act. On September 19, 2008, the FERC
denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’
request for a technical conference to review aspects of the RPM. The FERC also
ordered PJM to file on or before December 15, 2008, a report on potential
adjustments to the RPM program as suggested in a Brattle Group report. On
December 12, 2008, PJM filed proposed tariff amendments that would adjust
slightly the RPM program. PJM also requested that the FERC conduct a settlement
hearing to address changes to the RPM and suggested that the FERC should rule on
the tariff amendments only if settlement could not be reached in January, 2009.
The request for settlement hearings was granted. Settlement had not been reached
by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted
comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief
Judge issued an order terminating settlement talks. On February 9, 2009,
PJM and a group of stakeholders submitted an offer of settlement, which used the
PJM December 12, 2008 filing as its starting point, and stated that unless
otherwise specified, provisions filed by PJM on December 12, 2008,
apply.
On March 26, 2009,
the FERC accepted in part, and rejected in part, tariff provisions submitted by
PJM, revising certain parts of its RPM. Ordered changes included making
incremental improvements to RPM; however, the basic construct of RPM remains
intact. On April 3, 2009, PJM filed with the FERC requesting clarification on
certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM
submitted a compliance filing addressing the changes the FERC ordered in the
March 26, 2009 Order; numerous parties have filed requests for rehearing of
the March 26, 2009 Order. In addition, the FERC has indefinitely postponed
the technical conference on RPM granted in the FERC order of September 19,
2008.
MISO
Resource Adequacy Proposal
MISO made a filing
on December 28, 2007 that would create an enforceable planning reserve
requirement in the MISO tariff for load-serving entities such as the Ohio
Companies, Penn Power, and FES. This requirement is proposed to become effective
for the planning year beginning June 1, 2009. The filing would permit MISO to
establish the reserve margin requirement for load-serving entities based upon a
one day loss of load in ten years standard, unless the state utility regulatory
agency establishes a different planning reserve for load-serving entities in its
state. FirstEnergy believes the proposal promotes a mechanism that will result
in commitments from both load-serving entities and resources, including both
generation and demand side resources that are necessary for reliable resource
adequacy and planning in the MISO footprint. Comments on the filing were
submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource
Adequacy proposal on March 26, 2008, requiring MISO to submit to further
compliance filings. Rehearing requests are pending on the FERC’s March 26 Order.
On May 27, 2008, MISO submitted a compliance filing to address issues associated
with planning reserve margins. On June 17, 2008, various parties submitted
comments and protests to MISO’s compliance filing. FirstEnergy submitted
comments identifying specific issues that must be clarified and addressed. On
June 25, 2008, MISO submitted a second compliance filing establishing the
enforcement mechanism for the reserve margin requirement which establishes
deficiency payments for load-serving entities that do not meet the resource
adequacy requirements. Numerous parties, including FirstEnergy, protested this
filing.
On October 20, 2008,
the FERC issued three orders essentially permitting the MISO Resource Adequacy
program to proceed with some modifications. First, the FERC accepted MISO's
financial settlement approach for enforcement of Resource Adequacy subject to a
compliance filing modifying the cost of new entry penalty. Second, the FERC
conditionally accepted MISO's compliance filing on the qualifications for
purchased power agreements to be capacity resources, load forecasting, loss of
load expectation, and planning reserve zones. Additional compliance filings were
directed on accreditation of load modifying resources and price responsive
demand. Finally, the FERC largely denied rehearing of its March 26 order with
the exception of issues related to behind the meter resources and certain
ministerial matters. On November 19, 2008, MISO made various compliance
filings pursuant to these orders. Issuance of orders on rehearing and two of the
compliance filings occurred on February 19, 2009. No material changes were made
to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an
additional order on rehearing and compliance, approving MISO’s proposed
financial settlement provision for Resource Adequacy. The MISO Resource Adequacy
process is expected to start as planned effective June 1, 2009, the beginning of
the MISO planning year.
FES Sales to Affiliates
On October 24, 2008,
FES, on its own behalf and on behalf of its generation-controlling subsidiaries,
filed an application with the FERC seeking a waiver of the affiliate sales
restrictions between FES and the Ohio Companies. The purpose of the waiver is to
ensure that FES will be able to continue supplying a material portion of the
electric load requirements of the Ohio Companies after January 1, 2009
pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained
a similar waiver for electricity sales to its affiliates in New Jersey, New
York, and Pennsylvania. On December 23, 2008, the FERC issued an order
granting the waiver request and the Ohio Companies made the required compliance
filing on December 30, 2008. In January 2009,
several parties filed for rehearing of the FERC’s December 23, 2008 order. In
response, FES filed an answer to requests for rehearing on February 5, 2009. The
requests and responses are pending before the FERC.
FES supplied all of
the power requirements for the Ohio Companies pursuant to a Power Supply
Agreement that ended on December 31, 2008. On January 2, 2009, FES
signed an agreement to provide 75% of the Ohio Companies’ power requirements for
the period January 5, 2009 through March 31, 2009. Subsequently, FES
signed an agreement to provide 100% of the Ohio Companies’ power requirements
for the period April 1, 2009 through May 31, 2009. On March 4,
2009, the PUCO issued an order approving these two affiliate sales agreements.
FERC authorization for these affiliate sales was by means of the
December 23, 2008 waiver.
On October 31, 2008,
FES executed a Third Restated Partial Requirements Agreement with Met-Ed,
Penelec, and Waverly effective November 1, 2008. The Third Restated Partial
Requirements Agreement limits the amount of capacity and energy required to be
supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’
power supply requirements. Met-Ed, Penelec, and Waverly have committed resources
in place for the balance of their expected power supply during 2009 and 2010.
Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and
Waverly are responsible for obtaining additional power supply requirements
created by the default or failure of supply of their committed resources. Prices
for the power provided by FES were not changed in the Third Restated Partial
Requirements Agreement.
10.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP
FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for
the Asset or Liability Have Significantly Decreased and Identifying Transactions
That Are Not Orderly”
In April 2009, the
FASB issued Staff Position FAS 157-4, which provides additional guidance to
consider in estimating fair value when there has been a significant decrease in
market activity for a financial asset. The FSP establishes a two-step process
requiring a reporting entity to first determine if a market is not active in
relation to normal market activity for the asset. If evidence indicates the
market is not active, an entity would then need to determine whether a quoted
price in the market is associated with a distressed transaction. An entity will
need to further analyze the transactions or quoted prices, and an adjustment to
the transactions or quoted prices may be necessary to estimate fair value.
Additional disclosures related to the inputs and valuation techniques used in
the fair value measurements are also required. The FSP is effective for interim
and annual periods ending after June 15, 2009, with early adoption permitted for
periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its
interim period ending June 30, 2009. While the FSP will expand disclosure
requirements, FirstEnergy does not expect the FSP to have a material effect upon
its financial statements.
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FSP
FAS 115-2 and FAS 124-2 - “Recognition and Presentation of
Other-Than-Temporary Impairments”
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In April 2009, the
FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to
determine whether an other-than-temporary impairment exists for debt securities
and the amount of impairment to be recorded in earnings. Under the FSP,
management will be required to assert it does not have the intent to sell the
debt security, and it is more likely than not it will not have to sell the debt
security before recovery of its cost basis. If management is unable to make
these assertions, the debt security will be deemed other-than-temporarily
impaired and the security will be written down to fair value with the full
charge recorded through earnings. If management is able to make the assertions,
but there are credit losses associated with the debt security, the portion of
impairment related to credit losses will be recognized in earnings while the
remaining impairment will be recognized through other comprehensive income. The
FSP is effective for interim and annual reporting periods ending after June 15,
2009, with early adoption permitted for periods ending after March 15, 2009.
FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and
does not expect the FSP to have a material effect upon its financial
statements.
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FSP
FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of
Financial Instruments”
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In April 2009, the
FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of
the fair value of financial instruments in interim financial statements, as well
as in annual financial statements. The FSP also requires entities to disclose
the methods and significant assumptions used to estimate the fair value of
financial instruments in both interim and annual financial statements. The FSP
is effective for interim and annual reporting periods ending after June 15,
2009, with early adoption permitted for periods ending after March 15, 2009.
FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and
expects to expand its disclosures regarding the fair value of financial
instruments.
FSP FAS 132 (R)-1 – “Employers’
Disclosures about Postretirement Benefit Plan Assets”
In December 2008,
the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. Requirements of this FSP include disclosures about
investment policies and strategies, categories of plan assets, fair value
measurements of plan assets, and significant categories of risk. This FSP is
effective for fiscal years ending after December 15, 2009. FirstEnergy will
expand its disclosures related to postretirement benefit plan assets as a result
of this FSP.
11.
SEGMENT INFORMATION
FirstEnergy has
three reportable operating segments: energy delivery services, competitive
energy services and Ohio transitional generation services. The assets and
revenues for all other business operations are below the quantifiable threshold
for operating segments for separate disclosure as “reportable operating
segments.”
The energy delivery
services segment designs, constructs, operates and maintains FirstEnergy's
regulated transmission and distribution systems and is responsible for the
regulated generation commodity operations of FirstEnergy’s Pennsylvania and New
Jersey electric utility subsidiaries. Its revenues are primarily derived from
the delivery of electricity, cost recovery of regulatory assets, and default
service electric generation sales to non-shopping customers in its Pennsylvania
and New Jersey franchise areas. Its results reflect the commodity costs of
securing electric generation from FES under partial requirements purchased power
agreements and from non-affiliated power suppliers as well as the net PJM
transmission expenses related to the delivery of that generation
load.
The competitive
energy services segment supplies electric power to its electric utility
affiliates, provides competitive electricity sales primarily in Ohio,
Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s
generating facilities and purchases electricity to meet its sales obligations.
The segment's net income is primarily derived from the affiliated company PSA
sales and the non-affiliated electric generation sales revenues less the related
costs of electricity generation, including purchased power and net transmission
(including congestion) and ancillary costs charged by PJM and MISO to deliver
electricity to the segment’s customers. The segment’s internal revenues
represent the affiliated company PSA sales.
The Ohio
transitional generation services segment represents the regulated generation
commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its
revenues are primarily derived from electric generation sales to non-shopping
customers under the PLR obligations of the Ohio Companies. Its results reflect
the purchase of electricity from third parties and the competitive energy
services segment through a CBP, the deferral and amortization of certain fuel
costs authorized for recovery by the energy delivery services segment and the
net MISO transmission revenues and expenses related to the delivery of
generation load. This segment’s total assets consist of accounts receivable for
generation revenues from retail customers.
Segment
Financial Information
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Ohio
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Energy
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Competitive
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Transitional
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Delivery
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Energy
|
|
|
Generation
|
|
|
|
|
|
Reconciling
|
|
|
|
|
Three
Months Ended
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Other
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
March 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
2,109 |
|
|
$ |
335 |
|
|
$ |
912 |
|
|
$ |
7 |
|
|
$ |
(29 |
) |
|
$ |
3,334 |
|
Internal
revenues
|
|
|
- |
|
|
|
893 |
|
|
|
- |
|
|
|
- |
|
|
|
(893 |
) |
|
|
- |
|
Total
revenues
|
|
|
2,109 |
|
|
|
1,228 |
|
|
|
912 |
|
|
|
7 |
|
|
|
(922 |
) |
|
|
3,334 |
|
Depreciation
and amortization
|
|
|
472 |
|
|
|
64 |
|
|
|
(45 |
) |
|
|
1 |
|
|
|
3 |
|
|
|
495 |
|
Investment
income (loss), net
|
|
|
29 |
|
|
|
(29 |
) |
|
|
1 |
|
|
|
- |
|
|
|
(12 |
) |
|
|
(11 |
) |
Net interest
charges
|
|
|
110 |
|
|
|
18 |
|
|
|
- |
|
|
|
1 |
|
|
|
37 |
|
|
|
166 |
|
Income
taxes
|
|
|
(28 |
) |
|
|
103 |
|
|
|
16 |
|
|
|
(17 |
) |
|
|
(20 |
) |
|
|
54 |
|
Net income
(loss)
|
|
|
(42 |
) |
|
|
155 |
|
|
|
24 |
|
|
|
17 |
|
|
|
(39 |
) |
|
|
115 |
|
Total
assets
|
|
|
22,669 |
|
|
|
9,925 |
|
|
|
336 |
|
|
|
632 |
|
|
|
(5 |
) |
|
|
33,557 |
|
Total
goodwill
|
|
|
5,550 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,574 |
|
Property
additions
|
|
|
165 |
|
|
|
421 |
|
|
|
- |
|
|
|
49 |
|
|
|
19 |
|
|
|
654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
2,212 |
|
|
$ |
329 |
|
|
$ |
707 |
|
|
$ |
40 |
|
|
$ |
(11 |
) |
|
$ |
3,277 |
|
Internal
revenues
|
|
|
- |
|
|
|
776 |
|
|
|
- |
|
|
|
- |
|
|
|
(776 |
) |
|
|
- |
|
Total
revenues
|
|
|
2,212 |
|
|
|
1,105 |
|
|
|
707 |
|
|
|
40 |
|
|
|
(787 |
) |
|
|
3,277 |
|
Depreciation
and amortization
|
|
|
255 |
|
|
|
53 |
|
|
|
4 |
|
|
|
- |
|
|
|
5 |
|
|
|
317 |
|
Investment
income (loss), net
|
|
|
45 |
|
|
|
(6 |
) |
|
|
1 |
|
|
|
- |
|
|
|
(23 |
) |
|
|
17 |
|
Net interest
charges
|
|
|
103 |
|
|
|
27 |
|
|
|
- |
|
|
|
- |
|
|
|
41 |
|
|
|
171 |
|
Income
taxes
|
|
|
119 |
|
|
|
58 |
|
|
|
15 |
|
|
|
14 |
|
|
|
(19 |
) |
|
|
187 |
|
Net
income
|
|
|
179 |
|
|
|
87 |
|
|
|
23 |
|
|
|
22 |
|
|
|
(34 |
) |
|
|
277 |
|
Total
assets
|
|
|
23,211 |
|
|
|
8,108 |
|
|
|
257 |
|
|
|
281 |
|
|
|
558 |
|
|
|
32,415 |
|
Total
goodwill
|
|
|
5,582 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,606 |
|
Property
additions
|
|
|
255 |
|
|
|
462 |
|
|
|
- |
|
|
|
12 |
|
|
|
(18 |
) |
|
|
711 |
|
Reconciling
adjustments to segment operating results from internal management reporting to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses and elimination of intersegment transactions.
12.
SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007,
FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1. FES has fully and unconditionally and
irrevocably guaranteed all of FGCO’s obligations under each of the leases. The
related lessor notes and pass through certificates are not guaranteed by FES or
FGCO, but the notes are secured by, among other things, each lessor trust’s
undivided interest in Unit 1, rights and interests under the applicable lease
and rights and interests under other related agreements, including FES’ lease
guaranty. This transaction is classified as an operating lease under
GAAP for FES and a financing for FGCO.
The condensed
consolidating statements of income for the three months ended March 31,
2009, and 2008, consolidating balance sheets as of March 31, 2009, and
December 31, 2008, and consolidating statements of cash flows for the three
months ended March 31, 2009, and 2008 for FES (parent and guarantor), FGCO
and NGC (non-guarantor) are presented below. Investments in wholly owned
subsidiaries are accounted for by FES using the equity method. Results of
operations for FGCO and NGC are, therefore, reflected in FES’ investment
accounts and earnings as if operating lease treatment was achieved. The
principal elimination entries eliminate investments in subsidiaries and
intercompany balances and transactions and the entries required to reflect
operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale
and leaseback transaction.
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended March 31, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
1,201,895 |
|
|
$ |
545,926 |
|
|
$ |
395,628 |
|
|
$ |
(917,343 |
) |
|
$ |
1,226,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,095 |
|
|
|
274,847 |
|
|
|
29,216 |
|
|
|
- |
|
|
|
306,158 |
|
Purchased
power from non-affiliates
|
|
|
160,342 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
160,342 |
|
Purchased
power from affiliates
|
|
|
915,261 |
|
|
|
2,082 |
|
|
|
63,207 |
|
|
|
(917,343 |
) |
|
|
63,207 |
|
Other
operating expenses
|
|
|
38,267 |
|
|
|
104,443 |
|
|
|
152,456 |
|
|
|
12,190 |
|
|
|
307,356 |
|
Provision for
depreciation
|
|
|
1,019 |
|
|
|
30,020 |
|
|
|
31,649 |
|
|
|
(1,315 |
) |
|
|
61,373 |
|
General
taxes
|
|
|
4,706 |
|
|
|
12,626 |
|
|
|
6,044 |
|
|
|
- |
|
|
|
23,376 |
|
Total
expenses
|
|
|
1,121,690 |
|
|
|
424,018 |
|
|
|
282,572 |
|
|
|
(906,468 |
) |
|
|
921,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
80,205 |
|
|
|
121,908 |
|
|
|
113,056 |
|
|
|
(10,875 |
) |
|
|
304,294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income
from equity investees
|
|
|
120,513 |
|
|
|
(47 |
) |
|
|
(29,637 |
) |
|
|
(117,192 |
) |
|
|
(26,363 |
) |
Interest
expense to affiliates
|
|
|
(34 |
) |
|
|
(1,758 |
) |
|
|
(1,187 |
) |
|
|
- |
|
|
|
(2,979 |
) |
Interest
expense - other
|
|
|
(2,520 |
) |
|
|
(21,058 |
) |
|
|
(15,168 |
) |
|
|
16,219 |
|
|
|
(22,527 |
) |
Capitalized
interest
|
|
|
51 |
|
|
|
7,750 |
|
|
|
2,277 |
|
|
|
- |
|
|
|
10,078 |
|
Total other
income (expense)
|
|
|
118,010 |
|
|
|
(15,113 |
) |
|
|
(43,715 |
) |
|
|
(100,973 |
) |
|
|
(41,791 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
198,215 |
|
|
|
106,795 |
|
|
|
69,341 |
|
|
|
(111,848 |
) |
|
|
262,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
27,534 |
|
|
|
39,142 |
|
|
|
22,929 |
|
|
|
2,217 |
|
|
|
91,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
170,681 |
|
|
$ |
67,653 |
|
|
$ |
46,412 |
|
|
$ |
(114,065 |
) |
|
$ |
170,681 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended March 31, 2008
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
1,099,848 |
|
|
$ |
567,701 |
|
|
$ |
325,684 |
|
|
$ |
(894,117 |
) |
|
$ |
1,099,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
2,138 |
|
|
|
291,239 |
|
|
|
28,312 |
|
|
|
- |
|
|
|
321,689 |
|
Purchased
power from non-affiliates
|
|
|
206,724 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
206,724 |
|
Purchased
power from affiliates
|
|
|
891,979 |
|
|
|
2,138 |
|
|
|
25,485 |
|
|
|
(894,117 |
) |
|
|
25,485 |
|
Other
operating expenses
|
|
|
37,596 |
|
|
|
107,167 |
|
|
|
139,595 |
|
|
|
12,188 |
|
|
|
296,546 |
|
Provision for
depreciation
|
|
|
307 |
|
|
|
26,599 |
|
|
|
24,194 |
|
|
|
(1,358 |
) |
|
|
49,742 |
|
General
taxes
|
|
|
5,415 |
|
|
|
11,570 |
|
|
|
6,212 |
|
|
|
- |
|
|
|
23,197 |
|
Total
expenses
|
|
|
1,144,159 |
|
|
|
438,713 |
|
|
|
223,798 |
|
|
|
(883,287 |
) |
|
|
923,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
(44,311 |
) |
|
|
128,988 |
|
|
|
101,886 |
|
|
|
(10,830 |
) |
|
|
175,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income
from equity investees
|
|
|
121,725 |
|
|
|
(1,208 |
) |
|
|
(6,537 |
) |
|
|
(116,884 |
) |
|
|
(2,904 |
) |
Interest
expense to affiliates
|
|
|
(82 |
) |
|
|
(5,289 |
) |
|
|
(1,839 |
) |
|
|
- |
|
|
|
(7,210 |
) |
Interest
expense - other
|
|
|
(3,978 |
) |
|
|
(25,968 |
) |
|
|
(11,018 |
) |
|
|
16,429 |
|
|
|
(24,535 |
) |
Capitalized
interest
|
|
|
21 |
|
|
|
6,228 |
|
|
|
414 |
|
|
|
- |
|
|
|
6,663 |
|
Total other
income (expense)
|
|
|
117,686 |
|
|
|
(26,237 |
) |
|
|
(18,980 |
) |
|
|
(100,455 |
) |
|
|
(27,986 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
73,375 |
|
|
|
102,751 |
|
|
|
82,906 |
|
|
|
(111,285 |
) |
|
|
147,747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES (BENEFIT)
|
|
|
(16,609 |
) |
|
|
39,285 |
|
|
|
32,764 |
|
|
|
2,323 |
|
|
|
57,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
89,984 |
|
|
$ |
63,466 |
|
|
$ |
50,142 |
|
|
$ |
(113,608 |
) |
|
$ |
89,984 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of March 31, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
- |
|
|
$ |
34 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
34 |
|
Receivables-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
54,554 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
54,554 |
|
Associated
companies
|
|
|
295,513 |
|
|
|
192,816 |
|
|
|
125,514 |
|
|
|
(325,908 |
) |
|
|
287,935 |
|
Other
|
|
|
2,562 |
|
|
|
14,705 |
|
|
|
49,026 |
|
|
|
- |
|
|
|
66,293 |
|
Notes
receivable from associated companies
|
|
|
404,869 |
|
|
|
28,268 |
|
|
|
- |
|
|
|
- |
|
|
|
433,137 |
|
Materials and
supplies, at average cost
|
|
|
8,610 |
|
|
|
349,038 |
|
|
|
210,039 |
|
|
|
- |
|
|
|
567,687 |
|
Prepayments
and other
|
|
|
84,466 |
|
|
|
26,589 |
|
|
|
1,107 |
|
|
|
- |
|
|
|
112,162 |
|
|
|
|
850,574 |
|
|
|
611,450 |
|
|
|
385,686 |
|
|
|
(325,908 |
) |
|
|
1,521,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
88,064 |
|
|
|
5,477,939 |
|
|
|
4,736,544 |
|
|
|
(389,944 |
) |
|
|
9,912,603 |
|
Less -
Accumulated provision for depreciation
|
|
|
10,821 |
|
|
|
2,732,040 |
|
|
|
1,755,879 |
|
|
|
(171,499 |
) |
|
|
4,327,241 |
|
|
|
|
77,243 |
|
|
|
2,745,899 |
|
|
|
2,980,665 |
|
|
|
(218,445 |
) |
|
|
5,585,362 |
|
Construction
work in progress
|
|
|
4,728 |
|
|
|
1,626,685 |
|
|
|
483,418 |
|
|
|
- |
|
|
|
2,114,831 |
|
|
|
|
81,971 |
|
|
|
4,372,584 |
|
|
|
3,464,083 |
|
|
|
(218,445 |
) |
|
|
7,700,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
- |
|
|
|
- |
|
|
|
995,476 |
|
|
|
- |
|
|
|
995,476 |
|
Long-term
notes receivable from associated companies
|
|
|
- |
|
|
|
- |
|
|
|
62,900 |
|
|
|
- |
|
|
|
62,900 |
|
Investment in
associated companies
|
|
|
3,712,870 |
|
|
|
- |
|
|
|
- |
|
|
|
(3,712,870 |
) |
|
|
- |
|
Other
|
|
|
1,714 |
|
|
|
29,982 |
|
|
|
202 |
|
|
|
- |
|
|
|
31,898 |
|
|
|
|
3,714,584 |
|
|
|
29,982 |
|
|
|
1,058,578 |
|
|
|
(3,712,870 |
) |
|
|
1,090,274 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
deferred income tax benefits
|
|
|
18,209 |
|
|
|
458,730 |
|
|
|
- |
|
|
|
(235,332 |
) |
|
|
241,607 |
|
Lease
assignment receivable from associated companies
|
|
|
- |
|
|
|
71,356 |
|
|
|
- |
|
|
|
- |
|
|
|
71,356 |
|
Goodwill
|
|
|
24,248 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
24,248 |
|
Property
taxes
|
|
|
- |
|
|
|
27,494 |
|
|
|
22,610 |
|
|
|
- |
|
|
|
50,104 |
|
Unamortized
sale and leaseback costs
|
|
|
- |
|
|
|
32,128 |
|
|
|
- |
|
|
|
54,174 |
|
|
|
86,302 |
|
Other
|
|
|
65,233 |
|
|
|
58,004 |
|
|
|
8,332 |
|
|
|
(44,428 |
) |
|
|
87,141 |
|
|
|
|
107,690 |
|
|
|
647,712 |
|
|
|
30,942 |
|
|
|
(225,586 |
) |
|
|
560,758 |
|
|
|
$ |
4,754,819 |
|
|
$ |
5,661,728 |
|
|
$ |
4,939,289 |
|
|
$ |
(4,482,809 |
) |
|
$ |
10,873,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
708 |
|
|
$ |
930,763 |
|
|
$ |
777,218 |
|
|
$ |
(17,747 |
) |
|
$ |
1,690,942 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
- |
|
|
|
345,664 |
|
|
|
440,452 |
|
|
|
- |
|
|
|
786,116 |
|
Other
|
|
|
1,100,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,100,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
361,848 |
|
|
|
132,694 |
|
|
|
232,204 |
|
|
|
(317,586 |
) |
|
|
409,160 |
|
Other
|
|
|
27,081 |
|
|
|
117,756 |
|
|
|
- |
|
|
|
- |
|
|
|
144,837 |
|
Accrued
taxes
|
|
|
22,861 |
|
|
|
75,462 |
|
|
|
45,300 |
|
|
|
(20,889 |
) |
|
|
122,734 |
|
Other
|
|
|
58,938 |
|
|
|
112,048 |
|
|
|
23,023 |
|
|
|
45,975 |
|
|
|
239,984 |
|
|
|
|
1,571,436 |
|
|
|
1,714,387 |
|
|
|
1,518,197 |
|
|
|
(310,247 |
) |
|
|
4,493,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
3,120,406 |
|
|
|
1,901,085 |
|
|
|
1,797,764 |
|
|
|
(3,698,849 |
) |
|
|
3,120,406 |
|
Long-term debt
and other long-term obligations
|
|
|
21,819 |
|
|
|
1,466,373 |
|
|
|
469,839 |
|
|
|
(1,287,970 |
) |
|
|
670,061 |
|
|
|
|
3,142,225 |
|
|
|
3,367,458 |
|
|
|
2,267,603 |
|
|
|
(4,986,819 |
) |
|
|
3,790,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gain
on sale and leaseback transaction
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,018,156 |
|
|
|
1,018,156 |
|
Accumulated
deferred income taxes
|
|
|
- |
|
|
|
- |
|
|
|
203,899 |
|
|
|
(203,899 |
) |
|
|
- |
|
Accumulated
deferred investment tax credits
|
|
|
- |
|
|
|
38,669 |
|
|
|
22,976 |
|
|
|
- |
|
|
|
61,645 |
|
Asset
retirement obligations
|
|
|
- |
|
|
|
24,274 |
|
|
|
852,799 |
|
|
|
- |
|
|
|
877,073 |
|
Retirement
benefits
|
|
|
23,242 |
|
|
|
175,561 |
|
|
|
- |
|
|
|
- |
|
|
|
198,803 |
|
Property
taxes
|
|
|
- |
|
|
|
27,494 |
|
|
|
22,610 |
|
|
|
- |
|
|
|
50,104 |
|
Lease market
valuation liability
|
|
|
- |
|
|
|
296,376 |
|
|
|
- |
|
|
|
- |
|
|
|
296,376 |
|
Other
|
|
|
17,916 |
|
|
|
17,509 |
|
|
|
51,205 |
|
|
|
- |
|
|
|
86,630 |
|
|
|
|
41,158 |
|
|
|
579,883 |
|
|
|
1,153,489 |
|
|
|
814,257 |
|
|
|
2,588,787 |
|
|
|
$ |
4,754,819 |
|
|
$ |
5,661,728 |
|
|
$ |
4,939,289 |
|
|
$ |
(4,482,809 |
) |
|
$ |
10,873,027 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31, 2008
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
- |
|
|
$ |
39 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
39 |
|
Receivables-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
86,123 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
86,123 |
|
Associated
companies
|
|
|
363,226 |
|
|
|
225,622 |
|
|
|
113,067 |
|
|
|
(323,815 |
) |
|
|
378,100 |
|
Other
|
|
|
991 |
|
|
|
11,379 |
|
|
|
12,256 |
|
|
|
- |
|
|
|
24,626 |
|
Notes
receivable from associated companies
|
|
|
107,229 |
|
|
|
21,946 |
|
|
|
- |
|
|
|
- |
|
|
|
129,175 |
|
Materials and
supplies, at average cost
|
|
|
5,750 |
|
|
|
303,474 |
|
|
|
212,537 |
|
|
|
- |
|
|
|
521,761 |
|
Prepayments
and other
|
|
|
76,773 |
|
|
|
35,102 |
|
|
|
660 |
|
|
|
- |
|
|
|
112,535 |
|
|
|
|
640,092 |
|
|
|
597,562 |
|
|
|
338,520 |
|
|
|
(323,815 |
) |
|
|
1,252,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
134,905 |
|
|
|
5,420,789 |
|
|
|
4,705,735 |
|
|
|
(389,525 |
) |
|
|
9,871,904 |
|
Less -
Accumulated provision for depreciation
|
|
|
13,090 |
|
|
|
2,702,110 |
|
|
|
1,709,286 |
|
|
|
(169,765 |
) |
|
|
4,254,721 |
|
|
|
|
121,815 |
|
|
|
2,718,679 |
|
|
|
2,996,449 |
|
|
|
(219,760 |
) |
|
|
5,617,183 |
|
Construction
work in progress
|
|
|
4,470 |
|
|
|
1,441,403 |
|
|
|
301,562 |
|
|
|
- |
|
|
|
1,747,435 |
|
|
|
|
126,285 |
|
|
|
4,160,082 |
|
|
|
3,298,011 |
|
|
|
(219,760 |
) |
|
|
7,364,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
- |
|
|
|
- |
|
|
|
1,033,717 |
|
|
|
- |
|
|
|
1,033,717 |
|
Long-term
notes receivable from associated companies
|
|
|
- |
|
|
|
- |
|
|
|
62,900 |
|
|
|
- |
|
|
|
62,900 |
|
Investment in
associated companies
|
|
|
3,596,152 |
|
|
|
- |
|
|
|
- |
|
|
|
(3,596,152 |
) |
|
|
- |
|
Other
|
|
|
1,913 |
|
|
|
59,476 |
|
|
|
202 |
|
|
|
- |
|
|
|
61,591 |
|
|
|
|
3,598,065 |
|
|
|
59,476 |
|
|
|
1,096,819 |
|
|
|
(3,596,152 |
) |
|
|
1,158,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
deferred income tax benefits
|
|
|
24,703 |
|
|
|
476,611 |
|
|
|
- |
|
|
|
(233,552 |
) |
|
|
267,762 |
|
Lease
assignment receivable from associated companies
|
|
|
- |
|
|
|
71,356 |
|
|
|
- |
|
|
|
- |
|
|
|
71,356 |
|
Goodwill
|
|
|
24,248 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
24,248 |
|
Property
taxes
|
|
|
- |
|
|
|
27,494 |
|
|
|
22,610 |
|
|
|
- |
|
|
|
50,104 |
|
Unamortized
sale and leaseback costs
|
|
|
- |
|
|
|
20,286 |
|
|
|
- |
|
|
|
49,646 |
|
|
|
69,932 |
|
Other
|
|
|
59,642 |
|
|
|
59,674 |
|
|
|
21,743 |
|
|
|
(44,625 |
) |
|
|
96,434 |
|
|
|
|
108,593 |
|
|
|
655,421 |
|
|
|
44,353 |
|
|
|
(228,531 |
) |
|
|
579,836 |
|
|
|
$ |
4,473,035 |
|
|
$ |
5,472,541 |
|
|
$ |
4,777,703 |
|
|
$ |
(4,368,258 |
) |
|
$ |
10,355,021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
5,377 |
|
|
$ |
925,234 |
|
|
$ |
1,111,183 |
|
|
$ |
(16,896 |
) |
|
$ |
2,024,898 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
1,119 |
|
|
|
257,357 |
|
|
|
6,347 |
|
|
|
- |
|
|
|
264,823 |
|
Other
|
|
|
1,000,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,000,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
314,887 |
|
|
|
221,266 |
|
|
|
250,318 |
|
|
|
(314,133 |
) |
|
|
472,338 |
|
Other
|
|
|
35,367 |
|
|
|
119,226 |
|
|
|
- |
|
|
|
- |
|
|
|
154,593 |
|
Accrued
taxes
|
|
|
8,272 |
|
|
|
60,385 |
|
|
|
30,790 |
|
|
|
(19,681 |
) |
|
|
79,766 |
|
Other
|
|
|
61,034 |
|
|
|
136,867 |
|
|
|
13,685 |
|
|
|
36,853 |
|
|
|
248,439 |
|
|
|
|
1,426,056 |
|
|
|
1,720,335 |
|
|
|
1,412,323 |
|
|
|
(313,857 |
) |
|
|
4,244,857 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
2,944,423 |
|
|
|
1,832,678 |
|
|
|
1,752,580 |
|
|
|
(3,585,258 |
) |
|
|
2,944,423 |
|
Long-term debt
and other long-term obligations
|
|
|
61,508 |
|
|
|
1,328,921 |
|
|
|
469,839 |
|
|
|
(1,288,820 |
) |
|
|
571,448 |
|
|
|
|
3,005,931 |
|
|
|
3,161,599 |
|
|
|
2,222,419 |
|
|
|
(4,874,078 |
) |
|
|
3,515,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gain
on sale and leaseback transaction
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,026,584 |
|
|
|
1,026,584 |
|
Accumulated
deferred income taxes
|
|
|
- |
|
|
|
- |
|
|
|
206,907 |
|
|
|
(206,907 |
) |
|
|
- |
|
Accumulated
deferred investment tax credits
|
|
|
- |
|
|
|
39,439 |
|
|
|
23,289 |
|
|
|
- |
|
|
|
62,728 |
|
Asset
retirement obligations
|
|
|
- |
|
|
|
24,134 |
|
|
|
838,951 |
|
|
|
- |
|
|
|
863,085 |
|
Retirement
benefits
|
|
|
22,558 |
|
|
|
171,619 |
|
|
|
- |
|
|
|
- |
|
|
|
194,177 |
|
Property
taxes
|
|
|
- |
|
|
|
27,494 |
|
|
|
22,610 |
|
|
|
- |
|
|
|
50,104 |
|
Lease market
valuation liability
|
|
|
- |
|
|
|
307,705 |
|
|
|
- |
|
|
|
- |
|
|
|
307,705 |
|
Other
|
|
|
18,490 |
|
|
|
20,216 |
|
|
|
51,204 |
|
|
|
- |
|
|
|
89,910 |
|
|
|
|
41,048 |
|
|
|
590,607 |
|
|
|
1,142,961 |
|
|
|
819,677 |
|
|
|
2,594,293 |
|
|
|
$ |
4,473,035 |
|
|
$ |
5,472,541 |
|
|
$ |
4,777,703 |
|
|
$ |
(4,368,258 |
) |
|
$ |
10,355,021 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended March 31, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CASH PROVIDED FROM OPERATING ACTIVITIES
|
|
$ |
200,420 |
|
|
$ |
28,545 |
|
|
$ |
118,902 |
|
|
$ |
- |
|
|
$ |
347,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
100,000 |
|
|
|
- |
|
|
|
- |
|
|
|
100,000 |
|
Short-term
borrowings, net
|
|
|
98,881 |
|
|
|
88,308 |
|
|
|
434,105 |
|
|
|
- |
|
|
|
621,294 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(1,189 |
) |
|
|
(626 |
) |
|
|
(334,101 |
) |
|
|
- |
|
|
|
(335,916 |
) |
Net cash
provided from financing activities
|
|
|
97,692 |
|
|
|
187,682 |
|
|
|
100,004 |
|
|
|
- |
|
|
|
385,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(358 |
) |
|
|
(198,631 |
) |
|
|
(213,816 |
) |
|
|
- |
|
|
|
(412,805 |
) |
Proceeds from
asset sales
|
|
|
- |
|
|
|
7,573 |
|
|
|
- |
|
|
|
- |
|
|
|
7,573 |
|
Sales of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
351,414 |
|
|
|
- |
|
|
|
351,414 |
|
Purchases of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
(356,904 |
) |
|
|
- |
|
|
|
(356,904 |
) |
Loans to
associated companies, net
|
|
|
(297,641 |
) |
|
|
(6,322 |
) |
|
|
- |
|
|
|
- |
|
|
|
(303,963 |
) |
Other
|
|
|
(113 |
) |
|
|
(18,852 |
) |
|
|
400 |
|
|
|
- |
|
|
|
(18,565 |
) |
Net cash used
for investing activities
|
|
|
(298,112 |
) |
|
|
(216,232 |
) |
|
|
(218,906 |
) |
|
|
- |
|
|
|
(733,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
- |
|
|
|
(5 |
) |
|
|
- |
|
|
|
- |
|
|
|
(5 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
- |
|
|
|
39 |
|
|
|
- |
|
|
|
- |
|
|
|
39 |
|
Cash and cash
equivalents at end of period
|
|
$ |
- |
|
|
$ |
34 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
34 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended March 31, 2008
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CASH PROVIDED FROM (USED FOR)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
$ |
273,827 |
|
|
$ |
(122,171 |
) |
|
$ |
8,108 |
|
|
$ |
188 |
|
|
$ |
159,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
400,000 |
|
|
|
646,975 |
|
|
|
234,921 |
|
|
|
- |
|
|
|
1,281,896 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
(135,063 |
) |
|
|
(153,540 |
) |
|
|
- |
|
|
|
(288,603 |
) |
Common stock
dividend payments
|
|
|
(10,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(10,000 |
) |
Net cash
provided from financing activities
|
|
|
390,000 |
|
|
|
511,912 |
|
|
|
81,381 |
|
|
|
- |
|
|
|
983,293 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(19,406 |
) |
|
|
(375,391 |
) |
|
|
(81,545 |
) |
|
|
(187 |
) |
|
|
(476,529 |
) |
Proceeds from
asset sales
|
|
|
- |
|
|
|
5,088 |
|
|
|
- |
|
|
|
- |
|
|
|
5,088 |
|
Sales of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
173,123 |
|
|
|
- |
|
|
|
173,123 |
|
Purchases of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
(181,079 |
) |
|
|
- |
|
|
|
(181,079 |
) |
Loans to
associated companies, net
|
|
|
(644,604 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(644,604 |
) |
Other
|
|
|
183 |
|
|
|
(19,438 |
) |
|
|
12 |
|
|
|
(1 |
) |
|
|
(19,244 |
) |
Net cash used
for investing activities
|
|
|
(663,827 |
) |
|
|
(389,741 |
) |
|
|
(89,489 |
) |
|
|
(188 |
) |
|
|
(1,143,245 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Cash and cash
equivalents at beginning of period
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
Cash and cash
equivalents at end of period
|
|
$ |
2 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
2 |
|
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Market Risk Information” in Item 2 above.
ITEM
4. CONTROLS AND PROCEDURES
(a) EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY
FirstEnergy’s chief
executive officer and chief financial officer have reviewed and evaluated the
effectiveness of the registrant's disclosure controls and procedures as of the
end of the period covered by this report. The term disclosure controls and
procedures means controls and other procedures of a registrant that are designed
to ensure that information required to be disclosed by the registrant in the
reports that it files or submits under the Securities Exchange Act of 1934 (15
U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the
time periods specified in the Securities and Exchange Commission's rules and
forms. Disclosure controls and procedures include, without limitation, controls
and procedures designed to ensure that information required to be disclosed by
an issuer in the reports that it files or submits under that Act is accumulated
and communicated to the registrant's management, including its principal
executive and principal financial officers, or persons performing similar
functions, as appropriate to allow timely decisions regarding required
disclosure. Based on that evaluation, those officers have concluded that the
registrant's disclosure controls and procedures are effective as of the end of
the period covered by this report.
(b)
CHANGES IN INTERNAL CONTROLS
During the quarter
ended March 31, 2009, there were no changes in FirstEnergy’s internal control
over financial reporting that have materially affected, or are reasonably likely
to materially affect, the registrant’s internal control over financial
reporting.
ITEM
4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND
PENELEC
(a) EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant's
chief executive officer and chief financial officer have reviewed and evaluated
the effectiveness of such registrant's disclosure controls and procedures as of
the end of the period covered by this report. The term disclosure controls and
procedures means controls and other procedures of a registrant that are designed
to ensure that information required to be disclosed by the registrant in the
reports that it files or submits under the Securities Exchange Act of 1934 (15
U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the
time periods specified in the Securities and Exchange Commission's rules and
forms. Disclosure controls and procedures include, without limitation, controls
and procedures designed to ensure that information required to be disclosed by
an issuer in the reports that it files or submits under that Act is accumulated
and communicated to the registrant's management, including its principal
executive and principal financial officers, or persons performing similar
functions, as appropriate to allow timely decisions regarding required
disclosure. Based on that evaluation, those officers have concluded that such
registrant's disclosure controls and procedures are effective as of the end of
the period covered by this report.
(b) CHANGES
IN INTERNAL CONTROLS
During the quarter
ended March 31, 2009, 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 8 and 9 of the Consolidated Financial Statements in Part I, Item 1 of
this Form 10-Q.
ITEM
1A. RISK FACTORS
FirstEnergy’s Annual
Report on Form 10-K for the year ended December 31, 2008 includes a detailed
discussion of its risk factors. The information presented below updates
certain of those risk factors and should be read in conjunction with the risk
factors and information disclosed in FirstEnergy’s Annual Report on Form
10-K.
FES’ Business is Affected By
Competitive Procurement Processes Approved by State Regulators
The adoption of
competitive bid processes for PLR generation supply in Ohio and Pennsylvania may
affect the amount of generation that FES sells to its utility affiliates in
those states. For example, the Amended ESP approved by the PUCO established a
competitive bid process for generation supply and pricing for a two-year period
beginning June 1, 2009 through May 31, 2011. FES intends to
participate in the CBP as a supplier and its results of operations and financial
condition will be impacted by the price and the percentage of the load for which
it is ultimately the supplier.
Competitive Power Markets
FES’ financial
performance depends upon its success in competing in wholesale and retail
markets in MISO and PJM. FES’ ability to compete successfully in these markets
is affected by, among other things, the efficiency and cost structure of its
generation fleet, market prices, demand for electricity, effectiveness of risk
management practices and the market rules established by state and federal
regulators.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
(c) FirstEnergy
The
table below includes information on a monthly basis regarding purchases made by
FirstEnergy of its common stock during the first quarter of 2009.
|
|
Period
|
|
|
|
January
|
|
February
|
|
March
|
|
First
Quarter
|
|
Total Number
of Shares Purchased (a)
|
|
23,535
|
|
20,090
|
|
887,792
|
|
931,417
|
|
Average Price
Paid per Share
|
|
$50.09
|
|
$46.20
|
|
$41.34
|
|
$41.67
|
|
Total Number
of Shares Purchased
|
|
|
|
|
|
|
|
|
|
As Part of Publicly Announced
Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum Number
(or Approximate Dollar
|
|
|
|
|
|
|
|
|
|
Value) of Shares that May Yet
Be
|
|
|
|
|
|
|
|
|
|
Purchased Under the Plans or
Programs
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(a)
|
Share amounts
reflect purchases on the open market to satisfy FirstEnergy's obligations
to deliver common stock under its 2007 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 2007 Incentive Compensation Plan and the Executive Deferred
Compensation Plan, and shares purchased as part of publicly announced
plans.
|
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
|
|
10.1
|
Form of
Director Indemnification Agreement
|
|
|
10.2
|
Form of
Management Director Indemnification 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-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
|
|
101*
|
The following
materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for
the three months ended March 31, 2009, formatted in XBRL (eXtensible
Business Reporting Language): (i) Consolidated Statements of Income and
Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated
Statements of Cash Flows, (iv) related notes to these financial statements
tagged as blocks of text and (v) document and entity
information.
|
|
FES
|
|
|
4.1
|
Open-End
Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June
19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust
Company, N.A., as Trustee
|
|
4.1(a)
|
First
Supplemental Indenture dated as of June 25, 2008 providing among other
things for First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and
First Mortgage Bonds, Guarantee Series B of 2008 due
2009
|
|
4.1(b)
|
Second
Supplemental Indenture dated as of March 1, 2009 providing among other
things for First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and
First Mortgage Bonds, Guarantee Series B of 2009 due
2023
|
|
4.1(c)
|
Third
Supplemental Indenture dated as of March 31, 2009 providing among other
things for First Mortgage Bonds, Collateral Series A of 2009 due
2011
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
OE
|
|
|
12
|
Fixed charge
ratios
|
|
15
|
Letter from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
CEI
|
|
|
12
|
Fixed charge
ratios
|
|
15
|
Letter from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
TE
|
|
|
4.1
|
First
Supplemental Indenture, dated as of April 24, 2009, between the Toledo
Edison Company and The Bank of New York Mellon Trust Company, N.A., as
trustee to the Indenture dated as of November 1, 2006 (incorporated by
reference to April 24, 2009 Form 8-K, Exhibit 4.1)
|
|
4.2
|
Officer’s
Certificate (including the Form of the 7.25% Senior Secured Notes due
2020), dated April 24, 2009 (incorporated by reference to April 24, 2009
Form 8-K, Exhibit 4.2)
|
|
4.3
|
Fifty-sixth
Supplemental Indenture, dated as of April 23, 2009, between The Toledo
Edison Company and JPMorgan Chase Bank, N.A., as trustee, to the Indenture
of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by
reference to April 24, 2009 Form 8-K, Exhibit 4.3)
|
|
4.4
|
Fifty-seventh
Supplemental Indenture, dated as of April 24, 2009, between the Toledo
Edison Company and The Bank of New York Mellon Trust Company, N.A., as
successor trustee, to the Indenture of Mortgage and Deed of Trust dated as
of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K,
Exhibit 4.4)
|
|
4.5
|
Form of First
Mortgage Bonds, 7.25% Series of 2009 Due 2020 (incorporated by reference
to April 24, 2009 Form 8-K, Exhibit 4.5)
|
|
12
|
Fixed charge
ratios
|
|
15
|
Letter from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
JCP&L
|
|
|
12
|
Fixed charge
ratios
|
|
15
|
Letter from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section
1350
|
Met-Ed
|
|
|
12
|
Fixed charge
ratios
|
|
15
|
Letter from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
Penelec
|
|
|
12
|
Fixed charge
ratios
|
|
15
|
Letter from
independent registered public accounting firm
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
* Users of this data are advised
pursuant to Rule 401 of Regulation S-T that the financial information contained
in the XBRL-Related Documents is unaudited and the purpose of submitting these
XBRL-Related Documents is to test the related format and technology and, as a
result, investors should not rely on the XBRL-Related Documents in making
investment decisions. Furthermore, users of this data are advised in
accordance with Rule 406T of Regulation S-T promulgated by the Securities and
Exchange Commission that this Interactive Data File is deemed not filed or part
of a registration statement or prospectus for purposes of sections 11 or 12 of
the Securities Act of 1933, as amended, is deemed not filed for purposes of
section 18 of the Securities Exchange Act of 1934, as amended, and
otherwise is not subject to liability under these sections.
Pursuant to
reporting requirements of respective financings, FirstEnergy, OE, CEI, TE,
JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an
exhibit to this Form 10-Q.
Pursuant to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy,
FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this
Form 10-Q any instrument with respect to long-term debt if the respective
total amount of securities authorized thereunder does not exceed 10% of its
respective total assets, but each hereby agrees to furnish to the SEC on request
any such documents.
SIGNATURES
Pursuant to the
requirements of the Securities Exchange Act of 1934, each Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.
May 7,
2009
|
FIRSTENERGY
CORP.
|
|
Registrant
|
|
|
|
FIRSTENERGY SOLUTIONS
CORP.
|
|
Registrant
|
|
|
|
OHIO EDISON COMPANY
|
|
Registrant
|
|
|
|
THE
CLEVELAND ELECTRIC
|
|
ILLUMINATING COMPANY
|
|
Registrant
|
|
|
|
THE TOLEDO EDISON
COMPANY
|
|
Registrant
|
|
|
|
METROPOLITAN EDISON
COMPANY
|
|
Registrant
|
|
|
|
PENNSYLVANIA ELECTRIC
COMPANY
|
|
Registrant
|
|
|
|
Harvey L.
Wagner
|
|
Vice
President, Controller
|
|
and Chief
Accounting Officer
|
|
JERSEY CENTRAL POWER & LIGHT
COMPANY
|
|
Registrant
|
|
|
|
|
|
|
|
|
|
Paulette R.
Chatman
|
|
Controller
|
|
(Principal
Accounting Officer)
|