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 June 30, 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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000-53742
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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 (X) No ( )
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FirstEnergy
Corp.
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Yes ( )
No ( )
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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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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
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,
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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
impacts 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,
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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. A security
rating is not a recommendation to buy, sell or hold securities that may be
subject to revision or withdrawal at any time by the assigning rating
organization. Each rating should be evaluated independently of any other rating.
The registrants expressly disclaim any current intention to update any
forward-looking statements contained herein as a result of new information,
future events or otherwise.
TABLE
OF CONTENTS
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Pages
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Glossary of Terms
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iii-v
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Part
I. Financial Information
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Items 1. and 2. - Financial
Statements and Management's Discussion and Analysis 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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Results of Operations
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1-44
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Report of
Independent Registered Public Accounting Firm
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45
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Consolidated
Statements of Income
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46
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Consolidated
Statements of Comprehensive Income
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47
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Consolidated
Balance Sheets
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48
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Consolidated
Statements of Cash Flows
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49
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FirstEnergy Solutions
Corp.
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Management's
Narrative Analysis of Results of Operations
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50-53
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Report of
Independent Registered Public Accounting Firm
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54
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Consolidated
Statements of Income and Comprehensive Income
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55
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Consolidated
Balance Sheets
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56
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Consolidated
Statements of Cash Flows
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57
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Ohio Edison
Company
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Management's
Narrative Analysis of Results of Operations
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58-59
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Report of
Independent Registered Public Accounting Firm
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60
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Consolidated
Statements of Income and Comprehensive Income
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61
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Consolidated
Balance Sheets
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62
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Consolidated
Statements of Cash Flows
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63
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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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64-65
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Report of
Independent Registered Public Accounting Firm
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66
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Consolidated
Statements of Income and Comprehensive Income
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67
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Consolidated
Balance Sheets
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68
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Consolidated
Statements of Cash Flows
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69
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The Toledo Edison
Company
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Management's
Narrative Analysis of Results of Operations
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70-71
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Report of
Independent Registered Public Accounting Firm
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72
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Consolidated
Statements of Income and Comprehensive Income
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73
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Consolidated
Balance Sheets
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74
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Consolidated
Statements of Cash Flows
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75
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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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76-77
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Report of
Independent Registered Public Accounting Firm
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78
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Consolidated
Statements of Income and Comprehensive Income
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79
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Consolidated
Balance Sheets
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80
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Consolidated
Statements of Cash Flows
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81
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Metropolitan Edison
Company
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Management's
Narrative Analysis of Results of Operations
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82-83
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Report of
Independent Registered Public Accounting Firm
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84
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Consolidated
Statements of Income and Comprehensive Income
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85
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Consolidated
Balance Sheets
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86
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Consolidated
Statements of Cash Flows
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87
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Pennsylvania Electric
Company
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Management's
Narrative Analysis of Results of Operations
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88-89
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Report of
Independent Registered Public Accounting Firm
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90
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Consolidated
Statements of Income and Comprehensive Income
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91
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Consolidated
Balance Sheets
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92
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Consolidated
Statements of Cash Flows
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93
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Combined Management's Discussion
and Analysis of Registrant Subsidiaries
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94-109
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Combined Notes to Consolidated
Financial Statements
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110-147
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Item
3. Quantitative and Qualitative
Disclosures About Market Risk.
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148
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Item
4. Controls and Procedures –
FirstEnergy.
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148
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Item
4T. Controls and Procedures – FES, OE, CEI, TE,
JCP&L, Met-Ed and Penelec.
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148
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Part
II. Other Information
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Item
1. Legal
Proceedings.
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149
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Item
1A. Risk Factors.
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149
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Item
2. Unregistered Sales of Equity
Securities and Use of Proceeds.
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149
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Item
4. Submission of Matters to a
Vote of Security Holders.
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149-150
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Item
6. Exhibits.
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151-154
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GLOSSARY
OF TERMS
The following
abbreviations and acronyms are used in this report to identify FirstEnergy Corp.
and its current and former subsidiaries:
ATSI
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American
Transmission Systems, Incorporated, 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
|
FirstEnergy
Solutions Corp., provides energy-related products and
services
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FESC
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FirstEnergy
Service Company, provides legal, financial and other corporate support
services
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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
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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
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A joint
venture between FirstEnergy Ventures Corp. and Boich Companies, that owns
mining and
coal
transportation operations near Roundup, Montana
|
TE
|
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:
|
|
|
AEP
|
American
Electric Power Company, Inc.
|
ALJ
|
Administrative
Law Judge
|
AMP-Ohio
|
American
Municipal Power-Ohio, Inc.
|
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
|
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 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"
|
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
|
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
|
OCI
|
Other
Comprehensive Income
|
OPEB
|
Other
Post-Employment Benefits
|
OVEC
|
Ohio Valley
Electric Corporation
|
PCRB
|
Pollution
Control Revenue Bond
|
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
|
RCP
|
Rate Certainty
Plan
|
RFP
|
Request for
Proposal
|
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
|
SFAS
71
|
SFAS No. 71,
"Accounting for the Effects of Certain Types of
Regulation"
|
SFAS
107
|
SFAS No. 107,
"Disclosure about Fair Value of Financial Instruments"
|
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
140
|
SFAS No. 140,
“Accounting for Transfers and Servicing of Financial Assets and
Extinguishments
of
Liabilities – a replacement of FASB Statement No.
125”
|
GLOSSARY
OF TERMS, Cont'd.
|
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"
|
SFAS
166
|
SFAS No. 166,
“Accounting for Transfers of Financial Assets – an amendment of
FASB
Statement
No. 140”
|
SFAS
167
|
SFAS No. 167,
“Amendments to FASB Interpretation No. 46(R)”
|
SFAS
168
|
SFAS No. 168,
“The FASB Accounting
Standards CodificationTM
and the Hierarchy of Generally
Accepted
Accounting Principles – a replacement of FASB Statement No.
162”
|
SIP
|
State
Implementation Plan(s) Under the Clean Air Act
|
SNCR
|
Selective
Non-Catalytic Reduction
|
SO2
|
Sulfur
Dioxide
|
TBC
|
Transition
Bond Charge
|
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
second quarter of 2009 was $408 million, or basic and diluted earnings of $1.36
per share of common stock, compared with net income of $263 million, or
basic earnings of $0.86 per share of common stock ($0.85 diluted) in the second
quarter of 2008. Results in the second quarter of 2009 include a gain of $0.52
per share resulting from the sale of FirstEnergy’s 9% participation interest in
OVEC. Net income in the first six months of 2009 was $523 million, or basic and
diluted earnings of $1.75 per share of common
stock, compared with net income of $540 million, or basic earnings of $1.77 per share of common
stock ($1.75 diluted) in the first
six months of 2008.
Change
in Basic Earnings Per Share
From
Prior Year Periods
|
|
Three
Months
Ended
June 30
|
|
|
Six
Months
Ended
June 30
|
|
|
|
|
|
|
|
|
Basic Earnings
Per Share – 2008
|
|
|
$
|
0.86
|
|
|
|
$
|
1.77
|
|
Gain on
non-core asset sales
|
|
0.52
|
|
|
0.46
|
|
Regulatory
charges – 2009
|
|
-
|
|
|
(0.55
|
)
|
Income tax
resolution – 2009
|
|
-
|
|
|
0.04
|
|
Organizational
restructuring costs – 2009
|
|
(0.01
|
)
|
|
(0.06
|
)
|
Debt
redemption premium / Penelec strike costs – 2009
|
|
(0.01
|
)
|
|
(0.01
|
)
|
Litigation
settlement – 2008
|
|
(0.03
|
)
|
|
(0.03
|
)
|
Trust
securities impairment
|
|
0.04
|
|
|
(0.01
|
)
|
Revenues
(excluding asset sales)
|
|
(0.44
|
)
|
|
(0.26
|
)
|
Fuel and
purchased power
|
|
0.17
|
|
|
(0.07
|
)
|
Transmission
costs
|
|
0.20
|
|
|
0.26
|
|
Amortization
of regulatory assets, net
|
|
(0.08
|
)
|
|
0.04
|
|
Other
expenses
|
|
|
0.14
|
|
|
|
0.17
|
|
Basic Earnings
Per Share – 2009
|
|
|
$
|
1.36
|
|
|
|
$
|
1.75
|
|
Regulatory
Matters
Ohio
On May 14, 2009,
FirstEnergy announced that an auction to secure generation supply and pricing
for the Ohio Companies for the period June 1, 2009 through May 31, 2011,
was completed and the results were approved by the PUCO. The auction resulted in
an average weighted wholesale price for generation and transmission of 6.15
cents per KWH. FES was a successful bidder for 51% of the Ohio Companies’ PLR
generation requirements. Twelve bidders qualified to participate in the auction
with nine successful bidders each securing a portion of the Ohio Companies’
load. Subsequent to the auction FES purchased tranches totaling an
additional 11% of the load from other winning bidders. Effective August 1, 2009,
FES is supplying 62% of the Ohio Companies’ PLR generation
requirements.
On June 17, 2009,
the PUCO modified rules that implement the alternative energy portfolio
standards created by SB221, including the incorporation of energy efficiency
requirements, long-term forecast and greenhouse gas reporting and CO2 control
planning. The PUCO filed the rules with the Joint Committee on Agency Rule
Review on July 7, 2009, after which begins a 65-day review period. The Ohio
Companies and one other party filed applications for rehearing on the rules with
the PUCO on July 17, 2009.
On July 27, 2009,
the Ohio Companies filed applications with the PUCO to recover three different
categories of deferred distribution costs on an accelerated basis. In the Ohio
Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with
collection originally set to begin in January 2011 and to continue over a 5 or
25 year period. The principal amount plus carrying charges through August 31,
2009 for these deferrals is a total of $298.4 million. If the applications are
approved, recovery of this amount, together with carrying charges calculated as
approved in the Amended ESP, will be collected in the 18 non-summer months from
September 2009 through May 2011, subject to reconciliation until fully
collected, with $165 million of the above amount being recovered from
residential customers, and $133.4 million being recovered from
non-residential customers. Pursuant to the applications, customers would pay
significantly less over the life of the recovery of the deferral through the
reduction in carrying charges as compared to the expected recovery under the
previously approved recovery mechanism.
Pennsylvania
On May 28, 2009, the
PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC riders 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 resulted
in an approximate 1% decrease in monthly bills, reflecting projected PJM
transmission costs as well as a reconciliation for costs previously incurred.
The TSC for Met-Ed’s customers increased 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, the PPUC approved
Met-Ed’s proposal to continue to recover the prior period deferrals allowed in
the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future
TSC to be fully recovered by December 31, 2010. Under this proposal, monthly
bills for Met-Ed’s customers are expected to increase approximately 9.4% for the
period June 2009 through May 2010.
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 through 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. On March 30, 2009, Met-Ed and Penelec filed direct testimony pursuant to
the March 5, 2009 case schedule issued by the ALJ. The PPUC is expected to issue
a final decision in November 2009.
On June 18, 2009,
the PPUC issued standards for the smart meter technology procurement and
installation plans required by Act 129 to be filed by the state’s large electric
distribution companies by August 14, 2009. The PPUC also provided guidance on
the procedures to be followed for submittal, review and approval of all aspects
of the smart meter plans. On June 18, 2009, the PPUC also adopted a total
resource cost test to analyze the costs and benefits of energy efficiency and
conservation plans filed under Act 129. On July 1, 2009, Met-Ed, Penelec and
Penn filed energy efficiency and conservation plans in accordance with the
requirements of Act 129.
FERC
On July 31, 2009,
FirstEnergy announced its intention to withdraw its transmission facilities from
MISO and realign them into PJM. The effect of the realignment is to consolidate
essentially all of FirstEnergy's generation and transmission operations within a
single RTO. FirstEnergy expects to make a filing with the FERC in August 2009 to
obtain the necessary regulatory approvals. FirstEnergy plans to integrate its
operations into PJM by June 1, 2011. FERC approval will be sought by the end of
2009 in order to allow FirstEnergy's load and generation operations currently in
MISO to participate in the PJM capacity auction held in May 2010 for service
beginning June 1, 2013.
Operational
Matters
Recessionary
Market Conditions and Weather Impacts
The demand for
electricity produced and sold by FirstEnergy’s competitive subsidiary, FES,
along with the value of that electricity, is materially impacted by conditions
in competitive power markets, global economic activity, economic activity in the
Midwest and Mid-Atlantic regions, and weather conditions in FirstEnergy’s
service territories. The current recessionary economic conditions, particularly
in the automotive and steel industries, compounded by unusually mild regional
summertime temperatures, have directly impacted FirstEnergy’s operations and
revenues over the last six to nine months.
The level of demand
for electricity directly impacts FirstEnergy’s distribution, transmission and
generation revenues, the quantity of electricity produced, purchased power
expense and fuel expense. FirstEnergy has taken various actions and
instituted a number of changes in operating practices to mitigate these external
influences. These actions include employee severances, wage reductions, employee
and retiree benefit changes, reduced levels of overtime and the use of fewer
contractors. However, the continuation of recessionary economic conditions,
coupled with unusually mild weather patterns and the resulting impact on
electricity prices and demand could impact FirstEnergy's future operating
performance and financial condition and may require further changes in
FirstEnergy’s operations.
Refueling
Outages
On May 13, 2009, the
Perry Plant returned to service after completing its 12th refueling and
maintenance outage which began on February 23, 2009. On May 21, 2009, the Beaver
Valley Unit 1 returned to service after completing its 19th refueling outage
which began on April 20, 2009. Several safety inspections and maintenance
projects were completed during the outages which were designed to facilitate the
continued safe and reliable operations of the units.
FES
Retail Activities
As of August 1,
2009, FES has signed 50 government aggregation contracts that will provide
discounted generation prices to approximately 600,000 residential and small
commercial customers. The governmental aggregator may choose between a graduated
or flat percentage discount. The graduated discount plan offers savings of 10%,
6%, 5%, and 4% in the years 2009-2012, respectively. The flat percentage
contract offers a 6% discount through the end of the contract. Discounts will be
based on the generation price customers would have been charged if they
purchased electric generation service from their electric utility and will be
effective beginning in late summer or early fall.
Union
Contracts
On May 21, 2009, 517
Penelec employees, represented by the International Brotherhood of Electrical
Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009,
Penelec implemented its work-continuation plan to use nearly 400 non-represented
employees with previous line experience and training drawn from Penelec and
other FirstEnergy operations to perform service reliability and priority
maintenance work in Penelec’s service territory. Penelec's IBEW Local 459
employees ratified a three-year contract agreement on July 19, 2009, and
returned to work on July 20, 2009.
On June 26, 2009,
FirstEnergy announced that seven of its union locals, representing about 2,600
employees, have ratified contract extensions. These unions include employees
from Penelec, Penn, CEI, OE and TE, along with certain power plant
employees.
On July 8, 2009,
FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777
ratified a two-year contract. Union members had been working without
a contract since the previous agreement expired on April 30, 2009.
Voluntary
Early Retirement Program
In
June 2009, FirstEnergy offered a Voluntary Enhanced Retirement Option (VERO),
which provides additional benefits for qualified employees who elect to
retire. As of July 31, 2009, the VERO was accepted by 382
non-represented employees and 225 employees represented by
unions.
Financial
Matters
Rating
Agency Actions
On June 17, 2009,
Moody’s issued a report affirming FirstEnergy’s Baa3 and FES’ Baa2 credit
ratings and maintained its stable outlook. On July 9, 2009, S&P reaffirmed
ratings on FirstEnergy and its subsidiaries, including its BBB corporate credit
rating, and maintained its stable outlook.
Financing
Activities
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 June 16, 2009,
NGC issued a total of approximately $487.5 million in principal amount of FMBs,
of which $107.5 million related to one new refunding series of PCRBs and
approximately $380 million related to amendments to existing letter of credit
and reimbursement agreements supporting seven other series of PCRBs. Similarly,
FGCO issued a total of approximately $395.9 million in principal amount of FMBs,
of which $247.7 million related to three new refunding series of PCRBs and
approximately $148.2 million related to amendments to existing letter of credit
and reimbursement agreements supporting two other series of PCRBs. In addition,
on June 16, 2009, NGC issued an FMB in a principal amount of up to
$500 million in connection with its guaranty of FES’ obligations to post
and maintain collateral under the PSA entered into by FES with the Ohio
Companies as a result of the May 13-14, 2009 CBP auction.
On June 30, 2009,
NGC issued a total of approximately $273.3 million in principal amount of FMBs,
of which approximately $92 million related to three existing series of
PCRBs and approximately $181.3 million related to amendments to existing letter
of credit and reimbursement agreements supporting three other series of PCRBs.
FGCO issued a total of approximately $52.1 million in principal amount of
FMBs related to three existing series of PCRBs.
On June 30, 2009,
Penn privately placed $100 million of FMBs having a fixed interest rate of
6.09%, and maturing on June 30, 2022. The proceeds were used by Penn to
repurchase equity from OE and for capital expenditures.
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 derived primarily 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 derived primarily from electric
generation sales revenues (including transmission) less the cost of power
purchased through the Ohio Companies' CBP and 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. Earnings
by major business segment were as follows:
|
|
Three
Months Ended June 30
|
|
|
|
|
|
|
|
Increase
|
|
|
|
Increase
|
|
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions, except per share data)
|
|
Earnings
By Business Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
delivery services
|
|
$
|
133
|
|
$
|
193
|
|
$
|
(60
|
)
|
$
|
91
|
|
$
|
372
|
|
$
|
(281
|
)
|
Competitive
energy services
|
|
|
276
|
|
|
66
|
|
|
210
|
|
|
431
|
|
|
153
|
|
|
278
|
|
Ohio
transitional generation services
|
|
|
21
|
|
|
20
|
|
|
1
|
|
|
45
|
|
|
43
|
|
|
2
|
|
Other and
reconciling adjustments*
|
|
|
(16
|
)
|
|
(16
|
)
|
|
-
|
|
|
(34
|
)
|
|
(29
|
)
|
|
(5
|
)
|
Total
|
|
$
|
414
|
|
$
|
263
|
|
$
|
151
|
|
$
|
533
|
|
$
|
539
|
|
$
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share
|
|
$
|
1.36
|
|
$
|
0.86
|
|
$
|
0.50
|
|
$
|
1.75
|
|
$
|
1.77
|
|
$
|
(0.02
|
)
|
Diluted
Earnings Per Share
|
|
$
|
1.36
|
|
$
|
0.85
|
|
$
|
0.51
|
|
$
|
1.75
|
|
$
|
1.75
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Consists
primarily of interest expense related to holding company debt, corporate
support services revenues and expenses, noncontrolling interests and the
elimination of intersegment transactions.
|
|
Summary of Results of Operations –
Second Quarter 2009 Compared with Second Quarter 2008
Financial results
for FirstEnergy's major business segments in the second quarter of 2009 and 2008
were as follows:
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
Second
Quarter 2009 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
1,797 |
|
|
$ |
205 |
|
|
$ |
860 |
|
|
$ |
- |
|
|
$ |
2,862 |
|
Other
|
|
|
127 |
|
|
|
299 |
|
|
|
8 |
|
|
|
(25 |
) |
|
|
409 |
|
Internal
|
|
|
- |
|
|
|
839 |
|
|
|
- |
|
|
|
(839 |
) |
|
|
- |
|
Total
Revenues
|
|
|
1,924 |
|
|
|
1,343 |
|
|
|
868 |
|
|
|
(864 |
) |
|
|
3,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
- |
|
|
|
276 |
|
|
|
- |
|
|
|
- |
|
|
|
276 |
|
Purchased
power
|
|
|
864 |
|
|
|
186 |
|
|
|
813 |
|
|
|
(839 |
) |
|
|
1,024 |
|
Other
operating expenses
|
|
|
314 |
|
|
|
315 |
|
|
|
14 |
|
|
|
(31 |
) |
|
|
612 |
|
Provision for
depreciation
|
|
|
110 |
|
|
|
68 |
|
|
|
- |
|
|
|
7 |
|
|
|
185 |
|
Amortization
of regulatory assets
|
|
|
184 |
|
|
|
- |
|
|
|
49 |
|
|
|
- |
|
|
|
233 |
|
Deferral of
new regulatory assets
|
|
|
- |
|
|
|
- |
|
|
|
(45 |
) |
|
|
- |
|
|
|
(45 |
) |
General
taxes
|
|
|
152 |
|
|
|
25 |
|
|
|
2 |
|
|
|
5 |
|
|
|
184 |
|
Total
Expenses
|
|
|
1,624 |
|
|
|
870 |
|
|
|
833 |
|
|
|
(858 |
) |
|
|
2,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
300 |
|
|
|
473 |
|
|
|
35 |
|
|
|
(6 |
) |
|
|
802 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
35 |
|
|
|
6 |
|
|
|
- |
|
|
|
(14 |
) |
|
|
27 |
|
Interest
expense
|
|
|
(114 |
) |
|
|
(32 |
) |
|
|
- |
|
|
|
(60 |
) |
|
|
(206 |
) |
Capitalized
interest
|
|
|
1 |
|
|
|
14 |
|
|
|
- |
|
|
|
18 |
|
|
|
33 |
|
Total Other
Expense
|
|
|
(78 |
) |
|
|
(12 |
) |
|
|
- |
|
|
|
(56 |
) |
|
|
(146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
222 |
|
|
|
461 |
|
|
|
35 |
|
|
|
(62 |
) |
|
|
656 |
|
Income
taxes
|
|
|
89 |
|
|
|
185 |
|
|
|
14 |
|
|
|
(40 |
) |
|
|
248 |
|
Net
Income
|
|
|
133 |
|
|
|
276 |
|
|
|
21 |
|
|
|
(22 |
) |
|
|
408 |
|
Less:
Noncontrolling interest income (loss)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
(6 |
) |
Earnings
available to FirstEnergy Corp.
|
|
$ |
133 |
|
|
$ |
276 |
|
|
$ |
21 |
|
|
$ |
(16 |
) |
|
$ |
414 |
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
Second
Quarter 2008 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
2,030 |
|
|
$ |
324 |
|
|
$ |
670 |
|
|
$ |
- |
|
|
$ |
3,024 |
|
Other
|
|
|
152 |
|
|
|
51 |
|
|
|
13 |
|
|
|
5 |
|
|
|
221 |
|
Internal
|
|
|
- |
|
|
|
704 |
|
|
|
- |
|
|
|
(704 |
) |
|
|
- |
|
Total
Revenues
|
|
|
2,182 |
|
|
|
1,079 |
|
|
|
683 |
|
|
|
(699 |
) |
|
|
3,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
- |
|
|
|
316 |
|
|
|
- |
|
|
|
- |
|
|
|
316 |
|
Purchased
power
|
|
|
998 |
|
|
|
221 |
|
|
|
555 |
|
|
|
(704 |
) |
|
|
1,070 |
|
Other
operating expenses
|
|
|
413 |
|
|
|
312 |
|
|
|
81 |
|
|
|
(25 |
) |
|
|
781 |
|
Provision for
depreciation
|
|
|
104 |
|
|
|
59 |
|
|
|
- |
|
|
|
5 |
|
|
|
168 |
|
Amortization
of regulatory assets, net
|
|
|
235 |
|
|
|
- |
|
|
|
11 |
|
|
|
- |
|
|
|
246 |
|
Deferral of
new regulatory assets
|
|
|
(98 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(98 |
) |
General
taxes
|
|
|
149 |
|
|
|
24 |
|
|
|
2 |
|
|
|
5 |
|
|
|
180 |
|
Total
Expenses
|
|
|
1,801 |
|
|
|
932 |
|
|
|
649 |
|
|
|
(719 |
) |
|
|
2,663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
381 |
|
|
|
147 |
|
|
|
34 |
|
|
|
20 |
|
|
|
582 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
40 |
|
|
|
(8 |
) |
|
|
(1 |
) |
|
|
(15 |
) |
|
|
16 |
|
Interest
expense
|
|
|
(100 |
) |
|
|
(38 |
) |
|
|
- |
|
|
|
(50 |
) |
|
|
(188 |
) |
Capitalized
interest
|
|
|
1 |
|
|
|
10 |
|
|
|
- |
|
|
|
2 |
|
|
|
13 |
|
Total Other
Expense
|
|
|
(59 |
) |
|
|
(36 |
) |
|
|
(1 |
) |
|
|
(63 |
) |
|
|
(159 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
322 |
|
|
|
111 |
|
|
|
33 |
|
|
|
(43 |
) |
|
|
423 |
|
Income
taxes
|
|
|
129 |
|
|
|
45 |
|
|
|
13 |
|
|
|
(27 |
) |
|
|
160 |
|
Net
Income
|
|
|
193 |
|
|
|
66 |
|
|
|
20 |
|
|
|
(16 |
) |
|
|
263 |
|
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Earnings
available to FirstEnergy Corp.
|
|
$ |
193 |
|
|
$ |
66 |
|
|
$ |
20 |
|
|
$ |
(16 |
) |
|
$ |
263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between Second Quarter 2009 and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second
Quarter 2008 Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
(233 |
) |
|
$ |
(119 |
) |
|
$ |
190 |
|
|
$ |
- |
|
|
$ |
(162 |
) |
Other
|
|
|
(25 |
) |
|
|
248 |
|
|
|
(5 |
) |
|
|
(30 |
) |
|
|
188 |
|
Internal
|
|
|
- |
|
|
|
135 |
|
|
|
- |
|
|
|
(135 |
) |
|
|
- |
|
Total
Revenues
|
|
|
(258 |
) |
|
|
264 |
|
|
|
185 |
|
|
|
(165 |
) |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
- |
|
|
|
(40 |
) |
|
|
- |
|
|
|
- |
|
|
|
(40 |
) |
Purchased
power
|
|
|
(134 |
) |
|
|
(35 |
) |
|
|
258 |
|
|
|
(135 |
) |
|
|
(46 |
) |
Other
operating expenses
|
|
|
(99 |
) |
|
|
3 |
|
|
|
(67 |
) |
|
|
(6 |
) |
|
|
(169 |
) |
Provision for
depreciation
|
|
|
6 |
|
|
|
9 |
|
|
|
- |
|
|
|
2 |
|
|
|
17 |
|
Amortization
of regulatory assets
|
|
|
(51 |
) |
|
|
- |
|
|
|
38 |
|
|
|
- |
|
|
|
(13 |
) |
Deferral of
new regulatory assets
|
|
|
98 |
|
|
|
- |
|
|
|
(45 |
) |
|
|
- |
|
|
|
53 |
|
General
taxes
|
|
|
3 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
Total
Expenses
|
|
|
(177 |
) |
|
|
(62 |
) |
|
|
184 |
|
|
|
(139 |
) |
|
|
(194 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(81 |
) |
|
|
326 |
|
|
|
1 |
|
|
|
(26 |
) |
|
|
220 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(5 |
) |
|
|
14 |
|
|
|
1 |
|
|
|
1 |
|
|
|
11 |
|
Interest
expense
|
|
|
(14 |
) |
|
|
6 |
|
|
|
- |
|
|
|
(10 |
) |
|
|
(18 |
) |
Capitalized
interest
|
|
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
16 |
|
|
|
20 |
|
Total Other
Expense
|
|
|
(19 |
) |
|
|
24 |
|
|
|
1 |
|
|
|
7 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
(100 |
) |
|
|
350 |
|
|
|
2 |
|
|
|
(19 |
) |
|
|
233 |
|
Income
taxes
|
|
|
(40 |
) |
|
|
140 |
|
|
|
1 |
|
|
|
(13 |
) |
|
|
88 |
|
Net
Income
|
|
|
(60 |
) |
|
|
210 |
|
|
|
1 |
|
|
|
(6 |
) |
|
|
145 |
|
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6 |
) |
|
|
(6 |
) |
Earnings
available to FirstEnergy Corp.
|
|
$ |
(60 |
) |
|
$ |
210 |
|
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
151 |
|
Energy Delivery Services – Second
Quarter 2009 Compared with Second Quarter 2008
Net income decreased
$60 million to $133 million in the second quarter of 2009 compared to
$193 million in the second quarter of 2008, primarily due to lower revenues
and increased amortization of regulatory assets, partially offset by lower
purchased power and other operating expenses.
Revenues –
The
decrease in total revenues resulted from the following sources:
|
|
Three
Months
|
|
|
|
|
|
Ended
June 30
|
|
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
Decrease
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
decrease in distribution deliveries by customer class is summarized in the
following table:
Electric
Distribution KWH Deliveries
|
|
|
|
|
|
|
|
)% |
|
|
|
|
)% |
|
|
|
|
)% |
Total
Distribution KWH Deliveries
|
|
|
|
)% |
Lower deliveries to
residential customers reflected decreased weather-related usage in the second
quarter of 2009, as heating and cooling degree days decreased by 2% and 23%,
respectively, from the same period in 2008. The decrease in 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 (34.8%) and steel (50.7%).
Transition charges for OE and TE that ceased effective January 1, 2009 with
the full recovery of related costs and the Transition rate reduction for CEI
effective June 1, 2009, were offset by PUCO-approved distribution rate increases
(see Regulatory Matters – Ohio).
The following table
summarizes the price and volume factors contributing to the $144 million
decrease in generation revenues in the second quarter of 2009 compared to the
second quarter of 2008:
Sources
of Change in Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect
of 9.5 % decrease in sales volumes
|
|
$
|
(73
|
)
|
Change
in prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect
of 12.7 % decrease in sales volumes
|
|
|
(32
|
)
|
Change
in prices
|
|
|
|
)
|
|
|
|
|
)
|
Net Decrease
in Generation Revenues
|
|
$
|
(144
|
)
|
The decrease in
retail generation sales volumes was primarily due to weakened economic
conditions and the lower weather-related usage described above. The increase in
retail generation prices during the second quarter 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 available power from NUGs due to the
termination of a NUG purchase contract in October 2008. The decrease in prices
reflected lower spot prices for PJM market participants.
Transmission
revenues decreased $8 million primarily due to lower PJM transmission
revenues partially offset by higher transmission rates for Met-Ed and Penelec
resulting from the annual update to their TSC riders in June 2008 and 2009.
Met-Ed and Penelec defer the difference between transmission revenues and
transmission costs incurred, resulting in no material effect to current period
earnings (see Regulatory Matters – Pennsylvania).
Expenses –
Total expenses
decreased by $177 million due to the net impact of the
following:
|
·
|
Purchased
power costs were $134 million lower in the
second quarter of 2009 due to lower volume requirements and an increase in
the amount of NUG costs deferred. The increased unit costs reflected the
effect of higher JCP&L costs resulting from the BGS auction process.
However, 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
|
|
$
|
45
|
|
Change due to decreased
volumes
|
|
|
(165
|
)
|
|
|
|
(120
|
)
|
Purchases from
FES:
|
|
|
|
|
Change due to decreased unit
costs
|
|
|
(7
|
)
|
Change due to increased
volumes
|
|
|
15
|
|
|
|
|
8
|
|
|
|
|
|
|
Increase in
NUG costs deferred
|
|
|
(22
|
)
|
Net Decrease
in Purchased Power Costs
|
|
$
|
(134
|
)
|
|
·
|
PJM
transmission expenses were lower by $70 million resulting from
reduced volumes and congestion
costs.
|
|
·
|
Contractor and
material costs decreased $18 million due primarily to reduced maintenance
activities as more work was devoted to capital
projects.
|
|
·
|
Labor and
employee benefits decreased $13 million as a result of FirstEnergy
cost control initiatives.
|
|
·
|
Storm related
costs were $2 million higher than in the second quarter
2008.
|
|
·
|
Amortization
of regulatory assets decreased $51 million due primarily to the cessation
of transition cost amortizations for OE and TE, partially offset by PJM
transmission cost amortization in the second quarter of
2009.
|
|
·
|
The deferral
of new regulatory assets decreased by $98 million in the second quarter of
2009 principally due to the absence of PJM transmission cost deferrals and
RCP distribution cost deferrals by the Ohio
Companies.
|
|
·
|
Depreciation
expense increased $6 million due to property additions since the second
quarter of 2008.
|
|
·
|
General taxes
increased $3 million primarily due to higher property taxes associated
with the property additions noted
above.
|
Other Expense –
Other expense
increased $19 million
in the second quarter of 2009 compared to the second quarter of 2008 due to
lower investment income of $5 million, reflecting reduced
loan balances to the regulated money pool, and higher interest expense (net of
capitalized interest) of $14 million, reflecting $600
million of senior notes issuances by JCP&L and Met-Ed in January 2009, and
$300 million by TE in April 2009.
Competitive Energy Services – Second
Quarter 2009 Compared with Second Quarter 2008
Net income for this
segment was $276 million in the second quarter of 2009 compared to
$66 million in the same period in 2008. The $210 million increase in
net income principally reflects FGCO's $252 million gain from the sale of
9% of its participation in OVEC ($158 million after tax) and an increase in
gross sales margins.
Revenues –
Total revenues
increased $264 million
in the second quarter of 2009 due to the OVEC sale described above and higher
unit prices on affiliated generation sales to the Ohio Companies, partially
offset by lower non-affiliated generation sales volumes.
The
net increase in total revenues resulted from the following sources:
|
|
Three
Months
|
|
|
|
|
|
Ended
June 30
|
|
Increase
|
|
Revenues
By Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
)
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
)
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of OVEC
participation interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The lower retail
revenues reflect the expiration of certain government aggregation programs in
Ohio at the end of 2008 that were supplied by FES, partially offset by the
acquisition of new retail customer contracts in the MISO and PJM markets in the
second quarter of 2009. As of August 1, 2009, FES has signed new government
aggregation contracts with 50 communities that will provide discounted
generation prices to approximately 600,000 residential and small commercial
customers. The retail sales volumes associated with these new contracts are
expected to result in an increased level of retail revenues in the second half
of 2009 as compared to results for the period ended June 30, 2009.
Lower non-affiliated
wholesale revenues resulted from lower capacity prices and sales volumes in both
the PJM and MISO markets. The increased affiliated company generation revenues
were due to higher unit prices for sales to the Ohio Companies under a PSA in
April and May 2009 and the CBP in June 2009 (see Regulatory Matters – Ohio),
partially offset by lower unit prices to the Pennsylvania Companies and a
decrease in sales volumes to the Ohio Companies. Increased sales volumes to the
Pennsylvania Companies reflect FES’ sales to Met-Ed and Penelec, following the
expiration of a third-party supply contract at the end of 2008. 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 100% of
the power for the Ohio Companies’ PLR service in April and May 2009 and
approximately 56% of the Ohio Companies' supply needs for June 2009. Subsequent
to the Ohio Companies’ CBP, FES purchased additional tranches from other winning
bidders and effective August 1, 2009, FES will supply 62% of the Ohio Companies’
PLR generation requirements.
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 58.7 % decrease in sales
volumes
|
|
$
|
(91
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect of 36.2 % decrease in sales
volumes
|
|
|
(61
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
)
|
Net Decrease
in Non-Affiliated Generation Revenues
|
|
|
|
)
|
Source
of Change in Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect of 13.2 % decrease in sales
volumes
|
|
$
|
(74
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect of 10 % increase in sales
volumes
|
|
|
15
|
|
Change in prices
|
|
|
|
)
|
|
|
|
|
|
Net Increase
in Affiliated Generation Revenues
|
|
|
|
|
Transmission
revenues decreased $17 million due primarily to reduced loads following the
termination of the government aggregation programs mentioned above. The increase
in other revenues reflected NGC's increased rental income associated with its
acquisition of additional equity interests in the Perry and Beaver Valley
Unit 2 leases.
Expenses -
Total expenses
decreased $62 million in the second quarter of 2009 due to the following
factors:
·
|
Fuel costs
decreased $40 million due to decreased generation volumes
($70 million) partially offset by higher unit prices
($30 million). The increased unit prices, which are expected to
continue for the remainder of 2009, primarily reflect higher costs for
eastern coal.
|
·
|
Purchased
power costs decreased $35 million due primarily to lower unit costs
($34 million) and lower volume requirements
($1 million).
|
·
|
Fossil
operating costs decreased $28 million due to a reduction in contractor and
material costs ($18 million) and lower labor and employee benefit
expenses ($10 million), reflecting FirstEnergy’s cost control
initiatives.
|
·
|
Nuclear
operating costs decreased $7 million due to lower labor and employee
benefit expenses, partially offset by higher expenses associated with the
2009 Perry and Beaver Valley refueling outages and the Davis-Besse
maintenance outage.
|
·
|
Other
operating expenses increased $22 million due primarily to increased
intersegment billings for leasehold costs from the Ohio
Companies.
|
·
|
Transmission
expense increased $17 million due primarily to increased net
congestion and loss expenses in
PJM.
|
|
·
|
Higher
depreciation expense of $9 million was due primarily to NGC's
increased ownership interests in Perry and Beaver Valley Unit 2 following
its purchase of lease equity
interests.
|
Other Expense –
Total other expense
in the second quarter of 2009 was $24 million lower than the
second quarter of 2008, primarily due to a $16 million decrease in trust
securities impairments and a $10 million decrease in interest expense (net
of capitalized interest).
Ohio Transitional Generation Services –
Second Quarter 2009 Compared with Second Quarter 2008
Net income for this
segment increased to $21 million in the second
quarter of 2009 from $20 million in the same period of 2008. Higher
generation revenues and lower operating expenses were partially offset by higher
purchased power costs.
Revenues –
The
increase in reported segment revenues resulted from the following
sources:
|
|
Three
Months
|
|
|
|
|
|
Ended
June 30
|
|
|
|
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 4.4% increase in sales
volumes
|
|
$
|
26
|
|
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 following the
expiration of certain government aggregation programs in Ohio. Average prices
increased primarily due to an increase in the Ohio Companies' fuel cost recovery
rider that was effective from January through May 2009. Effective June 1,
2009, the transmission tariff ended and the recovery of transmission costs is
included in the generation rate established under the Ohio Companies'
CBP.
Decreased
transmission revenue of $22 million resulted from the termination of the
transmission tariff (as discussed above) and reduced MISO revenues, partially
offset by higher sales volumes. The difference between transmission revenues
accrued and transmission costs incurred is deferred, resulting in no material
impact to current period earnings.
Expenses -
Purchased power
costs were $258 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)
|
|
|
|
|
|
|
Change due to increased unit
costs
|
|
$
|
239
|
|
Change due to increased
volumes
|
|
|
19
|
|
|
|
$
|
258
|
|
The increase in
purchased volumes was due to the higher retail generation sales requirements
described above. The higher unit costs reflect the results of the Ohio
Companies' power supply procurement processes for retail customers during the
second quarter of 2009 (see Regulatory Matters – Ohio).
Other operating
expenses decreased $67 million due to lower MISO transmission-related
expenses ($43 million) and increased intersegment credits related to the Ohio
Companies' generation leasehold interests. The amortization of regulatory assets
increased by $38 million in the second quarter of 2009 due primarily to
increased MISO transmission cost amortization. The deferral of new regulatory
assets increased by $45 million due to CEI’s deferral of purchased power costs
as approved by the PUCO.
Summary of Results of Operations –
First Six Months of 2009 Compared with the First Six Months of 2008
Financial results
for FirstEnergy's major business segments in the first six months of 2009 and
2008 were as follows:
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
First
Six Months 2009 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
3,756 |
|
|
$ |
485 |
|
|
$ |
1,762 |
|
|
$ |
- |
|
|
$ |
6,003 |
|
Other
|
|
|
277 |
|
|
|
354 |
|
|
|
18 |
|
|
|
(47 |
) |
|
|
602 |
|
Internal
|
|
|
- |
|
|
|
1,732 |
|
|
|
- |
|
|
|
(1,732 |
) |
|
|
- |
|
Total
Revenues
|
|
|
4,033 |
|
|
|
2,571 |
|
|
|
1,780 |
|
|
|
(1,779 |
) |
|
|
6,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
- |
|
|
|
588 |
|
|
|
- |
|
|
|
- |
|
|
|
588 |
|
Purchased
power
|
|
|
1,842 |
|
|
|
346 |
|
|
|
1,711 |
|
|
|
(1,732 |
) |
|
|
2,167 |
|
Other
operating expenses
|
|
|
794 |
|
|
|
670 |
|
|
|
32 |
|
|
|
(57 |
) |
|
|
1,439 |
|
Provision for
depreciation
|
|
|
219 |
|
|
|
132 |
|
|
|
- |
|
|
|
11 |
|
|
|
362 |
|
Amortization
of regulatory assets
|
|
|
547 |
|
|
|
- |
|
|
|
95 |
|
|
|
- |
|
|
|
642 |
|
Deferral of
new regulatory assets
|
|
|
- |
|
|
|
- |
|
|
|
(136 |
) |
|
|
- |
|
|
|
(136 |
) |
General
taxes
|
|
|
320 |
|
|
|
57 |
|
|
|
4 |
|
|
|
14 |
|
|
|
395 |
|
Total
Expenses
|
|
|
3,722 |
|
|
|
1,793 |
|
|
|
1,706 |
|
|
|
(1,764 |
) |
|
|
5,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
311 |
|
|
|
778 |
|
|
|
74 |
|
|
|
(15 |
) |
|
|
1,148 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
64 |
|
|
|
(23 |
) |
|
|
1 |
|
|
|
(26 |
) |
|
|
16 |
|
Interest
expense
|
|
|
(225 |
) |
|
|
(60 |
) |
|
|
- |
|
|
|
(115 |
) |
|
|
(400 |
) |
Capitalized
interest
|
|
|
2 |
|
|
|
24 |
|
|
|
- |
|
|
|
35 |
|
|
|
61 |
|
Total Other
Expense
|
|
|
(159 |
) |
|
|
(59 |
) |
|
|
1 |
|
|
|
(106 |
) |
|
|
(323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
152 |
|
|
|
719 |
|
|
|
75 |
|
|
|
(121 |
) |
|
|
825 |
|
Income
taxes
|
|
|
61 |
|
|
|
288 |
|
|
|
30 |
|
|
|
(77 |
) |
|
|
302 |
|
Net
Income
|
|
|
91 |
|
|
|
431 |
|
|
|
45 |
|
|
|
(44 |
) |
|
|
523 |
|
Less:
Noncontrolling interest income (loss)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(10 |
) |
|
|
(10 |
) |
Earnings
available to FirstEnergy Corp.
|
|
$ |
91 |
|
|
$ |
431 |
|
|
$ |
45 |
|
|
$ |
(34 |
) |
|
$ |
533 |
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
Other
and
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
Reconciling
|
|
|
FirstEnergy
|
|
First
Six Months 2008 Financial Results
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
4,080 |
|
|
$ |
613 |
|
|
$ |
1,361 |
|
|
$ |
- |
|
|
$ |
6,054 |
|
Other
|
|
|
314 |
|
|
|
91 |
|
|
|
29 |
|
|
|
34 |
|
|
|
468 |
|
Internal
|
|
|
- |
|
|
|
1,480 |
|
|
|
- |
|
|
|
(1,480 |
) |
|
|
- |
|
Total
Revenues
|
|
|
4,394 |
|
|
|
2,184 |
|
|
|
1,390 |
|
|
|
(1,446 |
) |
|
|
6,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
1 |
|
|
|
643 |
|
|
|
- |
|
|
|
- |
|
|
|
644 |
|
Purchased
power
|
|
|
1,980 |
|
|
|
427 |
|
|
|
1,143 |
|
|
|
(1,480 |
) |
|
|
2,070 |
|
Other
operating expenses
|
|
|
858 |
|
|
|
621 |
|
|
|
158 |
|
|
|
(57 |
) |
|
|
1,580 |
|
Provision for
depreciation
|
|
|
210 |
|
|
|
112 |
|
|
|
- |
|
|
|
10 |
|
|
|
332 |
|
Amortization
of regulatory assets
|
|
|
484 |
|
|
|
- |
|
|
|
20 |
|
|
|
- |
|
|
|
504 |
|
Deferral of
new regulatory assets
|
|
|
(198 |
) |
|
|
- |
|
|
|
(5 |
) |
|
|
- |
|
|
|
(203 |
) |
General
taxes
|
|
|
322 |
|
|
|
56 |
|
|
|
3 |
|
|
|
14 |
|
|
|
395 |
|
Total
Expenses
|
|
|
3,657 |
|
|
|
1,859 |
|
|
|
1,319 |
|
|
|
(1,513 |
) |
|
|
5,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
737 |
|
|
|
325 |
|
|
|
71 |
|
|
|
67 |
|
|
|
1,200 |
|
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
85 |
|
|
|
(14 |
) |
|
|
- |
|
|
|
(38 |
) |
|
|
33 |
|
Interest
expense
|
|
|
(203 |
) |
|
|
(72 |
) |
|
|
- |
|
|
|
(92 |
) |
|
|
(367 |
) |
Capitalized
interest
|
|
|
1 |
|
|
|
17 |
|
|
|
- |
|
|
|
3 |
|
|
|
21 |
|
Total Other
Expense
|
|
|
(117 |
) |
|
|
(69 |
) |
|
|
- |
|
|
|
(127 |
) |
|
|
(313 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
620 |
|
|
|
256 |
|
|
|
71 |
|
|
|
(60 |
) |
|
|
887 |
|
Income
taxes
|
|
|
248 |
|
|
|
103 |
|
|
|
28 |
|
|
|
(32 |
) |
|
|
347 |
|
Net
Income
|
|
|
372 |
|
|
|
153 |
|
|
|
43 |
|
|
|
(28 |
) |
|
|
540 |
|
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
Earnings
available to FirstEnergy Corp.
|
|
$ |
372 |
|
|
$ |
153 |
|
|
$ |
43 |
|
|
$ |
(29 |
) |
|
$ |
539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
Between First Six Months 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
First Six Months 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Results Increase (Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
(324 |
) |
|
$ |
(128 |
) |
|
$ |
401 |
|
|
$ |
- |
|
|
$ |
(51 |
) |
Other
|
|
|
(37 |
) |
|
|
263 |
|
|
|
(11 |
) |
|
|
(81 |
) |
|
|
134 |
|
Internal
|
|
|
- |
|
|
|
252 |
|
|
|
- |
|
|
|
(252 |
) |
|
|
- |
|
Total
Revenues
|
|
|
(361 |
) |
|
|
387 |
|
|
|
390 |
|
|
|
(333 |
) |
|
|
83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
(1 |
) |
|
|
(55 |
) |
|
|
- |
|
|
|
- |
|
|
|
(56 |
) |
Purchased
power
|
|
|
(138 |
) |
|
|
(81 |
) |
|
|
568 |
|
|
|
(252 |
) |
|
|
97 |
|
Other
operating expenses
|
|
|
(64 |
) |
|
|
49 |
|
|
|
(126 |
) |
|
|
- |
|
|
|
(141 |
) |
Provision for
depreciation
|
|
|
9 |
|
|
|
20 |
|
|
|
- |
|
|
|
1 |
|
|
|
30 |
|
Amortization
of regulatory assets
|
|
|
63 |
|
|
|
- |
|
|
|
75 |
|
|
|
- |
|
|
|
138 |
|
Deferral of
new regulatory assets
|
|
|
198 |
|
|
|
- |
|
|
|
(131 |
) |
|
|
- |
|
|
|
67 |
|
General
taxes
|
|
|
(2 |
) |
|
|
1 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
Total
Expenses
|
|
|
65 |
|
|
|
(66 |
) |
|
|
387 |
|
|
|
(251 |
) |
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
(426 |
) |
|
|
453 |
|
|
|
3 |
|
|
|
(82 |
) |
|
|
(52 |
) |
Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
(21 |
) |
|
|
(9 |
) |
|
|
1 |
|
|
|
12 |
|
|
|
(17 |
) |
Interest
expense
|
|
|
(22 |
) |
|
|
12 |
|
|
|
- |
|
|
|
(23 |
) |
|
|
(33 |
) |
Capitalized
interest
|
|
|
1 |
|
|
|
7 |
|
|
|
- |
|
|
|
32 |
|
|
|
40 |
|
Total Other
Expense
|
|
|
(42 |
) |
|
|
10 |
|
|
|
1 |
|
|
|
21 |
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
Income Taxes
|
|
|
(468 |
) |
|
|
463 |
|
|
|
4 |
|
|
|
(61 |
) |
|
|
(62 |
) |
Income
taxes
|
|
|
(187 |
) |
|
|
185 |
|
|
|
2 |
|
|
|
(45 |
) |
|
|
(45 |
) |
Net
Income
|
|
|
(281 |
) |
|
|
278 |
|
|
|
2 |
|
|
|
(16 |
) |
|
|
(17 |
) |
Less:
Noncontrolling interest income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(11 |
) |
|
|
(11 |
) |
Earnings
available to FirstEnergy Corp.
|
|
$ |
(281 |
) |
|
$ |
278 |
|
|
$ |
2 |
|
|
$ |
(5 |
) |
|
$ |
(6 |
) |
Energy
Delivery Services – First Six Months of 2009 Compared to First Six Months of
2008
Net income decreased
$281 million to $91 million in the first six months of 2009 compared
to $372 million in the first six months of 2008, primarily due to decreased
revenues and increased amortization of regulatory assets, partially offset by
lower purchased power and other operating expenses.
Revenues –
The
decrease in total revenues resulted from the following sources:
|
|
Six
Months
|
|
|
|
|
|
Ended
June 30
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
The
decrease in distribution deliveries by customer class are 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
decreases in distribution deliveries to commercial and industrial customers were
primarily due to economic conditions in FirstEnergy's service territory. In the
industrial sector, KWH deliveries declined to major automotive (31.5%) and steel
(45.4%). Transition charges for OE and TE that ceased effective January 1,
2009 with the full recovery of related costs and the transition rate reduction
for CEI effective June 1, 2009, were offset by PUCO-approved distribution rate
increases (see Regulatory Matters – Ohio).
The following table
summarizes the price and volume factors contributing to the $153 million
decrease in generation revenues in the first six months of 2009 compared to the
same period of 2008:
|
|
Increase
|
|
Sources
of Change in Generation Revenues
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect of 6.3%
decrease in sales volumes
|
|
$
|
(98
|
)
|
Change in
prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect of
12.2% decrease in sales volumes
|
|
|
(57
|
)
|
Change in
prices
|
|
|
|
)
|
|
|
|
|
)
|
Net Decrease
in Generation Revenues
|
|
$
|
(153
|
)
|
The decrease in
retail generation sales volumes was primarily due to weakened economic
conditions and reduced weather-related usage. Cooling degree days decreased by
23% in the first six months of 2009, while heating degree days increased by 2%
compared to the same period last year. The increase in retail generation prices
during the first six months of 2009 was due to higher generation rates for
JCP&L and Penn under their power procurement processes. Wholesale generation
sales decreased principally as a result of JCP&L selling less available
power from NUGs due to the termination of a NUG purchase contract in October
2008. The decrease in wholesale prices reflected lower spot market prices in
PJM.
Transmission
revenues increased $3 million primarily due to higher transmission rates
for Met-Ed and Penelec resulting from the annual updates to their TSC riders.
Met-Ed and Penelec defer the difference between revenues from their transmission
riders and transmission costs incurred with no material effect on current period
earnings (see Regulatory Matters – Pennsylvania).
Expenses –
Total expenses
increased by $65 million due to the following:
|
·
|
Purchased
power costs were $138 million lower in the
first six months of 2009 due to lower volumes, partially offset by higher
unit costs and an increase in the amount of NUG costs deferred. The
increased unit costs primarily reflected the effect of higher JCP&L
costs resulting from its BGS auction process. 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
|
|
$
|
163
|
|
Change due to decreased
volumes
|
|
|
(266
|
)
|
|
|
|
(103
|
)
|
Purchases from
FES:
|
|
|
|
|
Change due to decreased unit
costs
|
|
|
(16
|
)
|
Change due to increased
volumes
|
|
|
37
|
|
|
|
|
21
|
|
|
|
|
|
|
Increase in
NUG costs deferred
|
|
|
(56
|
)
|
Net Decrease
in Purchased Power Costs
|
|
$
|
(138
|
)
|
|
·
|
PJM
transmission expenses were lower by $81 million, resulting primarily from
reduced volumes and congestion
costs.
|
|
·
|
An increase in
other operating expense of $32 million resulted from recognition of
economic development and energy efficiency obligations in accordance with
the PUCO-approved ESP.
|
|
·
|
A reduction in
contractor and material expenses of $21 million, reflecting more costs
dedicated to capital projects compared to the prior year, was partially
offset by an increase from organizational restructuring costs of $5
million.
|
|
·
|
A $63 million
increase in the amortization of regulatory assets was due primarily to the
ESP-related impairment of CEI’s regulatory assets and PJM transmission
cost amortization in the first six months of 2009, partially offset by the
cessation of transition cost amortizations for OE and
TE.
|
|
·
|
A $198 million
decrease in the deferral of new regulatory assets was principally due to
the absence of PJM transmission cost deferrals and RCP distribution cost
deferrals by the Ohio Companies.
|
|
·
|
Depreciation
expense increased $9 million due to property additions since the
second quarter of 2008.
|
|
·
|
General taxes
decreased $2 million due to lower gross receipts and excise
taxes.
|
Other Expense –
Other expense
increased $42 million in the first six months of 2009 compared to 2008.
Lower investment income of $21 million resulted primarily from repaid notes
receivable from affiliates since the second quarter of 2008. Higher interest
expense (net of capitalized interest) of $21 million was related to the
senior notes issuances of JCP&L and Met-Ed in January 2009 and TE in April
2009.
Competitive
Energy Services – First Six Months of 2009 Compared to First Six Months of
2008
Net income increased
to $431 million
in the first six months of 2009 compared to $153 million
in the same period in 2008. The increase in net income includes FGCO's
$252 million gain from the sale of 9% of its participation in OVEC
($158 million after tax) and an increase in gross sales margins, partially
offset by higher other operating costs.
Revenues –
Total revenues
increased $387 million
in the first six months of 2009 compared to the same period in 2008. This
increase primarily resulted from the OVEC sale and higher unit prices on
affiliated generation sales to the Ohio Companies and non-affiliated customers,
partially offset by lower sales volumes.
The
increase in reported segment revenues resulted from the following
sources:
|
|
Six
Months
|
|
|
|
|
|
Ended
June 30
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
)
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of OVEC
participation interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The lower retail
revenues resulted from the expiration of government aggregation programs in Ohio
at the end of 2008 that were supplied by FES, partially offset by increased
revenue from both the PJM and MISO markets. The increase in MISO retail sales is
primarily the result of the acquisition of new customers and higher unit prices.
The increase in PJM retail sales resulted from higher unit prices. As of August
1, 2009, FES has signed new government aggregation contracts with 50 communities
that will provide discounted generation prices to approximately 600,000
residential and small commercial customers. The retail sales volumes associated
with these new contracts are expected to result in an increased level of retail
revenues in the second half of 2009 as compared to results for the period ended
June 30, 2009.
Higher
non-affiliated wholesale revenues resulted from higher capacity prices in PJM
and increased sales volumes and favorable settlements on hedged transactions in
MISO, partially offset by decreased sales volumes and spot market prices in PJM.
The increased affiliated company generation revenues were due to higher unit
prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec,
partially offset by lower sales volumes to the Ohio Companies. The higher unit
prices reflected the results of the Ohio Companies' power procurement processes
in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to
the Pennsylvania Companies were due to increased Met-Ed and Penelec generation
sales requirements, partially offset by lower sales to Penn due to decreased
default service requirements in the first six months of 2009 compared to the
first six months of 2008.
In the first quarter
of 2009, FES supplied approximately 75% of the Ohio Companies’ power
requirements as one of four winning bidders in the Ohio Companies' RFP process.
In the second quarter of 2009, FES supplied 100% of the power for the Ohio
Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio
Companies' supply needs in June 2009. Subsequent to the Ohio Companies’
CBP, FES purchased additional tranches from other winning bidders and effective
August 1, 2009, FES will supply 62% of the Ohio Companies’ PLR generation
requirements.
The following tables
summarize the price and volume factors contributing to changes in revenues from
generation sales:
|
|
Increase
|
|
Source
of Change in Non-Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect of 57.8% decrease in sales
volumes
|
|
$
|
(182
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect of 4.1% decrease in sales
volumes
|
|
|
(12
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Net Decrease
in Non-Affiliated Generation Revenues
|
|
|
|
)
|
|
|
Increase
|
|
Source
of Change in Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect of 19.2% decrease in sales
volumes
|
|
$
|
(218
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect of 10.6% increase in sales
volumes
|
|
|
37
|
|
Change in prices
|
|
|
|
)
|
|
|
|
|
|
Net Increase
in Affiliated Generation Revenues
|
|
|
|
|
Transmission
revenues decreased $25 million due primarily to reduced retail loads in
MISO. Other revenue increased $36 million primarily due to rental income
associated with NGC's acquisition of additional equity interests in the Perry
and Beaver Valley Unit 2 leases.
Expenses -
Total expenses
decreased $66 million in the first six months of 2009 due to the following
factors:
|
·
|
Purchased
power costs decreased $81 million due to lower volume ($103 million),
partially offset by higher unit prices ($22 million) that resulted from
higher capacity costs.
|
|
·
|
Fuel costs
decreased $55 million due to lower generation volumes
($116 million) partially offset by higher unit prices
($61 million). The higher unit prices, which are expected to continue
for the remainder of 2009, primarily reflect increased costs for eastern
coal.
|
|
·
|
Fossil
operating costs decreased $32 million due to a $24 million reduction
in contractor and material costs that resulted from reduced maintenance
activities and more labor dedicated to capital projects compared to the
prior year.
|
|
·
|
Other expense
increased $49 million due primarily to increased intersegment
billings for leasehold costs from the Ohio
Companies.
|
|
·
|
Transmission
expense increased $24 million due primarily to increased net congestion
and loss expenses in PJM.
|
|
·
|
Higher
depreciation expense of $20 million was due to NGC's increased
ownership interest in Beaver Valley Unit 2 and
Perry.
|
|
·
|
Nuclear
operating costs increased $9 million in the first six months of 2009
due to an additional refueling outage during the 2009
period.
|
Other Expense –
Total other expense
in the first six months of 2009 was $10 million lower than the
first six months of 2009, primarily due to a decline in interest expense (net of
capitalized interest) of $19 million from the repayment of notes payable to
affiliates, partially offset by an $8 million decrease in earnings from
nuclear decommissioning trust investments resulting from securities
impairments.
Ohio Transitional Generation Services –
First Six Months of 2009 Compared to First Six Months of 2008
Net income for this
segment increased to $45 million in the first six
months of 2009 from $43 million in the same period of 2008. Higher
generation revenues, lower operating expenses and increased deferrals of
regulatory assets were partially offset by higher purchased power
expenses.
Revenues –
The
increase in reported segment revenues resulted from the following
sources:
|
|
Six
Months
|
|
|
|
|
|
Ended
June 30
|
|
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The following table
summarizes the price and volume factors contributing to the net increase in
sales revenues from retail customers:
Source
of Change in Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect of 4.7% increase in sales
volumes
|
|
$
|
56
|
|
Change in prices
|
|
|
|
|
Net
Increase in Retail Generation Revenues
|
|
|
|
|
The increase in
generation sales volume in the first six months of 2009 was primarily due to
reduced customer shopping, reflecting the return of customers to PLR service
following the expiration of certain government aggregation programs in Ohio in
2008. This increased sales volume was partially offset by lower sales due to
milder weather and economic conditions in the Ohio Companies' service territory.
Average prices increased primarily due to an increase in the Ohio Companies'
fuel cost recovery riders that were effective from January through May 2009.
Effective June 1, 2009, the transmission tariff ended and the recovery of
transmission costs is included in the generation rate established under the Ohio
Companies' CBP.
Decreased
transmission revenue of $5 million resulted from the termination of the
transmission tariff and lower MISO revenues partially offset by higher sales
volumes. The difference between transmission revenues accrued and transmission
costs incurred is deferred, resulting in no material impact to current period
earnings.
Expenses -
Purchased power
costs were $568 million
higher due primarily to higher unit costs for power. The factors contributing to
the higher costs are summarized in the following table:
Source
of Change in Purchased Power
|
|
Increase
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
Change due to increased unit
costs
|
|
$
|
523
|
|
Change due to increased
volumes
|
|
|
45
|
|
|
|
|
568
|
|
The increase in
purchased volumes was due to the higher retail generation sales requirements
described above. The higher unit costs reflect the results of the Ohio
Companies' power supply procurement processes for retail customers during the
first six months of 2009 (see Regulatory Matters – Ohio).
Other operating
expenses decreased $126 million due to lower MISO transmission expenses
($71 million) and associated company cost reimbursements related to the Ohio
Companies' generation leasehold interests. The amortization of regulatory assets
increased by $75 million in the first six months of 2009 due primarily to
increased MISO transmission cost amortization. The deferral of new regulatory
assets increased by $131 million due to CEI’s deferral of purchased power costs
as approved by the PUCO.
Other – First Six Months of 2009
Compared to First Six Months of 2008
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 $5 million decrease in FirstEnergy's net income in the first
six 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 June 30,
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 June 30,
2009, included the following (in millions):
Currently
Payable Long-term Debt
|
|
|
|
|
PCRBs
supported by bank LOCs(1)
|
|
$
|
1,553
|
|
FGCO and NGC
unsecured PCRBs(1)
|
|
|
97
|
|
CEI secured
notes(2)
|
|
|
150
|
|
Met-Ed
unsecured notes(3)
|
|
|
100
|
|
NGC
collateralized lease obligation bonds
|
|
|
44
|
|
Sinking fund
requirements
|
|
|
40
|
|
|
|
$
|
1,984
|
|
|
|
|
|
|
(1) Interest
rate mode permits individual debt holders to put the respective
debt back to the issuer prior to maturity.
(2) Mature
in November 2009.
(3) Mature
in March
2010.
|
Short-Term
Borrowings
FirstEnergy had
approximately $2.4 billion of short-term borrowings as of June 30, 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 July 30, 2009, FirstEnergy had $420 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 July 30, 2009, is summarized in the
following table:
Company
|
|
Type
|
|
Maturity
|
|
Commitment
|
|
Available
Liquidity
as of
July 30,
2009
|
|
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy(1)
|
|
Revolving
|
|
Aug.
2012
|
|
$
|
2,750
|
|
$
|
273
|
|
FirstEnergy
and FES
|
|
Bank
lines
|
|
Various(2)
|
|
|
120
|
|
|
20
|
|
FGCO
|
|
Term
loan
|
|
Oct. 2009(3)
|
|
|
300
|
|
|
300
|
|
Ohio and
Pennsylvania Companies
|
|
Receivables
financing
|
|
Various(4)
|
|
|
550
|
|
|
451
|
|
|
|
|
|
Subtotal
|
|
$
|
3,720
|
|
$
|
1,044
|
|
|
|
|
|
Cash
|
|
|
-
|
|
|
921
|
|
|
|
|
|
Total
|
|
$
|
3,720
|
|
$
|
1,965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) FirstEnergy
Corp. and subsidiary borrowers.
(2) $100 million
expires March 31, 2011; $20 million uncommitted line of credit has no
expiration 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 June 30, 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 June 30, 2009, FirstEnergy's and its
subsidiaries' debt to total capitalization ratios (as defined under the
revolving credit facility) were as follows:
Borrower
|
|
|
FirstEnergy(1)
|
|
60.7
|
%
|
FES
|
|
53.7
|
%
|
OE
|
|
47.8
|
%
|
Penn
|
|
28.2
|
%
|
CEI
|
|
54.4
|
%
|
TE
|
|
59.7
|
%
|
JCP&L
|
|
37.2
|
%
|
Met-Ed
|
|
49.8
|
%
|
Penelec
|
|
50.9
|
%
|
(1) As of June 30,
2009, FirstEnergy could issue additional debt of
approximately
$3.2 billion, or recognize
a reduction in equity of approximately $1.7 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 six months of 2009 was 0.86% for the regulated
companies' money pool and 1.00% for the unregulated companies' money
pool.
Pollution Control Revenue
Bonds
As of June 30, 2009,
FirstEnergy's currently payable long-term debt included approximately $1.6
billion (FES - $1.5 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(3)
|
|
LOC
Termination Date
|
|
LOC
Draws Due
|
|
|
(In
millions)
|
|
|
|
|
CitiBank
N.A.
|
|
$
|
166
|
|
June
2014
|
|
June
2014
|
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(1)
|
|
266
|
|
June
2010
|
|
6
months
|
Wachovia
Bank
|
|
153
|
|
March
2014
|
|
March
2014
|
Barclays
Bank(2)
|
|
528
|
|
Beginning
December 2010
|
|
30
days
|
PNC
Bank
|
|
|
70
|
|
Beginning
November 2010
|
|
180
days
|
Total
|
|
$
|
1,569
|
|
|
|
|
|
|
|
|
|
|
|
(1) Supported by
four participating banks, with the LOC bank having 62% of the total
commitment.
(2) Supported by
18 participating banks, with no one bank having more than 14% of the total
commitment.
(3) 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.
During the second quarter of 2009, NGC remarketed the remaining
$334 million of PCRBs, of which $170 million was remarketed in fixed
interest rate modes and secured by FMBs, thereby eliminating the need for
third-party credit support. During the second quarter of 2009, FGCO remarketed
approximately $248 million of PCRBs supported by LOCs set to expire in June
2009. These PCRBs were remarketed in fixed interest rate modes and secured by
FMBs, thereby eliminating the need for third-party credit support. Also, in June
2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in
connection with amendments to existing letter of credit and reimbursement
agreements supporting 12 other series of PCRBs as described below and
pledged FMBs to the applicable trustee under six separate series of
PCRBs.
Long-Term Debt Capacity
As of June 30, 2009,
the Ohio Companies and Penn had the aggregate capability to issue approximately
$2.3 billion of additional FMBs on the basis of property additions and
retired bonds under the terms of their respective mortgage indentures. 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 and CEI
to incur additional secured debt not otherwise permitted by a specified
exception of up to $167 million and $175 million, respectively, as of
June 30, 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. As a result, the
provisions for TE to incur additional secured debt do not apply.
Based upon FGCO's
FMB indenture, net earnings and available bondable property additions as of
June 30, 2009, FGCO had the capability to issue $2.2 billion of
additional FMBs under the terms of that indenture. On June 16, 2009, FGCO
issued a total of approximately $395.9 million in principal amount of FMBs, of
which $247.7 million related to three new refunding series of PCRBs and
approximately $148.2 million related to amendments to existing letter of credit
and reimbursement agreements supporting two other series of PCRBs. On June 30,
2009, FGCO issued a total of approximately $52.1 million in principal
amount of FMBs related to three existing series of PCRBs.
In June 2009, a new
FMB indenture was put in place for NGC. Based upon NGC’s FMB indenture, net
earnings and available bondable property additions, NGC had the capability to
issue $264 million of additional FMBs as of June 30, 2009. On June 16,
2009, NGC issued a total of approximately $487.5 million in principal
amount of FMBs, of which $107.5 million related to one new refunding series of
PCRBs and approximately $380 million related to amendments to existing letter of
credit and reimbursement agreements supporting seven other series of PCRBs. In
addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to
$500 million in connection with its guaranty of FES’ obligations to post
and maintain collateral under the Power Supply Agreement entered into by FES
with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On
June 30, 2009, NGC issued a total of approximately $273.3 million in
principal amount of FMBs, of which approximately $92 million related to
three existing series of PCRBs and approximately $181.3 million related to
amendments to existing letter of credit and reimbursement agreements supporting
three other series of PCRBs.
Met-Ed and Penelec
had the capability to issue secured debt of approximately $428 million and
$310 million, respectively, under provisions of their senior note
indentures as of June 30, 2009.
FirstEnergy's access
to capital markets and costs of financing are influenced by the ratings of its
securities. The following table displays FirstEnergy's, FES' and the Utilities'
securities ratings as of June 30, 2009. On June 17, 2009, Moody's
affirmed FirstEnergy's Baa3 and FES' Baa2 credit ratings. On July 9, 2009,
S&P affirmed its ratings on FirstEnergy and its subsidiaries. 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. On
July 29, 2009, FES registered its common stock pursuant to Section 12(g) of
the Securities Exchange Act of 1934.
Changes in Cash Position
As of June 30, 2009,
FirstEnergy had $900 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 June 30, 2009, approximately
$825 million of cash and cash equivalents represented temporary overnight
deposits.
During the first six
months of 2009, FirstEnergy received $453 million of cash from dividends
and equity repurchases from its subsidiaries and paid $335 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%. CEI and TE are
the only utility subsidiaries currently precluded from that action.
Cash Flows From Operating
Activities
FirstEnergy's
consolidated net cash from operating activities is provided primarily by its
competitive energy services and energy delivery services businesses (see Results
of Operations above). Net cash provided from operating activities was
$1.1 billion and $319 million in the first six months of 2009 and
2008, respectively, as summarized in the following table:
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
Net
income
|
|
$
|
523
|
|
$
|
540
|
|
Non-cash
charges
|
|
|
719
|
|
|
435
|
|
Working
capital and other
|
|
|
(140
|
)
|
|
(656
|
)
|
|
|
$
|
1,102
|
|
$
|
319
|
|
Net cash provided
from operating activities increased by $783 million in the first six months
of 2009 compared to the first six months of 2008 primarily due to a
$284 million increase in non-cash charges and a $516 million increase from
working capital and other changes, partially offset by a $17 million
decrease in net income (see Results of Operations above). The increase in
non-cash charges is primarily due to higher net 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 from higher non-cash retirement benefit
expenses recognized in the first six months of 2009. The changes in working
capital and other primarily resulted from lower net tax payments of $278
million, a $70 million decrease in stock-based compensation payments 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 six
months of 2009, cash provided from financing activities was $426 million
compared to $1.2 billion in the first six months of 2008. The decrease was
primarily due to reduced short-term borrowings, partially offset by long-term
debt issuances in the first six months of 2009. The following table summarizes
security issuances (net of any discounts) and redemptions.
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
Securities
Issued or Redeemed
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
New
issues
|
|
|
|
|
|
|
|
First mortgage
bonds
|
|
$
|
100
|
|
$
|
-
|
|
Pollution
control notes
|
|
|
682
|
|
|
529
|
|
Senior secured
notes
|
|
|
297
|
|
|
-
|
|
Unsecured
notes
|
|
|
600
|
|
|
20
|
|
|
|
$
|
1,679
|
|
$
|
549
|
|
|
|
|
|
|
|
|
|
Redemptions
|
|
|
|
|
|
|
|
First mortgage
bonds
|
|
$
|
-
|
|
$
|
1
|
|
Pollution
control notes
|
|
|
682
|
|
|
529
|
|
Senior secured
notes
|
|
|
46
|
|
|
15
|
|
Unsecured
notes
|
|
|
153
|
|
|
175
|
|
|
|
$
|
881
|
|
$
|
720
|
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
$
|
-
|
|
$
|
1,705
|
|
The following table
summarizes new debt issuances (excluding PCRB issuances and refinancings) during
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met-Ed*
|
|
01/20/2009
|
|
$300
|
|
7.70% Senior
Notes
|
|
2019
|
|
Repay
short-term borrowings
|
|
|
|
|
|
|
|
|
|
|
|
JCP&L*
|
|
01/27/2009
|
|
$300
|
|
7.35% Senior
Notes
|
|
2019
|
|
Repay
short-term borrowings, fund capital expenditures and other general
purposes
|
|
|
|
|
|
|
|
|
|
|
|
TE*
|
|
04/24/2009
|
|
$300
|
|
7.25% Senior
Secured
Notes
|
|
2020
|
|
Repay
short-term borrowings, fund capital expenditures and other general
purposes
|
|
|
|
|
|
|
|
|
|
|
|
Penn
|
|
06/30/2009
|
|
$100
|
|
6.09%
FMB
|
|
2022
|
|
Fund capital
expenditures and repurchase equity from OE
|
|
|
|
|
|
|
|
|
|
|
|
* Issuance was
sold off the shelf registration statement referenced
above.
|
Cash Flows From Investing
Activities
Net cash flows used
in investing activities resulted primarily from property additions. Additions
for the energy delivery services segment primarily represent 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 six months ended June
30, 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)
|
|
Six
Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
$ |
|
)
|
$ |
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
Inter-Segment
reconciling items
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
|
|
|
|
|
$ |
|
|
$ |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
Competitive
energy services
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-Segment
reconciling items
|
|
|
|
|
|
|
)
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for
investing activities in the first six months of 2009 decreased by $432 million
compared to the first six months of 2008. The decrease was principally due to a
$474 million decrease in property additions, which reflects lower AQC
system expenditures and the absence in 2009 of the purchase of certain lessor
equity interests in Beaver Valley Unit 2 and Perry, and the purchase of a
partially-completed generating plant in Fremont, Ohio. The decrease
in property additions was partially offset by the absence in 2009 of cash
proceeds from the sale of telecommunication assets in the first quarter of
2008.
During the second
half of 2009, capital requirements for property additions and capital leases are
expected to be approximately $773 million, including approximately $176
million for nuclear fuel. FirstEnergy has additional requirements of
approximately $177 million for maturing long-term debt during the remainder
of 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
$7.9 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 $337 million applies to 2009. During the same period,
FirstEnergy's nuclear fuel investments are expected to be reduced by
approximately $1.0 billion and $131 million, respectively, as the
nuclear fuel is consumed.
GUARANTEES
AND OTHER ASSURANCES
As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. Some of the
guaranteed contracts contain collateral provisions that are contingent upon
FirstEnergy’s credit ratings.
As of June 30, 2009,
FirstEnergy’s maximum exposure to potential future payments under outstanding
guarantees and other assurances approximated $4.6 billion, as summarized
below:
|
|
Maximum
|
|
Guarantees
and Other Assurances
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy
Guarantees on Behalf of its Subsidiaries
|
|
|
|
Energy and
Energy-Related Contracts (1)
|
|
$
|
427
|
|
LOC (long-term
debt) – interest coverage (2)
|
|
|
6
|
|
FirstEnergy
guarantee of OVEC obligations
|
|
|
300
|
|
Other (3)
|
|
|
600
|
|
|
|
|
1,333
|
|
|
|
|
|
|
Subsidiaries’
Guarantees
|
|
|
|
|
Energy and
Energy-Related Contracts
|
|
|
54
|
|
LOC (long-term
debt) – interest coverage (2)
|
|
|
6
|
|
FES’ guarantee
of NGC’s nuclear property insurance
|
|
|
77
|
|
FES’ guarantee
of FGCO’s sale and leaseback obligations
|
|
|
2,502
|
|
|
|
|
2,639
|
|
|
|
|
|
|
Surety
Bonds
|
|
|
108
|
|
LOC (long-term
debt) – interest coverage (2)
|
|
|
4
|
|
LOC (non-debt)
(4)(5)
|
|
|
501
|
|
|
|
|
613
|
|
Total
Guarantees and Other Assurances
|
|
$
|
4,585
|
|
|
(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 $80 million for nuclear decommissioning funding (see
Nuclear Plant
Matters below) assurances and $161 million supporting OE’s sale
and leaseback
arrangement. Also includes $300 million for a Credit Suisse credit
facility for
FGCO that is guaranteed by both FirstEnergy and
FES.
|
|
(4)
|
Includes
$161 million issued for various terms pursuant to LOC capacity
available
under
FirstEnergy’s revolving credit
facility.
|
|
(5)
|
Includes
approximately $206 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 by OE.
|
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 June 30, 2009, FirstEnergy’s maximum exposure
under these collateral provisions was $601 million as shown
below:
Collateral
Provisions
|
|
FES
|
|
Utilities
|
|
Total
|
|
|
|
(In
millions)
|
|
Credit rating
downgrade to
below
investment grade
|
|
$
|
315
|
|
$
|
110
|
|
$
|
425
|
|
Acceleration
of payment or
funding
obligation
|
|
|
80
|
|
|
55
|
|
|
135
|
|
Material
adverse event
|
|
|
41
|
|
|
-
|
|
|
41
|
|
Total
|
|
$
|
436
|
|
$
|
165
|
|
$
|
601
|
|
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 $700 million, consisting of
$49 million due to “material adverse event” contractual clauses and $651
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
June 30, 2009, and forward prices as of that date, FES had $179 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 $73 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 connection with
FES’ obligations to post and maintain collateral under the two-year PSA entered
into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009,
NGC entered into a Surplus Margin Guaranty in the amount of approximately
$500 million, dated as of June 16, 2009, in favor of the Ohio
Companies.
FES’ debt
obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant
to guarantees entered into on March 26, 2007. Similar guarantees were entered
into on that date pursuant to which FES guaranteed the debt obligations of each
of FGCO and NGC. Accordingly, present and future holders of
indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and
NGC regardless of whether their primary obligor is FES, FGCO or
NGC.
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 June 30, 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 three
months and six months ended June 30, 2009 are summarized in the following
table:
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
June 30, 2009
|
|
Ended
June 30, 2009
|
|
Fair Value of
Commodity Derivative Contracts
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
Non-Hedge
|
|
Hedge
|
|
Total
|
|
|
|
(In
millions)
|
|
Change
in the Fair Value of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
net liability at beginning of period
|
|
$
|
(457
|
)
|
$
|
(29
|
)
|
$
|
(486
|
)
|
$
|
(304
|
)
|
$
|
(41
|
)
|
$
|
(345
|
)
|
Additions/change
in value of existing contracts
|
|
|
(154
|
)
|
|
8
|
|
|
(146
|
)
|
|
(381
|
)
|
|
(2
|
)
|
|
(383
|
)
|
Settled
contracts
|
|
|
96
|
|
|
7
|
|
|
103
|
|
|
170
|
|
|
29
|
|
|
199
|
|
Outstanding
net liability at end of period (1)
|
|
$
|
(515
|
)
|
$
|
(14
|
)
|
$
|
(529
|
)
|
$
|
(515
|
)
|
$
|
(14
|
)
|
$
|
(529
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-commodity
Net Liabilities at End of Period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate
swaps (2)
|
|
|
-
|
|
|
(3
|
)
|
|
(3
|
)
|
|
-
|
|
|
(3
|
)
|
|
(3
|
)
|
Net
Liabilities - Derivative Contracts
at
End of Period
|
|
$
|
(515
|
)
|
$
|
(17
|
)
|
$
|
(532
|
)
|
$
|
(515
|
)
|
$
|
(17
|
)
|
$
|
(532
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact
of Changes in Commodity Derivative Contracts(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
statement effects (pre-tax)
|
|
$
|
2
|
|
$
|
-
|
|
$
|
2
|
|
$
|
3
|
|
$
|
-
|
|
$
|
3
|
|
Balance sheet
effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (pre-tax)
|
|
$
|
-
|
|
$
|
15
|
|
$
|
15
|
|
$
|
-
|
|
$
|
27
|
|
$
|
27
|
|
Regulatory
assets (net)
|
|
$
|
60
|
|
$
|
-
|
|
$
|
60
|
|
$
|
214
|
|
$
|
-
|
|
$
|
214
|
|
(1)
|
Includes
$517 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 June 30, 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
June 30, 2009 are summarized by year in the following table:
Source
of Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
Fair Value by Contract Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
Prices
actively quoted(2)
|
|
$
|
(7
|
)
|
$
|
(11
|
)
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(18
|
)
|
Other external
sources(3)
|
|
|
(147
|
)
|
|
(252
|
)
|
|
(204
|
)
|
|
(120
|
)
|
|
-
|
|
|
-
|
|
|
(723
|
)
|
Prices based
on models
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
Total(4)
|
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
|
|
|
)
|
(1) For
the last two quarters of 2009.
(2) Represents
exchange traded NYMEX futures and options.
(3) Primarily
represents contracts based on broker and ICE quotes.
|
(4)
|
Includes
$517 million in non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
FirstEnergy performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of June 30, 2009. Based on derivative contracts held as of June 30,
2009, an adverse 10% change in commodity prices would decrease net income by
approximately $4 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 six 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 million) will be recognized over the terms
of the associated future debt. As of June 30, 2009, FirstEnergy had outstanding
forward swaps with an aggregate notional amount of $200 million and an
aggregate fair value of $(3) million.
|
|
June
30, 2009
|
|
December
31, 2008
|
|
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
Notional
|
|
Maturity
|
|
Fair
|
|
|
|
Amount
|
|
Date
|
|
Value
|
|
Amount
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|
Date
|
|
Value
|
|
|
|
(In
millions)
|
|
Cash flow
hedges
|
|
$
|
|
|
|
|
|
$
|
|
|
$
|
|
|
|
|
|
$
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|
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|
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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.
FirstEnergy’s other postretirement benefits plans were remeasured as of May 31,
2009 as a result of a plan amendment announced on June 2, 2009, which
reduces future health care coverage subsidies paid by FirstEnergy on behalf of
plan participants. The remeasurement and plan amendment will result in a
$48 million reduction in FirstEnergy’s net postretirement benefit cost
(including amounts capitalized) for the remainder of 2009, including a
$7 million reduction that is applicable to the second quarter of 2009 (see
Note 5). 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 assumed 7-7.5%
discount rates, FirstEnergy's pre-tax net periodic pension and OPEB expense was
$38 million in the second quarter of 2009.
Nuclear
decommissioning trust funds have been established to satisfy NGC's and the
Utilities' nuclear decommissioning obligations. As of June 30, 2009,
approximately 34% of the funds were invested in equity securities and 66% 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 $588 million as of June 30, 2009. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$59 million reduction in fair value as of June 30, 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 June 18, 2009, the NRC informed
FENOC that its review tentatively concluded that a shortfall ($147.5 million net
present value) existed in the value of the decommissioning trust fund for Beaver
Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 (see
Nuclear Plant Matters) would mitigate the estimated shortfall in the unit’s
nuclear decommissioning funding status. FENOC continues to communicate with the
NRC regarding future actions to provide reasonable assurance for decommissioning
funding. Such actions may include additional parental guarantees or
contributions to those funds.
CREDIT
RISK
Credit risk is the
risk of an obligor's failure to meet the terms of any investment contract, loan
agreement or otherwise perform as agreed. Credit risk arises from all activities
in which success depends on issuer, borrower or counterparty performance,
whether reflected on or off the balance sheet. FirstEnergy engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.
FirstEnergy
maintains credit policies with respect to its counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of its credit program, FirstEnergy aggressively
manages the quality of its portfolio of energy contracts, evidenced by a current
weighted average risk rating for energy contract counterparties of BBB
(S&P). As of June 30, 2009, the largest credit concentration was with JP
Morgan, which is currently rated investment grade, representing 9.4% 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 $158 million as of June 30, 2009
(JCP&L - $48 million, Met-Ed - $95 million and Penelec - $15
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 and Penelec. The
following table discloses net regulatory assets by company:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
514
|
|
$
|
575
|
|
$
|
(61
|
)
|
CEI
|
|
|
628
|
|
|
784
|
|
|
(156
|
)
|
TE
|
|
|
91
|
|
|
109
|
|
|
(18
|
)
|
JCP&L
|
|
|
1,055
|
|
|
1,228
|
|
|
(173
|
)
|
Met-Ed
|
|
|
497
|
|
|
413
|
|
|
84
|
|
Penelec*
|
|
|
10
|
|
|
-
|
|
|
10
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
)
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec had
net regulatory liabilities of approximately $137 million
as of
December 31, 2008. These net regulatory liabilities are
included in
Other Non-current Liabilities on the Consolidated
Balance
Sheets.
|
Regulatory assets by
source are as follows:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets By Source
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Regulatory
transition costs
|
|
$
|
1,278
|
|
$
|
1,452
|
|
$
|
(174
|
)
|
Customer
shopping incentives
|
|
|
218
|
|
|
420
|
|
|
(202
|
)
|
Customer
receivables for future income taxes
|
|
|
332
|
|
|
245
|
|
|
87
|
|
Loss on
reacquired debt
|
|
|
52
|
|
|
51
|
|
|
1
|
|
Employee
postretirement benefits
|
|
|
27
|
|
|
31
|
|
|
(4
|
)
|
Nuclear
decommissioning, decontamination
|
|
|
|
|
|
|
|
|
|
|
and spent fuel
disposal costs
|
|
|
(115
|
)
|
|
(57
|
)
|
|
(58
|
)
|
Asset removal
costs
|
|
|
(226
|
)
|
|
(215
|
)
|
|
(11
|
)
|
MISO/PJM
transmission costs
|
|
|
279
|
|
|
389
|
|
|
(110
|
)
|
Purchased
power costs
|
|
|
360
|
|
|
214
|
|
|
146
|
|
Distribution
costs
|
|
|
482
|
|
|
475
|
|
|
7
|
|
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 the NERC’s request for factual data about the outage.
JCP&L submitted its written response on May 1, 2009. The NERC conducted
on site interviews with personnel involved in responding to the event on June
16-17, 2009. On July 7, 2009, the NERC issued additional questions
regarding the event and JCP&L is required to reply by August 7, 2009.
JCP&L is not able at this time to predict what actions, if any, that the
NERC may take based on the data submittal or interview results.
On June 5, 2009,
FirstEnergy self-reported to ReliabilityFirst a potential
violation of NERC Standard PRC-005 resulting from its inability to validate
maintenance records for 20 protection system relays in JCP&L’s and Penelec’s
transmission systems. These potential violations were discovered during a
comprehensive field review of all FirstEnergy substations to verify equipment
and maintenance database accuracy. FirstEnergy has completed all mitigation
actions, including calibrations and maintenance records for the relays.
ReliabilityFirst issued
an Initial Notice of Alleged Violation on June 22, 2009. FirstEnergy is not able
at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this
self-report of violation.
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 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 for the purpose of further
consideration. The PUCO has not yet issued a substantive Entry on
Rehearing.
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, which is
still pending. 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 provided generation service to the Ohio Companies’ retail
customers who chose 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 denied OE’s and TE’s request to continue collecting
RTC and denied the request to allow the Ohio Companies to continue collections
pursuant to the two existing fuel riders. The new fuel rider recovered the
increased purchased power costs for OE and TE, and recovered a portion of those
costs for CEI, with the remainder being deferred 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 provided that generation would 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 would be based upon the outcome of a descending clock CBP on a
slice-of-system basis. The Amended ESP further provided 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
would agree to write-off approximately $216 million of its Extended RTC
balance, and that the Ohio Companies would 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
addressed a number of other issues, including but not limited to, rate design
for various customer classes, and 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, 2009 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 took effect on April 1,
2009 while the remaining provisions took effect on June 1,
2009.
On July 27, 2009,
the Ohio Companies filed applications with the PUCO to recover three different
categories of deferred distribution costs on an accelerated basis. In the Ohio
Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with
collection originally set to begin in January 2011 and to continue over a 5 or
25 year period. The principal amount plus carrying charges through August 31,
2009 for these deferrals is a total of $298.4 million. If the applications are
approved, recovery of this amount, together with carrying charges calculated as
approved in the Amended ESP, will be collected in the 18 non-summer months from
September 2009 through May 2011, subject to reconciliation until fully
collected, with $165 million of the above amount being recovered from
residential customers, and $133.4 million being recovered from non-residential
customers. Pursuant to the applications, customers would pay significantly less
over the life of the recovery of the deferral through the reduction in carrying
charges as compared to the expected recovery under the previously approved
recovery mechanism.
The Ohio Companies
are presently involved in collaborative efforts related to energy efficiency and
a competitive bidding process, together with other implementation efforts
arising out of the Supplemental Stipulation. The CBP auction occurred on
May 13-14, 2009, and resulted in a weighted average wholesale price for
generation and transmission of 6.15 cents per KWH. The bid was for a single,
two-year product for the service period from June 1, 2009 through May 31,
2011. FES participated in the auction, winning 51% of the tranches (one tranche
equals one percent of the load supply). Subsequent to the signing of the
wholesale contracts, two winning bidders reached separate agreements with FES to
assign a total of 11 tranches to FES for various periods. In addition, FES has
separately contracted with numerous communities to provide retail generation
service through governmental aggregation programs.
SB221 also requires
electric distribution utilities to implement energy efficiency programs that
achieve a total annual 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 1%,
with an additional seventy-five hundredths of one percent reduction each year
thereafter through 2018. Additionally, electric utilities and electric service
companies are required to serve part of their load from renewable energy
resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has
efforts underway to address compliance with these requirements. Costs associated
with compliance are recoverable from customers.
On June 17, 2009,
the PUCO modified rules that implement the alternative energy portfolio
standards created by SB221, including the incorporation of energy efficiency
requirements, long-term forecast and greenhouse gas reporting and CO2 control
planning. The PUCO filed the rules with the Joint Committee on Agency Rule
Review on July 7, 2009, after which begins a 65-day review period. The Ohio
Companies and one other party filed applications for rehearing on the rules with
the PUCO on July 17, 2009.
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 included a component from
under-recovery of actual transmission costs incurred during the prior period
(Met-Ed - $144 million and Penelec - $4 million) and 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 May 28, 2009, the
PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider 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 resulted
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 increased 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, the PPUC approved Met-Ed’s
proposal to continue to recover the prior period deferrals allowed in the PPUC’s
May 2008 Order and defer $57.5 million of projected costs to a future TSC to be
fully recovered by December 31, 2010. Under this proposal, monthly bills for
Met-Ed’s customers will 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. Act 129 addresses issues
such as: energy efficiency and peak load reduction; generation procurement;
time-of-use rates; smart meters; and alternative energy. 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 prudent 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;
|
·
|
utilities must
reduce peak demand by a minimum of 4.5% by May 31,
2013;
|
·
|
utilities must
reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and
May 31, 2013, respectively; and
|
·
|
the definition
of Alternative Energy was expanded to include additional types of
hydroelectric and biomass
facilities.
|
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. On June 18, 2009, the PPUC issued its
guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec,
and Penn filed Energy Efficiency and Conservation Plans with the PPUC in
accordance with Act 129.
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 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 February 26,
2009, the PPUC approved a Voluntary Prepayment Plan 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 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. On July 30, 2009,
the PPUC entered an order approving the 5-year NUG Statement, approving the
reduction of the CTC, and directing Met-Ed and Penelec to file a tariff
supplement implementing this change. On July 31, 2009, Met-Ed and Penelec
filed tariff supplements decreasing the CTC rate in compliance with the
July 30, 2009 order, and increasing the generation rate in compliance with
the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are
awaiting PPUC action on the July 31, 2009
filings.
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 June 30,
2009, the accumulated deferred cost balance totaled approximately
$149 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.
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
a proposal to spend approximately $98 million on infrastructure and energy
efficiency projects in 2009. Under the proposal, an estimated $40
million would be spent on infrastructure projects, including substation
upgrades, new transformers, distribution line re-closers and automated breaker
operations. Approximately $34 million would be spent implementing new
demand response programs as well as expanding on existing
programs. Another $11 million would be spent on energy efficiency,
specifically replacing transformers and capacitor control systems and installing
new LED street lights. The remaining $13 million would be spent on energy
efficiency programs that would complement those currently being offered.
Implementation of the projects is dependent upon resolution of regulatory issues
including recovery of the costs associated with the proposal.
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. AEP's 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 arguments were
held on April 13, 2009. A decision is expected this summer.
The FERC’s orders on
PJM rate design would 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 would 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 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.
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. 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 discussions. 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; and subsequently, numerous parties filed requests for
rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied
rehearing and request for oral argument of the March 26 Order.
PJM has reconvened
the Capacity Market Evolution Committee to address issues not addressed in the
February 2009 settlement in preparation for September 1, 2009 and December 1,
2009 compliance filings that will recommend more incremental improvements to its
RPM.
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 and FES. This requirement was 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 was implemented as planned on June 1, 2009, the beginning of the MISO
planning year. On June 17, 2009, MISO submitted a compliance filing in
response to the FERC’s April 16, 2009 order directing it to address, among
others, various market monitoring and mitigation issues. On July 8, 2009,
various parties submitted comments on and protests to MISO’s compliance filing.
FirstEnergy submitted comments identifying specific aspects of the MISO’s and
Independent Market Monitor’s proposals for market monitoring and mitigation and
other issues that it believes the FERC should address and clarify.
FES Sales to Affiliates
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 a December 23,
2008 waiver of restrictions on affiliate sales without prior approval of the
FERC.
On May 13-14, 2009,
the Ohio Companies held an auction to secure generation supply for their PLR
obligation. The results of the auction were accepted by the PUCO on May 14,
2009. Twelve bidders qualified to participate in the auction with nine
successful bidders each securing a portion of the Ohio Companies' total supply
needs. FES was the successful bidder for 51 tranches, and subsequently purchased
11 additional tranches from other bidders. The auction resulted in an overall
weighted average wholesale price of 6.15 cents per KWH for generation and
transmission. The new prices for PLR service went into effect with usage
beginning June 1, 2009, and continuing through May 31, 2011.
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 approximately two-thirds of those
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,
under a Cooperative Agreement with the Agency for Toxic Substances and Disease
Registry, completed a Health Consultation regarding the Mansfield Plant and
issued a report dated March 31, 2009 which concluded there is insufficient
sampling data to determine if any public health threat exists for area residents
due to emissions from the Mansfield Plant. The report recommended additional air
monitoring and sample analysis in the vicinity of the Mansfield Plant which the
Pennsylvania Department of Environmental Protection is currently
conducting.
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. On October 30, 2008, the state of
Connecticut filed a Motion to Intervene, which the Court granted on March 24,
2009. Specifically, Connecticut and New Jersey allege 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 seek injunctive relief, penalties, attorney fees and mitigation of
the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation
to and from Sithe Energy is disputed. 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 and Connecticut’s
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 1,
2009, the Court held oral argument on Met-Ed’s motion to dismiss the
complaint.
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 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 2.5 million tons annually and NOX emissions
to 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. On July 10, 2009,
the United States Court of Appeals for the District of Columbia ruled in a
different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,”
cannot be used to satisfy certain CAA requirements (known as reasonably
available control technology) for areas in non-attainment under the "8-hour"
ozone NAAQS. FGCO's 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 any future regulations 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, by 2012, the amount
of man-made GHG, including CO2, emitted
by developed countries. The United States signed the Kyoto Protocol in 1998 but
it was never submitted for ratification by the United States Senate. 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 used in the United States comes from renewable sources by
2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade
program to reduce GHG emissions by 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 House of
Representatives passed one such bill, the American Clean Energy and Security Act
of 2009, on June 26, 2009. 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. In March and June 2009, the EPA requested
information from FGCO’s Bruce Mansfield Plant regarding the management of coal
combustion wastes. FGCO's future cost of compliance with any coal combustion
waste regulations which may be promulgated could be substantial and would
depend, in part, on the regulatory action taken by the EPA and implementation by
the states.
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 June 30, 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 $104 million have been
accrued through June 30, 2009. Included in the total are accrued
liabilities of approximately $68 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. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages due to the outages.
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. On March 31, 2009, the
trial court again granted JCP&L’s motion to decertify the class. On April
20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory
appeal to the trial court's decision to decertify the class, which was granted
by the Appellate Division on June 15, 2009. According to the scheduling order
issued by the Appellate Division, Plaintiffs' opening brief is due on August 25,
2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs'
reply is due on October 5, 2009.
Nuclear Plant Matters
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
June 8, 2009, the NRC issued the final Safety Evaluation Report (SER)
supporting the renewed license for Beaver Valley Units 1 and 2. On July 8,
2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public
meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved
questions raised by a letter from Citizens Power regarding the extent of
corrective actions for the 2009 discovery of a penetration in the Beaver Valley
Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC
further clarifications on the supplemental volumetric examinations of
Beaver Valley’s containment liners. FENOC anticipates another meeting with
the ACRS regarding the container liner during September 2009. FENOC will
continue to work with the NRC Staff as it completes its environmental and
technical reviews of the license renewal application, and is scheduled 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.
Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had
approximately $1.7 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 provided an additional $80 million parental guarantee
associated with the funding of decommissioning costs for these units and
indicated that it planned to contribute an additional $80 million to these
trusts by 2010. As required by the NRC, FirstEnergy annually
recalculates and adjusts the amount of its parental guarantee, as appropriate.
The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on
market conditions. If the value of the trusts decline by a material amount,
FirstEnergy’s obligations to fund the trusts may increase. The recent disruption
in the capital markets and its effects on particular businesses and the economy
in general also affects the values of the nuclear decommission trusts. On June
18, 2009, the NRC informed FENOC that its review tentatively concluded that a
shortfall ($147.5 million net present value) existed in the value of the
decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC
submitted a letter to the NRC that stated reasonable assurance of
decommissioning funding is provided for Beaver Valley Unit 1 through a
combination of the existing trust fund balances, the existing $80 million
parental guarantee from FirstEnergy and maintaining the plant in a safe-store
configuration, or extended safe shutdown condition, after plant shutdown.
Renewal of the operating license for Beaver Valley Unit 1, as described above,
would mitigate the estimated shortfall in the unit’s nuclear decommissioning
funding status. FENOC continues to communicate with the NRC regarding
future actions to provide reasonable assurance for decommissioning funding. Such
actions may include additional parental guarantees or contributions to those
funds.
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 bargaining unit
employees at the Bruce Mansfield Plant have been working without a labor
contract since February 15, 2008. On July 24,
2009, FirstEnergy declared that bargaining was at an impasse and portions of its
last contract offer were implemented August 1, 2009. A federal
mediator is continuing to assist the parties in reaching a negotiated contract
settlement. FirstEnergy has a strike mitigation plan ready in the event
of a strike.
On May 21, 2009, 517
Penelec employees, represented by the International Brotherhood of Electrical
Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009,
Penelec implemented its work-continuation plan to use nearly 400 non-represented
employees with previous line experience and training drawn from Penelec and
other FirstEnergy operations to perform service reliability and priority
maintenance work in Penelec’s service territory. Penelec's IBEW Local 459
employees ratified a three-year contract agreement on July 19, 2009, and
returned to work on July 20, 2009.
On June 26, 2009,
FirstEnergy announced that seven of its union locals, representing about 2,600
employees, have ratified contract extensions. These unions include employees
from Penelec, Penn, CEI, OE and TE, along with certain power plant
employees.
On July 8, 2009,
FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777
ratified a two-year contract. Union members had been working without a contract
since the previous agreement expired on April 30, 2009.
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 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 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.
SFAS
166 – “Accounting for Transfers of Financial Assets – an amendment of FASB
Statement No. 140”
In June 2009, the
FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and
eliminates the concept of a qualifying special-purpose entity (QSPE). It removes
the exception from applying FIN 46R to QSPEs and requires an evaluation of all
existing QSPEs to determine whether they must be consolidated in accordance with
SFAS 167. This Statement is effective for financial asset transfers that occur
in fiscal years beginning after November 15, 2009. FirstEnergy does not expect
this Standard to have a material effect upon its financial
statements.
SFAS 167 – “Amendments to FASB
Interpretation No. 46(R)”
In June 2009, the
FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs.
This Statement replaces the quantitative approach previously required to
determine which entity has a controlling financial interest in a VIE with a
qualitative approach. Under the new approach, the primary beneficiary of a VIE
is the entity that has both (a) the power to direct the activities of the VIE
that most significantly impact the entity’s economic performance, and (b) the
obligation to absorb losses of the entity, or the right to receive benefits from
the entity, that could be significant to the VIE. SFAS 167 also requires
ongoing reassessments of whether an entity is the primary beneficiary of a VIE
and enhanced disclosures about an entity’s involvement in VIEs. This Statement
is effective for fiscal years beginning after November 15, 2009. FirstEnergy is
currently evaluating the impact of adopting this Standard on its financial
statements.
SFAS 168 – “The FASB
Accounting Standards CodificationTM and the Hierarchy of Generally
Accepted Accounting Principles – a replacement of FASB Statement No.
162”
In June 2009, the
FASB issued SFAS 168, which recognizes the FASB Accounting Standards
CodificationTM
(Codification) as the source of authoritative GAAP. It also recognizes that
rules and interpretative releases of the SEC under federal securities laws are
sources of authoritative GAAP for SEC registrants. The Codification supersedes
all non-SEC accounting and reporting standards. This Statement is effective for
financial statements issued for interim and annual periods ending after
September 15, 2009. This Statement will change how FirstEnergy references GAAP
in its financial statement disclosures.
Report
of Independent Registered Public Accounting Firm
To the Stockholders
and Board of
Directors of
FirstEnergy Corp.:
We have reviewed the
accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of June 30, 2009 and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2009 and 2008 and the consolidated statement of cash
flows for the six-month periods ended June 30, 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
August 3,
2009
|
FIRSTENERGY
CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months
|
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
|
Ended
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
millions, except per share amounts)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
utilities
|
|
$ |
2,791 |
|
|
$ |
2,865 |
|
|
$ |
5,811 |
|
|
$ |
5,778 |
|
Unregulated
businesses
|
|
|
480 |
|
|
|
380 |
|
|
|
794 |
|
|
|
744 |
|
Total revenues
*
|
|
|
3,271 |
|
|
|
3,245 |
|
|
|
6,605 |
|
|
|
6,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
276 |
|
|
|
316 |
|
|
|
588 |
|
|
|
644 |
|
Purchased
power
|
|
|
1,024 |
|
|
|
1,070 |
|
|
|
2,167 |
|
|
|
2,070 |
|
Other
operating expenses
|
|
|
612 |
|
|
|
781 |
|
|
|
1,439 |
|
|
|
1,580 |
|
Provision for
depreciation
|
|
|
185 |
|
|
|
168 |
|
|
|
362 |
|
|
|
332 |
|
Amortization
of regulatory assets
|
|
|
233 |
|
|
|
246 |
|
|
|
642 |
|
|
|
504 |
|
Deferral of
regulatory assets
|
|
|
(45 |
) |
|
|
(98 |
) |
|
|
(136 |
) |
|
|
(203 |
) |
General
taxes
|
|
|
184 |
|
|
|
180 |
|
|
|
395 |
|
|
|
395 |
|
Total
expenses
|
|
|
2,469 |
|
|
|
2,663 |
|
|
|
5,457 |
|
|
|
5,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
802 |
|
|
|
582 |
|
|
|
1,148 |
|
|
|
1,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
27 |
|
|
|
16 |
|
|
|
16 |
|
|
|
33 |
|
Interest
expense
|
|
|
(206 |
) |
|
|
(188 |
) |
|
|
(400 |
) |
|
|
(367 |
) |
Capitalized
interest
|
|
|
33 |
|
|
|
13 |
|
|
|
61 |
|
|
|
21 |
|
Total other
expense
|
|
|
(146 |
) |
|
|
(159 |
) |
|
|
(323 |
) |
|
|
(313 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
656 |
|
|
|
423 |
|
|
|
825 |
|
|
|
887 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
248 |
|
|
|
160 |
|
|
|
302 |
|
|
|
347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
408 |
|
|
|
263 |
|
|
|
523 |
|
|
|
540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income (loss)
|
|
|
(6 |
) |
|
|
- |
|
|
|
(10 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
AVAILABLE TO FIRSTENERGY CORP.
|
|
$ |
414 |
|
|
$ |
263 |
|
|
$ |
533 |
|
|
$ |
539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK
|
|
$ |
1.36 |
|
|
$ |
0.86 |
|
|
$ |
1.75 |
|
|
$ |
1.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
|
|
304 |
|
|
|
304 |
|
|
|
304 |
|
|
|
304 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK
|
|
$ |
1.36 |
|
|
$ |
0.85 |
|
|
$ |
1.75 |
|
|
$ |
1.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
|
|
305 |
|
|
|
307 |
|
|
|
306 |
|
|
|
307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DIVIDENDS
DECLARED PER SHARE OF COMMON STOCK
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
0.55 |
|
|
$ |
0.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Includes
excise tax collections of $95 million and $100 million in the three months
ended June 30, 2009 and 2008, respectively, and
|
|
$204 million
and $214 million in the six months ended June 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
|
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
|
Ended
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
408 |
|
|
$ |
263 |
|
|
$ |
523 |
|
|
$ |
540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
469 |
|
|
|
(20 |
) |
|
|
504 |
|
|
|
(40 |
) |
Unrealized
gain (loss) on derivative hedges
|
|
|
23 |
|
|
|
8 |
|
|
|
38 |
|
|
|
(5 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
|
37 |
|
|
|
(23 |
) |
|
|
32 |
|
|
|
(81 |
) |
Other
comprehensive income (loss)
|
|
|
529 |
|
|
|
(35 |
) |
|
|
574 |
|
|
|
(126 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
227 |
|
|
|
(14 |
) |
|
|
242 |
|
|
|
(47 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
302 |
|
|
|
(21 |
) |
|
|
332 |
|
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
710 |
|
|
|
242 |
|
|
|
855 |
|
|
|
461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LESS:
COMPREHENSIVE INCOME ATTRIBUTABLE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TO
NONCONTROLLING INTEREST
|
|
|
(6 |
) |
|
|
- |
|
|
|
(10 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME AVAILABLE TO FIRSTENERGY CORP.
|
|
$ |
716 |
|
|
$ |
242 |
|
|
$ |
865 |
|
|
$ |
460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
millions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
900 |
|
|
$ |
545 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $26 million and $28
million,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
1,313 |
|
|
|
1,304 |
|
Other (less
accumulated provisions of $9 million for uncollectible
accounts)
|
|
|
127 |
|
|
|
167 |
|
Materials and
supplies, at average cost
|
|
|
644 |
|
|
|
605 |
|
Prepaid
taxes
|
|
|
457 |
|
|
|
283 |
|
Other
|
|
|
209 |
|
|
|
149 |
|
|
|
|
3,650 |
|
|
|
3,053 |
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
27,315 |
|
|
|
26,482 |
|
Less -
Accumulated provision for depreciation
|
|
|
11,113 |
|
|
|
10,821 |
|
|
|
|
16,202 |
|
|
|
15,661 |
|
Construction
work in progress
|
|
|
2,307 |
|
|
|
2,062 |
|
|
|
|
18,509 |
|
|
|
17,723 |
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
1,733 |
|
|
|
1,708 |
|
Investments in
lease obligation bonds
|
|
|
553 |
|
|
|
598 |
|
Other
|
|
|
696 |
|
|
|
711 |
|
|
|
|
2,982 |
|
|
|
3,017 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
5,575 |
|
|
|
5,575 |
|
Regulatory
assets
|
|
|
2,819 |
|
|
|
3,140 |
|
Power purchase
contract asset
|
|
|
214 |
|
|
|
434 |
|
Other
|
|
|
557 |
|
|
|
579 |
|
|
|
|
9,165 |
|
|
|
9,728 |
|
|
|
$ |
34,306 |
|
|
$ |
33,521 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
1,984 |
|
|
$ |
2,476 |
|
Short-term
borrowings
|
|
|
2,397 |
|
|
|
2,397 |
|
Accounts
payable
|
|
|
806 |
|
|
|
794 |
|
Accrued
taxes
|
|
|
259 |
|
|
|
333 |
|
Other
|
|
|
782 |
|
|
|
1,098 |
|
|
|
|
6,228 |
|
|
|
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
|
|
|
5,465 |
|
|
|
5,473 |
|
Accumulated
other comprehensive loss
|
|
|
(1,048 |
) |
|
|
(1,380 |
) |
Retained
earnings
|
|
|
4,525 |
|
|
|
4,159 |
|
Total common
stockholders' equity
|
|
|
8,973 |
|
|
|
8,283 |
|
Noncontrolling
interest
|
|
|
28 |
|
|
|
32 |
|
Total
equity
|
|
|
9,001 |
|
|
|
8,315 |
|
Long-term debt
and other long-term obligations
|
|
|
10,399 |
|
|
|
9,100 |
|
|
|
|
19,400 |
|
|
|
17,415 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
2,447 |
|
|
|
2,163 |
|
Asset
retirement obligations
|
|
|
1,379 |
|
|
|
1,335 |
|
Deferred gain
on sale and leaseback transaction
|
|
|
1,010 |
|
|
|
1,027 |
|
Power purchase
contract liability
|
|
|
750 |
|
|
|
766 |
|
Retirement
benefits
|
|
|
1,473 |
|
|
|
1,884 |
|
Lease market
valuation liability
|
|
|
285 |
|
|
|
308 |
|
Other
|
|
|
1,334 |
|
|
|
1,525 |
|
|
|
|
8,678 |
|
|
|
9,008 |
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
34,306 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
523 |
|
|
$ |
540 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
|
362 |
|
|
|
332 |
|
Amortization
of regulatory assets
|
|
|
642 |
|
|
|
504 |
|
Deferral of
regulatory assets
|
|
|
(136 |
) |
|
|
(203 |
) |
Nuclear fuel
and lease amortization
|
|
|
52 |
|
|
|
51 |
|
Deferred
purchased power and other costs
|
|
|
(135 |
) |
|
|
(95 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
69 |
|
|
|
129 |
|
Investment
impairment
|
|
|
39 |
|
|
|
38 |
|
Deferred rents
and lease market valuation liability
|
|
|
(59 |
) |
|
|
(101 |
) |
Accrued
compensation and retirement benefits
|
|
|
(93 |
) |
|
|
(140 |
) |
Stock-based
compensation
|
|
|
(2 |
) |
|
|
(72 |
) |
Gain on asset
sales
|
|
|
(12 |
) |
|
|
(41 |
) |
Electric
service prepayment programs
|
|
|
(10 |
) |
|
|
(39 |
) |
Cash
collateral, net
|
|
|
48 |
|
|
|
67 |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
32 |
|
|
|
(136 |
) |
Materials and
supplies
|
|
|
6 |
|
|
|
(31 |
) |
Prepaid
taxes
|
|
|
(204 |
) |
|
|
(393 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(11 |
) |
|
|
152 |
|
Accrued
taxes
|
|
|
(101 |
) |
|
|
(190 |
) |
Other
|
|
|
92 |
|
|
|
(53 |
) |
Net cash
provided from operating activities
|
|
|
1,102 |
|
|
|
319 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,679 |
|
|
|
549 |
|
Short-term
borrowings, net
|
|
|
- |
|
|
|
1,705 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(881 |
) |
|
|
(719 |
) |
Net controlled
disbursement activity
|
|
|
(15 |
) |
|
|
8 |
|
Common stock
dividend payments
|
|
|
(335 |
) |
|
|
(335 |
) |
Other
|
|
|
(22 |
) |
|
|
19 |
|
Net cash
provided from financing activities
|
|
|
426 |
|
|
|
1,227 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(1,143 |
) |
|
|
(1,617 |
) |
Proceeds from
asset sales
|
|
|
19 |
|
|
|
56 |
|
Sales of
investment securities held in trusts
|
|
|
1,001 |
|
|
|
726 |
|
Purchases of
investment securities held in trusts
|
|
|
(1,041 |
) |
|
|
(775 |
) |
Cash
investments
|
|
|
40 |
|
|
|
65 |
|
Other
|
|
|
(49 |
) |
|
|
(60 |
) |
Net cash used
for investing activities
|
|
|
(1,173 |
) |
|
|
(1,605 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
355 |
|
|
|
(59 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
545 |
|
|
|
129 |
|
Cash and cash
equivalents at end of period
|
|
$ |
900 |
|
|
$ |
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 supplied, 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.
The demand for
electricity produced and sold by FES, along with the value of that electricity,
is materially impacted by conditions in competitive power markets, global
economic activity, economic activity in the Midwest and Mid-Atlantic regions,
and weather conditions in FirstEnergy’s service territories. The current
recessionary economic conditions, particularly in the automotive and steel
industries, compounded by unusually mild regional summertime temperatures, have
directly impacted FES’ operations and revenues.
The level of demand
for electricity directly impacts FES’ generation revenues, the quantity of
electricity produced, purchased power expense and fuel expense. FirstEnergy and
FES have taken various actions and instituted a number of changes in operating
practices to mitigate these external influences. These actions include employee
severances, wage reductions, employee and retiree benefit changes, reduced
levels of overtime and the use of fewer contractors. However, the continuation
of recessionary economic conditions, coupled with unusually mild weather
patterns and the resulting impact on electricity prices and demand could impact
FES’ future operating performance and financial condition and may require
further changes in FES’ operations.
Results of
Operations
In the first six
months of 2009, net income increased to $468 million from $158 million in the same
period in 2008. The increase in net income includes FGCO’s $252 million pre-tax
gain from the sale of 9% of its participation in OVEC ($158 million
after-tax) and an increase in gross sales margins.
Revenues
Revenues increased
by $397 million in the
first six months of 2009 compared to the same period in 2008 due to the OVEC
sale and increases in revenues from non-affiliated and affiliated wholesale
sales, partially offset by lower retail generation sales. The increase in
revenues resulted from the following sources:
|
|
Six Months
Ended
|
|
|
|
|
|
June
30
|
|
Increase
|
|
Revenues
by Type of Service
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Non-Affiliated
Generation Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Non-Affiliated Generation Sales
|
|
|
|
|
|
|
|
|
|
)
|
Affiliated
Generation Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of OVEC
participation interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The lower retail
generation revenues resulted from the expiration of certain government
aggregation programs in the MISO market at the end of 2008 that were supplied by
FES, partially offset by increased retail revenues in both the PJM and MISO
markets. The increase in non-aggregation retail revenues in MISO was primarily
the result of the acquisition of new customers and higher unit prices. The
increase in PJM retail sales resulted from higher unit prices. Higher
non-affiliated wholesale revenues resulted from increased sales volumes and
prices in MISO partially offset by decreased sales volumes and prices in
PJM.
The increase in
affiliated company wholesale revenues was due to higher unit prices to the Ohio
Companies and increased sales volumes to Met-Ed and Penelec, partially offset by
lower sales volumes to the Ohio Companies. The higher unit prices reflected the
results of the Ohio Companies’ power procurement processes in the first half of
2009 (see Regulatory Matters – Ohio). In the first quarter of 2009, FES supplied
approximately 75% of the Ohio Companies’ power requirements as one of four
winning bidders in the Ohio Companies' RFP process. In the second quarter of
2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in
April and May 2009, and approximately 56% of the Ohio Companies' supply needs in
June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional
tranches from other winning bidders and effective August 1, 2009, FES will
supply 62% of the Ohio Companies’ PLR generation requirements.
Increased sales
volumes to the Pennsylvania Companies reflect higher sales to Met-Ed and
Penelec, following the expiration of a third-party supply contract for the
utilities at the end of 2008, partially offset by lower sales to Penn due to
decreased default service requirements in the first six months of 2009 compared
to the first six months of 2008. 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.
The following tables
summarize the price and volume factors contributing to changes in revenues from
non-affiliated and affiliated generation sales in the first six months of 2009
compared to the same period last year:
|
|
Increase
|
|
Source
of Change in Non-Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Retail:
|
|
|
|
|
Effect of 57.8% decrease in sales
volumes
|
|
$
|
(182
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
)
|
Wholesale:
|
|
|
|
|
Effect of 4.1% decrease in sales
volumes
|
|
|
(12
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Net Decrease
in Non-Affiliated Generation Revenues
|
|
|
|
)
|
|
|
Increase
|
|
Source
of Change in Affiliated Generation Revenues
|
|
|
|
|
|
(In
millions)
|
|
Ohio
Companies:
|
|
|
|
|
Effect of 19.2% decrease in sales
volumes
|
|
$
|
(218
|
)
|
Change in prices
|
|
|
|
|
|
|
|
|
|
Pennsylvania
Companies:
|
|
|
|
|
Effect of 10.6% increase in sales
volumes
|
|
|
37
|
|
Change in prices
|
|
|
|
)
|
|
|
|
|
|
Net Increase
in Affiliated Generation Revenues
|
|
|
|
|
Transmission revenue
decreased $25 million primarily due to reduced retail loads in MISO. Other
revenue increased by $46 million principally from rental income associated with
NGC's acquisition of additional equity interests in Perry and Beaver Valley Unit
2.
Expenses
Total expenses
decreased by $58 million in the first six 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 six 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
|
|
$
|
65
|
|
Change due to volume
consumed
|
|
|
(118
|
)
|
|
|
|
(53
|
)
|
Nuclear
Fuel:
|
|
|
|
|
Change due to increased unit
costs
|
|
|
5
|
|
Change due to volume
consumed
|
|
|
(7
|
)
|
|
|
|
(2
|
)
|
Non-affiliated
Purchased Power:
|
|
|
|
|
Change due to increased unit
costs
|
|
|
22
|
|
Change due to volume
purchased
|
|
|
(103
|
)
|
|
|
|
(81
|
)
|
Affiliated
Purchased Power:
|
|
|
|
|
Change due to increased unit
costs
|
|
|
51
|
|
Change due to volume
purchased
|
|
|
3
|
|
|
|
|
54
|
|
Net Decrease
in Fuel and Purchased Power Costs
|
|
|
|
)
|
Fossil fuel costs
decreased $53 million in the first six months of 2009 as a result of decreased
coal consumption, reflecting lower generation. Higher unit prices, which are
expected to continue during the remainder of 2009, were due to increased fuel
costs associated with purchases of eastern coal. Nuclear fuel costs were
relatively unchanged in the first six months of 2009 from last
year.
Purchased power
costs from non-affiliates decreased primarily as a result of reduced volume
requirements, partially offset by higher capacity costs. Purchases from
affiliated companies increased as a result of higher unit costs on purchases
from the OE’s and TE’s leasehold interests in Beaver Valley Unit 2 and
Perry.
Other operating
expenses increased by $1 million in the first six
months of 2009 from the same period of 2008. Higher expenses in the 2009 period
for organizational restructuring costs ($4 million), increased nuclear operating
costs for an additional refueling outage ($9 million) and higher transmission
expenses due to increased charges in the PJM market ($24 million) were offset by
lower fossil operating costs ($32 million) and lease expenses ($5 million).
Decreased fossil operating costs were primarily due to reduced maintenance
activities and more labor dedicated to capital projects compared to the 2008
period. Lower lease expenses were principally due to the transfer of CEI’s and
TE’s leasehold improvements for the Mansfield Plant to FGCO during the first
quarter of 2008.
Depreciation expense
increased by $21 million in the first six months of 2009 primarily due to
NGC’s increased ownership interest in Beaver Valley Unit 2 and
Perry.
Other Expense
Other expense
decreased by $11 million in the first six
months of 2009 from the same period of 2008 primarily due to a $12 million
decrease in interest expense to affiliates due to lower rates on loans from the
unregulated money pool and a $7 million increase in capitalized interest.
Partially offsetting the lower interest expense was an $8 million increase in
impairments (net of realized investment income) on the nuclear decommissioning
trust investments during the 2009 period.
The decrease in FES’
effective income tax rate for the first six months of 2009 is primarily due to
the phase out of the Ohio income-based franchise tax at the end of 2008 and an
increase in the manufacturing deduction in the 2009 period.
Working
Capital
As of June 30,
2009, FES’ net deficit in working capital (current assets less current
liabilities) was principally due to short-term borrowings and the classification
of certain variable interest rate PCRBs as currently payable long-term debt. As
of June 30, 2009, FES had access to $1.3 billion of short-term financing
under revolving credit facilities. FES also has the ability to borrow from
FirstEnergy under the unregulated money pool to meet its short-term working
capital requirements.
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 June 30, 2009 and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2009 and 2008 and the consolidated statement of cash
flows for the six-month periods ended June 30, 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
August 3,
2009
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric sales
to affiliates
|
|
$ |
839,751 |
|
|
$ |
704,283 |
|
|
$ |
1,732,441 |
|
|
$ |
1,480,590 |
|
Electric sales
to non-affiliates
|
|
|
205,379 |
|
|
|
324,276 |
|
|
|
485,125 |
|
|
|
612,617 |
|
Other
|
|
|
296,022 |
|
|
|
42,719 |
|
|
|
349,692 |
|
|
|
77,187 |
|
Total
revenues
|
|
|
1,341,152 |
|
|
|
1,071,278 |
|
|
|
2,567,258 |
|
|
|
2,170,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
270,309 |
|
|
|
310,550 |
|
|
|
576,467 |
|
|
|
632,239 |
|
Purchased
power from non-affiliates
|
|
|
185,613 |
|
|
|
220,339 |
|
|
|
345,955 |
|
|
|
427,063 |
|
Purchased
power from affiliates
|
|
|
51,249 |
|
|
|
34,528 |
|
|
|
114,456 |
|
|
|
60,013 |
|
Other
operating expenses
|
|
|
278,264 |
|
|
|
287,738 |
|
|
|
585,620 |
|
|
|
584,284 |
|
Provision for
depreciation
|
|
|
65,548 |
|
|
|
56,160 |
|
|
|
126,921 |
|
|
|
105,902 |
|
General
taxes
|
|
|
21,285 |
|
|
|
19,795 |
|
|
|
44,661 |
|
|
|
42,992 |
|
Total
expenses
|
|
|
872,268 |
|
|
|
929,110 |
|
|
|
1,794,080 |
|
|
|
1,852,493 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
468,884 |
|
|
|
142,168 |
|
|
|
773,178 |
|
|
|
317,901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense)
|
|
|
13,265 |
|
|
|
(2,074 |
) |
|
|
(13,098 |
) |
|
|
(4,978 |
) |
Interest
expense to affiliates
|
|
|
(3,315 |
) |
|
|
(10,728 |
) |
|
|
(6,294 |
) |
|
|
(17,938 |
) |
Interest
expense - other
|
|
|
(26,271 |
) |
|
|
(24,505 |
) |
|
|
(48,798 |
) |
|
|
(49,040 |
) |
Capitalized
interest
|
|
|
14,028 |
|
|
|
10,541 |
|
|
|
24,106 |
|
|
|
17,204 |
|
Total other
expense
|
|
|
(2,293 |
) |
|
|
(26,766 |
) |
|
|
(44,084 |
) |
|
|
(54,752 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
466,591 |
|
|
|
115,402 |
|
|
|
729,094 |
|
|
|
263,149 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
169,189 |
|
|
|
47,308 |
|
|
|
261,011 |
|
|
|
105,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
297,402 |
|
|
|
68,094 |
|
|
|
468,083 |
|
|
|
158,078 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
72,121 |
|
|
|
(1,821 |
) |
|
|
74,689 |
|
|
|
(3,641 |
) |
Unrealized
gain (loss) on derivative hedges
|
|
|
15,041 |
|
|
|
(17,920 |
) |
|
|
26,057 |
|
|
|
(12,202 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
|
39,504 |
|
|
|
(17,709 |
) |
|
|
38,027 |
|
|
|
(69,561 |
) |
Other
comprehensive income (loss)
|
|
|
126,666 |
|
|
|
(37,450 |
) |
|
|
138,773 |
|
|
|
(85,404 |
) |
Income tax
expense (benefit) related to other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
income
|
|
|
50,625 |
|
|
|
(13,313 |
) |
|
|
55,334 |
|
|
|
(30,716 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
76,041 |
|
|
|
(24,137 |
) |
|
|
83,439 |
|
|
|
(54,688 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
373,443 |
|
|
$ |
43,957 |
|
|
$ |
551,522 |
|
|
$ |
103,390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they related to
FirstEnergy Solutions Corp. are an integral part of
|
|
these balance
sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
120,034 |
|
|
$ |
39 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,904,000 and $5,899,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
75,753 |
|
|
|
86,123 |
|
Associated
companies
|
|
|
215,362 |
|
|
|
378,100 |
|
Other (less
accumulated provisions of $6,702,000 and $6,815,000
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
19,309 |
|
|
|
24,626 |
|
Notes
receivable from associated companies
|
|
|
370,345 |
|
|
|
129,175 |
|
Materials and
supplies, at average cost
|
|
|
550,212 |
|
|
|
521,761 |
|
Prepayments
and other
|
|
|
98,381 |
|
|
|
112,535 |
|
|
|
|
1,449,396 |
|
|
|
1,252,359 |
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
10,226,785 |
|
|
|
9,871,904 |
|
Less -
Accumulated provision for depreciation
|
|
|
4,400,182 |
|
|
|
4,254,721 |
|
|
|
|
5,826,603 |
|
|
|
5,617,183 |
|
Construction
work in progress
|
|
|
2,019,748 |
|
|
|
1,747,435 |
|
|
|
|
7,846,351 |
|
|
|
7,364,618 |
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
1,040,410 |
|
|
|
1,033,717 |
|
Long-term
notes receivable from associated companies
|
|
|
- |
|
|
|
62,900 |
|
Other
|
|
|
29,212 |
|
|
|
61,591 |
|
|
|
|
1,069,622 |
|
|
|
1,158,208 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income tax benefits
|
|
|
151,457 |
|
|
|
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
|
|
|
74,281 |
|
|
|
69,932 |
|
Other
|
|
|
62,305 |
|
|
|
96,434 |
|
|
|
|
433,751 |
|
|
|
579,836 |
|
|
|
$ |
10,799,120 |
|
|
$ |
10,355,021 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
1,632,264 |
|
|
$ |
2,024,898 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
309,832 |
|
|
|
264,823 |
|
Other
|
|
|
1,100,000 |
|
|
|
1,000,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
367,395 |
|
|
|
472,338 |
|
Other
|
|
|
168,485 |
|
|
|
154,593 |
|
Accrued
taxes
|
|
|
68,759 |
|
|
|
79,766 |
|
Other
|
|
|
180,990 |
|
|
|
248,439 |
|
|
|
|
3,827,725 |
|
|
|
4,244,857 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity -
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 750 shares,
|
|
|
|
|
|
|
|
|
7 shares
outstanding
|
|
|
1,463,074 |
|
|
|
1,464,229 |
|
Accumulated
other comprehensive loss
|
|
|
(8,432 |
) |
|
|
(91,871 |
) |
Retained
earnings
|
|
|
2,040,148 |
|
|
|
1,572,065 |
|
Total common
stockholder's equity
|
|
|
3,494,790 |
|
|
|
2,944,423 |
|
Long-term debt
and other long-term obligations
|
|
|
965,677 |
|
|
|
571,448 |
|
|
|
|
4,460,467 |
|
|
|
3,515,871 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Deferred gain
on sale and leaseback transaction
|
|
|
1,009,727 |
|
|
|
1,026,584 |
|
Accumulated
deferred investment tax credits
|
|
|
60,562 |
|
|
|
62,728 |
|
Asset
retirement obligations
|
|
|
891,505 |
|
|
|
863,085 |
|
Retirement
benefits
|
|
|
131,882 |
|
|
|
194,177 |
|
Property
taxes
|
|
|
50,104 |
|
|
|
50,104 |
|
Lease market
valuation liability
|
|
|
284,952 |
|
|
|
307,705 |
|
Other
|
|
|
82,196 |
|
|
|
89,910 |
|
|
|
|
2,510,928 |
|
|
|
2,594,293 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
10,799,120 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
468,083 |
|
|
$ |
158,078 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
126,921 |
|
|
|
105,902 |
|
Nuclear fuel
and lease amortization
|
|
|
53,265 |
|
|
|
51,207 |
|
Deferred rents
and lease market valuation liability
|
|
|
(55,493 |
) |
|
|
(52,537 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
63,309 |
|
|
|
51,961 |
|
Investment
impairment
|
|
|
36,154 |
|
|
|
33,533 |
|
Accrued
compensation and retirement benefits
|
|
|
(10,594 |
) |
|
|
(8,399 |
) |
Commodity
derivative transactions, net
|
|
|
17,688 |
|
|
|
3,705 |
|
Gain on asset
sales
|
|
|
(9,635 |
) |
|
|
(8,836 |
) |
Cash
collateral, net
|
|
|
40,471 |
|
|
|
(5,355 |
) |
Decrease
(increase) in operating assets:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
179,373 |
|
|
|
(86,773 |
) |
Materials and
supplies
|
|
|
16,609 |
|
|
|
(27,867 |
) |
Prepayments
and other current assets
|
|
|
7,555 |
|
|
|
(14,512 |
) |
Increase
(decrease) in operating liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(102,907 |
) |
|
|
(37,794 |
) |
Accrued
taxes
|
|
|
(14,333 |
) |
|
|
(98,948 |
) |
Accrued
interest
|
|
|
1,871 |
|
|
|
(1,603 |
) |
Other
|
|
|
(6,121 |
) |
|
|
(16,743 |
) |
Net cash
provided from operating activities
|
|
|
812,216 |
|
|
|
45,019 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
681,675 |
|
|
|
455,735 |
|
Short-term
borrowings, net
|
|
|
145,009 |
|
|
|
1,652,643 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(622,853 |
) |
|
|
(458,377 |
) |
Common stock
dividend payments
|
|
|
- |
|
|
|
(10,000 |
) |
Net cash
provided from financing activities
|
|
|
203,831 |
|
|
|
1,640,001 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(634,967 |
) |
|
|
(1,152,502 |
) |
Proceeds from
asset sales
|
|
|
15,771 |
|
|
|
10,875 |
|
Sales of
investment securities held in trusts
|
|
|
537,078 |
|
|
|
384,692 |
|
Purchases of
investment securities held in trusts
|
|
|
(550,730 |
) |
|
|
(404,502 |
) |
Loans to
associated companies, net
|
|
|
(241,170 |
) |
|
|
(461,496 |
) |
Other
|
|
|
(22,034 |
) |
|
|
(62,087 |
) |
Net cash used
for investing activities
|
|
|
(896,052 |
) |
|
|
(1,685,020 |
) |
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
119,995 |
|
|
|
- |
|
Cash and cash
equivalents at beginning of period
|
|
|
39 |
|
|
|
2 |
|
Cash and cash
equivalents at end of period
|
|
$ |
120,034 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes to Consolidated Financial Statements as they related to
FirstEnergy Solutions Corp. are an
|
|
integral
part of these balance sheets.
|
|
|
|
|
|
|
|
|
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 six
months of 2009, net income decreased to $45 million from $93 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.
Revenues
Revenues increased
by $159 million, or 12.6%, in the first six months of 2009 compared with the
same period in 2008, primarily due to increases in retail generation revenues
($213 million) and wholesale revenues ($59 million), partially offset by
decreases in distribution throughput revenues ($109 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
service territory. Average prices increased primarily due to an
increase in OE's fuel cost recovery rider that was effective from January
through May 2009. Effective June 1, 2009, the transmission tariff ended and
the recovery of transmission costs is included in the generation rate
established under OE’s CBP.
Changes in retail
generation sales and revenues in the first six months of 2009 from the same
period in 2008 are summarized in the following tables:
Retail
Generation KWH Sales |
|
Increase
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
12.9
|
%
|
Commercial
|
|
|
19.1
|
%
|
Industrial
|
|
|
(10.8
|
)%
|
Net
Increase in Generation Sales
|
|
|
6.9
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
98
|
|
Commercial
|
|
|
83
|
|
Industrial
|
|
|
32
|
|
Increase
in Generation Revenues
|
|
$
|
213
|
|
Revenues from
distribution throughput decreased by $109 million in the first six 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 reflect 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 six months of 2009 from
the same period in 2008 are summarized in the following tables.
Distribution
KWH Deliveries
|
|
Decrease
|
|
|
|
|
|
|
Residential
|
|
|
(0.9
|
)%
|
Commercial
|
|
|
(3.6
|
)%
|
Industrial
|
|
|
(25.8
|
)%
|
Decrease
in Distribution Deliveries
|
|
|
(10.4
|
)%
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(14
|
)
|
Commercial
|
|
|
(44
|
)
|
Industrial
|
|
|
(51
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(109
|
)
|
Expenses
Total expenses
increased by $223 million in the first six 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
|
|
$
|
235
|
|
Other
operating costs
|
|
|
(8
|
)
|
Provision for
depreciation
|
|
|
1
|
|
Amortization
of regulatory assets, net
|
|
|
(3
|
)
|
General
taxes
|
|
|
(2
|
)
|
Net
Increase in Expenses
|
|
$
|
223
|
|
Higher purchased
power costs reflect the results of OE’s power procurement process for retail
customers in the first six months of 2009 (see Regulatory Matters – Ohio) and
higher volumes due to increased retail generation KWH sales. The decrease in
other operating costs for the first six months of 2009 was primarily due to
lower MISO transmission expenses (included in the cost of power purchased
from others beginning June 1, 2009), partially offset by accruals for
economic development programs and energy efficiency obligations. Lower
amortization of net regulatory assets was primarily due to the conclusion of
transition cost recovery in 2008, partially offset by lower MISO transmission
cost deferrals and lower RCP distribution deferrals. The decrease in general
taxes for the first six months of 2009 was primarily due to lower Ohio KWH
taxes.
Other Expenses
Other expenses
increased by $11 million in the first six months of 2009 compared to the same
period in 2008 primarily due to higher interest expense associated with the
issuance of $300 million of FMBs by OE 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 June 30, 2009 and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2009 and 2008 and the consolidated statement of cash
flows for the six-month periods ended June 30, 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
August 3,
2009
|
OHIO
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
647,224 |
|
|
$ |
583,268 |
|
|
$ |
1,367,235 |
|
|
$ |
1,205,539 |
|
Excise and
gross receipts tax collections
|
|
|
24,948 |
|
|
|
26,287 |
|
|
|
53,928 |
|
|
|
56,665 |
|
Total
revenues
|
|
|
672,172 |
|
|
|
609,555 |
|
|
|
1,421,163 |
|
|
|
1,262,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
314,870 |
|
|
|
280,024 |
|
|
|
647,206 |
|
|
|
599,735 |
|
Purchased
power from non-affiliates
|
|
|
98,330 |
|
|
|
28,025 |
|
|
|
236,143 |
|
|
|
48,500 |
|
Other
operating costs
|
|
|
111,938 |
|
|
|
137,619 |
|
|
|
269,768 |
|
|
|
277,945 |
|
Provision for
depreciation
|
|
|
21,996 |
|
|
|
21,414 |
|
|
|
43,509 |
|
|
|
42,907 |
|
Amortization
of regulatory assets, net
|
|
|
22,295 |
|
|
|
21,955 |
|
|
|
42,506 |
|
|
|
45,082 |
|
General
taxes
|
|
|
43,903 |
|
|
|
44,389 |
|
|
|
93,023 |
|
|
|
94,842 |
|
Total
expenses
|
|
|
613,332 |
|
|
|
533,426 |
|
|
|
1,332,155 |
|
|
|
1,109,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
58,840 |
|
|
|
76,129 |
|
|
|
89,008 |
|
|
|
153,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
10,149 |
|
|
|
11,488 |
|
|
|
19,511 |
|
|
|
26,543 |
|
Miscellaneous
income (expense)
|
|
|
2,681 |
|
|
|
(126 |
) |
|
|
1,871 |
|
|
|
(3,778 |
) |
Interest
expense
|
|
|
(21,469 |
) |
|
|
(16,901 |
) |
|
|
(44,756 |
) |
|
|
(34,542 |
) |
Capitalized
interest
|
|
|
279 |
|
|
|
159 |
|
|
|
499 |
|
|
|
269 |
|
Total other
expense
|
|
|
(8,360 |
) |
|
|
(5,380 |
) |
|
|
(22,875 |
) |
|
|
(11,508 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
50,480 |
|
|
|
70,749 |
|
|
|
66,133 |
|
|
|
141,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
16,852 |
|
|
|
21,748 |
|
|
|
20,857 |
|
|
|
48,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
33,628 |
|
|
|
49,001 |
|
|
|
45,276 |
|
|
|
93,064 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income
|
|
|
143 |
|
|
|
159 |
|
|
|
289 |
|
|
|
313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
AVAILABLE TO PARENT
|
|
$ |
33,485 |
|
|
$ |
48,842 |
|
|
$ |
44,987 |
|
|
$ |
92,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
33,628 |
|
|
$ |
49,001 |
|
|
$ |
45,276 |
|
|
$ |
93,064 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
89,864 |
|
|
|
(3,994 |
) |
|
|
95,602 |
|
|
|
(7,988 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
|
728 |
|
|
|
(2,803 |
) |
|
|
(1,981 |
) |
|
|
(10,374 |
) |
Other
comprehensive income (loss)
|
|
|
90,592 |
|
|
|
(6,797 |
) |
|
|
93,621 |
|
|
|
(18,362 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
37,310 |
|
|
|
(2,564 |
) |
|
|
37,839 |
|
|
|
(6,826 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
53,282 |
|
|
|
(4,233 |
) |
|
|
55,782 |
|
|
|
(11,536 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
86,910 |
|
|
|
44,768 |
|
|
|
101,058 |
|
|
|
81,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TO
NONCONTROLLING INTEREST
|
|
|
143 |
|
|
|
159 |
|
|
|
289 |
|
|
|
313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME AVAILABLE TO PARENT
|
|
$ |
86,767 |
|
|
$ |
44,609 |
|
|
$ |
100,769 |
|
|
$ |
81,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
223,812 |
|
|
$ |
146,343 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $6,186,000 and $6,065,000,
respectively,
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
289,084 |
|
|
|
277,377 |
|
Associated
companies
|
|
|
244,266 |
|
|
|
234,960 |
|
Other (less
accumulated provisions of $99,000 and $7,000,
respectively,
|
|
|
|
|
|
|
|
|
for
uncollectible accounts)
|
|
|
12,970 |
|
|
|
14,492 |
|
Notes
receivable from associated companies
|
|
|
172,061 |
|
|
|
222,861 |
|
Prepayments
and other
|
|
|
19,027 |
|
|
|
5,452 |
|
|
|
|
961,220 |
|
|
|
901,485 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,956,467 |
|
|
|
2,903,290 |
|
Less -
Accumulated provision for depreciation
|
|
|
1,135,811 |
|
|
|
1,113,357 |
|
|
|
|
1,820,656 |
|
|
|
1,789,933 |
|
Construction
work in progress
|
|
|
37,385 |
|
|
|
37,766 |
|
|
|
|
1,858,041 |
|
|
|
1,827,699 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Long-term
notes receivable from associated companies
|
|
|
193,071 |
|
|
|
256,974 |
|
Investment in
lease obligation bonds
|
|
|
230,150 |
|
|
|
239,625 |
|
Nuclear plant
decommissioning trusts
|
|
|
117,523 |
|
|
|
116,682 |
|
Other
|
|
|
97,807 |
|
|
|
100,792 |
|
|
|
|
638,551 |
|
|
|
714,073 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
514,415 |
|
|
|
575,076 |
|
Property
taxes
|
|
|
60,542 |
|
|
|
60,542 |
|
Unamortized
sale and leaseback costs
|
|
|
37,629 |
|
|
|
40,130 |
|
Other
|
|
|
33,290 |
|
|
|
33,710 |
|
|
|
|
645,876 |
|
|
|
709,458 |
|
|
|
$ |
4,103,688 |
|
|
$ |
4,152,715 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
2,715 |
|
|
$ |
101,354 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
114,771 |
|
|
|
- |
|
Other
|
|
|
1,386 |
|
|
|
1,540 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
78,944 |
|
|
|
131,725 |
|
Other
|
|
|
74,371 |
|
|
|
26,410 |
|
Accrued
taxes
|
|
|
77,974 |
|
|
|
77,592 |
|
Accrued
interest
|
|
|
25,709 |
|
|
|
25,673 |
|
Other
|
|
|
95,689 |
|
|
|
85,209 |
|
|
|
|
471,559 |
|
|
|
449,503 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 175,000,000 shares -
|
|
|
|
|
|
|
|
|
60 shares
outstanding
|
|
|
1,224,398 |
|
|
|
1,224,416 |
|
Accumulated
other comprehensive loss
|
|
|
(128,603 |
) |
|
|
(184,385 |
) |
Retained
earnings
|
|
|
174,010 |
|
|
|
254,023 |
|
Total common
stockholder's equity
|
|
|
1,269,805 |
|
|
|
1,294,054 |
|
Noncontrolling
interest
|
|
|
6,835 |
|
|
|
7,106 |
|
Total
equity
|
|
|
1,276,640 |
|
|
|
1,301,160 |
|
Long-term debt
and other long-term obligations
|
|
|
1,160,609 |
|
|
|
1,122,247 |
|
|
|
|
2,437,249 |
|
|
|
2,423,407 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
681,972 |
|
|
|
653,475 |
|
Accumulated
deferred investment tax credits
|
|
|
12,335 |
|
|
|
13,065 |
|
Asset
retirement obligations
|
|
|
83,261 |
|
|
|
80,647 |
|
Retirement
benefits
|
|
|
216,661 |
|
|
|
308,450 |
|
Other
|
|
|
200,651 |
|
|
|
224,168 |
|
|
|
|
1,194,880 |
|
|
|
1,279,805 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
4,103,688 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
45,276 |
|
|
$ |
93,064 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
|
43,509 |
|
|
|
42,907 |
|
Amortization
of regulatory assets, net
|
|
|
42,506 |
|
|
|
45,082 |
|
Purchased
power cost recovery reconciliation
|
|
|
11,068 |
|
|
|
- |
|
Amortization
of lease costs
|
|
|
(4,540 |
) |
|
|
(4,399 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(11,252 |
) |
|
|
7,059 |
|
Accrued
compensation and retirement benefits
|
|
|
(4,593 |
) |
|
|
(31,579 |
) |
Accrued
regulatory obligations
|
|
|
18,350 |
|
|
|
- |
|
Electric
service prepayment programs
|
|
|
(4,603 |
) |
|
|
(21,771 |
) |
Cash
collateral from suppliers
|
|
|
6,380 |
|
|
|
- |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(16,509 |
) |
|
|
30,159 |
|
Prepayments
and other current assets
|
|
|
(6,290 |
) |
|
|
(2,485 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(4,820 |
) |
|
|
(6,831 |
) |
Accrued
taxes
|
|
|
(19,523 |
) |
|
|
(31,306 |
) |
Accrued
interest
|
|
|
36 |
|
|
|
(1,252 |
) |
Other
|
|
|
10,086 |
|
|
|
2,798 |
|
Net cash
provided from operating activities
|
|
|
105,081 |
|
|
|
121,446 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
100,000 |
|
|
|
- |
|
Short-term
borrowings, net
|
|
|
114,617 |
|
|
|
69,573 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(100,984 |
) |
|
|
(175,572 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(125,000 |
) |
|
|
(50,000 |
) |
Other
|
|
|
(1,627 |
) |
|
|
(445 |
) |
Net cash used
for financing activities
|
|
|
(12,994 |
) |
|
|
(156,444 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(69,512 |
) |
|
|
(92,061 |
) |
Sales of
investment securities held in trusts
|
|
|
24,941 |
|
|
|
79,613 |
|
Purchases of
investment securities held in trusts
|
|
|
(30,877 |
) |
|
|
(84,130 |
) |
Loan
repayments from associated companies, net
|
|
|
51,803 |
|
|
|
123,905 |
|
Cash
investments
|
|
|
7,929 |
|
|
|
5,000 |
|
Other
|
|
|
1,098 |
|
|
|
2,828 |
|
Net cash
provided from (used for) investing activities
|
|
|
(14,618 |
) |
|
|
35,155 |
|
|
|
|
|
|
|
|
|
|
Net increase
in cash and cash equivalents
|
|
|
77,469 |
|
|
|
157 |
|
Cash and cash
equivalents at beginning of period
|
|
|
146,343 |
|
|
|
732 |
|
Cash and cash
equivalents at end of period
|
|
$ |
223,812 |
|
|
$ |
889 |
|
|
|
|
|
|
|
|
|
|
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 experienced a
net loss of $58 million in the first six months of 2009 compared to net income
of $125 million in the same period of 2008. The loss in 2009 resulted primarily
from regulatory charges ($228 million) related to the implementation of
CEI's ESP. The 2009 results were also adversely impacted by increased purchased
power costs, partially offset by higher deferrals of new regulatory assets,
increased revenues and lower other operating costs.
Revenues
Revenues increased
by $53 million, or 6.1%, in the first six months of 2009 compared to the
same period of 2008 primarily due to an increase in retail generation revenues
($81 million), partially offset by a decrease in distribution revenues
($19 million) and
other miscellaneous revenues ($9 million).
Retail generation
revenues increased in the first six months of 2009 due to higher average unit
prices in all customer classes and increased sales volume to residential and
commercial customers, compared to the same period of 2008. Average prices
increased due to an increase in CEI’s fuel cost recovery rider that was
effective from January through May 2009, and effective June 1, 2009, the
transmission tariff ended, with transmission services now included in the
generation rate established under CEI's CBP. Reduced industrial KWH sales,
principally to major automotive and steel customers, reflected weakened economic
conditions. The increase in sales volumes for residential and commercial
customers resulted from a decrease in customer shopping, as most of CEI’s
customers returned to PLR service in December 2008 following the termination of
certain government aggregation programs in CEI’s service territory.
Changes in retail
generation sales and revenues in the first six months of 2009 compared to the
same period in 2008 are summarized in the following tables:
|
|
Increase
|
|
Retail
Generation KWH Sales
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
8.3
%
|
|
Commercial
|
|
|
14.6
%
|
|
Industrial
|
|
|
(8.6)%
|
|
Increase
in Retail Generation Sales
|
|
|
2.0
%
|
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(in
millions)
|
|
Residential
|
|
$
|
27
|
|
Commercial
|
|
|
34
|
|
Industrial
|
|
|
20
|
|
Increase
in Generation Revenues
|
|
$
|
81
|
|
Revenues from
distribution throughput decreased by $19 million in the first six months of
2009 compared to the same period of 2008 due to a decrease in KWH deliveries,
partially offset by higher average unit prices in the commercial and industrial
sectors. The higher average unit prices was the net result of a PUCO-approved
distribution rate increase effective May 1, 2009, partially
offset by reduced transition rates (see Regulatory Matters – Ohio). The lower
KWH deliveries in the first six months of 2009 were due to economic conditions.
Cooling degree days in the first six months of 2009 were 17% lower than in the
previous year, while heating degree days increased slightly.
Changes in
distribution KWH deliveries and revenues in the first six months of 2009
compared to the same period of 2008 are summarized in the following
tables.
Distribution
KWH Deliveries
|
|
Decrease
|
|
|
|
|
|
|
Residential
|
|
|
(0.5)
%
|
|
Commercial
|
|
|
(3.6)
%
|
|
Industrial
|
|
|
(19.1)
%
|
|
Decrease
in Distribution Deliveries
|
|
|
(9.8)
%
|
|
|
|
|
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(10
|
)
|
Commercial
|
|
|
(3
|
)
|
Industrial
|
|
|
(6
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(19
|
)
|
Expenses
Total expenses
increased by $333 million in the first six 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
|
|
$
|
225
|
|
Other
operating costs
|
|
|
(24
|
)
|
Amortization
of regulatory assets
|
|
|
209
|
|
Deferral of
new regulatory assets
|
|
|
(79
|
)
|
General
Taxes
|
|
|
2
|
|
Net
Increase in Expenses
|
|
$
|
333
|
|
Higher purchased
power costs reflect the results of CEI’s power procurement process for retail
customers in the first six months of 2009 (see Regulatory Matters – Ohio).
Increased amortization of regulatory assets was primarily due to the impairment
of CEI’s Extended RTC balance ($216 million) in accordance with the
PUCO-approved ESP. The increase in the deferral of new regulatory assets was 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. Other operating costs
were $24 million lower than in the previous year due to lower transmission
expenses (included in the cost of power purchased from others beginning
June 1, 2009) and reduced labor and contractor costs, partially offset by
costs associated with the ESP for economic development and energy efficiency
programs, higher pension expense and restructuring costs. The increase in
general taxes was primarily due to higher 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 June 30, 2009 and the related
consolidated statements of income and comprehensive income for each of the
three-month and six-month periods ended June 30, 2009 and 2008 and the
consolidated statement of cash flows for the six-month periods ended
June 30, 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
August 3,
2009
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
STATEMENTS OF INCOME
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
458,287 |
|
|
$ |
418,194 |
|
|
$ |
889,692 |
|
|
$ |
836,902 |
|
Excise tax
collections
|
|
|
16,799 |
|
|
|
16,195 |
|
|
|
35,119 |
|
|
|
34,795 |
|
Total
revenues
|
|
|
475,086 |
|
|
|
434,389 |
|
|
|
924,811 |
|
|
|
871,697 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
243,499 |
|
|
|
185,483 |
|
|
|
482,371 |
|
|
|
375,679 |
|
Purchased
power from non-affiliates
|
|
|
49,414 |
|
|
|
128 |
|
|
|
121,160 |
|
|
|
3,176 |
|
Other
operating costs
|
|
|
39,177 |
|
|
|
62,659 |
|
|
|
104,007 |
|
|
|
127,777 |
|
Provision for
depreciation
|
|
|
17,852 |
|
|
|
17,744 |
|
|
|
36,132 |
|
|
|
36,820 |
|
Amortization
of regulatory assets
|
|
|
29,580 |
|
|
|
38,525 |
|
|
|
286,317 |
|
|
|
76,781 |
|
Deferral of
new regulatory assets
|
|
|
(39,771 |
) |
|
|
(26,019 |
) |
|
|
(134,587 |
) |
|
|
(55,267 |
) |
General
taxes
|
|
|
36,856 |
|
|
|
32,425 |
|
|
|
74,997 |
|
|
|
72,508 |
|
Total
expenses
|
|
|
376,607 |
|
|
|
310,945 |
|
|
|
970,397 |
|
|
|
637,474 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
98,479 |
|
|
|
123,444 |
|
|
|
(45,586 |
) |
|
|
234,223 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
7,614 |
|
|
|
8,394 |
|
|
|
16,034 |
|
|
|
17,582 |
|
Miscellaneous
income (expense)
|
|
|
798 |
|
|
|
(280 |
) |
|
|
2,792 |
|
|
|
838 |
|
Interest
expense
|
|
|
(32,757 |
) |
|
|
(30,935 |
) |
|
|
(66,079 |
) |
|
|
(63,455 |
) |
Capitalized
interest
|
|
|
51 |
|
|
|
188 |
|
|
|
118 |
|
|
|
384 |
|
Total other
expense
|
|
|
(24,294 |
) |
|
|
(22,633 |
) |
|
|
(47,135 |
) |
|
|
(44,651 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
74,185 |
|
|
|
100,811 |
|
|
|
(92,721 |
) |
|
|
189,572 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAX EXPENSE (BENEFIT)
|
|
|
26,461 |
|
|
|
33,779 |
|
|
|
(35,045 |
) |
|
|
64,105 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
|
47,724 |
|
|
|
67,032 |
|
|
|
(57,676 |
) |
|
|
125,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income
|
|
|
419 |
|
|
|
459 |
|
|
|
877 |
|
|
|
1,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
(LOSS) AVAILABLE TO PARENT
|
|
$ |
47,305 |
|
|
$ |
66,573 |
|
|
$ |
(58,553 |
) |
|
$ |
124,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
$ |
47,724 |
|
|
$ |
67,032 |
|
|
$ |
(57,676 |
) |
|
$ |
125,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
43,903 |
|
|
|
(213 |
) |
|
|
47,870 |
|
|
|
(426 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
17,936 |
|
|
|
(390 |
) |
|
|
19,306 |
|
|
|
(109 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
25,967 |
|
|
|
177 |
|
|
|
28,564 |
|
|
|
(317 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME (LOSS)
|
|
|
73,691 |
|
|
|
67,209 |
|
|
|
(29,112 |
) |
|
|
125,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TO
NONCONTROLLING INTEREST
|
|
|
419 |
|
|
|
459 |
|
|
|
877 |
|
|
|
1,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME (LOSS) AVAILABLE TO PARENT
|
|
$ |
73,272 |
|
|
$ |
66,750 |
|
|
$ |
(29,989 |
) |
|
$ |
124,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
230 |
|
|
$ |
226 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $6,252,000 and
|
|
|
|
|
|
|
|
|
$5,916,000,
respectively, for uncollectible accounts)
|
|
|
317,526 |
|
|
|
276,400 |
|
Associated
companies
|
|
|
158,425 |
|
|
|
113,182 |
|
Other
|
|
|
11,934 |
|
|
|
13,834 |
|
Notes
receivable from associated companies
|
|
|
24,510 |
|
|
|
19,060 |
|
Prepayments
and other
|
|
|
3,933 |
|
|
|
2,787 |
|
|
|
|
516,558 |
|
|
|
425,489 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,258,897 |
|
|
|
2,221,660 |
|
Less -
Accumulated provision for depreciation
|
|
|
870,038 |
|
|
|
846,233 |
|
|
|
|
1,388,859 |
|
|
|
1,375,427 |
|
Construction
work in progress
|
|
|
40,553 |
|
|
|
40,651 |
|
|
|
|
1,429,412 |
|
|
|
1,416,078 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Investment in
lessor notes
|
|
|
388,645 |
|
|
|
425,715 |
|
Other
|
|
|
10,227 |
|
|
|
10,249 |
|
|
|
|
398,872 |
|
|
|
435,964 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,688,521 |
|
|
|
1,688,521 |
|
Regulatory
assets
|
|
|
628,068 |
|
|
|
783,964 |
|
Property
taxes
|
|
|
71,500 |
|
|
|
71,500 |
|
Other
|
|
|
10,343 |
|
|
|
10,818 |
|
|
|
|
2,398,432 |
|
|
|
2,554,803 |
|
|
|
$ |
4,743,274 |
|
|
$ |
4,832,334 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
150,721 |
|
|
$ |
150,688 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
293,574 |
|
|
|
227,949 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
61,603 |
|
|
|
106,074 |
|
Other
|
|
|
45,657 |
|
|
|
7,195 |
|
Accrued
taxes
|
|
|
63,500 |
|
|
|
87,810 |
|
Accrued
interest
|
|
|
14,165 |
|
|
|
13,932 |
|
Other
|
|
|
47,890 |
|
|
|
40,095 |
|
|
|
|
677,110 |
|
|
|
633,743 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 105,000,000 shares -
|
|
|
|
|
|
|
|
|
67,930,743
shares outstanding
|
|
|
878,735 |
|
|
|
878,785 |
|
Accumulated
other comprehensive loss
|
|
|
(106,293 |
) |
|
|
(134,857 |
) |
Retained
earnings
|
|
|
801,401 |
|
|
|
859,954 |
|
Total common
stockholder's equity
|
|
|
1,573,843 |
|
|
|
1,603,882 |
|
Noncontrolling
interest
|
|
|
20,592 |
|
|
|
22,555 |
|
Total
equity
|
|
|
1,594,435 |
|
|
|
1,626,437 |
|
Long-term debt
and other long-term obligations
|
|
|
1,573,094 |
|
|
|
1,591,586 |
|
|
|
|
3,167,529 |
|
|
|
3,218,023 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
665,370 |
|
|
|
704,270 |
|
Accumulated
deferred investment tax credits
|
|
|
12,433 |
|
|
|
13,030 |
|
Retirement
benefits
|
|
|
90,331 |
|
|
|
128,738 |
|
Lease
assignment payable to associated companies
|
|
|
40,827 |
|
|
|
40,827 |
|
Other
|
|
|
89,674 |
|
|
|
93,703 |
|
|
|
|
898,635 |
|
|
|
980,568 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
4,743,274 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net income
(loss)
|
|
$ |
(57,676 |
) |
|
$ |
125,467 |
|
Adjustments to
reconcile net income (loss) to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
36,132 |
|
|
|
36,820 |
|
Amortization
of regulatory assets
|
|
|
286,317 |
|
|
|
76,781 |
|
Deferral of
new regulatory assets
|
|
|
(134,587 |
) |
|
|
(55,267 |
) |
Purchased
power cost recovery reconciliation
|
|
|
2,072 |
|
|
|
- |
|
Deferred
income taxes and investment tax credits, net
|
|
|
(58,506 |
) |
|
|
(12,125 |
) |
Accrued
compensation and retirement benefits
|
|
|
2,092 |
|
|
|
(4,027 |
) |
Accrued
regulatory obligations
|
|
|
12,057 |
|
|
|
- |
|
Electric
service prepayment programs
|
|
|
(3,510 |
) |
|
|
(11,498 |
) |
Cash
collateral from suppliers
|
|
|
5,365 |
|
|
|
- |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(84,469 |
) |
|
|
73,484 |
|
Prepayments
and other current assets
|
|
|
(1,145 |
) |
|
|
(689 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
18,991 |
|
|
|
11,076 |
|
Accrued
taxes
|
|
|
(29,434 |
) |
|
|
(38,654 |
) |
Accrued
interest
|
|
|
232 |
|
|
|
178 |
|
Other
|
|
|
3,265 |
|
|
|
4,203 |
|
Net cash
provided from (used for) operating activities
|
|
|
(2,804 |
) |
|
|
205,749 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Short-term
borrowings, net
|
|
|
47,423 |
|
|
|
- |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(368 |
) |
|
|
(335 |
) |
Short-term
borrowings, net
|
|
|
- |
|
|
|
(100,562 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(25,000 |
) |
|
|
(100,000 |
) |
Other
|
|
|
(3,019 |
) |
|
|
(2,955 |
) |
Net cash
provided from (used for) financing activities
|
|
|
19,036 |
|
|
|
(203,852 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(46,434 |
) |
|
|
(67,206 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(5,449 |
) |
|
|
30,132 |
|
Redemption of
lessor notes
|
|
|
37,070 |
|
|
|
37,712 |
|
Other
|
|
|
(1,415 |
) |
|
|
(2,528 |
) |
Net cash used
for investing activities
|
|
|
(16,228 |
) |
|
|
(1,890 |
) |
|
|
|
|
|
|
|
|
|
Net increase
in cash and cash equivalents
|
|
|
4 |
|
|
|
7 |
|
Cash and cash
equivalents at beginning of period
|
|
|
226 |
|
|
|
232 |
|
Cash and cash
equivalents at end of period
|
|
$ |
230 |
|
|
$ |
239 |
|
|
|
|
|
|
|
|
|
|
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 six months of 2009 decreased to $7 million from $38 million in the same
period of 2008. The decrease resulted primarily from the completion of
transition cost recovery in 2008.
Revenues
Revenues increased
$38 million, or
8.7%, in the first six months of 2009 compared to the same period of 2008
primarily due to increased retail generation revenues ($117 million), partially
offset by lower distribution revenues ($70 million) and wholesale
generation revenues ($11 million).
Retail generation
revenues increased in the first six 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. Average prices
increased primarily due to an increase in TE's fuel cost recovery rider that was
effective from January through May 2009. Effective June 1, 2009, the
transmission tariff ended and the recovery of transmission costs is included in
the generation rate established under TE’s CBP. 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 from a decrease in customer shopping. Most of TE’s customers
returned to PLR service in December 2008, following the termination of certain
government aggregation programs in TE’s service territory.
The decrease in
wholesale revenues was due to the expiration of a sales agreement with AMP-Ohio
at the end of 2008 ($6 million) and lower revenues from associated company sales
to NGC ($5 million) from TE’s leasehold interest in Beaver Valley Unit
2.
Changes in retail
electric generation KWH sales and revenues in the first six months of 2009 from
the same period of 2008 are summarized in the following tables.
|
|
Increase
|
|
Retail
Generation KWH Sales
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
8.1
|
%
|
Commercial
|
|
|
39.1
|
%
|
Industrial
|
|
|
(13.5
|
)%
|
Net
Increase in Retail Generation Sales
|
|
|
2.6
|
%
|
Retail
Generation Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
28
|
|
Commercial
|
|
|
51
|
|
Industrial
|
|
|
38
|
|
Increase
in Retail Generation Revenues
|
|
$
|
117
|
|
Revenues from
distribution throughput decreased by $70 million in the first six months of 2009
compared to the same period of 2008 due to lower average unit prices and lower
KWH deliveries for all customer classes due primarily to economic conditions.
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).
Decreases in
distribution KWH deliveries and revenues in the first six months of 2009 from
the same period of 2008 are summarized in the following tables.
Distribution
KWH Deliveries
|
|
Decrease
|
|
|
|
|
|
|
Residential
|
|
|
(2.0
|
)%
|
Commercial
|
|
|
(8.7
|
)%
|
Industrial
|
|
|
(15.7
|
)%
|
Decrease
in Distribution Deliveries
|
|
|
(10.5
|
)%
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(14
|
)
|
Commercial
|
|
|
(35
|
)
|
Industrial
|
|
|
(21
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(70
|
)
|
Expenses
Total expenses
increased $83 million in the first six 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
|
|
$
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
|
|
|
Amortization
of regulatory assets, net
|
|
|
|
|
|
|
|
|
|
Higher purchased
power costs reflect the results of TE’s power procurement process for retail
customers in the first six months of 2009 (see Regulatory Matters – Ohio). Other
operating costs decreased primarily due to reduced transmission expenses
(included in the cost of power purchased from others beginning June 1,
2009) and lower costs associated with TE’s leasehold interest in Beaver Valley
Unit 2 (absence of a refueling outage in the 2009 period). These reductions were
partially offset by cost increases associated with regulatory obligations for
economic development and energy efficiency programs. 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
completion of transition cost recovery, partially offset by a reduction in
transmission cost 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 June 30, 2009 and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2009 and 2008 and the consolidated statement of cash
flows for the six-month periods ended June 30, 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
August 3,
2009
|
THE
TOLEDO EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
219,911 |
|
|
$ |
214,353 |
|
|
$ |
456,996 |
|
|
$ |
418,022 |
|
Excise tax
collections
|
|
|
6,297 |
|
|
|
7,153 |
|
|
|
14,026 |
|
|
|
15,178 |
|
Total
revenues
|
|
|
226,208 |
|
|
|
221,506 |
|
|
|
471,022 |
|
|
|
433,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
130,564 |
|
|
|
102,773 |
|
|
|
255,888 |
|
|
|
202,267 |
|
Purchased
power from non-affiliates
|
|
|
18,244 |
|
|
|
77 |
|
|
|
58,781 |
|
|
|
1,881 |
|
Other
operating costs
|
|
|
35,480 |
|
|
|
50,805 |
|
|
|
80,484 |
|
|
|
96,134 |
|
Provision for
depreciation
|
|
|
7,717 |
|
|
|
7,941 |
|
|
|
15,289 |
|
|
|
16,966 |
|
Amortization
of regulatory assets, net
|
|
|
11,771 |
|
|
|
16,431 |
|
|
|
21,668 |
|
|
|
31,962 |
|
General
taxes
|
|
|
12,349 |
|
|
|
12,605 |
|
|
|
26,599 |
|
|
|
26,982 |
|
Total
expenses
|
|
|
216,125 |
|
|
|
190,632 |
|
|
|
458,709 |
|
|
|
376,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
10,083 |
|
|
|
30,874 |
|
|
|
12,313 |
|
|
|
57,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
income
|
|
|
7,529 |
|
|
|
5,224 |
|
|
|
13,013 |
|
|
|
11,705 |
|
Miscellaneous
income (expense)
|
|
|
1,375 |
|
|
|
(1,947 |
) |
|
|
35 |
|
|
|
(3,459 |
) |
Interest
expense
|
|
|
(9,262 |
) |
|
|
(5,578 |
) |
|
|
(14,795 |
) |
|
|
(11,613 |
) |
Capitalized
interest
|
|
|
50 |
|
|
|
88 |
|
|
|
92 |
|
|
|
125 |
|
Total other
expense
|
|
|
(308 |
) |
|
|
(2,213 |
) |
|
|
(1,655 |
) |
|
|
(3,242 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
9,775 |
|
|
|
28,661 |
|
|
|
10,658 |
|
|
|
53,766 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
3,370 |
|
|
|
7,352 |
|
|
|
3,261 |
|
|
|
15,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
6,405 |
|
|
|
21,309 |
|
|
|
7,397 |
|
|
|
38,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Noncontrolling
interest income
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS
AVAILABLE TO PARENT
|
|
$ |
6,404 |
|
|
$ |
21,307 |
|
|
$ |
7,394 |
|
|
$ |
38,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
6,405 |
|
|
$ |
21,309 |
|
|
$ |
7,397 |
|
|
$ |
38,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
19,016 |
|
|
|
(64 |
) |
|
|
19,149 |
|
|
|
(127 |
) |
Change in
unrealized gain on available-for-sale securities
|
|
|
(2,739 |
) |
|
|
(2,481 |
) |
|
|
(3,548 |
) |
|
|
(520 |
) |
Other
comprehensive income (loss)
|
|
|
16,277 |
|
|
|
(2,545 |
) |
|
|
15,601 |
|
|
|
(647 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
7,224 |
|
|
|
(914 |
) |
|
|
7,205 |
|
|
|
(186 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
9,053 |
|
|
|
(1,631 |
) |
|
|
8,396 |
|
|
|
(461 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME
|
|
|
15,458 |
|
|
|
19,678 |
|
|
|
15,793 |
|
|
|
37,865 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME ATTRIBUTABLE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TO
NONCONTROLLING INTEREST
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE
INCOME AVAILABLE TO PARENT
|
|
$ |
15,457 |
|
|
$ |
19,676 |
|
|
$ |
15,790 |
|
|
$ |
37,861 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
319,454 |
|
|
$ |
14 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
|
|
|
508 |
|
|
|
751 |
|
Associated
companies
|
|
|
64,734 |
|
|
|
61,854 |
|
Other (less
accumulated provisions of $192,000 and $203,000,
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
19,978 |
|
|
|
23,336 |
|
Notes
receivable from associated companies
|
|
|
131,556 |
|
|
|
111,579 |
|
Prepayments
and other
|
|
|
5,193 |
|
|
|
1,213 |
|
|
|
|
541,423 |
|
|
|
198,747 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
891,108 |
|
|
|
870,911 |
|
Less -
Accumulated provision for depreciation
|
|
|
417,418 |
|
|
|
407,859 |
|
|
|
|
473,690 |
|
|
|
463,052 |
|
Construction
work in progress
|
|
|
8,065 |
|
|
|
9,007 |
|
|
|
|
481,755 |
|
|
|
472,059 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Investment in
lessor notes
|
|
|
124,357 |
|
|
|
142,687 |
|
Long-term
notes receivable from associated companies
|
|
|
37,075 |
|
|
|
37,233 |
|
Nuclear plant
decommissioning trusts
|
|
|
73,696 |
|
|
|
73,500 |
|
Other
|
|
|
1,625 |
|
|
|
1,668 |
|
|
|
|
236,753 |
|
|
|
255,088 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
500,576 |
|
|
|
500,576 |
|
Regulatory
assets
|
|
|
91,407 |
|
|
|
109,364 |
|
Property
taxes
|
|
|
22,970 |
|
|
|
22,970 |
|
Other
|
|
|
66,161 |
|
|
|
51,315 |
|
|
|
|
681,114 |
|
|
|
684,225 |
|
|
|
$ |
1,941,045 |
|
|
$ |
1,610,119 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
222 |
|
|
$ |
34 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
31,622 |
|
|
|
70,455 |
|
Other
|
|
|
24,178 |
|
|
|
4,812 |
|
Notes payable
to associated companies
|
|
|
171,180 |
|
|
|
111,242 |
|
Accrued
taxes
|
|
|
25,777 |
|
|
|
24,433 |
|
Lease market
valuation liability
|
|
|
36,900 |
|
|
|
36,900 |
|
Other
|
|
|
23,311 |
|
|
|
22,489 |
|
|
|
|
313,190 |
|
|
|
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
|
|
|
175,883 |
|
|
|
175,879 |
|
Accumulated
other comprehensive loss
|
|
|
(24,976 |
) |
|
|
(33,372 |
) |
Retained
earnings
|
|
|
197,927 |
|
|
|
190,533 |
|
Total common
stockholder's equity
|
|
|
495,844 |
|
|
|
480,050 |
|
Noncontrolling
interest
|
|
|
2,678 |
|
|
|
2,675 |
|
Total
equity
|
|
|
498,522 |
|
|
|
482,725 |
|
Long-term debt
and other long-term obligations
|
|
|
600,430 |
|
|
|
299,626 |
|
|
|
|
1,098,952 |
|
|
|
782,351 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
85,343 |
|
|
|
78,905 |
|
Accumulated
deferred investment tax credits
|
|
|
6,585 |
|
|
|
6,804 |
|
Lease market
valuation liability
|
|
|
254,650 |
|
|
|
273,100 |
|
Retirement
benefits
|
|
|
57,734 |
|
|
|
73,106 |
|
Asset
retirement obligations
|
|
|
31,234 |
|
|
|
30,213 |
|
Lease
assignment payable to associated companies
|
|
|
30,529 |
|
|
|
30,529 |
|
Other
|
|
|
62,828 |
|
|
|
64,746 |
|
|
|
|
528,903 |
|
|
|
557,403 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
1,941,045 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
7,397 |
|
|
$ |
38,326 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
|
15,289 |
|
|
|
16,966 |
|
Amortization
of regulatory assets, net
|
|
|
21,668 |
|
|
|
31,962 |
|
Purchased
power cost recovery reconciliation
|
|
|
(4,197 |
) |
|
|
- |
|
Deferred rents
and lease market valuation liability
|
|
|
(40,697 |
) |
|
|
(39,045 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
(1,206 |
) |
|
|
(3,113 |
) |
Accrued
compensation and retirement benefits
|
|
|
711 |
|
|
|
(1,160 |
) |
Accrued
regulatory obligations
|
|
|
4,450 |
|
|
|
- |
|
Electric
service prepayment programs
|
|
|
(1,458 |
) |
|
|
(6,017 |
) |
Cash
collateral from suppliers
|
|
|
2,755 |
|
|
|
- |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
1,075 |
|
|
|
76,978 |
|
Prepayments
and other current assets
|
|
|
(220 |
) |
|
|
(292 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
5,533 |
|
|
|
(166,120 |
) |
Accrued
taxes
|
|
|
(2,936 |
) |
|
|
(7,923 |
) |
Accrued
interest
|
|
|
3,983 |
|
|
|
- |
|
Other
|
|
|
1,788 |
|
|
|
866 |
|
Net cash
provided from (used for) operating activities
|
|
|
13,935 |
|
|
|
(58,572 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
297,422 |
|
|
|
- |
|
Short-term
borrowings, net
|
|
|
59,938 |
|
|
|
21,558 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(236 |
) |
|
|
(17 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(25,000 |
) |
|
|
(35,000 |
) |
Other
|
|
|
(247 |
) |
|
|
- |
|
Net cash
provided from (used for) financing activities
|
|
|
331,877 |
|
|
|
(13,459 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(21,661 |
) |
|
|
(34,388 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(19,819 |
) |
|
|
97,614 |
|
Redemption of
lessor notes
|
|
|
18,330 |
|
|
|
11,959 |
|
Sales of
investment securities held in trusts
|
|
|
77,323 |
|
|
|
21,791 |
|
Purchases of
investment securities held in trusts
|
|
|
(78,700 |
) |
|
|
(23,581 |
) |
Other
|
|
|
(1,845 |
) |
|
|
(1,364 |
) |
Net cash
provided from (used for) investing activities
|
|
|
(26,372 |
) |
|
|
72,031 |
|
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
319,440 |
|
|
|
- |
|
Cash and cash
equivalents at beginning of period
|
|
|
14 |
|
|
|
22 |
|
Cash and cash
equivalents at end of period
|
|
$ |
319,454 |
|
|
$ |
22 |
|
|
|
|
|
|
|
|
|
|
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 six months of 2009 decreased to $66 million from $77 million in the same
period in 2008. The decrease was primarily due to lower revenues, partially
offset by lower purchased power costs and reduced amortization of regulatory
assets.
Revenues
In the first six
months of 2009, revenues decreased by $147 million, or 9%, compared with the
same period of 2008. Retail and wholesale generation revenues decreased by
$3 million and
$124 million,
respectively, and distribution revenues decreased by $14 million in the first
six months of 2009.
Retail generation
revenues decreased due to lower retail generation KWH sales in all sectors,
partially offset by higher unit prices in the residential and commercial sectors
resulting from the BGS auctions effective June 1, 2008, and June 1, 2009.
Lower sales to the residential sector reflected milder weather in JCP&L’s
service territory, while the decrease in sales to the commercial sector was
primarily due to an increase in the number of shopping customers. Industrial
sales were lower as a result of weakened economic conditions.
Wholesale generation
revenues decreased $124 million in the first six
months of 2009 due to lower market prices and a decrease in sales volume from
NUG purchases resulting from the termination of a NUG contract in October
2008.
Changes in retail
generation KWH sales and revenues by customer class in the first six months of
2009 compared to the same period of 2008 are summarized in the following
tables:
Retail
Generation KWH Sales
|
|
Decrease
|
|
|
|
|
|
|
Residential
|
|
|
(3.5)
|
%
|
Commercial
|
|
|
(13.6)
|
%
|
Industrial
|
|
|
(6.6)
|
%
|
Decrease
in Generation Sales
|
|
|
(7.7)
|
%
|
Retail
Generation Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
29
|
|
Commercial
|
|
|
(27
|
)
|
Industrial
|
|
|
(5
|
)
|
Net
Decrease in Generation Revenues
|
|
$
|
(3
|
)
|
Distribution
revenues decreased $14 million in the first six months of 2009 compared to the
same period of 2008 due to lower KWH deliveries, reflecting weather and economic
impacts in JCP&L’s service territory, partially offset by an increase in
composite unit prices.
Changes in
distribution KWH deliveries and revenues by customer class in the first six
months of 2009 compared to the same period in 2008 are summarized in the
following tables:
Distribution
KWH Deliveries
|
|
Decrease
|
|
|
|
|
|
|
|
Residential
|
|
|
|
(3.5)
|
%
|
Commercial
|
|
|
|
(3.3)
|
%
|
Industrial
|
|
|
|
(12.6)
|
%
|
Decrease
in Distribution Deliveries
|
|
|
|
(4.6)
|
%
|
Distribution
Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
(8
|
)
|
Commercial
|
|
|
(5
|
)
|
Industrial
|
|
|
(1
|
)
|
Decrease
in Distribution Revenues
|
|
$
|
(14
|
)
|
Expenses
Total expenses
decreased by $135 million in the first six 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
|
|
|
$
|
(126
|
)
|
Provision for
depreciation
|
|
|
|
4
|
|
Amortization
of regulatory assets
|
|
|
|
(11
|
)
|
General
taxes
|
|
|
|
(2
|
)
|
Net
decrease in expenses
|
|
|
$
|
(135
|
)
|
Purchased power
costs decreased in the first six months of 2009 primarily due to the lower KWH
sales requirements discussed above, partially offset by higher unit prices
resulting from the BGS auction process. Depreciation expense increased due to an
increase in depreciable property since the second quarter of 2008. Amortization
of regulatory assets decreased in the first six months of 2009 primarily due to
the full recovery of certain regulatory assets in June 2008. General
taxes decreased principally as the result of lower sales taxes.
Other Expenses
Other expenses
increased by $7 million in the first six
months of 2009 compared to the same period in 2008 primarily due to higher
interest expense associated with JCP&L's $300 million Senior Notes issuance
in January 2009.
Sale
of Investment
On April 17, 2008,
JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim
Power Corp. for $20 million, as approved by an earlier order from the NJBPU. The
New Jersey Rate Counsel appealed the sale to the Appellate Division of the
Superior Court of New Jersey. On July 10, 2009, the Court upheld the
NJBPU’s order and the sale of the plant.
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 June 30, 2009 and the related
consolidated statements of income and comprehensive income for each of the
three-month and six-month periods ended June 30, 2009 and 2008 and the
consolidated statement of cash flows for the six-month periods ended
June 30, 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
August 3,
2009
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
697,061 |
|
|
$ |
823,104 |
|
|
$ |
1,457,981 |
|
|
$ |
1,604,537 |
|
Excise tax
collections
|
|
|
11,031 |
|
|
|
11,639 |
|
|
|
23,762 |
|
|
|
24,434 |
|
Total
revenues
|
|
|
708,092 |
|
|
|
834,743 |
|
|
|
1,481,743 |
|
|
|
1,628,971 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
423,950 |
|
|
|
534,177 |
|
|
|
905,191 |
|
|
|
1,030,858 |
|
Other
operating costs
|
|
|
70,876 |
|
|
|
77,569 |
|
|
|
156,746 |
|
|
|
156,353 |
|
Provision for
depreciation
|
|
|
25,301 |
|
|
|
23,543 |
|
|
|
50,404 |
|
|
|
46,825 |
|
Amortization
of regulatory assets
|
|
|
80,018 |
|
|
|
86,507 |
|
|
|
166,849 |
|
|
|
178,026 |
|
General
taxes
|
|
|
12,587 |
|
|
|
15,538 |
|
|
|
30,083 |
|
|
|
32,566 |
|
Total
expenses
|
|
|
612,732 |
|
|
|
737,334 |
|
|
|
1,309,273 |
|
|
|
1,444,628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
95,360 |
|
|
|
97,409 |
|
|
|
172,470 |
|
|
|
184,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
2,007 |
|
|
|
1,413 |
|
|
|
2,812 |
|
|
|
1,024 |
|
Interest
expense
|
|
|
(29,671 |
) |
|
|
(24,840 |
) |
|
|
(57,539 |
) |
|
|
(49,304 |
) |
Capitalized
interest
|
|
|
218 |
|
|
|
430 |
|
|
|
280 |
|
|
|
706 |
|
Total other
expense
|
|
|
(27,446 |
) |
|
|
(22,997 |
) |
|
|
(54,447 |
) |
|
|
(47,574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
67,914 |
|
|
|
74,412 |
|
|
|
118,023 |
|
|
|
136,769 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
29,848 |
|
|
|
31,468 |
|
|
|
52,399 |
|
|
|
59,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
38,066 |
|
|
|
42,944 |
|
|
|
65,624 |
|
|
|
76,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
20,918 |
|
|
|
(3,449 |
) |
|
|
25,039 |
|
|
|
(6,898 |
) |
Unrealized
gain on derivative hedges
|
|
|
69 |
|
|
|
69 |
|
|
|
138 |
|
|
|
138 |
|
Other
comprehensive income (loss)
|
|
|
20,987 |
|
|
|
(3,380 |
) |
|
|
25,177 |
|
|
|
(6,760 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
11,059 |
|
|
|
(1,469 |
) |
|
|
12,489 |
|
|
|
(2,939 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
9,928 |
|
|
|
(1,911 |
) |
|
|
12,688 |
|
|
|
(3,821 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
47,994 |
|
|
$ |
41,033 |
|
|
$ |
78,312 |
|
|
$ |
73,077 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
138 |
|
|
$ |
66 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,158,000 and $3,230,000
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
315,553 |
|
|
|
340,485 |
|
Associated
companies
|
|
|
166 |
|
|
|
265 |
|
Other
|
|
|
21,337 |
|
|
|
37,534 |
|
Notes
receivable - associated companies
|
|
|
17,595 |
|
|
|
16,254 |
|
Prepaid
taxes
|
|
|
156,503 |
|
|
|
10,492 |
|
Other
|
|
|
17,598 |
|
|
|
18,066 |
|
|
|
|
528,890 |
|
|
|
423,162 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
4,386,758 |
|
|
|
4,307,556 |
|
Less -
Accumulated provision for depreciation
|
|
|
1,582,136 |
|
|
|
1,551,290 |
|
|
|
|
2,804,622 |
|
|
|
2,756,266 |
|
Construction
work in progress
|
|
|
57,080 |
|
|
|
77,317 |
|
|
|
|
2,861,702 |
|
|
|
2,833,583 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear fuel
disposal trust
|
|
|
192,585 |
|
|
|
181,468 |
|
Nuclear plant
decommissioning trusts
|
|
|
146,098 |
|
|
|
143,027 |
|
Other
|
|
|
2,163 |
|
|
|
2,145 |
|
|
|
|
340,846 |
|
|
|
326,640 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,810,936 |
|
|
|
1,810,936 |
|
Regulatory
assets
|
|
|
1,055,327 |
|
|
|
1,228,061 |
|
Other
|
|
|
24,978 |
|
|
|
29,946 |
|
|
|
|
2,891,241 |
|
|
|
3,068,943 |
|
|
|
$ |
6,622,679 |
|
|
$ |
6,652,328 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
29,831 |
|
|
$ |
29,094 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
65,113 |
|
|
|
121,380 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
14,863 |
|
|
|
12,821 |
|
Other
|
|
|
177,379 |
|
|
|
198,742 |
|
Accrued
taxes
|
|
|
7,258 |
|
|
|
20,561 |
|
Accrued
interest
|
|
|
18,570 |
|
|
|
9,197 |
|
Other
|
|
|
108,311 |
|
|
|
133,091 |
|
|
|
|
421,325 |
|
|
|
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
|
|
|
2,502,675 |
|
|
|
2,644,756 |
|
Accumulated
other comprehensive loss
|
|
|
(203,850 |
) |
|
|
(216,538 |
) |
Retained
earnings
|
|
|
134,200 |
|
|
|
156,576 |
|
Total common
stockholder's equity
|
|
|
2,569,309 |
|
|
|
2,729,010 |
|
Long-term debt
and other long-term obligations
|
|
|
1,817,960 |
|
|
|
1,531,840 |
|
|
|
|
4,387,269 |
|
|
|
4,260,850 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Power purchase
contract liability
|
|
|
474,533 |
|
|
|
531,686 |
|
Accumulated
deferred income taxes
|
|
|
680,159 |
|
|
|
689,065 |
|
Nuclear fuel
disposal costs
|
|
|
196,357 |
|
|
|
196,235 |
|
Asset
retirement obligations
|
|
|
98,365 |
|
|
|
95,216 |
|
Retirement
benefits
|
|
|
172,668 |
|
|
|
190,182 |
|
Other
|
|
|
192,003 |
|
|
|
164,208 |
|
|
|
|
1,814,085 |
|
|
|
1,866,592 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
6,622,679 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
65,624 |
|
|
$ |
76,898 |
|
Adjustments to
reconcile net income to net cash from operating activities
-
|
|
|
|
|
|
|
|
|
Provision for
depreciation
|
|
|
50,404 |
|
|
|
46,825 |
|
Amortization
of regulatory assets
|
|
|
166,849 |
|
|
|
178,026 |
|
Deferred
purchased power and other costs
|
|
|
(50,542 |
) |
|
|
(69,247 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
3,440 |
|
|
|
(8,656 |
) |
Accrued
compensation and retirement benefits
|
|
|
(2,883 |
) |
|
|
(28,695 |
) |
Cash
collateral received from (returned to) suppliers
|
|
|
(209 |
) |
|
|
66,040 |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
41,228 |
|
|
|
(79,001 |
) |
Prepaid
taxes
|
|
|
(146,011 |
) |
|
|
(137,006 |
) |
Other current
assets
|
|
|
271 |
|
|
|
534 |
|
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(19,321 |
) |
|
|
96,297 |
|
Accrued
taxes
|
|
|
(14,007 |
) |
|
|
(1,972 |
) |
Accrued
interest
|
|
|
9,373 |
|
|
|
(54 |
) |
Tax
collections payable
|
|
|
(9,714 |
) |
|
|
(12,493 |
) |
Other
|
|
|
4,555 |
|
|
|
(14,194 |
) |
Net cash
provided from operating activities
|
|
|
99,057 |
|
|
|
113,302 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
299,619 |
|
|
|
- |
|
Short-term
borrowings, net
|
|
|
- |
|
|
|
164,358 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(13,093 |
) |
|
|
(12,012 |
) |
Common
Stock
|
|
|
(150,000 |
) |
|
|
- |
|
Short-term
borrowings, net
|
|
|
(56,267 |
) |
|
|
- |
|
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(88,000 |
) |
|
|
(176,000 |
) |
Other
|
|
|
(2,260 |
) |
|
|
(67 |
) |
Net cash used
for financing activities
|
|
|
(10,001 |
) |
|
|
(23,721 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(78,401 |
) |
|
|
(98,068 |
) |
Proceeds from
asset sales
|
|
|
- |
|
|
|
20,000 |
|
Loans to
associated companies, net
|
|
|
(1,341 |
) |
|
|
(653 |
) |
Sales of
investment securities held in trusts
|
|
|
244,880 |
|
|
|
113,970 |
|
Purchases of
investment securities held in trusts
|
|
|
(252,856 |
) |
|
|
(122,324 |
) |
Other
|
|
|
(1,266 |
) |
|
|
(2,368 |
) |
Net cash used
for investing activities
|
|
|
(88,984 |
) |
|
|
(89,443 |
) |
|
|
|
|
|
|
|
|
|
Net increase
in cash and cash equivalents
|
|
|
72 |
|
|
|
138 |
|
Cash and cash
equivalents at beginning of period
|
|
|
66 |
|
|
|
94 |
|
Cash and cash
equivalents at end of period
|
|
$ |
138 |
|
|
$ |
232 |
|
|
|
|
|
|
|
|
|
|
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 $27 million in the first six months of 2009, compared to $42 million in the same
period of 2008. The decrease was primarily due to increased amortization of
regulatory assets, partially offset by higher revenues and lower other operating
costs.
Revenues
Revenues increased
by $15 million, or 1.9%, in the first six months of 2009, compared to the
same period of 2008, primarily due to higher distribution throughput revenues,
partially offset by a decrease in retail generation and wholesale revenues.
Wholesale revenues decreased by $1 million in the first six
months of 2009 due to lower wholesale KWH sales volume, partially offset by
higher capacity prices for PJM market participants.
In the first six
months of 2009, retail generation revenues decreased $17 million due to lower
KWH sales to all classes with a slight increase in composite unit prices in all
customer classes. Lower KWH sales to commercial and industrial customers were
principally due to economic conditions in Met-Ed’s service territory. Lower KWH
sales in the residential sector were due to decreased weather-related usage,
reflecting a 22.5% decrease in cooling degree days in the first six months of
2009 and a 2.5% decrease in heating degree days in the second quarter of
2009.
Changes in retail
generation sales and revenues in the first six months of 2009 compared to the
same period of 2008 are summarized in the following tables:
|
|
|
|
Retail
Generation KWH Sales
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
(0.2
|
)%
|
Commercial
|
|
|
(4.3
|
)%
|
Industrial
|
|
|
(13.6
|
)%
|
Decrease
in Retail Generation Sales
|
|
|
(5.3
|
)%
|
|
|
|
|
Retail
Generation Revenues
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
-
|
|
Commercial
|
|
|
(5
|
)
|
Industrial
|
|
|
(12
|
)
|
Decrease
in Retail Generation Revenues
|
|
$
|
(17
|
)
|
In the first six
months of 2009, distribution throughput revenues increased $38 million primarily due to
higher transmission rates, resulting from the annual updates to Met-Ed’s TSC
rider in June 2008 and 2009. Decreased deliveries to commercial and industrial
customers reflected the weakened economy, while decreased deliveries to
residential customers were a result of the weather conditions described
above.
Changes in
distribution KWH deliveries and revenues in the first six months of 2009
compared to the same period of 2008 are summarized in the following
tables:
|
|
|
|
Distribution
KWH Deliveries
|
|
(Decrease)
|
|
|
|
|
|
|
Residential
|
|
|
(0.2
|
)%
|
Commercial
|
|
|
(4.3
|
)%
|
Industrial
|
|
|
(13.6
|
)%
|
Decrease
in Distribution Deliveries
|
|
|
(5.3
|
)%
|
Distribution
Revenues
|
|
Increase
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
22
|
|
Commercial
|
|
|
11
|
|
Industrial
|
|
|
5
|
|
Increase
in Distribution Revenues
|
|
$
|
38
|
|
PJM transmission
service revenues decreased by $5 million in the first six
months of 2009 compared to the same period of 2008, primarily due to decreased
revenues related to Met-Ed’s 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 $33 million in the first six months 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
|
|
$
|
(9
|
)
|
Other
operating costs
|
|
|
(66
|
)
|
Provision for
depreciation
|
|
|
3
|
|
Amortization
of regulatory assets, net
|
|
|
103
|
|
General
taxes
|
|
|
2
|
|
Net
Increase in Expenses
|
|
$
|
33
|
|
The net amortization
of regulatory assets increased by $103 million in the first six months of
2009 compared to the same period of 2008 primarily due to increased transmission
cost recovery reflecting lower PJM transmission service expenses and the
increased transmission revenues described above. Other operating costs decreased
$66 million in the first six months of 2009 primarily due to lower transmission
expenses as a result of decreased congestion costs and transmission loss
expenses. Purchased power costs decreased by $9 million, or 2.0%, in the first
six months of 2009 due to reduced volume as a result of lower KWH sales
requirements, partially offset by an increase in composite unit prices.
Depreciation expense increased primarily due to an increase in depreciable
property since the second quarter of 2008.
Other Expense
Other expense
increased in the first six months of 2009 primarily due to a decrease in
interest earned 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 June 30, 2009 and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2009 and 2008 and the consolidated statement of cash
flows for the six-month periods ended June 30, 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
August 3,
2009
|
METROPOLITAN
EDISON COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
360,022 |
|
|
$ |
373,821 |
|
|
$ |
769,708 |
|
|
$ |
753,429 |
|
Gross receipts
tax collections
|
|
|
17,586 |
|
|
|
18,158 |
|
|
|
37,569 |
|
|
|
38,876 |
|
Total
revenues
|
|
|
377,608 |
|
|
|
391,979 |
|
|
|
807,277 |
|
|
|
792,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
78,652 |
|
|
|
68,209 |
|
|
|
178,729 |
|
|
|
151,651 |
|
Purchased
power from non-affiliates
|
|
|
123,299 |
|
|
|
149,534 |
|
|
|
247,210 |
|
|
|
283,074 |
|
Other
operating costs
|
|
|
51,309 |
|
|
|
117,028 |
|
|
|
157,666 |
|
|
|
224,045 |
|
Provision for
depreciation
|
|
|
12,919 |
|
|
|
10,940 |
|
|
|
25,058 |
|
|
|
22,052 |
|
Amortization
(deferral) of regulatory assets, net
|
|
|
61,548 |
|
|
|
(11,645 |
) |
|
|
89,139 |
|
|
|
(13,842 |
) |
General
taxes
|
|
|
22,034 |
|
|
|
20,076 |
|
|
|
43,969 |
|
|
|
41,857 |
|
Total
expenses
|
|
|
349,761 |
|
|
|
354,142 |
|
|
|
741,771 |
|
|
|
708,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
27,847 |
|
|
|
37,837 |
|
|
|
65,506 |
|
|
|
83,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
2,769 |
|
|
|
4,873 |
|
|
|
5,955 |
|
|
|
10,352 |
|
Miscellaneous
income
|
|
|
1,058 |
|
|
|
789 |
|
|
|
1,914 |
|
|
|
480 |
|
Interest
expense
|
|
|
(14,763 |
) |
|
|
(10,980 |
) |
|
|
(28,122 |
) |
|
|
(22,652 |
) |
Capitalized
interest
|
|
|
62 |
|
|
|
199 |
|
|
|
77 |
|
|
|
(20 |
) |
Total other
expense
|
|
|
(10,874 |
) |
|
|
(5,119 |
) |
|
|
(20,176 |
) |
|
|
(11,840 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
16,973 |
|
|
|
32,718 |
|
|
|
45,330 |
|
|
|
71,628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
6,968 |
|
|
|
12,921 |
|
|
|
18,703 |
|
|
|
29,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
10,005 |
|
|
|
19,797 |
|
|
|
26,627 |
|
|
|
42,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
27,369 |
|
|
|
(2,233 |
) |
|
|
31,922 |
|
|
|
(4,466 |
) |
Unrealized
gain on derivative hedges
|
|
|
84 |
|
|
|
84 |
|
|
|
168 |
|
|
|
168 |
|
Other
comprehensive income (loss)
|
|
|
27,453 |
|
|
|
(2,149 |
) |
|
|
32,090 |
|
|
|
(4,298 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
13,592 |
|
|
|
(971 |
) |
|
|
15,385 |
|
|
|
(1,941 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
13,861 |
|
|
|
(1,178 |
) |
|
|
16,705 |
|
|
|
(2,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
23,866 |
|
|
$ |
18,619 |
|
|
$ |
43,332 |
|
|
$ |
39,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009 |
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
125 |
|
|
$ |
144 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $3,421,000 and $3,616,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
163,556 |
|
|
|
159,975 |
|
Associated
companies
|
|
|
20,145 |
|
|
|
17,034 |
|
Other
|
|
|
12,387 |
|
|
|
19,828 |
|
Notes
receivable from associated companies
|
|
|
317,894 |
|
|
|
11,446 |
|
Prepaid
taxes
|
|
|
46,403 |
|
|
|
6,121 |
|
Other
|
|
|
4,595 |
|
|
|
1,621 |
|
|
|
|
565,105 |
|
|
|
216,169 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,116,595 |
|
|
|
2,065,847 |
|
Less -
Accumulated provision for depreciation
|
|
|
794,738 |
|
|
|
779,692 |
|
|
|
|
1,321,857 |
|
|
|
1,286,155 |
|
Construction
work in progress
|
|
|
17,763 |
|
|
|
32,305 |
|
|
|
|
1,339,620 |
|
|
|
1,318,460 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
233,289 |
|
|
|
226,139 |
|
Other
|
|
|
976 |
|
|
|
976 |
|
|
|
|
234,265 |
|
|
|
227,115 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
416,499 |
|
|
|
416,499 |
|
Regulatory
assets
|
|
|
496,902 |
|
|
|
412,994 |
|
Power purchase
contract asset
|
|
|
183,639 |
|
|
|
300,141 |
|
Other
|
|
|
34,308 |
|
|
|
31,031 |
|
|
|
|
1,131,348 |
|
|
|
1,160,665 |
|
|
|
$ |
3,270,338 |
|
|
$ |
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
|
|
|
29,094 |
|
|
|
28,707 |
|
Other
|
|
|
36,319 |
|
|
|
55,330 |
|
Accrued
taxes
|
|
|
14,484 |
|
|
|
16,238 |
|
Accrued
interest
|
|
|
16,985 |
|
|
|
6,755 |
|
Other
|
|
|
27,754 |
|
|
|
30,647 |
|
|
|
|
503,136 |
|
|
|
431,180 |
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
Common
stockholder's equity-
|
|
|
|
|
|
|
|
|
Common stock,
without par value, authorized 900,000 shares-
|
|
|
|
|
|
|
|
|
859,500 shares
outstanding
|
|
|
1,196,136 |
|
|
|
1,196,172 |
|
Accumulated
other comprehensive loss
|
|
|
(124,279 |
) |
|
|
(140,984 |
) |
Accumulated
deficit
|
|
|
(24,496 |
) |
|
|
(51,124 |
) |
Total common
stockholder's equity
|
|
|
1,047,361 |
|
|
|
1,004,064 |
|
Long-term debt
and other long-term obligations
|
|
|
713,812 |
|
|
|
513,752 |
|
|
|
|
1,761,173 |
|
|
|
1,517,816 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
429,032 |
|
|
|
387,757 |
|
Accumulated
deferred investment tax credits
|
|
|
7,540 |
|
|
|
7,767 |
|
Nuclear fuel
disposal costs
|
|
|
44,356 |
|
|
|
44,328 |
|
Asset
retirement obligations
|
|
|
174,424 |
|
|
|
170,999 |
|
Retirement
benefits
|
|
|
121,326 |
|
|
|
145,218 |
|
Power purchase
contract liability
|
|
|
161,106 |
|
|
|
150,324 |
|
Other
|
|
|
68,245 |
|
|
|
67,020 |
|
|
|
|
1,006,029 |
|
|
|
973,413 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
3,270,338 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
26,627 |
|
|
$ |
42,032 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
25,058 |
|
|
|
22,052 |
|
Amortization
(deferral) of regulatory assets, net
|
|
|
89,139 |
|
|
|
(13,842 |
) |
Deferred costs
recoverable as regulatory assets
|
|
|
(47,592 |
) |
|
|
(12,468 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
30,135 |
|
|
|
29,113 |
|
Accrued
compensation and retirement benefits
|
|
|
3,250 |
|
|
|
(14,819 |
) |
Cash
collateral
|
|
|
(6,800 |
) |
|
|
- |
|
Decrease
(Increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
346 |
|
|
|
(31,840 |
) |
Prepayments
and other current assets
|
|
|
(39,068 |
) |
|
|
(25,316 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(18,624 |
) |
|
|
7,411 |
|
Accrued
taxes
|
|
|
(1,754 |
) |
|
|
(14,451 |
) |
Accrued
interest
|
|
|
10,230 |
|
|
|
31 |
|
Other
|
|
|
7,870 |
|
|
|
7,608 |
|
Net cash
provided from (used for) operating activities
|
|
|
78,817 |
|
|
|
(4,489 |
) |
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
300,000 |
|
|
|
28,500 |
|
Short-term
borrowings, net
|
|
|
- |
|
|
|
72,485 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
(28,637 |
) |
Short-term
borrowings, net
|
|
|
(15,003 |
) |
|
|
- |
|
Other
|
|
|
(2,267 |
) |
|
|
- |
|
Net cash
provided from financing activities
|
|
|
282,730 |
|
|
|
72,348 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(48,464 |
) |
|
|
(62,011 |
) |
Sales of
investment securities held in trusts
|
|
|
63,086 |
|
|
|
81,538 |
|
Purchases of
investment securities held in trusts
|
|
|
(67,668 |
) |
|
|
(87,193 |
) |
Loans from
(to) associated companies, net
|
|
|
(306,448 |
) |
|
|
395 |
|
Other
|
|
|
(2,072 |
) |
|
|
(593 |
) |
Net cash used
for investing activities
|
|
|
(361,566 |
) |
|
|
(67,864 |
) |
|
|
|
|
|
|
|
|
|
Net decrease
in cash and cash equivalents
|
|
|
(19 |
) |
|
|
(5 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
144 |
|
|
|
135 |
|
Cash and cash
equivalents at end of period
|
|
$ |
125 |
|
|
$ |
130 |
|
|
|
|
|
|
|
|
|
|
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 $34 million in the first six months of 2009, compared to $40 million in
the same period of 2008. The decrease was primarily due to lower revenues,
partially offset by lower purchased power costs and decreased amortization of
regulatory assets.
Revenues
Revenues decreased
by $27 million, or 3.6%, in the first six months of 2009 primarily due to lower
retail generation revenues and PJM transmission revenues, partially offset by
higher wholesale generation revenues and distribution throughput revenues.
Wholesale revenues increased $3 million in the first six months of 2009,
compared to the same period of 2008, primarily reflecting higher KWH
sales.
In the first six
months of 2009, retail generation revenues decreased $19 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 six months of 2009 compared to the
same period of 2008 are summarized in the following tables:
Retail
Generation KWH Sales
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
0.3
|
%
|
Commercial
|
|
|
(2.9
|
)%
|
Industrial
|
|
|
(16.9
|
)%
|
Net
Decrease in Retail Generation Sales
|
|
|
(6.1
|
)%
|
|
|
|
|
Retail
Generation Revenues
|
|
Decrease
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
-
|
|
Commercial
|
|
|
(4
|
)
|
Industrial
|
|
|
(15
|
)
|
Decrease
in Retail Generation Revenues
|
|
$
|
(19
|
)
|
Revenues from
distribution throughput increased $5 million in the first six months 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 six months of 2009
compared to the same period of 2008 are summarized in the following
tables:
Distribution
KWH Deliveries
|
|
Increase
(Decrease)
|
|
|
|
|
|
Residential
|
|
|
0.3
|
%
|
Commercial
|
|
|
(2.9
|
)%
|
Industrial
|
|
|
(16.4
|
)%
|
Net
Decrease in Distribution Deliveries
|
|
|
(6.3
|
)%
|
Distribution
Revenues
|
|
Increase
(Decrease)
|
|
|
|
(In
millions)
|
|
Residential
|
|
$
|
5
|
|
Commercial
|
|
|
1
|
|
Industrial
|
|
|
(1
|
)
|
Net
Increase in Distribution Revenues
|
|
$
|
5
|
|
PJM transmission
revenues decreased by $20 million in the first six months 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 decreased by $7 million in the first six months 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
|
|
$
|
(6
|
)
|
Other
operating costs
|
|
|
2
|
|
Provision for
depreciation
|
|
|
4
|
|
Amortization
of regulatory assets, net
|
|
|
(5
|
)
|
General
taxes
|
|
|
(2
|
)
|
Net
Decrease in Expenses
|
|
$
|
(7
|
)
|
Purchased power
costs decreased by $6 million, or 1.5%, in the first six months of 2009 compared
to the same period of 2008 due to reduced volume as a result of lower KWH sales
requirements, partially offset by increased composite unit prices. Other
operating costs increased by $2 million in the first six months of 2009 due
primarily to higher pension and OPEB expenses. Depreciation expense increased
primarily due to an increase in depreciable property since the second quarter of
2008. The net amortization of regulatory assets decreased in the first six
months of 2009 primarily due to increased transmission cost deferrals as a
result of increased net congestion costs.
Other Expense
In the first six
months of 2009, other expense decreased primarily due to lower interest expense
on borrowings from the regulated money pool combined with reduced interest
expense on long-term debt due to the $100 million repayment of unsecured
notes in April 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 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 June 30, 2009 and the related consolidated statements of
income and comprehensive income for each of the three-month and six-month
periods ended June 30, 2009 and 2008 and the consolidated statement of cash
flows for the six-month periods ended June 30, 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
August 3,
2009
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
sales
|
|
$ |
316,881 |
|
|
$ |
335,382 |
|
|
$ |
688,174 |
|
|
$ |
711,410 |
|
Gross receipts
tax collections
|
|
|
14,804 |
|
|
|
16,040 |
|
|
|
32,096 |
|
|
|
35,504 |
|
Total
revenues
|
|
|
331,685 |
|
|
|
351,422 |
|
|
|
720,270 |
|
|
|
746,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power from affiliates
|
|
|
72,166 |
|
|
|
62,568 |
|
|
|
168,247 |
|
|
|
146,032 |
|
Purchased
power from non-affiliates
|
|
|
125,317 |
|
|
|
143,223 |
|
|
|
252,483 |
|
|
|
280,993 |
|
Other
operating costs
|
|
|
46,301 |
|
|
|
50,100 |
|
|
|
123,590 |
|
|
|
121,177 |
|
Provision for
depreciation
|
|
|
15,581 |
|
|
|
13,918 |
|
|
|
30,036 |
|
|
|
26,434 |
|
Amortization
of regulatory assets, net
|
|
|
18,113 |
|
|
|
19,111 |
|
|
|
26,889 |
|
|
|
31,931 |
|
General
taxes
|
|
|
18,251 |
|
|
|
18,345 |
|
|
|
38,844 |
|
|
|
40,200 |
|
Total
expenses
|
|
|
295,729 |
|
|
|
307,265 |
|
|
|
640,089 |
|
|
|
646,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
35,956 |
|
|
|
44,157 |
|
|
|
80,181 |
|
|
|
100,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income
|
|
|
911 |
|
|
|
1,058 |
|
|
|
1,709 |
|
|
|
867 |
|
Interest
expense
|
|
|
(11,843 |
) |
|
|
(14,901 |
) |
|
|
(25,076 |
) |
|
|
(30,223 |
) |
Capitalized
interest
|
|
|
29 |
|
|
|
70 |
|
|
|
51 |
|
|
|
(736 |
) |
Total other
expense
|
|
|
(10,903 |
) |
|
|
(13,773 |
) |
|
|
(23,316 |
) |
|
|
(30,092 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
25,053 |
|
|
|
30,384 |
|
|
|
56,865 |
|
|
|
70,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
10,232 |
|
|
|
11,987 |
|
|
|
23,354 |
|
|
|
30,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
|
14,821 |
|
|
|
18,397 |
|
|
|
33,511 |
|
|
|
39,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and
other postretirement benefits
|
|
|
29,400 |
|
|
|
(3,474 |
) |
|
|
32,355 |
|
|
|
(6,947 |
) |
Unrealized
gain on derivative hedges
|
|
|
16 |
|
|
|
16 |
|
|
|
32 |
|
|
|
32 |
|
Change in
unrealized gain on available-for-sale securities
|
|
|
6 |
|
|
|
(21 |
) |
|
|
(16 |
) |
|
|
(10 |
) |
Other
comprehensive income (loss)
|
|
|
29,422 |
|
|
|
(3,479 |
) |
|
|
32,371 |
|
|
|
(6,925 |
) |
Income tax
expense (benefit) related to other comprehensive income
|
|
|
15,100 |
|
|
|
(1,520 |
) |
|
|
16,155 |
|
|
|
(3,026 |
) |
Other
comprehensive income (loss), net of tax
|
|
|
14,322 |
|
|
|
(1,959 |
) |
|
|
16,216 |
|
|
|
(3,899 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COMPREHENSIVE INCOME
|
|
$ |
29,143 |
|
|
$ |
16,438 |
|
|
$ |
49,727 |
|
|
$ |
35,890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
11 |
|
|
$ |
23 |
|
Receivables-
|
|
|
|
|
|
|
|
|
Customers
(less accumulated provisions of $2,889,000 and $3,121,000,
|
|
|
|
|
|
|
|
|
respectively,
for uncollectible accounts)
|
|
|
129,092 |
|
|
|
146,831 |
|
Associated
companies
|
|
|
55,221 |
|
|
|
65,610 |
|
Other
|
|
|
11,976 |
|
|
|
26,766 |
|
Notes
receivable from associated companies
|
|
|
14,770 |
|
|
|
14,833 |
|
Prepaid
taxes
|
|
|
53,095 |
|
|
|
16,310 |
|
Other
|
|
|
482 |
|
|
|
1,517 |
|
|
|
|
264,647 |
|
|
|
271,890 |
|
UTILITY
PLANT:
|
|
|
|
|
|
|
|
|
In
service
|
|
|
2,371,657 |
|
|
|
2,324,879 |
|
Less -
Accumulated provision for depreciation
|
|
|
884,685 |
|
|
|
868,639 |
|
|
|
|
1,486,972 |
|
|
|
1,456,240 |
|
Construction
work in progress
|
|
|
28,105 |
|
|
|
25,146 |
|
|
|
|
1,515,077 |
|
|
|
1,481,386 |
|
OTHER
PROPERTY AND INVESTMENTS:
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
122,343 |
|
|
|
115,292 |
|
Non-utility
generation trusts
|
|
|
118,302 |
|
|
|
116,687 |
|
Other
|
|
|
287 |
|
|
|
293 |
|
|
|
|
240,932 |
|
|
|
232,272 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
768,628 |
|
|
|
768,628 |
|
Power purchase
contract asset
|
|
|
21,347 |
|
|
|
119,748 |
|
Regulatory
assets
|
|
|
9,911 |
|
|
|
- |
|
Other
|
|
|
15,106 |
|
|
|
18,658 |
|
|
|
|
814,992 |
|
|
|
907,034 |
|
|
|
$ |
2,835,648 |
|
|
$ |
2,892,582 |
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
45,000 |
|
|
$ |
145,000 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
178,056 |
|
|
|
31,402 |
|
Other
|
|
|
250,000 |
|
|
|
250,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
27,055 |
|
|
|
63,692 |
|
Other
|
|
|
40,162 |
|
|
|
48,633 |
|
Accrued
taxes
|
|
|
5,490 |
|
|
|
13,264 |
|
Accrued
interest
|
|
|
11,462 |
|
|
|
13,131 |
|
Other
|
|
|
23,395 |
|
|
|
31,730 |
|
|
|
|
580,620 |
|
|
|
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
|
|
|
912,420 |
|
|
|
912,441 |
|
Accumulated
other comprehensive loss
|
|
|
(111,781 |
) |
|
|
(127,997 |
) |
Retained
earnings
|
|
|
109,624 |
|
|
|
76,113 |
|
Total common
stockholder's equity
|
|
|
998,815 |
|
|
|
949,109 |
|
Long-term debt
and other long-term obligations
|
|
|
633,259 |
|
|
|
633,132 |
|
|
|
|
1,632,074 |
|
|
|
1,582,241 |
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
- |
|
|
|
136,579 |
|
Accumulated
deferred income taxes
|
|
|
210,952 |
|
|
|
169,807 |
|
Retirement
benefits
|
|
|
146,751 |
|
|
|
172,718 |
|
Asset
retirement obligations
|
|
|
88,852 |
|
|
|
87,089 |
|
Power purchase
contract liability
|
|
|
114,164 |
|
|
|
83,600 |
|
Other
|
|
|
62,235 |
|
|
|
63,696 |
|
|
|
|
622,954 |
|
|
|
713,489 |
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
|
|
|
|
$ |
2,835,648 |
|
|
$ |
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)
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
33,511 |
|
|
$ |
39,789 |
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
|
|
|
|
|
Provision for
depreciation
|
|
|
30,036 |
|
|
|
26,434 |
|
Amortization
of regulatory assets, net
|
|
|
26,889 |
|
|
|
31,931 |
|
Deferred costs
recoverable as regulatory assets
|
|
|
(46,349 |
) |
|
|
(13,288 |
) |
Deferred
income taxes and investment tax credits, net
|
|
|
24,700 |
|
|
|
12,760 |
|
Accrued
compensation and retirement benefits
|
|
|
490 |
|
|
|
(16,293 |
) |
Cash
collateral
|
|
|
2 |
|
|
|
301 |
|
Decrease
(increase) in operating assets-
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
42,494 |
|
|
|
(11,082 |
) |
Prepayments
and other current assets
|
|
|
(35,750 |
) |
|
|
(33,370 |
) |
Increase
(decrease) in operating liabilities-
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
(10,108 |
) |
|
|
(9,438 |
) |
Accrued
taxes
|
|
|
(7,629 |
) |
|
|
(11,804 |
) |
Accrued
interest
|
|
|
(1,669 |
) |
|
|
- |
|
Other
|
|
|
2,302 |
|
|
|
9,714 |
|
Net cash
provided from operating activities
|
|
|
58,919 |
|
|
|
25,654 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
45,000 |
|
Short-term
borrowings, net
|
|
|
146,654 |
|
|
|
96,880 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(100,000 |
) |
|
|
(45,320 |
) |
Dividend
Payments-
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
(35,000 |
) |
|
|
(55,000 |
) |
Net cash
provided from financing activities
|
|
|
11,654 |
|
|
|
41,560 |
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(59,606 |
) |
|
|
(57,314 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
63 |
|
|
|
(151 |
) |
Sales of
investment securities held in trust
|
|
|
53,504 |
|
|
|
45,108 |
|
Purchases of
investment securities held in trust
|
|
|
(60,378 |
) |
|
|
(53,537 |
) |
Other
|
|
|
(4,168 |
) |
|
|
(1,328 |
) |
Net cash used
for investing activities
|
|
|
(70,585 |
) |
|
|
(67,222 |
) |
|
|
|
|
|
|
|
|
|
Net decrease
in cash and cash equivalents
|
|
|
(12 |
) |
|
|
(8 |
) |
Cash and cash
equivalents at beginning of period
|
|
|
23 |
|
|
|
46 |
|
Cash and cash
equivalents at end of period
|
|
$ |
11 |
|
|
$ |
38 |
|
|
|
|
|
|
|
|
|
|
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 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 $158 million as of June 30, 2009
(JCP&L - $48 million, Met-Ed - $95 million and Penelec - $15
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 and Penelec. The
following table discloses net regulatory assets by company:
|
|
June
30,
|
|
December
31,
|
|
Increase
|
|
Regulatory
Assets
|
|
2009
|
|
2008
|
|
(Decrease)
|
|
|
|
(In
millions)
|
|
OE
|
|
$
|
514
|
|
$
|
575
|
|
$
|
(61
|
)
|
CEI
|
|
|
628
|
|
|
784
|
|
|
(156
|
)
|
TE
|
|
|
91
|
|
|
109
|
|
|
(18
|
)
|
JCP&L
|
|
|
1,055
|
|
|
1,228
|
|
|
(173
|
)
|
Met-Ed
|
|
|
497
|
|
|
413
|
|
|
84
|
|
Penelec*
|
|
|
10
|
|
|
-
|
|
|
10
|
|
ATSI
|
|
|
|
|
|
|
|
|
|
)
|
Total
|
|
|
|
|
|
|
|
|
|
)
|
*
|
Penelec had
net regulatory liabilities of approximately $137 million
as of
December 31, 2008. 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 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 for the purpose of further
consideration. The PUCO has not yet issued a substantive Entry on
Rehearing.
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, which is
still pending. 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 provided generation service to the Ohio Companies’ retail
customers who chose 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 denied OE’s and TE’s request to continue collecting
RTC and denied the request to allow the Ohio Companies to continue collections
pursuant to the two existing fuel riders. The new fuel rider recovered the
increased purchased power costs for OE and TE, and recovered a portion of those
costs for CEI, with the remainder being deferred 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 provided that generation would 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 would be based upon the outcome of a descending clock CBP on a
slice-of-system basis. The Amended ESP further provided 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
would agree to write-off approximately $216 million of its Extended RTC
balance, and that the Ohio Companies would 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
addressed a number of other issues, including but not limited to, rate design
for various customer classes, and 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, 2009 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 took effect on April 1,
2009 while the remaining provisions took effect on June 1,
2009.
On July 27, 2009,
the Ohio Companies filed applications with the PUCO to recover three different
categories of deferred distribution costs on an accelerated basis. In the Ohio
Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with
collection originally set to begin in January 2011 and to continue over a 5 or
25 year period. The principal amount plus carrying charges through August 31,
2009 for these deferrals is a total of $298.4 million. If the applications are
approved, recovery of this amount, together with carrying charges calculated as
approved in the Amended ESP, will be collected in the 18 non-summer months from
September 2009 through May 2011, subject to reconciliation until fully
collected, with $165 million of the above amount being recovered from
residential customers, and $133.4 million being recovered from non-residential
customers. Pursuant to the applications, customers would pay significantly less
over the life of the recovery of the deferral through the reduction in carrying
charges as compared to the expected recovery under the previously approved
recovery mechanism.
The Ohio Companies
are presently involved in collaborative efforts related to energy efficiency and
a competitive bidding process, together with other implementation efforts
arising out of the Supplemental Stipulation. The CBP auction occurred on
May 13-14, 2009, and resulted in a weighted average wholesale price for
generation and transmission of 6.15 cents per KWH. The bid was for a single,
two-year product for the service period from June 1, 2009 through May 31,
2011. FES participated in the auction, winning 51% of the tranches (one tranche
equals one percent of the load supply). Subsequent to the signing of the
wholesale contracts, two winning bidders reached separate agreements with FES to
assign a total of 11 tranches to FES for various periods. In addition, FES has
separately contracted with numerous communities to provide retail generation
service through governmental aggregation programs.
As a result of the
CBP auction, FES expects to sell less of its generation output to its affiliated
utilities in 2009 and 2010 than it has done historically. By 2011, FES' supply
obligations to its affiliated Pennsylvania utilities expire pursuant to the
terms of the existing partial requirements wholesale power agreement, with all
of its output expected to be subject to market-based generation pricing.
Accordingly, FES continues to focus on expanding its retail opportunities and
has recently increased retail sales to governmental aggregation groups in Ohio
and large industrial customers both inside and outside of Ohio. As of
August 1, 2009, FES has signed 50 government aggregation contracts that
will provide discounted generation prices to approximately 600,000 residential
and small commercial customers. The governmental aggregator may choose between a
graduated or flat percentage discount. When FES' sales to the governmental
aggregation groups are combined with all of its other committed sales, including
its position in the Ohio auction, FES' total generation hedged as a percentage
of forecasted output is expected to be 93% in 2009 and 76% in 2010.
SB221 also requires
electric distribution utilities to implement energy efficiency programs that
achieve a total annual 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 1%,
with an additional seventy-five hundredths of one percent reduction each year
thereafter through 2018. Additionally, electric utilities and electric service
companies are required to serve part of their load from renewable energy
resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has
efforts underway to address compliance with these requirements. Costs associated
with compliance are recoverable from customers.
On June 17, 2009,
the PUCO modified rules that implement the alternative energy portfolio
standards created by SB221, including the incorporation of energy efficiency
requirements, long-term forecast and greenhouse gas reporting and CO2 control
planning. The PUCO filed the rules with the Joint Committee on Agency Rule
Review on July 7, 2009, after which begins a 65-day review period. The Ohio
Companies and one other party filed applications for rehearing on the rules with
the PUCO on July 17, 2009.
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 included a component from
under-recovery of actual transmission costs incurred during the prior period
(Met-Ed - $144 million and Penelec - $4 million) and 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 May 28, 2009, the
PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider 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 resulted
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 increased 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, the PPUC approved Met-Ed’s
proposal to continue to recover the prior period deferrals allowed in the PPUC’s
May 2008 Order and defer $57.5 million of projected costs to a future TSC to be
fully recovered by December 31, 2010. Under this proposal, monthly bills for
Met-Ed’s customers will 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. Act 129 addresses issues
such as: energy efficiency and peak load reduction; generation procurement;
time-of-use rates; smart meters; and alternative energy. 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 prudent 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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utilities must
reduce peak demand by a minimum of 4.5% by May 31,
2013;
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utilities must
reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and
May 31, 2013, respectively; and
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the definition
of Alternative Energy was expanded to include additional types of
hydroelectric and biomass
facilities.
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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. On June 18, 2009, the PPUC issued its
guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec,
and Penn filed Energy Efficiency and Conservation Plans with the PPUC in
accordance with Act 129.
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 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 February 26,
2009, the PPUC approved a Voluntary Prepayment Plan 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 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. On July 30, 2009,
the PPUC entered an order approving the 5-year NUG Statement, approving the
reduction of the CTC, and directing Met-Ed and Penelec to file a tariff
supplement implementing this change. On July 31, 2009, Met-Ed and Penelec
filed tariff supplements decreasing the CTC rate in compliance with the
July 30, 2009 order, and increasing the generation rate in compliance with
the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are
awaiting PPUC action on the July 31, 2009 filings.
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 June 30,
2009, the accumulated deferred cost balance totaled approximately
$149 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.
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, 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
a proposal to spend approximately $98 million on infrastructure and energy
efficiency projects in 2009. Under the proposal, an estimated $40
million would be spent on infrastructure projects, including substation
upgrades, new transformers, distribution line re-closers and automated breaker
operations. Approximately $34 million would be spent implementing new
demand response programs as well as expanding on existing
programs. Another $11 million would be spent on energy efficiency,
specifically replacing transformers and capacitor control systems and installing
new LED street lights. The remaining $13 million would be spent on energy
efficiency programs that would complement those currently being offered.
Implementation of the projects is dependent upon resolution of regulatory issues
including recovery of the costs associated with the proposal.
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. AEP's 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 arguments were
held on April 13, 2009. A decision is expected this summer.
The FERC’s orders on
PJM rate design would 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 would 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 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.
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. 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 discussions. 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; and subsequently, numerous parties filed requests for
rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied
rehearing and request for oral argument of the March 26 Order.
PJM has reconvened
the Capacity Market Evolution Committee to address issues not addressed in the
February 2009 settlement in preparation for September 1, 2009 and December 1,
2009 compliance filings that will recommend more incremental improvements to its
RPM.
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 and FES. This requirement was 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 was implemented as planned on June 1, 2009, the beginning of the MISO
planning year. On June 17, 2009, MISO submitted a compliance filing in
response to the FERC’s April 16, 2009 order directing it to address, among
others, various market monitoring and mitigation issues. On July 8, 2009,
various parties submitted comments on and protests to MISO’s compliance filing.
FirstEnergy submitted comments identifying specific aspects of the MISO’s and
Independent Market Monitor’s proposals for market monitoring and mitigation and
other issues that it believes the FERC should address and clarify.
FES Sales to Affiliates
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 a December 23,
2008 waiver of restrictions on affiliate sales without prior approval of the
FERC.
On May 13-14, 2009,
the Ohio Companies held an auction to secure generation supply for their PLR
obligation. The results of the auction were accepted by the PUCO on May 14,
2009. Twelve bidders qualified to participate in the auction with nine
successful bidders each securing a portion of the Ohio Companies' total supply
needs. FES was the successful bidder for 51 tranches, and subsequently purchased
11 additional tranches from other bidders. The auction resulted in an overall
weighted average wholesale price of 6.15 cents per KWH for generation and
transmission. The new prices for PLR service went into effect with usage
beginning June 1, 2009, and continuing through May 31, 2011.
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 approximately two-thirds of those
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,
under a Cooperative Agreement with the Agency for Toxic Substances and Disease
Registry, completed a Health Consultation regarding the Mansfield Plant and
issued a report dated March 31, 2009 which concluded there is insufficient
sampling data to determine if any public health threat exists for area residents
due to emissions from the Mansfield Plant. The report recommended additional air
monitoring and sample analysis in the vicinity of the Mansfield Plant which the
Pennsylvania Department of Environmental Protection is currently
conducting.
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. On October 30, 2008, the state of
Connecticut filed a Motion to Intervene, which the Court granted on March 24,
2009. Specifically, Connecticut and New Jersey allege 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 seek injunctive relief, penalties, attorney fees and mitigation of
the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation
to and from Sithe Energy is disputed. 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 and Connecticut’s
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 1,
2009, the Court held oral argument on Met-Ed’s motion to dismiss the
complaint.
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 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 2.5 million tons annually and NOX emissions
to 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. On July 10, 2009,
the United States Court of Appeals for the District of Columbia ruled in a
different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,”
cannot be used to satisfy certain CAA requirements (known as reasonably
available control technology) for areas in non-attainment under the "8-hour"
ozone NAAQS. FGCO's 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 any future regulations 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, by 2012, the amount
of man-made GHG, including CO2, emitted
by developed countries. The United States signed the Kyoto Protocol in 1998 but
it was never submitted for ratification by the United States Senate. 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 used in the United States comes from renewable sources by
2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade
program to reduce GHG emissions by 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 House of
Representatives passed one such bill, the American Clean Energy and Security Act
of 2009, on June 26, 2009. 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. In March and June 2009, the EPA requested
information from FGCO’s Bruce Mansfield Plant regarding the management of coal
combustion wastes. FGCO's future cost of compliance with any coal combustion
waste regulations which may be promulgated could be substantial and would
depend, in part, on the regulatory action taken by the EPA and implementation by
the states.
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 June 30, 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 $104 million (JCP&L
- $77 million, TE - $1 million, CEI - $1 million and FirstEnergy
Corp. - $25 million) have been accrued through June 30, 2009. Included in
the total are accrued liabilities of approximately $68 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. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages due to the outages.
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. On March 31, 2009, the
trial court again granted JCP&L’s motion to decertify the class. On April
20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory
appeal to the trial court's decision to decertify the class, which was granted
by the Appellate Division on June 15, 2009. According to the scheduling order
issued by the Appellate Division, Plaintiffs' opening brief is due on August 25,
2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs'
reply is due on October 5, 2009.
Nuclear Plant
Matters (Applicable to FES)
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
June 8, 2009, the NRC issued the final Safety Evaluation Report (SER)
supporting the renewed license for Beaver Valley Units 1 and 2. On July 8,
2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public
meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved
questions raised by a letter from Citizens Power regarding the extent of
corrective actions for the 2009 discovery of a penetration in the Beaver Valley
Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC
further clarifications on the supplemental volumetric examinations of
Beaver Valley’s containment liners. FENOC anticipates another meeting with
the ACRS regarding the container liner during September 2009. FENOC will
continue to work with the NRC Staff as it completes its environmental and
technical reviews of the license renewal application, and is scheduled 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.
Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had
approximately $1.7 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 provided an additional $80 million parental guarantee
associated with the funding of decommissioning costs for these units and
indicated that it planned to contribute an additional $80 million to these
trusts by 2010. As required by the NRC, FirstEnergy annually
recalculates and adjusts the amount of its parental guarantee, as appropriate.
The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on
market conditions. If the value of the trusts decline by a material amount,
FirstEnergy’s obligations to fund the trusts may increase. The recent disruption
in the capital markets and its effects on particular businesses and the economy
in general also affects the values of the nuclear decommission trusts. On June
18, 2009, the NRC informed FENOC that its review tentatively concluded that a
shortfall ($147.5 million net present value) existed in the value of the
decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC
submitted a letter to the NRC that stated reasonable assurance of
decommissioning funding is provided for Beaver Valley Unit 1 through a
combination of the existing trust fund balances, the existing $80 million
parental guarantee from FirstEnergy and maintaining the plant in a safe-store
configuration, or extended safe shutdown condition, after plant shutdown.
Renewal of the operating license for Beaver Valley Unit 1, as described above,
would mitigate the estimated shortfall in the unit’s nuclear decommissioning
funding status. FENOC continues to communicate with the NRC regarding
future actions to provide reasonable assurance for decommissioning funding. Such
actions may include additional parental guarantees or contributions to those
funds.
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 bargaining unit
employees at the Bruce Mansfield Plant have been working without a labor
contract since February 15, 2008. On July 24,
2009, FirstEnergy declared that bargaining was at an impasse and portions of its
last contract offer were implemented August 1, 2009. A federal
mediator is continuing to assist the parties in reaching a negotiated contract
settlement. FirstEnergy has a strike mitigation plan ready in the event
of a strike.
On May 21, 2009, 517
Penelec employees, represented by the International Brotherhood of Electrical
Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009,
Penelec implemented its work-continuation plan to use nearly 400 non-represented
employees with previous line experience and training drawn from Penelec and
other FirstEnergy operations to perform service reliability and priority
maintenance work in Penelec’s service territory. Penelec's IBEW Local 459
employees ratified a three-year contract agreement on July 19, 2009, and
returned to work on July 20, 2009.
On June 26, 2009,
FirstEnergy announced that seven of its union locals, representing about 2,600
employees, have ratified contract extensions. These unions include employees
from Penelec, Penn, CEI, OE and TE, along with certain power plant
employees.
On July 8, 2009,
FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777
ratified a two-year contract. Union members had been working without a contract
since the previous agreement expired on April 30, 2009.
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 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 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.
SFAS
166 – “Accounting for Transfers of Financial Assets – an amendment of FASB
Statement No. 140”
In June 2009, the
FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and
eliminates the concept of a qualifying special-purpose entity (QSPE). It removes
the exception from applying FIN 46R to QSPEs and requires an evaluation of all
existing QSPEs to determine whether they must be consolidated in accordance with
SFAS 167. This Statement is effective for financial asset transfers that occur
in fiscal years beginning after November 15, 2009. FES and the Utilities do not
expect this Standard to have a material effect upon their financial
statements.
SFAS 167 – “Amendments to FASB
Interpretation No. 46(R)”
In June 2009, the
FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs.
This Statement replaces the quantitative approach previously required to
determine which entity has a controlling financial interest in a VIE with a
qualitative approach. Under the new approach, the primary beneficiary of a VIE
is the entity that has both (a) the power to direct the activities of the VIE
that most significantly impact the entity’s economic performance, and (b) the
obligation to absorb losses of the entity, or the right to receive benefits from
the entity, that could be significant to the VIE. SFAS 167 also requires
ongoing reassessments of whether an entity is the primary beneficiary of a VIE
and enhanced disclosures about an entity’s involvement in VIEs. This Statement
is effective for fiscal years beginning after November 15, 2009. FES and the
Utilities are currently evaluating the impact of adopting this Standard on their
financial statements.
SFAS 168 – “The FASB
Accounting Standards CodificationTM and the Hierarchy of Generally
Accepted Accounting Principles – a replacement of FASB Statement No.
162”
In June 2009, the
FASB issued SFAS 168, which recognizes the FASB Accounting Standards
CodificationTM
(Codification) as the source of authoritative GAAP. It also recognizes that
rules and interpretative releases of the SEC under federal securities laws are
sources of authoritative GAAP for SEC registrants. The Codification supersedes
all non-SEC accounting and reporting standards. This Statement is effective for
financial statements issued for interim and annual periods ending after
September 15, 2009. This Statement will change how FES and the Utilities
reference GAAP in their financial statement disclosures.
Debt
Capacity and Financing Activities (Applicable to FES and
each of the Utilities)
Long-Term Debt Capacity
As of June 30, 2009,
the Ohio Companies and Penn had the aggregate capability to issue approximately
$2.3 billion of additional FMBs on the basis of property additions and
retired bonds under the terms of their respective mortgage indentures. 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 and CEI
to incur additional secured debt not otherwise permitted by a specified
exception of up to $167 million and $175 million, respectively, as of
June 30, 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. As a result, the
provisions for TE to incur additional secured debt do not apply.
Based upon FGCO's
FMB indenture, net earnings and available bondable property additions as of
June 30, 2009, FGCO had the capability to issue $2.2 billion of
additional FMBs under the terms of that indenture. On June 16, 2009, FGCO
issued a total of approximately $395.9 million in principal amount of FMBs, of
which $247.7 million related to three new refunding series of PCRBs and
approximately $148.2 million related to amendments to existing letter of credit
and reimbursement agreements supporting two other series of PCRBs. On June 30,
2009, FGCO issued a total of approximately $52.1 million in principal
amount of FMBs related to three existing series of PCRBs.
In June 2009, a new
FMB indenture was put in place for NGC. Based upon NGC’s FMB indenture, net
earnings and available bondable property additions, NGC had the capability to
issue $264 million of additional FMBs as of June 30, 2009. On June 16,
2009, NGC issued a total of approximately $487.5 million in principal
amount of FMBs, of which $107.5 million related to one new refunding series of
PCRBs and approximately $380 million related to amendments to existing letter of
credit and reimbursement agreements supporting seven other series of PCRBs. In
addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to
$500 million in connection with its guaranty of FES’ obligations to post
and maintain collateral under the Power Supply Agreement entered into by FES
with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On
June 30, 2009, NGC issued a total of approximately $273.3 million in
principal amount of FMBs, of which approximately $92 million related to
three existing series of PCRBs and approximately $181.3 million related to
amendments to existing letter of credit and reimbursement agreements supporting
three other series of PCRBs.
Met-Ed and Penelec
had the capability to issue secured debt of approximately $428 million and
$310 million, respectively, under provisions of their senior note
indentures as of June 30, 2009.
FES' and the
Utilities’ access to capital markets and costs of financing are influenced by
the ratings of their securities and those of FirstEnergy. The following table
displays FirstEnergy's, FES' and the Utilities' securities ratings as of
June 30, 2009. On June 17, 2009, Moody's affirmed FirstEnergy’s Baa3
and FES' Baa2 credit ratings. On July 9, 2009, S&P affirmed its ratings
on FirstEnergy and its subsidiaries. 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. On
July 29, 2009, FES registered its common stock pursuant to Section 12(g) of
the Securities Exchange Act of 1934.
Pollution Control Revenue
Bonds
As of June 30, 2009,
FES’, Met-Ed’s and Penelec’s currently payable long-term debt included
$1.5 billion, $29 million and $45 million, respectively, 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.
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.
During the second quarter of 2009, NGC remarketed the remaining
$334 million of PCRBs, of which $170 million was remarketed in fixed
interest rate modes and secured by FMBs, thereby eliminating the need for
third-party credit support. During the second quarter of 2009, FGCO remarketed
approximately $248 million of PCRBs supported by LOCs set to expire in June
2009. These PCRBs were remarketed in fixed interest rate modes and secured by
FMBs, thereby eliminating the need for third-party credit support. Also, in June
2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in
connection with amendments to existing letter of credit and reimbursement
agreements supporting 12 other series of PCRBs as described above and
pledged FMBs to the applicable trustee under six separate series of
PCRBs.
Financing Activities
The following table
summarizes new debt issuances (excluding PCRB issuances and refinancings) during
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Met-Ed*
|
|
01/20/2009
|
|
$300
|
|
7.70% Senior
Notes
|
|
2019
|
|
Repay
short-term borrowings
|
|
|
|
|
|
|
|
|
|
|
|
JCP&L*
|
|
01/27/2009
|
|
$300
|
|
7.35% Senior
Notes
|
|
2019
|
|
Repay
short-term borrowings, fund capital expenditures and other general
purposes
|
|
|
|
|
|
|
|
|
|
|
|
TE*
|
|
04/24/2009
|
|
$300
|
|
7.25% Senior
Secured
Notes
|
|
2020
|
|
Repay
short-term borrowings, fund capital expenditures and other general
purposes
|
|
|
|
|
|
|
|
|
|
|
|
Penn
|
|
06/30/2009
|
|
$100
|
|
6.09%
FMB
|
|
2022
|
|
Fund capital
expenditures and repurchase equity from OE
|
|
|
|
|
|
|
|
|
|
|
|
* Issuance was
sold off the shelf registration statement referenced
above.
|
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. In preparing the financial statements,
FirstEnergy and its subsidiaries have evaluated events and transactions for
potential recognition or disclosure through August 3, 2009, the date the
financial statements were issued.
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 June 30, 2009 and for the three-month and
six-month periods ended June 30, 2009 and 2008, have been reviewed by
PricewaterhouseCoopers LLP, an independent registered public accounting firm.
Their report (dated August 3, 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 are computed using the weighted average of actual common
shares outstanding during the respective period as the denominator. The
denominator for diluted earnings per share 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:
|
|
Three
Months
|
|
Six
Months
|
|
Reconciliation
of Basic and Diluted Earnings per Share
|
|
|
|
|
|
of
Common Stock
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
(In
millions, except per share amounts)
|
|
Earnings
available to FirstEnergy Corp.
|
|
$
|
414
|
|
$
|
263
|
|
$
|
533
|
|
$
|
539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares
of common stock outstanding - Basic
|
|
|
304
|
|
|
304
|
|
|
304
|
|
|
304
|
|
Assumed
exercise of dilutive stock options and awards
|
|
|
1
|
|
|
3
|
|
|
2
|
|
|
3
|
|
Average shares
of common stock outstanding - Diluted
|
|
|
305
|
|
|
307
|
|
|
306
|
|
|
307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings
per share of common stock
|
|
$
|
1.36
|
|
$
|
0.86
|
|
$
|
1.75
|
|
$
|
1.77
|
|
Diluted
earnings per share of common stock
|
|
$
|
1.36
|
|
$
|
0.85
|
|
$
|
1.75
|
|
$
|
1.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings in the
second quarter of 2009 include a gain of $254 million ($0.52 per share) from the
sale of FirstEnergy’s nine percent interest in the stock and output of
OVEC.
3.
FAIR VALUE OF FINANCIAL INSTRUMENTS
(A)
|
LONG-TERM
DEBT AND OTHER LONG-TERM
OBLIGATIONS
|
All borrowings with
initial maturities of less than one year are defined as short-term financial
instruments under GAAP and are reported on the Consolidated Balance Sheets at
cost, which approximates their fair market value, in the caption "short-term
borrowings." The following table provides the approximate fair value and related
carrying amounts of long-term debt and other long-term obligations as of
June 30, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair values of
long-term debt and other long-term obligations reflect the present value of the
cash outflows relating to those securities based on the current call price, the
yield to maturity or the yield to call, as deemed appropriate at the end of each
respective period. The yields assumed were based on securities with similar
characteristics offered by corporations with credit ratings similar to those of
FES and the Utilities.
All temporary cash
investments purchased with an initial maturity of three months or less are
reported as cash equivalents on the Consolidated Balance Sheets at cost, which
approximates their fair market value. Investments other than cash and cash
equivalents include held-to-maturity securities and available-for-sale
securities.
FES and the
Utilities periodically evaluate their investments for other-than-temporary
impairment. They first consider their intent and ability to hold an equity
investment until recovery and then consider, among other factors, the duration
and the extent to which the security's fair value has been less than cost and
the near-term financial prospects of the security issuer when evaluating an
investment for impairment. For debt securities, in accordance with FSP FAS 115-2
and FAS 124-2, FES and the Utilities consider their intent to hold the security,
the likelihood that they will be required to sell the security before recovery
of its cost basis, and the likelihood of recovery of the security's entire
amortized cost basis.
Available-For-Sale
Securities
FES and the
Utilities hold debt and equity securities within their nuclear decommissioning
trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are
classified as available-for-sale with the fair value representing quoted market
prices. FES and the Utilities have no securities held for trading
purposes.
The following table
summarizes the amortized cost basis, unrealized gains and losses and fair values
of investments in available-for-sale securities as of June 30, 2009 and December
31, 2008:
|
|
June 30, 2009(1)
|
|
December 31, 2008(2)
|
|
|
|
Cost
|
|
Unrealized
|
|
Unrealized
|
|
Fair
|
|
Cost
|
|
Unrealized
|
|
Unrealized
|
|
Fair
|
|
|
|
Basis
|
|
Gains
|
|
Losses
|
|
Value
|
|
Basis
|
|
Gains
|
|
Losses
|
|
Value
|
|
Debt
securities
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Excludes cash balances of $231 million at FirstEnergy,
$209 million at FES, $14 million at JCP&L, $4 million
at OE, $3 million at Penelec and $1 million at
TE.
(2)
Excludes cash balances of $244 million at FirstEnergy,
$225 million at FES, $12 million at Penelec, $4 million at
OE and $1 million at Met-Ed.
(3)
Includes fair values as of June 30, 2009 and December 31, 2008 of
$982 million and $953 million of government obligations,
$238 million and $175 million of corporate debt and
$5 million and $6 million of mortgage backed
securities.
|
Proceeds from the
sale of investments in available-for-sale securities, realized gains and losses
on those sales, and interest and dividend income as of June 30, 2009 were
as follows:
|
|
FirstEnergy
|
|
FES
|
|
OE
|
|
TE
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
|
|
(In
millions)
|
|
|
|
$
|
1,001
|
|
$
|
537
|
|
$
|
25
|
|
$
|
77
|
|
$
|
245
|
|
$
|
63
|
|
$
|
54
|
|
|
|
|
30
|
|
|
24
|
|
|
-
|
|
|
3
|
|
|
3
|
|
|
1
|
|
|
-
|
|
|
|
|
91
|
|
|
58
|
|
|
3
|
|
|
-
|
|
|
11
|
|
|
12
|
|
|
7
|
|
Interest and
dividend income
|
|
|
30
|
|
|
14
|
|
|
2
|
|
|
1
|
|
|
7
|
|
|
3
|
|
|
3
|
|
Unrealized gains
applicable to the decommissioning trusts of OE, TE and FES are recognized in OCI
in accordance with SFAS 115, as fluctuations in fair value will eventually
impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are
subject to regulatory accounting in accordance with SFAS 71. Net unrealized
gains and losses are 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.
The investment
policy for the nuclear decommissioning trust funds restricts or limits the
ability to hold certain types of assets including private or direct placements,
warrants, securities of FirstEnergy, investments in companies owning nuclear
power plants, financial derivatives, preferred stocks, securities convertible
into common stock and securities of the trust fund's custodian or managers and
their parents or subsidiaries.
Held-To-Maturity
Securities
The following table
provides the amortized cost basis, unrealized gains and losses, and approximate
fair values of investments in held-to-maturity securities except for investments
of $271 million and $293 million excluded by SFAS 107 as of
June 30, 2009 and December 31, 2008:
|
|
June
30, 2009
|
|
December
31, 2008
|
|
|
|
Cost
|
|
Unrealized
|
|
Unrealized
|
|
Fair
|
|
Cost
|
|
Unrealized
|
|
Unrealized
|
|
Fair
|
|
|
|
Basis
|
|
Gains
|
|
Losses
|
|
Value
|
|
Basis
|
|
Gains
|
|
Losses
|
|
Value
|
|
Debt
securities
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
provides the approximate fair value and related carrying amounts of notes
receivable as of June 30, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
|
|
|
|
|
|
|
|
|
Notes
receivable
|
|
(In
millions)
|
|
FirstEnergy
|
|
$
|
40
|
|
$
|
38
|
|
$
|
45
|
|
$
|
44
|
|
FES
|
|
|
6
|
|
|
6
|
|
|
75
|
|
|
74
|
|
OE
|
|
|
193
|
|
|
233
|
|
|
257
|
|
|
294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of
notes receivable represents the present value of the cash inflows based on the
yield to maturity. The yields assumed were based on financial instruments with
similar characteristics and terms. The maturity dates range from 2009 to
2040.
(C)
|
RECURRING
FAIR VALUE MEASUREMENTS
|
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 on Form 10-K for the
year ended December 31, 2008.
The following tables
set forth financial assets and financial liabilities that are accounted for at
fair value by level within the fair value hierarchy as of June 30, 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 June 30,
2009
|
|
|
Level
1 -
Assets (In
millions)
|
|
|
Level
1 - Liabilities
|
|
|
Derivatives
|
|
Available-for-Sale
Securities(1)
|
|
Other
Investments
|
|
Total
|
|
|
Derivatives
|
|
NUG
Contracts(2)
|
|
Total
|
FirstEnergy
|
$
|
1
|
$
|
495
|
$
|
-
|
$
|
496
|
|
$
|
19
|
$
|
-
|
$
|
19
|
FES
|
|
1
|
|
237
|
|
-
|
|
238
|
|
|
19
|
|
-
|
|
19
|
OE
|
|
-
|
|
18
|
|
-
|
|
18
|
|
|
-
|
|
-
|
|
-
|
JCP&L
|
|
-
|
|
70
|
|
-
|
|
70
|
|
|
-
|
|
-
|
|
-
|
Met-Ed
|
|
-
|
|
109
|
|
-
|
|
109
|
|
|
-
|
|
-
|
|
-
|
Penelec
|
|
-
|
|
61
|
|
-
|
|
61
|
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
2 - Assets
|
|
|
Level
2 - Liabilities
|
|
|
Derivatives
|
|
Available-for-Sale
Securities(1)
|
|
Other
Investments
|
|
Total
|
|
|
Derivatives
|
|
NUG
Contracts(2)
|
|
Total
|
FirstEnergy
|
$
|
41
|
$
|
1,547
|
$
|
84
|
$
|
1,672
|
|
$
|
19
|
$
|
-
|
$
|
19
|
FES
|
|
21
|
|
800
|
|
-
|
|
821
|
|
|
15
|
|
-
|
|
15
|
OE
|
|
-
|
|
98
|
|
-
|
|
98
|
|
|
-
|
|
-
|
|
-
|
TE
|
|
-
|
|
73
|
|
-
|
|
73
|
|
|
-
|
|
-
|
|
-
|
JCP&L
|
|
5
|
|
270
|
|
-
|
|
275
|
|
|
-
|
|
-
|
|
-
|
Met-Ed
|
|
9
|
|
126
|
|
-
|
|
135
|
|
|
-
|
|
-
|
|
-
|
Penelec
|
|
5
|
|
179
|
|
-
|
|
184
|
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
3 - Assets
|
|
|
Level
3 - Liabilities
|
|
|
Derivatives
|
|
Available-for-Sale
Securities(1)
|
|
NUG
Contracts(2)
|
|
Total
|
|
|
Derivatives
|
|
NUG
Contracts(2)
|
|
Total
|
FirstEnergy
|
$
|
-
|
$
|
-
|
$
|
214
|
$
|
214
|
|
$
|
-
|
$
|
750
|
$
|
750
|
JCP&L
|
|
-
|
|
-
|
|
9
|
|
9
|
|
|
-
|
|
475
|
|
475
|
Met-Ed
|
|
-
|
|
-
|
|
184
|
|
184
|
|
|
-
|
|
161
|
|
161
|
Penelec
|
|
-
|
|
-
|
|
21
|
|
21
|
|
|
-
|
|
114
|
|
114
|
|
(1)
|
Consists of
investments in the nuclear decommissioning trusts, the spent nuclear fuel
trusts and the NUG trusts. Balance
excludes
$2 million of receivables, payables and accrued
income.
|
(2) NUG
contracts are completely offset by regulatory assets and do not impact
earnings.
Recurring Fair Value Measures as of December 31,
2008
|
|
|
Level
1 –
Assets (In
millions)
|
|
|
Level
1 - Liabilities
|
|
|
Derivatives
|
|
Available-for-Sale
Securities(1)
|
|
Other
Investments
|
|
Total
|
|
|
Derivatives
|
|
NUG
Contracts(2)
|
|
Total
|
FirstEnergy
|
$
|
-
|
$
|
537
|
$
|
-
|
$
|
537
|
|
$
|
25
|
$
|
-
|
$
|
25
|
FES
|
|
-
|
|
290
|
|
-
|
|
290
|
|
|
25
|
|
-
|
|
25
|
OE
|
|
-
|
|
18
|
|
-
|
|
18
|
|
|
-
|
|
-
|
|
-
|
JCP&L
|
|
-
|
|
67
|
|
-
|
|
67
|
|
|
-
|
|
-
|
|
-
|
Met-Ed
|
|
-
|
|
104
|
|
-
|
|
104
|
|
|
-
|
|
-
|
|
-
|
Penelec
|
|
-
|
|
58
|
|
-
|
|
58
|
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
2 - Assets
|
|
|
Level
2 - Liabilities
|
|
|
Derivatives
|
|
Available-for-Sale
Securities(1)
|
|
Other
Investments
|
|
Total
|
|
|
Derivatives
|
|
NUG
Contracts(2)
|
|
Total
|
FirstEnergy
|
$
|
40
|
$
|
1,464
|
$
|
83
|
$
|
1,587
|
|
$
|
31
|
$
|
-
|
$
|
31
|
FES
|
|
12
|
|
744
|
|
-
|
|
756
|
|
|
28
|
|
-
|
|
28
|
OE
|
|
-
|
|
98
|
|
-
|
|
98
|
|
|
-
|
|
-
|
|
-
|
TE
|
|
-
|
|
73
|
|
-
|
|
73
|
|
|
-
|
|
-
|
|
-
|
JCP&L
|
|
7
|
|
255
|
|
-
|
|
262
|
|
|
-
|
|
-
|
|
-
|
Met-Ed
|
|
14
|
|
121
|
|
-
|
|
135
|
|
|
-
|
|
-
|
|
-
|
Penelec
|
|
7
|
|
174
|
|
-
|
|
181
|
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level
3 - Assets
|
|
|
Level
3 - Liabilities
|
|
|
Derivatives
|
|
Available-for-Sale
Securities(1)
|
|
NUG
Contracts(2)
|
|
Total
|
|
|
Derivatives
|
|
NUG
Contracts(2)
|
|
Total
|
FirstEnergy
|
$
|
-
|
$
|
-
|
$
|
434
|
$
|
434
|
|
$
|
-
|
$
|
766
|
$
|
766
|
JCP&L
|
|
-
|
|
-
|
|
14
|
|
14
|
|
|
-
|
|
532
|
|
532
|
Met-Ed
|
|
-
|
|
-
|
|
300
|
|
300
|
|
|
-
|
|
150
|
|
150
|
Penelec
|
|
-
|
|
-
|
|
120
|
|
120
|
|
|
-
|
|
84
|
|
84
|
|
(1)
|
Consists of
investments in the 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 and do not impact
earnings.
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 tables
set forth a reconciliation of changes in the fair value of NUG contracts
classified as Level 3 in the fair value hierarchy for the three and six months
ended June 30, 2009 and 2008 (in millions):
|
|
FirstEnergy
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
Balance as of
January 1, 2009
|
|
$
|
(332
|
)
|
$
|
(518
|
)
|
$
|
150
|
|
$
|
36
|
|
Settlements(1)
|
|
|
179
|
|
|
90
|
|
|
43
|
|
|
47
|
|
Unrealized
gains (losses)(1)
|
|
|
(383
|
)
|
|
(38
|
)
|
|
(170
|
)
|
|
(176
|
)
|
Net
transfers to (from) Level 3
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance as of
June 30, 2009
|
|
$
|
(536
|
)
|
$
|
(466
|
)
|
$
|
23
|
|
$
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
unrealized gains (losses) relating to instruments held as of
June 30, 2009
|
|
$
|
(383
|
)
|
$
|
(38
|
)
|
$
|
(170
|
)
|
$
|
(176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of
April 1, 2009
|
|
$
|
(476
|
)
|
$
|
(518
|
)
|
$
|
76
|
|
$
|
(34
|
)
|
Settlements(1)
|
|
|
96
|
|
|
44
|
|
|
26
|
|
|
27
|
|
Unrealized
gains (losses)(1)
|
|
|
(156
|
)
|
|
8
|
|
|
(79
|
)
|
|
(86
|
)
|
Net
transfers to (from) Level 3
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance as of
June 30, 2009
|
|
$
|
(536
|
)
|
$
|
(466
|
)
|
$
|
23
|
|
$
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
unrealized gains (losses) relating to instruments held as of June 30,
2009
|
|
$
|
(156
|
)
|
$
|
8
|
|
$
|
(79
|
)
|
$
|
(86
|
)
|
|
|
FirstEnergy
|
|
JCP&L
|
|
Met-Ed
|
|
Penelec
|
|
Balance as of
January 1, 2008
|
|
$
|
(803
|
)
|
$
|
(750
|
)
|
$
|
(28
|
)
|
$
|
(25
|
)
|
Settlements(1)
|
|
|
110
|
|
|
95
|
|
|
2
|
|
|
13
|
|
Unrealized
gains (losses)(1)
|
|
|
676
|
|
|
11
|
|
|
376
|
|
|
290
|
|
Net
transfers to (from) Level 3
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance as of
June 30, 2008
|
|
$
|
(17
|
)
|
$
|
(644
|
)
|
$
|
350
|
|
$
|
278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
unrealized gains (losses) relating to instruments held as of
June 30, 2008
|
|
$
|
676
|
|
$
|
11
|
|
$
|
376
|
|
$
|
290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of
April 1, 2008
|
|
$
|
(419
|
)
|
$
|
(682
|
)
|
$
|
145
|
|
$
|
119
|
|
Settlements(1)
|
|
|
46
|
|
|
45
|
|
|
(3
|
)
|
|
5
|
|
Unrealized
gains (losses)(1)
|
|
|
356
|
|
|
(7
|
)
|
|
208
|
|
|
154
|
|
Net
transfers to (from) Level 3
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Balance as of
June 30, 2008
|
|
$
|
(17
|
)
|
$
|
(644
|
)
|
$
|
350
|
|
$
|
278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
unrealized gains (losses) relating to instruments held as of June 30,
2008
|
|
$
|
356
|
|
$
|
(7
|
)
|
$
|
208
|
|
$
|
154
|
|
(1) Changes
in 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 Sheets 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 $300 million
to hedge against changes in associated interest rates. Hedges with a notional
value of $100 million expire in November 2009 and $100 million expire
in November 2010. The swaps are accounted for as cash flow hedges under SFAS
133. As of June 30, 2009, the fair value of outstanding swaps was
$(3) 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 six months 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.
As of June 30,
2009 and December 31, 2008, the fair value of outstanding interest rate
derivatives was $(3) million. Interest rate derivatives are included in
"Other Noncurrent Liabilities" on FirstEnergy’s consolidated balance sheets. The
effect of interest rate derivatives on the consolidated statements of income and
comprehensive income during the three months and six months ended June 30,
2009 and 2008 were:
|
|
|
Three
Months
|
|
Six
Months
|
|
|
|
|
Ended
June 30
|
|
Ended
June 30
|
|
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
|
(In
millions)
|
|
Effective
Portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
Recognized in AOCL
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
|
Loss
Reclassified from AOCL into Interest Expense
|
|
|
(6
|
)
|
|
(3
|
)
|
|
(11
|
)
|
|
(7
|
)
|
Ineffective
Portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
Recognized in Interest Expense
|
|
|
-
|
|
|
(4
|
)
|
|
-
|
|
|
(5
|
)
|
Total unamortized
losses included in AOCL associated with prior interest rate hedges totaled
$113 million ($68 million net of tax) as of June 30, 2009. Based
on current estimates, approximately $9 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
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
June
30,
|
|
December
31,
|
|
|
|
2009
|
|
2008
|
|
|
|
2009
|
|
2008
|
Cash
Flow Hedges
|
|
(In
millions)
|
|
Cash
Flow Hedges
|
|
(In
millions)
|
Electricity
Forwards
|
|
|
|
|
|
Electricity
Forwards
|
|
|
|
|
|
Current
Assets
|
$
|
21
|
$
|
11
|
|
|
Current
Liabilities
|
$
|
15
|
$
|
27
|
Natural Gas
Futures
|
|
|
|
|
|
Natural Gas
Futures
|
|
|
|
|
|
Current
Assets
|
|
-
|
|
-
|
|
|
Current
Liabilities
|
|
9
|
|
4
|
|
Long-Term
Deferred Charges
|
|
-
|
|
-
|
|
|
Noncurrent
Liabilities
|
|
3
|
|
5
|
Other
|
|
|
|
|
|
Other
|
|
|
|
|
|
Current
Assets
|
|
-
|
|
-
|
|
|
Current
Liabilities
|
|
7
|
|
12
|
|
Long-Term
Deferred Charges
|
|
-
|
|
-
|
|
|
Noncurrent
Liabilities
|
|
4
|
|
4
|
|
|
$
|
21
|
$
|
11
|
|
|
$
|
38
|
$
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Assets
|
|
Derivative
Liabilities
|
|
|
|
Fair
Value
|
|
|
|
Fair
Value
|
|
|
|
June
30, 2009
|
|
December
31,
2008
|
|
|
|
June
30, 2009
|
|
December
31,
2008
|
Economic
Hedges
|
|
(In
millions)
|
|
Economic
Hedges
|
|
(In
millions)
|
NUG
Contracts
|
|
|
|
NUG
Contracts
|
|
|
|
Power
Purchase
|
|
|
|
|
|
|
Power
Purchase
|
|
|
|
|
|
Contract
Asset
|
$
|
214
|
$
|
434
|
|
|
Contract
Liability
|
$
|
750
|
$
|
766
|
Other
|
|
|
|
|
|
Other
|
|
|
|
|
|
Current
Assets
|
|
2
|
|
1
|
|
|
Current
Liabilities
|
|
-
|
|
1
|
|
Long-Term
Deferred Charges
|
|
19
|
|
28
|
|
|
Noncurrent
Liabilities
|
|
-
|
|
-
|
|
|
$
|
235
|
$
|
463
|
|
|
$
|
750
|
$
|
767
|
Total
Commodity Derivatives
|
$
|
256
|
$
|
474
|
|
Total
Commodity Derivatives
|
$
|
788
|
$
|
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 June 30, 2009.
|
Purchases
|
|
Sales
|
|
Net
|
|
|
Units
|
|
|
(In
thousands)
|
|
Electricity
Forwards
|
|
471
|
|
|
(3,735
|
)
|
|
(3,264
|
)
|
|
MWH
|
|
Heating Oil
Futures
|
|
13,188
|
|
|
(1,260
|
)
|
|
11,928
|
|
|
Gallons
|
|
Natural Gas
Futures
|
|
3,850
|
|
|
-
|
|
|
3,850
|
|
|
mmBtu
|
|
The effect of
derivative instruments on the consolidated statements of income and
comprehensive income for the three and six months ended June 30, 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
|
|
Three
Months Ended June 30, 2009
|
|
(in
millions)
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$
|
6
|
|
$
|
-
|
|
$
|
2
|
|
$
|
8
|
|
Effective Gain
(Loss) Reclassified to:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power Expense
|
|
1
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
Fuel
Expense
|
|
-
|
|
|
(4
|
)
|
|
(4
|
)
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$
|
4
|
|
$
|
(7
|
)
|
$
|
1
|
|
$
|
(2
|
)
|
Effective Gain
(Loss) Reclassified to:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power Expense
|
|
(17
|
)
|
|
-
|
|
|
-
|
|
|
(17
|
)
|
|
Fuel
Expense
|
|
-
|
|
|
(4
|
)
|
|
(8
|
)
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$
|
(16
|
)
|
$
|
3
|
|
$
|
-
|
|
$
|
(13
|
)
|
Effective Gain
(Loss) Reclassified to:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power Expense
|
|
4
|
|
|
-
|
|
|
-
|
|
|
4
|
|
|
Fuel
Expense
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$
|
(30
|
)
|
$
|
6
|
|
$
|
-
|
|
$
|
(24
|
)
|
Effective Gain
(Loss) Reclassified to:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power Expense
|
|
(13
|
)
|
|
-
|
|
|
-
|
|
|
(13
|
)
|
|
Fuel
Expense
|
|
-
|
|
|
1
|
|
|
-
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The ineffective portion was immaterial.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30
|
|
|
Six
Months Ended June 30
|
|
Derivatives
Not in Hedging Relationships
|
|
|
NUG
|
|
|
|
|
|
|
|
|
|
NUG
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
|
|
Other
|
|
|
Total
|
|
|
|
Contracts
|
|
|
Other
|
|
|
Total
|
|
2009
|
|
(In
millions)
|
|
Unrealized
Gain (Loss) Recognized in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
Expense(1)
|
|
$
|
-
|
|
$
|
2
|
|
$
|
2
|
|
|
$
|
-
|
|
$
|
2
|
|
$
|
2
|
|
Regulatory
Assets(2)
|
|
|
(156
|
)
|
|
-
|
|
|
(156
|
)
|
|
|
(383
|
)
|
|
-
|
|
|
(383
|
)
|
|
|
$
|
(156
|
)
|
$
|
2
|
|
$
|
(154
|
)
|
|
$
|
(383
|
)
|
$
|
2
|
|
$
|
(381
|
)
|
Realized Gain
(Loss) Reclassified to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
Expense(1)
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
|
$
|
-
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
Regulatory
Assets(2)
|
|
|
(96
|
)
|
|
-
|
|
|
(96
|
)
|
|
|
(179
|
)
|
|
10
|
|
|
(169
|
)
|
|
|
$
|
(96
|
)
|
$
|
-
|
|
$
|
(96
|
)
|
|
$
|
(179
|
)
|
$
|
9
|
|
$
|
(170
|
)
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
Gain (Loss) Recognized in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
Assets(2)
|
|
$
|
356
|
|
$
|
-
|
|
$
|
356
|
|
|
$
|
676
|
|
$
|
-
|
|
$
|
676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain
(Loss) Reclassified to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
Assets(2)
|
|
$
|
(46
|
)
|
$
|
(1
|
)
|
$
|
(47
|
)
|
|
$
|
(110
|
)
|
$
|
10
|
|
$
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The realized
gain (loss) is reclassified upon termination of the derivative
instrument.
|
|
(2)
|
Changes in the
fair value of NUG contracts are deferred for future recovery from (or
refund to) customers.
|
|
Total unamortized
losses included in AOCL associated with commodity derivatives were
$17 million ($10 million net of tax) as of June 30, 2009, as
compared to $44 million ($27 million net of tax) as of December 31,
2008. The net of tax change resulted from a net $1 million decrease related
to current hedging activity and a $16 million decrease due to net hedge
losses reclassified to earnings during the first six months of 2009. Based on
current estimates, approximately $6 million (after tax) of the net deferred
losses on derivative instruments in AOCL as of June 30, 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
June 30, 2009, FirstEnergy posted $133 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 June 30, 2009 was $1 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 $19 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.
On June 2, 2009,
FirstEnergy amended its health care benefits plan (Plan) for all employees and
retirees eligible to participate in the Plan. The Plan amendment, which reduces
future health care coverage subsidies paid by FirstEnergy on behalf of
participants, triggered a remeasurement of FirstEnergy’s other postretirement
benefit plans as of May 31, 2009. As a result of the remeasurement, the
Plan’s discount rate was revised to 7.5% while the expected long-term rate of
return on assets remained at 9%. The remeasurement and Plan amendment increased
FirstEnergy’s accumulated other comprehensive income by $449 million in the
second quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit
cost (including amounts capitalized) for the remainder of 2009 by
$48 million, including a $7 million reduction that is applicable to the
second quarter of 2009.
FirstEnergy’s net
pension and OPEB expenses (benefits) for the three months ended June 30, 2009
and 2008 were $38 million and $(15) million, respectively. For the six
months ended June 30, 2009 and 2008, FirstEnergy’s net pension and OPEB expenses
(benefits) were $80 million and $(29) million, respectively. The components
of FirstEnergy's net pension and other postretirement benefit costs (including
amounts capitalized) for the three months and six months ended June 30,
2009 and 2008, consisted of the following:
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
Ended
June 30
|
|
Pension
Benefits
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
22
|
|
$
|
22
|
|
$
|
43
|
|
$
|
43
|
|
Interest
cost
|
|
|
80
|
|
|
75
|
|
|
159
|
|
|
150
|
|
Expected
return on plan assets
|
|
|
(81
|
)
|
|
(116
|
)
|
|
(162
|
)
|
|
(231
|
)
|
Amortization
of prior service cost
|
|
|
3
|
|
|
3
|
|
|
7
|
|
|
6
|
|
Recognized net
actuarial loss
|
|
|
42
|
|
|
2
|
|
|
85
|
|
|
4
|
|
Net periodic
cost (credit)
|
|
$
|
66
|
|
$
|
(14
|
)
|
$
|
132
|
|
$
|
(28
|
)
|
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
Ended
June 30
|
|
Other
Postretirement Benefits
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
Service
cost
|
|
$
|
4
|
|
$
|
5
|
|
$
|
8
|
|
$
|
9
|
|
Interest
cost
|
|
|
18
|
|
|
18
|
|
|
38
|
|
|
37
|
|
Expected
return on plan assets
|
|
|
(9
|
)
|
|
(13
|
)
|
|
(18
|
)
|
|
(26
|
)
|
Amortization
of prior service cost
|
|
|
(41
|
)
|
|
(37
|
)
|
|
(79
|
)
|
|
(74
|
)
|
Recognized net
actuarial loss
|
|
|
15
|
|
|
12
|
|
|
31
|
|
|
24
|
|
Net periodic
cost (credit)
|
|
$
|
(13
|
)
|
$
|
(15
|
)
|
$
|
(20
|
)
|
$
|
(30
|
)
|
Pension and
postretirement benefit obligations are allocated to FirstEnergy's subsidiaries
employing the plan participants. FES and the Utilities capitalize employee
benefits related to construction projects. The net periodic pension costs and
net periodic postretirement benefit costs (including amounts capitalized)
recognized by FES and each of the Utilities for the three months and six months
ended June 30, 2009 and 2008 were as follows:
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
Ended
June 30
|
|
Pension
Benefit Cost (Credit)
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
FES
|
|
$
|
18
|
|
$
|
5
|
|
$
|
36
|
|
$
|
11
|
|
OE
|
|
|
7
|
|
|
(6
|
)
|
|
14
|
|
|
(12
|
)
|
CEI
|
|
|
5
|
|
|
(1
|
)
|
|
10
|
|
|
(2
|
)
|
TE
|
|
|
2
|
|
|
(1
|
)
|
|
3
|
|
|
(1
|
)
|
JCP&L
|
|
|
9
|
|
|
(3
|
)
|
|
18
|
|
|
(7
|
)
|
Met-Ed
|
|
|
6
|
|
|
(2
|
)
|
|
11
|
|
|
(5
|
)
|
Penelec
|
|
|
4
|
|
|
(3
|
)
|
|
9
|
|
|
(6
|
)
|
Other
FirstEnergy subsidiaries
|
|
|
15
|
|
|
(3
|
)
|
|
31
|
|
|
(6
|
)
|
|
|
$
|
66
|
|
$
|
(14
|
)
|
$
|
132
|
|
$
|
(28
|
)
|
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
Ended
June 30
|
|
Other
Postretirement Benefit Cost (Credit)
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
FES
|
|
$
|
(3
|
)
|
$
|
(2
|
)
|
$
|
(4
|
)
|
$
|
(4
|
)
|
OE
|
|
|
(3
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(3
|
)
|
CEI
|
|
|
-
|
|
|
1
|
|
|
1
|
|
|
1
|
|
TE
|
|
|
-
|
|
|
1
|
|
|
1
|
|
|
2
|
|
JCP&L
|
|
|
(1
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|
(8
|
)
|
Met-Ed
|
|
|
(1
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(5
|
)
|
Penelec
|
|
|
(1
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(6
|
)
|
Other
FirstEnergy subsidiaries
|
|
|
(4
|
)
|
|
(3
|
)
|
|
(7
|
)
|
|
(7
|
)
|
|
|
$
|
(13
|
)
|
$
|
(15
|
)
|
$
|
(20
|
)
|
$
|
(30
|
)
|
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 distribution 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 to affiliates of the Boich Companies to
purchase an additional 5% economic interest in the Signal Peak mining and coal
transportation operations. Voting interests remained unchanged after the sale
was 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:
|
|
Maximum
Exposure
|
|
Discounted
Lease Payments, net(1)
|
|
Net
Exposure
|
|
|
(In
millions)
|
FES
|
|
$
|
1,347
|
|
$
|
1,172
|
|
$
|
175
|
OE
|
|
749
|
|
549
|
|
200
|
CEI
|
|
703
|
|
74
|
|
629
|
TE
|
|
703
|
|
376
|
|
327
|
|
|
|
|
|
|
|
|
|
(1) The
net present value of FirstEnergy's consolidated sale and leaseback
operating
lease commitments is $1.7 billion
|
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 Utilities 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 25 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. As of June 30, 2009, the net above-market loss liability projected
for these eight NUG agreements was $9 million. Purchased power costs from these
entities during the three months ended June 30, 2009 and 2008 are shown in the
following table:
|
|
Three
Months
|
|
Six
Months
|
|
|
|
Ended
June 30
|
|
Ended
June 30
|
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
|
(In
millions)
|
|
JCP&L
|
|
$
|
18
|
|
$
|
22
|
|
$
|
37
|
|
$
|
41
|
|
Met-Ed
|
|
|
13
|
|
|
16
|
|
|
28
|
|
|
32
|
|
Penelec
|
|
|
8
|
|
|
8
|
|
|
17
|
|
|
17
|
|
Total
|
|
$
|
39
|
|
$
|
46
|
|
$
|
82
|
|
$
|
90
|
|
Transition Bonds
The consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned
limited liability companies of JCP&L. In June 2002, JCP&L Transition
Funding sold $320 million of transition bonds to securitize the recovery of
JCP&L's bondable stranded costs associated with the previously divested
Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition
Funding II sold $182 million of transition bonds to securitize the recovery
of deferred costs associated with JCP&L's supply of BGS.
JCP&L did not
purchase and does not own any of the transition bonds, which are included as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As
of June 30, 2009, $356 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 its 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 second quarter
of 2009 and the first six months of 2008, there were no material changes to
FirstEnergy's unrecognized tax benefits. As of June 30, 2009, FirstEnergy
expects that it is reasonably possible that $195 million of 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 June 30,
2009 was $64 million, as compared to $59 million as of
December 31, 2008. During the first six months of 2009 and 2008, there were
no material changes to the amount of interest accrued.
In 2008,
FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method
related to the costs to repair and maintain electric generation stations. During
the second quarter of 2009, the IRS approved the change in accounting method and
FGCO and NGC are in the process of computing the amount of costs that will
qualify as a deduction. If the IRS completes its review process by the extended
filing date of September 15, 2009, an amount for the repair deduction will
be included in FirstEnergy’s 2008 consolidated tax return. This change in
accounting method could have a significant impact on taxable income for 2008 and
could reduce the amount of taxes to be accrued in the third quarter of 2009,
with no corresponding impact to the effective tax rate for the
quarter.
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 June
30, 2009, outstanding guarantees and other assurances aggregated approximately
$4.6 billion, consisting primarily of parental guarantees -
$1.3 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds -
$0.1 billion and LOCs - $0.5 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 $1.3 billion discussed above) as of June 30, 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 June 30, 2009, FirstEnergy's maximum exposure under these collateral
provisions was $601 million, consisting of $41 million due to
“material adverse event” contractual clauses and $560 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 $700 million, consisting of $49 million due to “material adverse
event” contractual clauses and $651 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 $108 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 June
30, 2009, and forward prices as of that date, FES had $179 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 $73 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 irrevocably
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.
In connection with
FES’ obligations to post and maintain collateral under the two-year PSA entered
into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009,
NGC entered into a Surplus Margin Guaranty in the amount of approximately $500
million, dated as of June 16, 2009, in favor of the Ohio Companies.
FES’ debt
obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant
to guarantees entered into on March 26, 2007. Similar guarantees were
entered into on that date pursuant to which FES guaranteed the debt obligations
of each of FGCO and NGC. Accordingly, present and future holders of
indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and
NGC regardless of whether their primary obligor is FES, FGCO or
NGC.
|
(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,
under a Cooperative Agreement with the Agency for Toxic Substances and Disease
Registry, completed a Health Consultation regarding the Mansfield Plant and
issued a report dated March 31, 2009 which concluded there is insufficient
sampling data to determine if any public health threat exists for area residents
due to emissions from the Mansfield Plant. The report recommended additional air
monitoring and sample analysis in the vicinity of the Mansfield Plant which the
Pennsylvania Department of Environmental Protection is currently
conducting.
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. On October 30, 2008, the state of
Connecticut filed a Motion to Intervene, which the Court granted on March 24,
2009. Specifically, Connecticut and New Jersey allege 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 seek injunctive relief, penalties, attorney fees and mitigation of
the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation
to and from Sithe Energy is disputed. 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 and Connecticut’s
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 1,
2009, the Court held oral argument on Met-Ed’s motion to dismiss the
complaint.
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 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 2.5 million tons annually and NOX emissions
to 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. On July 10, 2009,
the United States Court of Appeals for the District of Columbia ruled in a
different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,”
cannot be used to satisfy certain CAA requirements (known as reasonably
available control technology) for areas in non-attainment under the "8-hour"
ozone NAAQS. FGCO's 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 any future regulations 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, by 2012, the amount
of man-made GHG, including CO2, emitted
by developed countries. The United States signed the Kyoto Protocol in 1998 but
it was never submitted for ratification by the United States Senate. 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 used in the United States comes from renewable sources by
2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade
program to reduce GHG emissions by 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 House of
Representatives passed one such bill, the American Clean Energy and Security Act
of 2009, on June 26, 2009. 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. In March and June 2009, the EPA requested
information from FGCO’s Bruce Mansfield Plant regarding the management of coal
combustion wastes. FGCO's future cost of compliance with any coal combustion
waste regulations which may be promulgated could be substantial and would
depend, in part, on the regulatory action taken by the EPA and implementation by
the states.
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 June 30, 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 $104 million (JCP&L
- $77 million, TE - $1 million, CEI - $1 million and FirstEnergy
Corp. - $25 million) have been accrued through June 30, 2009. Included
in the total are accrued liabilities of approximately $68 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
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. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages due to the outages.
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. On March 31, 2009, the
trial court again granted JCP&L’s motion to decertify the class. On April
20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory
appeal to the trial court's decision to decertify the class, which was granted
by the Appellate Division on June 15, 2009. According to the scheduling order
issued by the Appellate Division, Plaintiffs' opening brief is due on August 25,
2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs'
reply is due on October 5, 2009.
Nuclear Plant Matters
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
June 8, 2009, the NRC issued the final Safety Evaluation Report (SER)
supporting the renewed license for Beaver Valley Units 1 and 2. On July 8,
2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public
meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved
questions raised by a letter from Citizens Power regarding the extent of
corrective actions for the 2009 discovery of a penetration in the Beaver Valley
Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC
further clarifications on the supplemental volumetric examinations of
Beaver Valley’s containment liners. FENOC anticipates another meeting with
the ACRS regarding the container liner during September 2009. FENOC will
continue to work with the NRC Staff as it completes its environmental and
technical reviews of the license renewal application, and is scheduled 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.
Under NRC
regulations, FirstEnergy must ensure that adequate funds will be available to
decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had
approximately $1.7 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 provided an additional $80 million parental guarantee
associated with the funding of decommissioning costs for these units and
indicated that it planned to contribute an additional $80 million to these
trusts by 2010. As required by the NRC, FirstEnergy annually
recalculates and adjusts the amount of its parental guarantee, as appropriate.
The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on
market conditions. If the value of the trusts decline by a material amount,
FirstEnergy’s obligations to fund the trusts may increase. The recent disruption
in the capital markets and its effects on particular businesses and the economy
in general also affects the values of the nuclear decommission trusts. On June
18, 2009, the NRC informed FENOC that its review tentatively concluded that a
shortfall ($147.5 million net present value) existed in the value of the
decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC
submitted a letter to the NRC that stated reasonable assurance of
decommissioning funding is provided for Beaver Valley Unit 1 through a
combination of the existing trust fund balances, the existing $80 million
parental guarantee from FirstEnergy and maintaining the plant in a safe-store
configuration, or extended safe shutdown condition, after plant shutdown.
Renewal of the operating license for Beaver Valley Unit 1, as described above,
would mitigate the estimated shortfall in the unit’s nuclear decommissioning
funding status. FENOC continues to communicate with the NRC regarding
future actions to provide reasonable assurance for decommissioning funding. Such
actions may include additional parental guarantees or contributions to those
funds.
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 bargaining unit
employees at the Bruce Mansfield Plant have been working without a labor
contract since February 15, 2008. On July 24,
2009, FirstEnergy declared that bargaining was at an impasse and portions of its
last contract offer were implemented August 1, 2009. A federal
mediator is continuing to assist the parties in reaching a negotiated contract
settlement. FirstEnergy has a strike mitigation plan ready in the event
of a strike.
On May 21, 2009, 517
Penelec employees, represented by the International Brotherhood of Electrical
Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009,
Penelec implemented its work-continuation plan to use nearly 400 non-represented
employees with previous line experience and training drawn from Penelec and
other FirstEnergy operations to perform service reliability and priority
maintenance work in Penelec’s service territory. Penelec's IBEW Local 459
employees ratified a three-year contract agreement on July 19, 2009, and
returned to work on July 20, 2009.
On June 26, 2009,
FirstEnergy announced that seven of its union locals, representing about 2,600
employees, have ratified contract extensions. These unions include employees
from Penelec, Penn, CEI, OE and TE, along with certain power plant
employees.
On July 8, 2009,
FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777
ratified a two-year contract. Union members had been working without a contract
since the previous agreement expired on April 30, 2009.
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 the NERC’s request for factual data about the outage.
JCP&L submitted its written response on May 1, 2009. The NERC conducted
on site interviews with personnel involved in responding to the event on June
16-17, 2009. On July 7, 2009, the NERC issued additional questions
regarding the event and JCP&L is required to reply by August 7, 2009.
JCP&L is not able at this time to predict what actions, if any, that the
NERC may take based on the data submittal or interview results.
On June 5, 2009,
FirstEnergy self-reported to ReliabilityFirst a potential
violation of NERC Standard PRC-005 resulting from its inability to validate
maintenance records for 20 protection system relays in JCP&L’s and Penelec’s
transmission systems. These potential violations were discovered during a
comprehensive field review of all FirstEnergy substations to verify equipment
and maintenance database accuracy. FirstEnergy has completed all mitigation
actions, including calibrations and maintenance records for the relays.
ReliabilityFirst issued
an Initial Notice of Alleged Violation on June 22, 2009. FirstEnergy is not able
at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this
self-report of violation.
(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 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 for the purpose of further
consideration. The PUCO has not yet issued a substantive Entry on
Rehearing.
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, which is
still pending. 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 provided generation service to the Ohio Companies’ retail
customers who chose 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 denied OE’s and TE’s request to continue collecting
RTC and denied the request to allow the Ohio Companies to continue collections
pursuant to the two existing fuel riders. The new fuel rider recovered the
increased purchased power costs for OE and TE, and recovered a portion of those
costs for CEI, with the remainder being deferred 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 provided that generation would 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 would be based upon the outcome of a descending clock CBP on a
slice-of-system basis. The Amended ESP further provided 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
would agree to write-off approximately $216 million of its Extended RTC
balance, and that the Ohio Companies would 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
addressed a number of other issues, including but not limited to, rate design
for various customer classes, and 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, 2009 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 took effect on April 1,
2009 while the remaining provisions took effect on June 1,
2009.
On July 27, 2009,
the Ohio Companies filed applications with the PUCO to recover three different
categories of deferred distribution costs on an accelerated basis. In the Ohio
Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with
collection originally set to begin in January 2011 and to continue over a 5 or
25 year period. The principal amount plus carrying charges through August 31,
2009 for these deferrals is a total of $298.4 million. If the applications are
approved, recovery of this amount, together with carrying charges calculated as
approved in the Amended ESP, will be collected in the 18 non-summer months from
September 2009 through May 2011, subject to reconciliation until fully
collected, with $165 million of the above amount being recovered from
residential customers, and $133.4 million being recovered from non-residential
customers. Pursuant to the applications, customers would pay significantly less
over the life of the recovery of the deferral through the reduction in carrying
charges as compared to the expected recovery under the previously approved
recovery mechanism.
The Ohio Companies
are presently involved in collaborative efforts related to energy efficiency and
a competitive bidding process, together with other implementation efforts
arising out of the Supplemental Stipulation. The CBP auction occurred on
May 13-14, 2009, and resulted in a weighted average wholesale price for
generation and transmission of 6.15 cents per KWH. The bid was for a single,
two-year product for the service period from June 1, 2009 through May 31,
2011. FES participated in the auction, winning 51% of the tranches (one tranche
equals one percent of the load supply). Subsequent to the signing of the
wholesale contracts, two winning bidders reached separate agreements with FES to
assign a total of 11 tranches to FES for various periods. In addition, FES has
separately contracted with numerous communities to provide retail generation
service through governmental aggregation programs.
SB221 also requires
electric distribution utilities to implement energy efficiency programs that
achieve a total annual 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 1%,
with an additional seventy-five hundredths of one percent reduction each year
thereafter through 2018. Additionally, electric utilities and electric service
companies are required to serve part of their load from renewable energy
resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has
efforts underway to address compliance with these requirements. Costs associated
with compliance are recoverable from customers.
On June 17, 2009,
the PUCO modified rules that implement the alternative energy portfolio
standards created by SB221, including the incorporation of energy efficiency
requirements, long-term forecast and greenhouse gas reporting and CO2 control
planning. The PUCO filed the rules with the Joint Committee on Agency Rule
Review on July 7, 2009, after which begins a 65-day review period. The Ohio
Companies and one other party filed applications for rehearing on the rules with
the PUCO on July 17, 2009.
(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 included a component from
under-recovery of actual transmission costs incurred during the prior period
(Met-Ed - $144 million and Penelec - $4 million) and 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 May 28, 2009, the
PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider 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 resulted
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 increased 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, the PPUC approved Met-Ed’s
proposal to continue to recover the prior period deferrals allowed in the PPUC’s
May 2008 Order and defer $57.5 million of projected costs to a future TSC to be
fully recovered by December 31, 2010. Under this proposal, monthly bills for
Met-Ed’s customers will 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. Act 129 addresses issues
such as: energy efficiency and peak load reduction; generation procurement;
time-of-use rates; smart meters; and alternative energy. 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 prudent 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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utilities must
reduce peak demand by a minimum of 4.5% by May 31,
2013;
|
·
|
utilities must
reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and
May 31, 2013, respectively; and
|
·
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the definition
of Alternative Energy was expanded to include additional types of
hydroelectric and biomass
facilities.
|
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. On June 18, 2009, the PPUC issued its
guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec,
and Penn filed Energy Efficiency and Conservation Plans with the PPUC in
accordance with Act 129.
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 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 February 26,
2009, the PPUC approved a Voluntary Prepayment Plan 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 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. On July 30, 2009,
the PPUC entered an order approving the 5-year NUG Statement, approving the
reduction of the CTC, and directing Met-Ed and Penelec to file a tariff
supplement implementing this change. On July 31, 2009, Met-Ed and Penelec
filed tariff supplements decreasing the CTC rate in compliance with the
July 30, 2009 order, and increasing the generation rate in compliance with
the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are
awaiting PPUC action on the July 31, 2009
filings.
(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 June 30,
2009, the accumulated deferred cost balance totaled approximately
$149 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.
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;
|
·
|
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
|
·
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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
a proposal to spend approximately $98 million on infrastructure and energy
efficiency projects in 2009. Under the proposal, an estimated $40
million would be spent on infrastructure projects, including substation
upgrades, new transformers, distribution line re-closers and automated breaker
operations. Approximately $34 million would be spent implementing new
demand response programs as well as expanding on existing
programs. Another $11 million would be spent on energy efficiency,
specifically replacing transformers and capacitor control systems and installing
new LED street lights. The remaining $13 million would be spent on energy
efficiency programs that would complement those currently being offered.
Implementation of the projects is dependent upon resolution of regulatory issues
including recovery of the costs associated with the proposal.
(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. AEP's 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 arguments were
held on April 13, 2009. A decision is expected this summer.
The FERC’s orders on
PJM rate design would 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 would 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 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.
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. 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 discussions. 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; and subsequently, numerous parties filed requests for
rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied
rehearing and request for oral argument of the March 26 Order.
PJM has reconvened
the Capacity Market Evolution Committee to address issues not addressed in the
February 2009 settlement in preparation for September 1, 2009 and December 1,
2009 compliance filings that will recommend more incremental improvements to its
RPM.
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 and FES. This requirement was 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 was implemented as planned on June 1, 2009, the beginning of the MISO
planning year. On June 17, 2009, MISO submitted a compliance filing in
response to the FERC’s April 16, 2009 order directing it to address, among
others, various market monitoring and mitigation issues. On July 8, 2009,
various parties submitted comments on and protests to MISO’s compliance filing.
FirstEnergy submitted comments identifying specific aspects of the MISO’s and
Independent Market Monitor’s proposals for market monitoring and mitigation and
other issues that it believes the FERC should address and clarify.
FES Sales to Affiliates
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 a December 23,
2008 waiver of restrictions on affiliate sales without prior approval of the
FERC.
On May 13-14, 2009,
the Ohio Companies held an auction to secure generation supply for their PLR
obligation. The results of the auction were accepted by the PUCO on May 14,
2009. Twelve bidders qualified to participate in the auction with nine
successful bidders each securing a portion of the Ohio Companies' total supply
needs. FES was the successful bidder for 51 tranches, and subsequently purchased
11 additional tranches from other bidders. The auction resulted in an overall
weighted average wholesale price of 6.15 cents per KWH for generation and
transmission. The new prices for PLR service went into effect with usage
beginning June 1, 2009, and continuing through May 31, 2011.
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 approximately two-thirds of those
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 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 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.
SFAS
166 – “Accounting for Transfers of Financial Assets – an amendment of FASB
Statement No. 140”
In June 2009, the
FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and
eliminates the concept of a qualifying special-purpose entity (QSPE). It removes
the exception from applying FIN 46R to QSPEs and requires an evaluation of all
existing QSPEs to determine whether they must be consolidated in accordance with
SFAS 167. This Statement is effective for financial asset transfers that occur
in fiscal years beginning after November 15, 2009. FirstEnergy does not expect
this Standard to have a material effect upon its financial
statements.
SFAS 167 – “Amendments to FASB
Interpretation No. 46(R)”
In June 2009, the
FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs.
This Statement replaces the quantitative approach previously required to
determine which entity has a controlling financial interest in a VIE with a
qualitative approach. Under the new approach, the primary beneficiary of a VIE
is the entity that has both (a) the power to direct the activities of the VIE
that most significantly impact the entity’s economic performance, and (b) the
obligation to absorb losses of the entity, or the right to receive benefits from
the entity, that could be significant to the VIE. SFAS 167 also requires
ongoing reassessments of whether an entity is the primary beneficiary of a VIE
and enhanced disclosures about an entity’s involvement in VIEs. This Statement
is effective for fiscal years beginning after November 15, 2009. FirstEnergy is
currently evaluating the impact of adopting this Standard on its financial
statements.
SFAS 168 – “The FASB
Accounting Standards CodificationTM and the Hierarchy of Generally
Accepted Accounting Principles – a replacement of FASB Statement No.
162”
In June 2009, the
FASB issued SFAS 168, which recognizes the FASB Accounting Standards
CodificationTM
(Codification) as the source of authoritative GAAP. It also recognizes that
rules and interpretative releases of the SEC under federal securities laws are
sources of authoritative GAAP for SEC registrants. The Codification supersedes
all non-SEC accounting and reporting standards. This Statement is effective for
financial statements issued for interim and annual periods ending after
September 15, 2009. This Statement will change how FirstEnergy references
GAAP in its financial statement disclosures.
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." FES and the Utilities do not have separate 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 Met-Ed's and Penelec's 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 affiliated and 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 sales to
its affiliates in Ohio and Pennsylvania.
The Ohio
transitional generation services segment represents the 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 primarily of accounts receivable for
generation revenues from retail customers.
Segment
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Competitive
|
|
|
Transitional
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivery
|
|
|
Energy
|
|
|
Generation
|
|
|
|
|
|
Reconciling
|
|
|
|
|
Three
Months Ended
|
|
Services
|
|
|
Services
|
|
|
Services
|
|
|
Other
|
|
|
Adjustments
|
|
|
Consolidated
|
|
|
|
(In
millions)
|
|
June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
1,924 |
|
|
$ |
504 |
|
|
$ |
868 |
|
|
$ |
5 |
|
|
$ |
(30 |
) |
|
$ |
3,271 |
|
Internal
revenues
|
|
|
- |
|
|
|
839 |
|
|
|
- |
|
|
|
- |
|
|
|
(839 |
) |
|
|
- |
|
Total
revenues
|
|
|
1,924 |
|
|
|
1,343 |
|
|
|
868 |
|
|
|
5 |
|
|
|
(869 |
) |
|
|
3,271 |
|
Depreciation
and amortization
|
|
|
294 |
|
|
|
68 |
|
|
|
4 |
|
|
|
3 |
|
|
|
4 |
|
|
|
373 |
|
Investment
income
|
|
|
35 |
|
|
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
(14 |
) |
|
|
27 |
|
Net interest
charges
|
|
|
113 |
|
|
|
18 |
|
|
|
- |
|
|
|
2 |
|
|
|
40 |
|
|
|
173 |
|
Income
taxes
|
|
|
89 |
|
|
|
185 |
|
|
|
14 |
|
|
|
(20 |
) |
|
|
(20 |
) |
|
|
248 |
|
Net
income
|
|
|
133 |
|
|
|
276 |
|
|
|
21 |
|
|
|
18 |
|
|
|
(40 |
) |
|
|
408 |
|
Total
assets
|
|
|
22,849 |
|
|
|
10,144 |
|
|
|
366 |
|
|
|
684 |
|
|
|
263 |
|
|
|
34,306 |
|
Total
goodwill
|
|
|
5,551 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,575 |
|
Property
additions
|
|
|
178 |
|
|
|
248 |
|
|
|
- |
|
|
|
70 |
|
|
|
(7 |
) |
|
|
489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
2,182 |
|
|
$ |
375 |
|
|
$ |
683 |
|
|
$ |
20 |
|
|
$ |
(15 |
) |
|
$ |
3,245 |
|
Internal
revenues
|
|
|
- |
|
|
|
704 |
|
|
|
- |
|
|
|
- |
|
|
|
(704 |
) |
|
|
- |
|
Total
revenues
|
|
|
2,182 |
|
|
|
1,079 |
|
|
|
683 |
|
|
|
20 |
|
|
|
(719 |
) |
|
|
3,245 |
|
Depreciation
and amortization
|
|
|
241 |
|
|
|
59 |
|
|
|
11 |
|
|
|
1 |
|
|
|
4 |
|
|
|
316 |
|
Investment
income
|
|
|
40 |
|
|
|
(8 |
) |
|
|
(1 |
) |
|
|
6 |
|
|
|
(21 |
) |
|
|
16 |
|
Net interest
charges
|
|
|
99 |
|
|
|
28 |
|
|
|
- |
|
|
|
- |
|
|
|
48 |
|
|
|
175 |
|
Income
taxes
|
|
|
129 |
|
|
|
45 |
|
|
|
13 |
|
|
|
(1 |
) |
|
|
(26 |
) |
|
|
160 |
|
Net
income
|
|
|
193 |
|
|
|
66 |
|
|
|
19 |
|
|
|
26 |
|
|
|
(41 |
) |
|
|
263 |
|
Total
assets
|
|
|
23,423 |
|
|
|
9,240 |
|
|
|
266 |
|
|
|
281 |
|
|
|
335 |
|
|
|
33,545 |
|
Total
goodwill
|
|
|
5,582 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,606 |
|
Property
additions
|
|
|
196 |
|
|
|
683 |
|
|
|
- |
|
|
|
9 |
|
|
|
18 |
|
|
|
906 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
4,033 |
|
|
$ |
839 |
|
|
$ |
1,780 |
|
|
$ |
12 |
|
|
$ |
(59 |
) |
|
$ |
6,605 |
|
Internal
revenues
|
|
|
- |
|
|
|
1,732 |
|
|
|
- |
|
|
|
- |
|
|
|
(1,732 |
) |
|
|
- |
|
Total
revenues
|
|
|
4,033 |
|
|
|
2,571 |
|
|
|
1,780 |
|
|
|
12 |
|
|
|
(1,791 |
) |
|
|
6,605 |
|
Depreciation
and amortization
|
|
|
766 |
|
|
|
132 |
|
|
|
(41 |
) |
|
|
4 |
|
|
|
7 |
|
|
|
868 |
|
Investment
income
|
|
|
64 |
|
|
|
(23 |
) |
|
|
1 |
|
|
|
- |
|
|
|
(26 |
) |
|
|
16 |
|
Net interest
charges
|
|
|
223 |
|
|
|
36 |
|
|
|
- |
|
|
|
3 |
|
|
|
77 |
|
|
|
339 |
|
Income
taxes
|
|
|
61 |
|
|
|
288 |
|
|
|
30 |
|
|
|
(37 |
) |
|
|
(40 |
) |
|
|
302 |
|
Net
income
|
|
|
91 |
|
|
|
431 |
|
|
|
45 |
|
|
|
35 |
|
|
|
(79 |
) |
|
|
523 |
|
Total
assets
|
|
|
22,849 |
|
|
|
10,144 |
|
|
|
366 |
|
|
|
684 |
|
|
|
263 |
|
|
|
34,306 |
|
Total
goodwill
|
|
|
5,551 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,575 |
|
Property
additions
|
|
|
343 |
|
|
|
669 |
|
|
|
- |
|
|
|
119 |
|
|
|
12 |
|
|
|
1,143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
revenues
|
|
$ |
4,394 |
|
|
$ |
704 |
|
|
$ |
1,390 |
|
|
$ |
60 |
|
|
$ |
(26 |
) |
|
$ |
6,522 |
|
Internal
revenues
|
|
|
- |
|
|
|
1,480 |
|
|
|
- |
|
|
|
- |
|
|
|
(1,480 |
) |
|
|
- |
|
Total
revenues
|
|
|
4,394 |
|
|
|
2,184 |
|
|
|
1,390 |
|
|
|
60 |
|
|
|
(1,506 |
) |
|
|
6,522 |
|
Depreciation
and amortization
|
|
|
496 |
|
|
|
112 |
|
|
|
15 |
|
|
|
1 |
|
|
|
9 |
|
|
|
633 |
|
Investment
income
|
|
|
85 |
|
|
|
(14 |
) |
|
|
- |
|
|
|
6 |
|
|
|
(44 |
) |
|
|
33 |
|
Net interest
charges
|
|
|
202 |
|
|
|
55 |
|
|
|
- |
|
|
|
- |
|
|
|
89 |
|
|
|
346 |
|
Income
taxes
|
|
|
248 |
|
|
|
103 |
|
|
|
28 |
|
|
|
13 |
|
|
|
(45 |
) |
|
|
347 |
|
Net
income
|
|
|
372 |
|
|
|
153 |
|
|
|
43 |
|
|
|
48 |
|
|
|
(76 |
) |
|
|
540 |
|
Total
assets
|
|
|
23,423 |
|
|
|
9,240 |
|
|
|
266 |
|
|
|
281 |
|
|
|
335 |
|
|
|
33,545 |
|
Total
goodwill
|
|
|
5,582 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,606 |
|
Property
additions
|
|
|
451 |
|
|
|
1,145 |
|
|
|
- |
|
|
|
21 |
|
|
|
- |
|
|
|
1,617 |
|
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, 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 FirstEnergy and as a financing for FGCO.
The condensed
consolidating statements of income for the three-month and six-month periods
ended June 30, 2009 and 2008, consolidating balance sheets as of
June 30, 2009 and December 31, 2008 and consolidating statements of cash
flows for the six months ended June 30, 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 June 30, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
1,067,987 |
|
|
$ |
703,110 |
|
|
$ |
389,695 |
|
|
$ |
(819,640 |
) |
|
$ |
1,341,152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
5,027 |
|
|
|
238,832 |
|
|
|
26,450 |
|
|
|
- |
|
|
|
270,309 |
|
Purchased
power from non-affiliates
|
|
|
185,613 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
185,613 |
|
Purchased
power from affiliates
|
|
|
814,622 |
|
|
|
5,018 |
|
|
|
51,249 |
|
|
|
(819,640 |
) |
|
|
51,249 |
|
Other
operating expenses
|
|
|
35,771 |
|
|
|
99,145 |
|
|
|
131,159 |
|
|
|
12,189 |
|
|
|
278,264 |
|
Provision for
depreciation
|
|
|
1,017 |
|
|
|
30,191 |
|
|
|
35,654 |
|
|
|
(1,314 |
) |
|
|
65,548 |
|
General
taxes
|
|
|
3,769 |
|
|
|
11,332 |
|
|
|
6,184 |
|
|
|
- |
|
|
|
21,285 |
|
Total
expenses
|
|
|
1,045,819 |
|
|
|
384,518 |
|
|
|
250,696 |
|
|
|
(808,765 |
) |
|
|
872,268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
22,168 |
|
|
|
318,592 |
|
|
|
138,999 |
|
|
|
(10,875 |
) |
|
|
468,884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income, including net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
from equity
investees
|
|
|
288,794 |
|
|
|
951 |
|
|
|
6,030 |
|
|
|
(282,510 |
) |
|
|
13,265 |
|
Interest
expense - affiliates
|
|
|
(34 |
) |
|
|
(1,623 |
) |
|
|
(1,658 |
) |
|
|
- |
|
|
|
(3,315 |
) |
Interest
expense - other
|
|
|
(2,900 |
) |
|
|
(24,967 |
) |
|
|
(14,677 |
) |
|
|
16,273 |
|
|
|
(26,271 |
) |
Capitalized
interest
|
|
|
46 |
|
|
|
11,126 |
|
|
|
2,856 |
|
|
|
- |
|
|
|
14,028 |
|
Total other
income (expense)
|
|
|
285,906 |
|
|
|
(14,513 |
) |
|
|
(7,449 |
) |
|
|
(266,237 |
) |
|
|
(2,293 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
308,074 |
|
|
|
304,079 |
|
|
|
131,550 |
|
|
|
(277,112 |
) |
|
|
466,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
10,672 |
|
|
|
108,114 |
|
|
|
48,163 |
|
|
|
2,240 |
|
|
|
169,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
297,402 |
|
|
$ |
195,965 |
|
|
$ |
83,387 |
|
|
$ |
(279,352 |
) |
|
$ |
297,402 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30, 2008
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
1,064,627 |
|
|
$ |
565,225 |
|
|
$ |
287,028 |
|
|
$ |
(845,602 |
) |
|
$ |
1,071,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
3,605 |
|
|
|
277,192 |
|
|
|
29,753 |
|
|
|
- |
|
|
|
310,550 |
|
Purchased
power from non-affiliates
|
|
|
220,339 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
220,339 |
|
Purchased
power from affiliates
|
|
|
842,670 |
|
|
|
2,932 |
|
|
|
34,528 |
|
|
|
(845,602 |
) |
|
|
34,528 |
|
Other
operating expenses
|
|
|
29,842 |
|
|
|
124,173 |
|
|
|
121,534 |
|
|
|
12,189 |
|
|
|
287,738 |
|
Provision for
depreciation
|
|
|
1,600 |
|
|
|
30,027 |
|
|
|
25,893 |
|
|
|
(1,360 |
) |
|
|
56,160 |
|
General
taxes
|
|
|
4,727 |
|
|
|
11,504 |
|
|
|
3,564 |
|
|
|
- |
|
|
|
19,795 |
|
Total
expenses
|
|
|
1,102,783 |
|
|
|
445,828 |
|
|
|
215,272 |
|
|
|
(834,773 |
) |
|
|
929,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
(38,156 |
) |
|
|
119,397 |
|
|
|
71,756 |
|
|
|
(10,829 |
) |
|
|
142,168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income
from equity investees
|
|
|
98,590 |
|
|
|
489 |
|
|
|
(9,449 |
) |
|
|
(91,704 |
) |
|
|
(2,074 |
) |
Interest
expense - affiliates
|
|
|
(50 |
) |
|
|
(7,920 |
) |
|
|
(2,758 |
) |
|
|
- |
|
|
|
(10,728 |
) |
Interest
expense - other
|
|
|
(6,663 |
) |
|
|
(23,697 |
) |
|
|
(10,632 |
) |
|
|
16,487 |
|
|
|
(24,505 |
) |
Capitalized
interest
|
|
|
28 |
|
|
|
9,856 |
|
|
|
657 |
|
|
|
- |
|
|
|
10,541 |
|
Total other
income (expense)
|
|
|
91,905 |
|
|
|
(21,272 |
) |
|
|
(22,182 |
) |
|
|
(75,217 |
) |
|
|
(26,766 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
53,749 |
|
|
|
98,125 |
|
|
|
49,574 |
|
|
|
(86,046 |
) |
|
|
115,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES (BENEFIT)
|
|
|
(14,345 |
) |
|
|
38,467 |
|
|
|
20,838 |
|
|
|
2,348 |
|
|
|
47,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
68,094 |
|
|
$ |
59,658 |
|
|
$ |
28,736 |
|
|
$ |
(88,394 |
) |
|
$ |
68,094 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
2,269,882 |
|
|
$ |
1,249,036 |
|
|
$ |
785,323 |
|
|
$ |
(1,736,983 |
) |
|
$ |
2,567,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
7,122 |
|
|
|
513,679 |
|
|
|
55,666 |
|
|
|
- |
|
|
|
576,467 |
|
Purchased
power from non-affiliates
|
|
|
345,955 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
345,955 |
|
Purchased
power from affiliates
|
|
|
1,729,883 |
|
|
|
7,100 |
|
|
|
114,456 |
|
|
|
(1,736,983 |
) |
|
|
114,456 |
|
Other
operating expenses
|
|
|
74,038 |
|
|
|
203,588 |
|
|
|
283,615 |
|
|
|
24,379 |
|
|
|
585,620 |
|
Provision for
depreciation
|
|
|
2,036 |
|
|
|
60,211 |
|
|
|
67,303 |
|
|
|
(2,629 |
) |
|
|
126,921 |
|
General
taxes
|
|
|
8,475 |
|
|
|
23,958 |
|
|
|
12,228 |
|
|
|
- |
|
|
|
44,661 |
|
Total
expenses
|
|
|
2,167,509 |
|
|
|
808,536 |
|
|
|
533,268 |
|
|
|
(1,715,233 |
) |
|
|
1,794,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
102,373 |
|
|
|
440,500 |
|
|
|
252,055 |
|
|
|
(21,750 |
) |
|
|
773,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income
from equity investees
|
|
|
409,307 |
|
|
|
904 |
|
|
|
(23,607 |
) |
|
|
(399,702 |
) |
|
|
(13,098 |
) |
Interest
expense - affiliates
|
|
|
(68 |
) |
|
|
(3,381 |
) |
|
|
(2,845 |
) |
|
|
- |
|
|
|
(6,294 |
) |
Interest
expense - other
|
|
|
(5,420 |
) |
|
|
(46,025 |
) |
|
|
(29,845 |
) |
|
|
32,492 |
|
|
|
(48,798 |
) |
Capitalized
interest
|
|
|
97 |
|
|
|
18,876 |
|
|
|
5,133 |
|
|
|
- |
|
|
|
24,106 |
|
Total other
income (expense)
|
|
|
403,916 |
|
|
|
(29,626 |
) |
|
|
(51,164 |
) |
|
|
(367,210 |
) |
|
|
(44,084 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
506,289 |
|
|
|
410,874 |
|
|
|
200,891 |
|
|
|
(388,960 |
) |
|
|
729,094 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
38,206 |
|
|
|
147,256 |
|
|
|
71,092 |
|
|
|
4,457 |
|
|
|
261,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
468,083 |
|
|
$ |
263,618 |
|
|
$ |
129,799 |
|
|
$ |
(393,417 |
) |
|
$ |
468,083 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30, 2008
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
$ |
2,164,475 |
|
|
$ |
1,132,926 |
|
|
$ |
612,712 |
|
|
$ |
(1,739,719 |
) |
|
$ |
2,170,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
5,743 |
|
|
|
568,431 |
|
|
|
58,065 |
|
|
|
- |
|
|
|
632,239 |
|
Purchased
power from non-affiliates
|
|
|
427,063 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
427,063 |
|
Purchased
power from affiliates
|
|
|
1,734,649 |
|
|
|
5,070 |
|
|
|
60,013 |
|
|
|
(1,739,719 |
) |
|
|
60,013 |
|
Other
operating expenses
|
|
|
67,438 |
|
|
|
231,340 |
|
|
|
261,129 |
|
|
|
24,377 |
|
|
|
584,284 |
|
Provision for
depreciation
|
|
|
1,907 |
|
|
|
56,626 |
|
|
|
50,087 |
|
|
|
(2,718 |
) |
|
|
105,902 |
|
General
taxes
|
|
|
10,142 |
|
|
|
23,074 |
|
|
|
9,776 |
|
|
|
- |
|
|
|
42,992 |
|
Total
expenses
|
|
|
2,246,942 |
|
|
|
884,541 |
|
|
|
439,070 |
|
|
|
(1,718,060 |
) |
|
|
1,852,493 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME (LOSS)
|
|
|
(82,467 |
) |
|
|
248,385 |
|
|
|
173,642 |
|
|
|
(21,659 |
) |
|
|
317,901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miscellaneous
income (expense), including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net income
from equity investees
|
|
|
220,315 |
|
|
|
(719 |
) |
|
|
(15,986 |
) |
|
|
(208,588 |
) |
|
|
(4,978 |
) |
Interest
expense - affiliates
|
|
|
(132 |
) |
|
|
(13,209 |
) |
|
|
(4,597 |
) |
|
|
- |
|
|
|
(17,938 |
) |
Interest
expense - other
|
|
|
(10,641 |
) |
|
|
(49,665 |
) |
|
|
(21,650 |
) |
|
|
32,916 |
|
|
|
(49,040 |
) |
Capitalized
interest
|
|
|
49 |
|
|
|
16,084 |
|
|
|
1,071 |
|
|
|
- |
|
|
|
17,204 |
|
Total other
income (expense)
|
|
|
209,591 |
|
|
|
(47,509 |
) |
|
|
(41,162 |
) |
|
|
(175,672 |
) |
|
|
(54,752 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
127,124 |
|
|
|
200,876 |
|
|
|
132,480 |
|
|
|
(197,331 |
) |
|
|
263,149 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAXES (BENEFIT)
|
|
|
(30,954 |
) |
|
|
77,752 |
|
|
|
53,602 |
|
|
|
4,671 |
|
|
|
105,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
158,078 |
|
|
$ |
123,124 |
|
|
$ |
78,878 |
|
|
$ |
(202,002 |
) |
|
$ |
158,078 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of June 30, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
120,000 |
|
|
$ |
34 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
120,034 |
|
Receivables-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers
|
|
|
75,753 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
75,753 |
|
Associated
companies
|
|
|
222,514 |
|
|
|
152,509 |
|
|
|
105,559 |
|
|
|
(265,220 |
) |
|
|
215,362 |
|
Other
|
|
|
3,477 |
|
|
|
10,979 |
|
|
|
4,853 |
|
|
|
- |
|
|
|
19,309 |
|
Notes
receivable from associated companies
|
|
|
369,068 |
|
|
|
1,277 |
|
|
|
- |
|
|
|
- |
|
|
|
370,345 |
|
Materials and
supplies, at average cost
|
|
|
10,370 |
|
|
|
329,132 |
|
|
|
210,710 |
|
|
|
- |
|
|
|
550,212 |
|
Prepayments
and other
|
|
|
76,784 |
|
|
|
18,875 |
|
|
|
2,722 |
|
|
|
- |
|
|
|
98,381 |
|
|
|
|
877,966 |
|
|
|
512,806 |
|
|
|
323,844 |
|
|
|
(265,220 |
) |
|
|
1,449,396 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
service
|
|
|
89,296 |
|
|
|
5,501,668 |
|
|
|
5,025,760 |
|
|
|
(389,939 |
) |
|
|
10,226,785 |
|
Less -
Accumulated provision for depreciation
|
|
|
11,838 |
|
|
|
2,760,063 |
|
|
|
1,801,089 |
|
|
|
(172,808 |
) |
|
|
4,400,182 |
|
|
|
|
77,458 |
|
|
|
2,741,605 |
|
|
|
3,224,671 |
|
|
|
(217,131 |
) |
|
|
5,826,603 |
|
Construction
work in progress
|
|
|
3,832 |
|
|
|
1,735,258 |
|
|
|
280,658 |
|
|
|
- |
|
|
|
2,019,748 |
|
|
|
|
81,290 |
|
|
|
4,476,863 |
|
|
|
3,505,329 |
|
|
|
(217,131 |
) |
|
|
7,846,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear plant
decommissioning trusts
|
|
|
- |
|
|
|
- |
|
|
|
1,040,410 |
|
|
|
- |
|
|
|
1,040,410 |
|
Investment in
associated companies
|
|
|
4,059,946 |
|
|
|
- |
|
|
|
- |
|
|
|
(4,059,946 |
) |
|
|
- |
|
Other
|
|
|
1,517 |
|
|
|
27,493 |
|
|
|
202 |
|
|
|
- |
|
|
|
29,212 |
|
|
|
|
4,061,463 |
|
|
|
27,493 |
|
|
|
1,040,612 |
|
|
|
(4,059,946 |
) |
|
|
1,069,622 |
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
deferred income taxes
|
|
|
7,250 |
|
|
|
424,814 |
|
|
|
- |
|
|
|
(280,607 |
) |
|
|
151,457 |
|
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
|
|
|
- |
|
|
|
17,533 |
|
|
|
- |
|
|
|
56,748 |
|
|
|
74,281 |
|
Other
|
|
|
40,108 |
|
|
|
67,288 |
|
|
|
8,782 |
|
|
|
(53,873 |
) |
|
|
62,305 |
|
|
|
|
71,606 |
|
|
|
608,485 |
|
|
|
31,392 |
|
|
|
(277,732 |
) |
|
|
433,751 |
|
|
|
$ |
5,092,325 |
|
|
$ |
5,625,647 |
|
|
$ |
4,901,177 |
|
|
$ |
(4,820,029 |
) |
|
$ |
10,799,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND CAPITALIZATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currently
payable long-term debt
|
|
$ |
717 |
|
|
$ |
698,493 |
|
|
$ |
951,240 |
|
|
$ |
(18,186 |
) |
|
$ |
1,632,264 |
|
Short-term
borrowings-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
- |
|
|
|
174,769 |
|
|
|
135,063 |
|
|
|
- |
|
|
|
309,832 |
|
Other
|
|
|
1,100,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,100,000 |
|
Accounts
payable-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated
companies
|
|
|
288,626 |
|
|
|
184,839 |
|
|
|
131,438 |
|
|
|
(237,508 |
) |
|
|
367,395 |
|
Other
|
|
|
55,039 |
|
|
|
113,446 |
|
|
|
- |
|
|
|
- |
|
|
|
168,485 |
|
Accrued
taxes
|
|
|
56,092 |
|
|
|
33,217 |
|
|
|
22,274 |
|
|
|
(42,824 |
) |
|
|
68,759 |
|
Other
|
|
|
38,397 |
|
|
|
97,054 |
|
|
|
10,824 |
|
|
|
34,715 |
|
|
|
180,990 |
|
|
|
|
1,538,871 |
|
|
|
1,301,818 |
|
|
|
1,250,839 |
|
|
|
(263,803 |
) |
|
|
3,827,725 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stockholder's equity
|
|
|
3,494,790 |
|
|
|
2,136,867 |
|
|
|
1,905,900 |
|
|
|
(4,042,767 |
) |
|
|
3,494,790 |
|
Long-term debt
and other long-term obligations
|
|
|
21,620 |
|
|
|
1,688,863 |
|
|
|
533,990 |
|
|
|
(1,278,796 |
) |
|
|
965,677 |
|
|
|
|
3,516,410 |
|
|
|
3,825,730 |
|
|
|
2,439,890 |
|
|
|
(5,321,563 |
) |
|
|
4,460,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gain
on sale and leaseback transaction
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,009,727 |
|
|
|
1,009,727 |
|
Accumulated
deferred income taxes
|
|
|
- |
|
|
|
- |
|
|
|
244,390 |
|
|
|
(244,390 |
) |
|
|
- |
|
Accumulated
deferred investment tax credits
|
|
|
- |
|
|
|
37,899 |
|
|
|
22,663 |
|
|
|
- |
|
|
|
60,562 |
|
Asset
retirement obligations
|
|
|
- |
|
|
|
24,627 |
|
|
|
866,878 |
|
|
|
- |
|
|
|
891,505 |
|
Retirement
benefits
|
|
|
18,841 |
|
|
|
113,041 |
|
|
|
- |
|
|
|
- |
|
|
|
131,882 |
|
Property
taxes
|
|
|
- |
|
|
|
27,494 |
|
|
|
22,610 |
|
|
|
- |
|
|
|
50,104 |
|
Lease market
valuation liability
|
|
|
- |
|
|
|
284,952 |
|
|
|
- |
|
|
|
- |
|
|
|
284,952 |
|
Other
|
|
|
18,203 |
|
|
|
10,086 |
|
|
|
53,907 |
|
|
|
- |
|
|
|
82,196 |
|
|
|
|
37,044 |
|
|
|
498,099 |
|
|
|
1,210,448 |
|
|
|
765,337 |
|
|
|
2,510,928 |
|
|
|
$ |
5,092,325 |
|
|
$ |
5,625,647 |
|
|
$ |
4,901,177 |
|
|
$ |
(4,820,029 |
) |
|
$ |
10,799,120 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Six Months Ended June 30, 2009
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CASH PROVIDED FROM OPERATING ACTIVITIES
|
|
$ |
285,284 |
|
|
$ |
314,041 |
|
|
$ |
221,625 |
|
|
$ |
(8,734 |
) |
|
$ |
812,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
347,710 |
|
|
|
333,965 |
|
|
|
- |
|
|
|
681,675 |
|
Short-term
borrowings, net
|
|
|
98,880 |
|
|
|
- |
|
|
|
128,716 |
|
|
|
(82,587 |
) |
|
|
145,009 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(1,696 |
) |
|
|
(260,372 |
) |
|
|
(369,519 |
) |
|
|
8,734 |
|
|
|
(622,853 |
) |
Short-term
borrowings, net
|
|
|
- |
|
|
|
(82,587 |
) |
|
|
- |
|
|
|
82,587 |
|
|
|
- |
|
Net cash
provided from financing activities
|
|
|
97,184 |
|
|
|
4,751 |
|
|
|
93,162 |
|
|
|
8,734 |
|
|
|
203,831 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(694 |
) |
|
|
(332,789 |
) |
|
|
(301,484 |
) |
|
|
- |
|
|
|
(634,967 |
) |
Proceeds from
asset sales
|
|
|
- |
|
|
|
15,771 |
|
|
|
- |
|
|
|
- |
|
|
|
15,771 |
|
Sales of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
537,078 |
|
|
|
- |
|
|
|
537,078 |
|
Purchases of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
(550,730 |
) |
|
|
- |
|
|
|
(550,730 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(261,839 |
) |
|
|
20,669 |
|
|
|
- |
|
|
|
- |
|
|
|
(241,170 |
) |
Other
|
|
|
65 |
|
|
|
(22,448 |
) |
|
|
349 |
|
|
|
- |
|
|
|
(22,034 |
) |
Net cash used
for investing activities
|
|
|
(262,468 |
) |
|
|
(318,797 |
) |
|
|
(314,787 |
) |
|
|
- |
|
|
|
(896,052 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
120,000 |
|
|
|
(5 |
) |
|
|
- |
|
|
|
- |
|
|
|
119,995 |
|
Cash and cash
equivalents at beginning of period
|
|
|
- |
|
|
|
39 |
|
|
|
- |
|
|
|
- |
|
|
|
39 |
|
Cash and cash
equivalents at end of period
|
|
$ |
120,000 |
|
|
$ |
34 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
120,034 |
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30, 2008
|
|
FES
|
|
|
FGCO
|
|
|
NGC
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CASH PROVIDED FROM (USED FOR)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
$ |
(138,894 |
) |
|
$ |
109,372 |
|
|
$ |
82,857 |
|
|
$ |
(8,316 |
) |
|
$ |
45,019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Financing-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
- |
|
|
|
276,235 |
|
|
|
179,500 |
|
|
|
- |
|
|
|
455,735 |
|
Short-term
borrowings, net
|
|
|
700,000 |
|
|
|
535,705 |
|
|
|
416,938 |
|
|
|
- |
|
|
|
1,652,643 |
|
Redemptions
and Repayments-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
(792 |
) |
|
|
(285,567 |
) |
|
|
(180,334 |
) |
|
|
8,316 |
|
|
|
(458,377 |
) |
Common stock
dividend payment
|
|
|
(10,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(10,000 |
) |
Net cash
provided from financing activities
|
|
|
689,208 |
|
|
|
526,373 |
|
|
|
416,104 |
|
|
|
8,316 |
|
|
|
1,640,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
additions
|
|
|
(20,176 |
) |
|
|
(584,151 |
) |
|
|
(548,175 |
) |
|
|
- |
|
|
|
(1,152,502 |
) |
Proceeds from
asset sales
|
|
|
- |
|
|
|
10,875 |
|
|
|
- |
|
|
|
- |
|
|
|
10,875 |
|
Sales of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
384,692 |
|
|
|
- |
|
|
|
384,692 |
|
Purchases of
investment securities held in trusts
|
|
|
- |
|
|
|
- |
|
|
|
(404,502 |
) |
|
|
- |
|
|
|
(404,502 |
) |
Loan
repayments from (loans to) associated companies, net
|
|
|
(530,508 |
) |
|
|
- |
|
|
|
69,012 |
|
|
|
- |
|
|
|
(461,496 |
) |
Other
|
|
|
370 |
|
|
|
(62,469 |
) |
|
|
12 |
|
|
|
- |
|
|
|
(62,087 |
) |
Net cash used
for investing activities
|
|
|
(550,314 |
) |
|
|
(635,745 |
) |
|
|
(498,961 |
) |
|
|
- |
|
|
|
(1,685,020 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 were effective as of the end of
the period covered by this report.
(b)
CHANGES IN INTERNAL CONTROLS
During the quarter
ended June 30, 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 were effective as of the end of
the period covered by this report.
(b) CHANGES
IN INTERNAL CONTROLS
During the quarter
ended June 30, 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, and Quarterly Report
on Form 10-Q for the quarter ended March 31, 2009, include a detailed
discussion of its risk factors. For the quarter ended June 30, 2009, there
have been no material changes to these risk factors.
ITEM
2. UNREGISTERED SALES OF
EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The
table below includes information on a monthly basis regarding purchases made by
FirstEnergy of its common stock during the second quarter of 2009.
|
|
Period
|
|
|
|
April
|
|
May
|
|
June
|
|
Second
Quarter
|
|
Total Number
of Shares Purchased (a)
|
|
25,666
|
|
26,682
|
|
436,452
|
|
488,800
|
|
Average Price
Paid per Share
|
|
$39.08
|
|
$39.86
|
|
$38.68
|
|
$38.76
|
|
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.
|
ITEM
4. SUBMISSION OF MATTERS
TO A VOTE OF SECURITY HOLDERS
(a)
|
The annual
meeting of FirstEnergy shareholders was held on May 19,
2009.
|
(b)
|
At this
meeting, the following persons (comprising all members of the Board) were
elected to FirstEnergy's Board of Directors until the Annual Meeting of
Shareholders in 2010 and until their successors have been
elected:
|
|
|
Number
of Votes
|
|
|
|
For
|
|
Withheld
|
|
|
|
|
|
|
|
Paul T.
Addison
|
|
|
115,453,478
|
|
|
107,532,193
|
|
Anthony J.
Alexander
|
|
|
115,319,952
|
|
|
107,665,719
|
|
Michael J.
Anderson
|
|
|
115,182,823
|
|
|
107,802,848
|
|
Dr. Carol A.
Cartwright
|
|
|
107,462,102
|
|
|
115,523,569
|
|
William T.
Cottle
|
|
|
108,415,632
|
|
|
114,570,039
|
|
Robert B.
Heisler, Jr.
|
|
|
114,997,860
|
|
|
107,987,811
|
|
Ernest J.
Novak, Jr.
|
|
|
115,243,864
|
|
|
107,741,807
|
|
Catherine A.
Rein
|
|
|
114,687,786
|
|
|
108,297,885
|
|
George M.
Smart
|
|
|
107,568,271
|
|
|
115,417,400
|
|
Wes M.
Taylor
|
|
|
115,400,913
|
|
|
107,584,758
|
|
Jesse T.
Williams, Sr.
|
|
|
107,935,870
|
|
|
115,049,801
|
|
(c)
|
(i)
|
At this
meeting, the appointment of PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as auditor for the 2009 fiscal
year was ratified:
|
Number
of Votes
|
For
|
|
Against
|
|
Abstentions
|
|
|
|
|
|
219,754,593
|
|
2,100,019
|
|
1,131,567
|
|
(ii)
|
At this
meeting, a shareholder proposal recommending that the Board of Directors
adopt simple majority shareholder voting was approved (approval required a
favorable vote of a majority of the votes
cast):
|
Number
of Votes
|
|
|
|
|
|
|
Broker
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
155,741,944
|
|
36,909,437
|
|
2,395,715
|
|
27,939,083
|
Based on this
result, the Board of Directors will further review this proposal.
(iii)
|
At this
meeting, a shareholder proposal recommending that the Board of Directors
amend the company's bylaws to reduce the percentage of shareholders
required to call a special shareholder meeting was approved (approval
required a favorable vote of a majority of the votes
cast):
|
Number
of Votes
|
|
|
|
|
|
|
Broker
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
110,529,850
|
|
82,017,229
|
|
2,499,618
|
|
27,939,482
|
Based on this
result, the Board of Directors will further review this proposal.
(iv)
|
At this
meeting, a shareholder proposal recommending that the Board of Directors
adopt a policy establishing an engagement process with proponents of
shareholder proposals that are supported by a majority of the votes cast,
excluding abstentions and broker non-votes, at any annual meeting was not
approved (approval required a favorable vote of a majority of the votes
cast):
|
Number
of Votes
|
|
|
|
|
|
|
Broker
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
88,329,182
|
|
103,545,248
|
|
3,172,666
|
|
27,939,083
|
(v)
|
At this
meeting, a shareholder proposal recommending that the Board of Directors
adopt a majority vote standard for the election of directors was approved
(approval required a favorable vote of a majority of the votes
cast):
|
Number
of Votes
|
|
|
|
|
|
|
Broker
|
For
|
|
Against
|
|
Abstentions
|
|
Non-Votes
|
|
|
|
|
|
|
|
128,558,349
|
|
64,162,961
|
|
2,325,387
|
|
27,939,482
|
Based on this
result, the Board of Directors will further review this proposal.
ITEM
6. EXHIBITS
Exhibit
Number
|
|
|
|
|
|
|
|
|
FirstEnergy
|
|
|
|
10.1
|
Form of
Written Consent for Named Executive Officers dated June 1,
2009
|
|
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 period ended June 30, 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
1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank
of New York Mellon Trust Company, N.A., as trustee (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.1)
|
|
4.2
|
First
Supplemental Indenture, dated as of June 15, 2009, to Open-End Mortgage,
General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by
and between FirstEnergy Nuclear Generation Corp. and The Bank of New York
Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’
Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit
4.2)
|
|
4.2(a)
|
Form of First
Mortgage Bonds, Guarantee Series A of 2009 due 2033 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(a))
|
|
4.2(b)
|
Form of First
Mortgage Bonds, Guarantee Series B of 2009 due 2011 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(b))
|
|
4.2(c)
|
Form of First
Mortgage Bonds, Collateral Series A of 2009 due 2010 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(c))
|
|
4.2(d)
|
Form of First
Mortgage Bonds, Collateral Series B of 2009 due 2010 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(d))
|
|
4.2(e)
|
Form of First
Mortgage Bonds, Collateral Series C of 2009 due 2010 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(e))
|
|
4.2(f)
|
Form of First
Mortgage Bonds, Collateral Series D of 2009 due 2010 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(f))
|
|
4.2(g)
|
Form of First
Mortgage Bonds, Collateral Series E of 2009 due 2010 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(g))
|
|
4.2(h)
|
Form of First
Mortgage Bonds, Collateral Series F of 2009 due 2011 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(h))
|
|
4.2(i)
|
Form of First
Mortgage Bonds, Collateral Series G of 2009 due 2011 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(i))
|
|
4.3
|
Second
Supplemental Indenture, dated as of June 30, 2009, to Open-End Mortgage,
General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by
and between FirstEnergy Nuclear Generation Corp. and The Bank of New York
Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’
Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit
4.1)
|
|
4.3(a)
|
Form of First
Mortgage Bonds, Guarantee Series C of 2009 due 2033 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit
4.1(a))
|
|
4.3(b)
|
Form of First
Mortgage Bonds, Guarantee Series D of 2009 due 2033 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.1(b))
|
|
4.3(c)
|
Form of First
Mortgage Bonds, Guarantee Series E of 2009 due 2033 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.1(c))
|
|
4.3(d)
|
Form of First
Mortgage Bonds, Collateral Series H of 2009 due 2011 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.1(d))
|
|
4.3(e)
|
Form of First
Mortgage Bonds, Collateral Series I of 2009 due 2011 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.1(e))
|
|
4.3(f)
|
Form of First
Mortgage Bonds, Collateral Series J of 2009 due 2010 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.1(f))
|
|
4.4
|
Fourth
Supplemental Indenture, dated as of June 1, 2009, to Open-End Mortgage,
General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008,
by and between FirstEnergy Generation Corp. and The Bank of New York
Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust
Company, N.A.), as trustee (incorporated by reference to FES’ Form 8-K
filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit
4.3(a))
|
|
4.4(a)
|
Form of First
Mortgage Bonds, Guarantee Series C of 2009 due 2018 (incorporated by
reference to FES Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01, Exhibit 4.3(a))
|
|
4.4(b)
|
Form of First
Mortgage Bonds, Guarantee Series D of 2009 due 2029 (incorporated by
reference to FES Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01, Exhibit 4.3(b))
|
|
4.4(c)
|
Form of First
Mortgage Bonds, Guarantee Series E of 2009 due 2029 (incorporated by
reference to FES Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01, Exhibit 4.3(c))
|
|
4.4(d)
|
Form of First
Mortgage Bonds, Collateral Series B of 2009 due 2011 (incorporated by
reference to FES Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01, Exhibit 4.3(d))
|
|
4.4(e)
|
Form of First
Mortgage Bonds, Collateral Series C of 2009 due 2011 (incorporated by
reference to FES Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01, Exhibit 4.3(e))
|
|
4.5
|
Fifth
Supplemental Indenture, dated as of June 30, 2009, to Open-End Mortgage,
General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008,
by and between FirstEnergy Generation Corp. and The Bank of New York
Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust
Company, N.A.), as trustee (incorporated by reference to FES’ Form 8-K
(SEC File No. 333-145140-01) filed on July 6, 2009, Exhibit
4.2)
|
|
4.5(a)
|
Form of First
Mortgage Bonds, Guarantee Series F of 2009 due 2047 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(a))
|
|
4.5(b)
|
Form of First
Mortgage Bonds, Guarantee Series G of 2009 due 2018 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(b))
|
|
4.5(c)
|
Form of First
Mortgage Bonds, Guarantee Series H of 2009 due 2018 (incorporated by
reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No.
333-145140-01), Exhibit 4.2(c))
|
|
10.2
|
Master SSO
Supply Agreement, entered into May 18, 2009, by and between The Cleveland
Electric Illuminating Company, the Toledo Edison Company and Ohio Edison
Company and FirstEnergy Solutions Corp.
|
|
(A)
10.2
|
Form of
Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as
of June 12, 2009, by and among FirstEnergy Nuclear Generation Corp.,
FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the
banks party thereto, and Barclays Bank PLC, as fronting Bank and
administrative agent, to Letter of Credit and Reimbursement Agreement
dated as of December 16, 2005 (incorporated by reference to FES’ Form 8-K
filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit
10.1)
|
|
(B)
10.3
|
Form of
Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as
of June 12, 2009, by and among FirstEnergy Generation Corp., FirstEnergy
Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party
thereto, Barclays Bank PLC, as fronting Bank and administrative agent and
KeyBank National Association, as syndication agent, to Letter of Credit
and Reimbursement Agreement dated as of April 3, 2006 (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 10.2)
|
|
|
10.4
|
Surplus Margin
Guaranty, dated as of June 16, 2009, made by FirstEnergy Nuclear
Generation Corp. in favor of The Cleveland Electric Illuminating Company,
The Toledo Edison Company and Ohio Edison Company (incorporated by
reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No.
333-145140-01), Exhibit 10.3)
|
|
|
12
|
Fixed charge
ratios
|
|
|
31.1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
31.2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-14(a)
|
|
|
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. Section 1350
|
|
OE
|
|
|
|
10.2
|
Master SSO
Supply Agreement, entered into May 18, 2009, by and between The Cleveland
Electric Illuminating Company, the Toledo Edison Company and Ohio Edison
Company and FirstEnergy Solutions Corp.
|
|
|
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
|
|
|
|
10.2
|
Master SSO
Supply Agreement, entered into May 18, 2009, by and between The Cleveland
Electric Illuminating Company, the Toledo Edison Company and Ohio Edison
Company and FirstEnergy Solutions Corp.
|
|
|
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
|
|
|
|
10.2
|
Master SSO
Supply Agreement, entered into May 18, 2009, by and between The Cleveland
Electric Illuminating Company, the Toledo Edison Company and Ohio Edison
Company and FirstEnergy Solutions Corp.
|
|
|
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
|
|
|
|
|
(A)
|
Four
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to four other series of pollution control revenue refunding bonds issued
by the Ohio Water Development Authority, the Ohio Air Quality Authority
and Beaver County Industrial Development Authority, Pennsylvania, relating
to pollution control notes of FirstEnergy Nuclear Generation
Corp.
|
|
|
|
|
(B)
|
Three
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to three other series of pollution control revenue refunding bonds issued
by the Ohio Water Development Authority and the Beaver County Industrial
Development Authority relating to pollution control notes of FirstEnergy
Generation Corp. and FirstEnergy Nuclear Generation
Corp.
|
* 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, 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.
August 3,
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)
|