form10k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D. C. 20549
FORM
10-K
(Mark
One)
[X] ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
For
the fiscal year ended December 31, 2009
OR
[
] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
For
the transition period from __________________ to
___________________
Commission
|
Registrant;
State of Incorporation;
|
I.R.S.
Employer
|
File Number
|
Address; and Telephone
Number
|
Identification No.
|
|
|
|
333-21011
|
FIRSTENERGY
CORP.
|
34-1843785
|
|
(An
Ohio Corporation)
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
|
|
333-145140-01
|
FIRSTENERGY
SOLUTIONS CORP.
|
31-1560186
|
|
(An
Ohio Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
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|
1-2578
|
OHIO
EDISON COMPANY
|
34-0437786
|
|
(An
Ohio Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
|
|
1-2323
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
34-0150020
|
|
(An
Ohio Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
|
|
1-3583
|
THE
TOLEDO EDISON COMPANY
|
34-4375005
|
|
(An
Ohio Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
|
|
1-3141
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
21-0485010
|
|
(A
New Jersey Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
|
|
1-446
|
METROPOLITAN
EDISON COMPANY
|
23-0870160
|
|
(A
Pennsylvania Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
|
|
|
1-3522
|
PENNSYLVANIA
ELECTRIC COMPANY
|
25-0718085
|
|
(A
Pennsylvania Corporation)
|
|
|
c/o
FirstEnergy Corp.
|
|
|
76
South Main Street
|
|
|
Akron,
OH 44308
|
|
|
Telephone
(800)736-3402
|
|
SECURITIES
REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
|
|
|
|
Name
of Each Exchange
|
|
|
|
|
|
|
|
|
|
|
FirstEnergy
Corp.
|
|
Common
Stock, $0.10 par value
|
|
New
York Stock Exchange
|
SECURITIES
REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
Edison Company
|
|
Common
Stock, no par value per share
|
|
|
|
|
|
|
|
The
Cleveland Electric Illuminating Company
|
|
Common
Stock, no par value per share
|
|
|
|
|
|
|
|
The
Toledo Edison Company
|
|
Common
Stock, $5.00 par value per share
|
|
|
|
|
|
|
|
Jersey
Central Power & Light Company
|
|
Common
Stock, $10.00 par value per share
|
|
|
|
|
|
|
|
Metropolitan
Edison Company
|
|
Common
Stock, no par value per share
|
|
|
|
|
|
|
|
Pennsylvania
Electric Company
|
|
Common
Stock, $20.00 par value per share
|
|
|
|
|
|
|
|
FirstEnergy
Solutions Corp.
|
|
Common
Stock, no par value per share
|
|
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes
(X) No
( )
|
FirstEnergy
Corp.
|
Yes ( )
No (X)
|
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
|
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes
( )
No (X)
|
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, FirstEnergy
Solutions Corp.
|
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 ( )
|
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, FirstEnergy
Solutions Corp.
|
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
(X)
|
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
|
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
definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer
(X)
|
FirstEnergy
Corp.
|
Accelerated
filer
( )
|
N/A
|
Non-accelerated
filer (do not check if a smaller reporting company)
(X)
|
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
|
Smaller
reporting company
( )
|
N/A
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).
Yes
( )
No (X)
|
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
|
State
the aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and ask price of such common equity, as of the
last business day of the registrant’s most recently completed second fiscal
quarter.
FirstEnergy
Corp., $11,812,372,021 as of June 30, 2009; and for all other registrants,
none.
Indicate
the number of shares outstanding of each of the registrant’s classes of common
stock, as of the latest practicable date.
|
|
OUTSTANDING
|
|
CLASS
|
|
|
|
FirstEnergy
Corp., $.10 par value
|
|
|
304,835,407 |
|
FirstEnergy
Solutions Corp., no par value
|
|
|
7 |
|
Ohio
Edison Company, no par value
|
|
|
60 |
|
The
Cleveland Electric Illuminating Company, no par value
|
|
|
67,930,743 |
|
The
Toledo Edison Company, $5 par value
|
|
|
29,402,054 |
|
Jersey
Central Power & Light Company, $10 par value
|
|
|
13,628,447 |
|
Metropolitan
Edison Company, no par value
|
|
|
859,500 |
|
Pennsylvania
Electric Company, $20 par value
|
|
|
4,427,577 |
|
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.
Documents
incorporated by reference (to the extent indicated herein):
|
|
PART
OF FORM 10-K INTO WHICH
|
|
|
|
|
|
|
FirstEnergy
Corp. Annual Report to Stockholders for
|
|
|
the
fiscal year ended December 31, 2009
|
|
Part
II
|
|
|
|
Proxy
Statement for 2010 Annual Meeting of Stockholders
|
|
|
to
be held May 18, 2010
|
|
Part
III
|
This
combined Form 10-K 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 I(1)(a) and (b) of Form 10-K and are
therefore filing this Form 10-K with the reduced disclosure format specified in
General Instruction I(2) to Form 10-K.
Forward-Looking Statements:
This Form 10-K 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:
|
·
|
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.
|
|
·
|
The
impact of the regulatory process on the pending matters in Ohio,
Pennsylvania and New Jersey.
|
|
·
|
Business
and regulatory impacts from ATSI’s realignment into
PJM.
|
|
·
|
Economic
or weather conditions affecting future sales and
margins.
|
|
·
|
Changes
in markets for energy services.
|
|
·
|
Changing
energy and commodity market prices and
availability.
|
|
·
|
Replacement
power costs being higher than anticipated or inadequately
hedged.
|
|
·
|
The
continued ability of FirstEnergy’s regulated utilities to collect
transition and other charges or to recover increased transmission
costs.
|
|
·
|
Operation
and maintenance costs being higher than
anticipated.
|
|
·
|
Other
legislative and regulatory changes, and revised environmental
requirements, including possible GHG emission
regulations.
|
|
·
|
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.
|
|
·
|
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 similar regulatory initiatives or
actions.
|
|
·
|
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.
|
|
·
|
Ultimate
resolution of Met-Ed’s and Penelec’s TSC filings with the
PPUC.
|
|
·
|
The
continuing availability of generating units and their ability to operate
at or near full capacity.
|
|
·
|
The
ability to comply with applicable state and federal reliability standards
and energy efficiency mandates.
|
|
·
|
The
ability to accomplish or realize anticipated benefits from strategic goals
(including employee workforce
initiatives).
|
|
·
|
The
ability to improve electric commodity margins and to experience growth in
the distribution business.
|
|
·
|
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 amounts that are larger than currently
anticipated.
|
|
·
|
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.
|
|
·
|
Changes
in general economic conditions affecting the
registrants.
|
|
·
|
The
state of the capital and credit markets affecting the
registrants.
|
|
·
|
Interest
rates and any actions taken by credit rating agencies that could
negatively affect the registrants’ access to financing or their costs and
increase requirements to post additional collateral to support outstanding
commodity positions, LOCs and other financial
guarantees.
|
|
·
|
The
continuing decline of the national and regional economy and its impact on
the registrants’ major industrial and commercial
customers.
|
|
·
|
Issues
concerning the soundness of financial institutions and counterparties with
which the registrants do business.
|
|
·
|
The
expected timing and likelihood of completion of the proposed merger with
Allegheny Energy, Inc., including the timing, receipt and terms and
conditions of any required governmental and regulatory approvals of the
proposed merger that could reduce anticipated benefits or cause the
parties to abandon the merger, the diversion of management's time and
attention from our ongoing business during this time period, the ability
to maintain relationships with customers, employees or suppliers as well
as the ability to successfully integrate the businesses and realize cost
savings and any other synergies and the risk that the credit ratings of
the combined company or its subsidiaries may be different from what the
companies expect.
|
|
·
|
The
risks and other factors discussed from time to time in the registrants’
SEC filings, and other similar
factors.
|
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.
GLOSSARY
OF TERMS
The
following abbreviations and acronyms are used in this report to identify
FirstEnergy Corp. and its current and former subsidiaries:
ATSI
|
American
Transmission Systems, Incorporated, owns and operates transmission
facilities
|
CEI
|
The
Cleveland Electric Illuminating Company, an Ohio electric utility
operating subsidiary
|
FENOC
|
FirstEnergy
Nuclear Operating Company, operates nuclear generating
facilities
|
FES
|
FirstEnergy
Solutions Corp., provides energy-related products and
services
|
FESC
|
FirstEnergy
Service Company, provides legal, financial and other corporate support
services
|
FEV
|
FirstEnergy
Ventures Corp., invests in certain unregulated enterprises and business
ventures
|
FGCO
|
FirstEnergy
Generation Corp., owns and operates non-nuclear generating
facilities
|
FirstEnergy
|
FirstEnergy
Corp., a public utility holding company
|
GPU
|
GPU,
Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with
FirstEnergy on
November 7,
2001
|
JCP&L
|
Jersey
Central Power & Light Company, a New Jersey electric utility operating
subsidiary
|
JCP&L
Transition
Funding
|
JCP&L
Transition Funding LLC, a Delaware limited liability company and issuer of
transition bonds
|
JCP&L
Transition
Funding
II
|
JCP&L
Transition Funding II LLC, a Delaware limited liability company and issuer
of transition bonds
|
Met-Ed
|
Metropolitan
Edison Company, a Pennsylvania electric utility operating
subsidiary
|
NGC
|
FirstEnergy
Nuclear Generation Corp., owns nuclear generating
facilities
|
OE
|
Ohio
Edison Company, an Ohio electric utility operating
subsidiary
|
Ohio
Companies
|
CEI,
OE and TE
|
Penelec
|
Pennsylvania
Electric Company, a Pennsylvania electric utility operating
subsidiary
|
Penn
|
Pennsylvania
Power Company, a Pennsylvania electric utility operating subsidiary of
OE
|
Pennsylvania
Companies
|
Met-Ed,
Penelec and Penn
|
PNBV
|
PNBV
Capital Trust, a special purpose entity created by OE in
1996
|
Shelf
Registrants
|
FirstEnergy,
OE, CEI, TE, JCP&L, Met-Ed and Penelec
|
Shippingport
|
Shippingport
Capital Trust, a special purpose entity created by CEI and TE in
1997
|
Signal
Peak
|
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
|
Waverly
|
The
Waverly Power and Light Company, a wholly owned subsidiary of
Penelec
|
|
|
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
|
ARO
|
Asset
Retirement Obligation
|
BGS
|
Basic
Generation Service
|
CAA
|
Clean
Air Act
|
CAIR
|
Clean
Air Interstate Rule
|
CAMR
|
Clean
Air Mercury Rule
|
CAVR
|
Clean
Air Visibility Rule
|
CBP
|
Competitive
Bid Process
|
CMEC
|
Capacity
market Evolution Committee
|
CO2
|
Carbon
dioxide
|
CTC
|
Competitive
Transition Charge
|
DOE
|
United
States Department of Energy
|
DOJ
|
United
States Department of Justice
|
DCPD
|
Deferred
Compensation Plan for Outside Directors
|
DPA
|
Department
of the Public Advocate, Division of Rate Counsel (New
Jersey)
|
ECAR
|
East
Central Area Reliability Coordination Agreement
|
EDCP
|
Executive
Deferred Compensation Plan
|
EE&C
|
Energy
Efficiency and Conservation
|
EMP
|
Energy
Master Plan
|
EPA
|
United
States Environmental Protection Agency
|
EPACT
|
Energy
Policy Act of 2005
|
EPRI
|
Electric
Power Research Institute
|
ESOP
|
Employee
Stock Ownership Plan
|
ESP
|
Electric
Security Plan
|
FASB
|
Financial
Accounting Standards Board
|
GLOSSARY
OF TERMS, Cont'd.
FERC
|
Federal
Energy Regulatory Commission
|
FMB
|
First
Mortgage Bond
|
FPA
|
Federal
Power Act
|
FRR
|
Fixed
Resource Requirement
|
GAAP
|
Accounting
Principles Generally Accepted in the United States
|
GHG
|
Greenhouse
Gases
|
IBEW
|
International
Brotherhood of Electrical Workers
|
IFRS
|
International
Financial Reporting Standards
|
IRS
|
Internal
Revenue Service
|
JCARR
|
Joint
Committee on Agency Review
|
kV
|
Kilovolt
|
KWH
|
Kilowatt-hours
|
LED
|
Light-emitting
Diode
|
LIBOR
|
London
Interbank Offered Rate
|
LOC
|
Letter
of Credit
|
LTIP
|
Long-Term
Incentive Plan
|
MACT
|
Maximum
Achievable Control Technology
|
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
|
NEIL
|
Nuclear
Electric Insurance Limited
|
NERC
|
North
American Electric Reliability Corporation
|
NJBPU
|
New
Jersey Board of Public Utilities
|
NNSR
|
Non-Attainment
New Source Review
|
NOPEC
|
Northeast
Ohio Public Energy Council
|
NOV
|
Notice
of Violation
|
NOX
|
Nitrogen
Oxide
|
NRC
|
Nuclear
Regulatory Commission
|
NSR
|
New
Source Review
|
NUG
|
Non-Utility
Generation
|
NUGC
|
Non-Utility
Generation Charge
|
OCC
|
Ohio
Consumers’ Counsel
|
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
|
PSD
|
Prevention
of Significant Deterioration
|
PUCO
|
Public
Utilities Commission of Ohio
|
QSPE
|
Qualifying
Special-Purpose Entity
|
RCP
|
Rate
Certainty Plan
|
RECs
|
Renewable
Energy Credits
|
RFP
|
Request
for Proposal
|
RPM
|
Reliability
Pricing Model
|
RTEP
|
Regional
Transmission Expansion Plan
|
RTC
|
Regulatory
Transition Charge
|
RTO
|
Regional
Transmission Organization
|
S&P
|
Standard
& Poor's Ratings Service
|
SB221
|
Amended
Substitute Senate Bill 221
|
SBC
|
Societal
Benefits Charge
|
SEC
|
U.S.
Securities and Exchange Commission
|
SECA
|
Seams
Elimination Cost Adjustment
|
SIP
|
State
Implementation Plan(s) Under the Clean Air Act
|
SNCR
|
Selective
Non-Catalytic Reduction
|
SO2
|
Sulfur
Dioxide
|
SRECs
|
Solar
Renewable Energy Credits
|
TBC
|
Transition
Bond Charge
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GLOSSARY
OF TERMS, Cont'd.
TMI-2
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Three
Mile Island Unit 2
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TSC
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Transmission
Service Charge
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VERO
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Voluntary
Enhanced Retirement Option
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VIE
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Variable
Interest Entity
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FORM
10-K TABLE OF CONTENTS
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Page
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Glossary
of Terms
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i-iii
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Part
I
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Item
1.
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Business
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1-26
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The
Company
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1-2
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Utility
Regulation
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2-13
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State
Regulation
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2
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Federal
Regulation
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3
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Regulatory
Accounting
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3-4
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Reliability
Initiatives
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4
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Ohio
Regulatory Matters
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4-6
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Pennsylvania
Regulatory Matters
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6-8
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New
Jersey Regulatory Matters
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8-9
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FERC
Matters
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9-13
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Capital
Requirements
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13-15
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Nuclear
Operating Licenses
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15-16
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Nuclear
Regulation
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16
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Nuclear
Insurance
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16-17
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Environmental
Matters
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17-21
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Fuel
Supply
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21-22
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System
Demand
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22-23
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Supply
Plan
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23
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Regional
Reliability
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23
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Competition
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23-24
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Research
and Development
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24
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Executive
Officers
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25
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Employees
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26
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FirstEnergy
Web Site
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26
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Item
1A.
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Risk
Factors
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27-41
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Item
1B.
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Unresolved
Staff Comments
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41
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Item 2.
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Properties
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41-43
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Item 3.
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Legal
Proceedings
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43
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Item 4.
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Submission
of Matters to a Vote of Security Holders
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43
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Part
II
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Item 5.
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Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
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43-44
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Item 6.
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Selected
Financial Data
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44-45
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Item 7.
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Management’s
Discussion and Analysis of Registrant and Subsidiaries
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45-130
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FirstEnergy
Corp.
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47-105
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FirstEnergy
Solutions Corp.
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106-110
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Ohio
Edison Company
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111-113
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The
Cleveland Electric Illuminating Company
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114-115
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The
Toledo Edison Company
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116-118
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Jersey
Central Power & Light Company
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119-122
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Metropolitan
Edison Company
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123-126
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Pennsylvania
Electric Company
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127-130
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Item 7A.
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Quantitative
and Qualitative Disclosures About Market Risk
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131
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Item 8.
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Financial
Statements and Supplementary Data
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132-186
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Management Reports
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132-139
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Report
of Independent Registered Public Accounting Firm.
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140-147
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TABLE
OF CONTENTS (Cont'd)
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Page
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Financial
Statements
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FirstEnergy Corp.
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Consolidated
Statements of Income
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148
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Consolidated
Balance Sheets
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149
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Consolidated
Statements of Common Stockholders Equity
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150
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Consolidated
Statements of Cash Flows
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151
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FirstEnergy Solutions
Corp.
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Consolidated
Statements of Income
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152
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Consolidated
Balance Sheets
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153
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Consolidated
Statements of Capitalization
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154
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Consolidated
Statements of Common Stockholders Equity
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155
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Consolidated
Statements of Cash Flows
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156
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Ohio Edison
Company
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Consolidated
Statements of Income
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157
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Consolidated
Balance Sheets
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158
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Consolidated
Statements of Capitalization
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159
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Consolidated
Statements of Common Stockholders Equity
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160
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Consolidated
Statements of Cash Flows
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161
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The Cleveland Electric
Illuminating Company
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Consolidated
Statements of Income
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162
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Consolidated
Balance Sheets
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163
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Consolidated
Statements of Capitalization
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164
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Consolidated
Statements of Common Stockholders Equity
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165
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Consolidated
Statements of Cash Flows
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166
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The Toledo Edison
Company
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Consolidated
Statements of Income
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167
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Consolidated
Balance Sheets
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168
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Consolidated
Statements of Capitalization
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169
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Consolidated
Statements of Common Stockholders Equity
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170
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Consolidated
Statements of Cash Flows
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171
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Jersey Central Power & Light
Company
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Consolidated
Statements of Income
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172
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Consolidated
Balance Sheets
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173
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Consolidated
Statements of Capitalization
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174
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Consolidated
Statements of Common Stockholders Equity
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175
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Consolidated
Statements of Cash Flows
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176
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Metropolitan Edison
Company
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Consolidated
Statements of Income
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177
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Consolidated
Balance Sheets
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178
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Consolidated
Statements of Capitalization
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179
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Consolidated
Statements of Common Stockholders Equity
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180
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Consolidated
Statements of Cash Flows
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181
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Pennsylvania Electric
Company
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Consolidated
Statements of Income
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182
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Consolidated
Balance Sheets
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183
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Consolidated
Statements of Capitalization
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184
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Consolidated
Statements of Common Stockholders Equity
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185
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Consolidated
Statements of Cash Flows
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186
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TABLE
OF CONTENTS (Cont'd)
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Page
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Combined
Notes to Consolidated Financial Statements
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187-254
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Item 9.
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Changes
In and Disagreements with Accountants on Accounting and Financial
Disclosure
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255
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Item 9A.
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Controls
and Procedures - FirstEnergy
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255
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Item 9A(T).
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Controls
and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and
Penelec
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255
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Item
9B.
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Other
Information
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255
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Part
III
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Item 10.
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Directors,
Executive Officers and Corporate Governance
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256
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Item 11.
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Executive
Compensation
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256
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Item 12.
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Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
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256
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Item 13.
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Certain
Relationships and Related Transactions, and Director
Independence
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256
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Item
14.
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Principal
Accounting Fees and Services
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256
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Part
IV
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Item 15.
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Exhibits,
Financial Statement Schedules
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Report
of Independent Registered Public Accounting Firm on Financial Statement
Schedule
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257-293
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PART
I
ITEM
1. BUSINESS
Proposed
Merger with Allegheny Energy, Inc.
On
February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger
(Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its
wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland
corporation (Allegheny). Upon the terms and subject to the conditions set forth
in the Merger Agreement, Merger Sub will merge with and into Allegheny with
Allegheny continuing as the surviving corporation and a wholly-owned subsidiary
of FirstEnergy. Pursuant to the Merger Agreement, upon the closing of
the merger, each issued and outstanding share of Allegheny common stock,
including grants of restricted common stock, will automatically be converted
into the right to receive 0.667 of a share of common stock of FirstEnergy.
Completion of the merger is conditioned upon, among other things, shareholder
approval of both companies as well as expiration or termination of any
applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976 and approval by the FERC, the Maryland Public Service Commission, PPUC, the
Virginia State Corporation Commission and the West Virginia Public Service
Commission. FirstEnergy anticipates that the necessary approvals will be
obtained within 12 to 14 months. The Merger Agreement contains
certain termination rights for both FirstEnergy and Allegheny, and further
provides for the payment of fees and expenses upon termination under specified
circumstances. Further information concerning the proposed merger will be
included in a joint proxy statement/prospectus contained in the registration
statement on Form S-4 to be filed by FirstEnergy with the SEC in connection with
the merger. See Note 21 to the consolidated financial
statements.
The
Company
FirstEnergy
Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy’s
principal business is the holding, directly or indirectly, of all of the
outstanding common stock of its eight principal electric utility operating
subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec; and of its
generating and marketing subsidiary, FES. FirstEnergy’s consolidated revenues
are primarily derived from electric service provided by its utility operating
subsidiaries and the revenues of its other principal subsidiary, FES. In
addition, FirstEnergy holds all of the outstanding common stock of other direct
subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc.,
FirstEnergy Facilities Services Group, LLC, FirstEnergy Fiber Holdings Corp.,
GPU Power, Inc., GPU Nuclear, Inc., MARBEL Energy Corporation, and
FESC.
FES was
organized under the laws of the State of Ohio in 1997. FES provides
energy-related products and services to wholesale and retail customers in the
MISO and PJM markets. FES also owns and operates, through its subsidiary, FGCO,
FirstEnergy’s fossil and hydroelectric generating facilities and owns, through
its subsidiary, NGC, FirstEnergy’s nuclear generating facilities. FENOC, a
separate subsidiary of FirstEnergy, organized under the laws of the State of
Ohio in 1998, operates and maintains NGC’s nuclear generating facilities. FES
purchases the entire output of the generation facilities owned by FGCO and NGC,
as well as the output relating to leasehold interests of the Ohio Companies in
certain of those facilities that are subject to sale and leaseback arrangements
with non-affiliates, pursuant to full output, cost-of-service PSAs.
FirstEnergy’s
generating portfolio includes 13,970 MW of diversified capacity (FES –
13,770 MW and JCP&L – 200 MW). Within FES’ portfolio, approximately
7,469 MW, or 54.2%, consists of coal-fired capacity; 3,991 MW, or 29.0%,
consists of nuclear capacity; 1,599 MW, or 11.6%, consists of oil and natural
gas peaking units; 451 MW, or 3.3%, consists of hydroelectric capacity; and 260
MW, or 1.9%, consists of capacity from FGCO’s current 11.5% entitlement to the
generation output owned by the OVEC. FirstEnergy’s nuclear and non-nuclear
facilities are operated by FENOC and FGCO, respectively, and, except for
portions of certain facilities that are subject to the sale and leaseback
arrangements with non-affiliates referred to above for which the corresponding
output is available to FES through power sale agreements, are all owned directly
by NGC and FGCO, respectively. The FES generating assets are concentrated
primarily in Ohio, plus the bordering regions of Pennsylvania and Michigan. All
FES units are dedicated to MISO except the Beaver Valley Power Station, which is
designated as a PJM resource. Additionally, see FERC Matters for RTO
Consolidation.
FES,
FGCO and NGC comply with the regulations, orders, policies and practices
prescribed by the SEC and the FERC. In addition, NGC and FENOC comply with the
regulations, orders, policies and practices prescribed by the NRC.
The
Utilities’ combined service areas encompass approximately 36,100 square miles in
Ohio, New Jersey and Pennsylvania. The areas they serve have a combined
population of approximately 11.3 million.
OE was
organized under the laws of the State of Ohio in 1930 and owns property and does
business as an electric public utility in that state. OE engages in the
distribution and sale of electric energy to communities in a 7,000 square mile
area of central and northeastern Ohio. The area it serves has a population of
approximately 2.8 million. OE complies with the regulations, orders, policies
and practices prescribed by the SEC, FERC and PUCO.
OE owns
all of Penn’s outstanding common stock. Penn was organized under the laws of the
Commonwealth of Pennsylvania in 1930 and owns property and does business as an
electric public utility in that state. Penn is also authorized to do business in
the State of Ohio (see Item 2 – Properties). Penn furnishes electric service to
communities in 1,100 square miles of western Pennsylvania. The area it serves
has a population of approximately 0.4 million. Penn complies with the
regulations, orders, policies and practices prescribed by the FERC and PPUC.
CEI was
organized under the laws of the State of Ohio in 1892 and does business as an
electric public utility in that state. CEI engages in the distribution and sale
of electric energy in an area of approximately 1,600 square miles in
northeastern Ohio. The area it serves has a population of approximately
1.8 million. CEI complies with the regulations, orders, policies and
practices prescribed by the SEC, FERC and PUCO.
TE was
organized under the laws of the State of Ohio in 1901 and does business as an
electric public utility in that state. TE engages in the distribution and sale
of electric energy in an area of approximately 2,300 square miles in
northwestern Ohio. The area it serves has a population of approximately
0.8 million. TE complies with the regulations, orders, policies and
practices prescribed by the SEC, FERC and PUCO.
ATSI was
organized under the laws of the State of Ohio in 1998. ATSI owns transmission
assets that were formerly owned by the Ohio Companies and Penn. ATSI owns major,
high-voltage transmission facilities, which consist of approximately 5,821 pole
miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69
kV. Effective October 1, 2003, ATSI transferred operational control of its
transmission facilities to MISO. With its affiliation with MISO, ATSI plans,
operates, and maintains its transmission system in accordance with NERC
reliability standards, and applicable regulatory agencies to ensure reliable
service to customers. Additionally, see FERC Matters for RTO
Consolidation.
JCP&L
was organized under the laws of the State of New Jersey in 1925 and owns
property and does business as an electric public utility in that state.
JCP&L provides transmission and distribution services in 3,200 square miles
of northern, western and east central New Jersey. The area it serves has a
population of approximately 2.6 million. JCP&L complies with the
regulations, orders, policies and practices prescribed by the SEC, FERC and the
NJBPU.
Met-Ed
was organized under the laws of the Commonwealth of Pennsylvania in 1922 and
owns property and does business as an electric public utility in that state.
Met-Ed provides transmission and distribution services in 3,300 square miles of
eastern and south central Pennsylvania. The area it serves has a population of
approximately 1.3 million. Met-Ed complies with the regulations, orders,
policies and practices prescribed by the SEC, FERC and PPUC.
Penelec
was organized under the laws of the Commonwealth of Pennsylvania in 1919 and
owns property and does business as an electric public utility in that state.
Penelec provides transmission and distribution services in 17,600 square miles
of western, northern and south central Pennsylvania. The area it serves has a
population of approximately 1.6 million. Penelec, as lessee of the property
of its subsidiary, The Waverly Electric Light & Power Company, also serves
customers in Waverly, New York and its vicinity. Penelec complies with the
regulations, orders, policies and practices prescribed by the SEC, FERC and
PPUC.
FESC
provides legal, financial and other corporate support services to affiliated
FirstEnergy companies.
Reference
is made to Note 16, Segment Information, of the Notes to Consolidated
Financial Statements contained in Item 8 for information regarding
FirstEnergy's reportable segments.
Utility
Regulation
State
Regulation
Each of
the Utilities’ retail rates, conditions of service, issuance of securities and
other matters are subject to regulation in the state in which each company
operates – in Ohio by the PUCO, in New Jersey by the NJBPU and in Pennsylvania
by the PPUC. In addition, under Ohio law, municipalities may regulate rates of a
public utility, subject to appeal to the PUCO if not acceptable to the
utility.
As a
competitive retail electric supplier serving retail customers in Ohio,
Pennsylvania, New Jersey, Maryland, Michigan, and Illinois, FES is subject to
state laws applicable to competitive electric suppliers in those states,
including affiliate codes of conduct that apply to FES and its public utility
affiliates. In addition, if FES or any of its subsidiaries were to engage in the
construction of significant new generation facilities, they would also be
subject to state siting authority.
Federal
Regulation
With
respect to their wholesale and interstate electric operations and rates, the
Utilities, ATSI, FES, FGCO and NGC are subject to regulation by the FERC. Under
the FPA, the FERC regulates rates for interstate sales at wholesale,
transmission of electric power, accounting and other matters, including
construction and operation of hydroelectric projects. The FERC regulations
require ATSI, Met-Ed, JCP&L and Penelec to provide open access transmission
service at FERC-approved rates, terms and conditions. Transmission service over
ATSI’s facilities is provided by MISO under its open access transmission tariff,
and transmission service over Met-Ed’s, JCP&L’s and Penelec’s facilities is
provided by PJM under its open access transmission tariff. The FERC also
regulates unbundled transmission service to retail customers. Additionally, see
FERC Matters for RTO Consolidation.
The FERC
regulates the sale of power for resale in interstate commerce by granting
authority to public utilities to sell wholesale power at market-based rates upon
a showing that the seller cannot exert market power in generation or
transmission. FES, FGCO and NGC have been authorized by the FERC to sell
wholesale power in interstate commerce and have a market-based tariff on file
with the FERC. By virtue of this tariff and authority to sell wholesale power,
each company is regulated as a public utility under the FPA. However, consistent
with its historical practice, the FERC has granted FES, FGCO and NGC a waiver
from most of the reporting, record-keeping and accounting requirements that
typically apply to traditional public utilities. Along with market-based rate
authority, the FERC also granted FES, FGCO and NGC blanket authority to issue
securities and assume liabilities under Section 204 of the FPA. As a condition
to selling electricity on a wholesale basis at market-based rates, FES, FGCO and
NGC, like all other entities granted market-based rate authority, must file
electronic quarterly reports with the FERC, listing its sales transactions for
the prior quarter.
The
nuclear generating facilities owned and leased by NGC are subject to extensive
regulation by the NRC. The NRC subjects nuclear generating stations to
continuing review and regulation covering, among other things, operations,
maintenance, emergency planning, security and environmental and radiological
aspects of those stations. The NRC may modify, suspend or revoke operating
licenses and impose civil penalties for failure to comply with the Atomic Energy
Act, the regulations under such Act or the terms of the licenses. FENOC is the
licensee for these plants and has direct compliance responsibility for NRC
matters. FES controls the economic dispatch of NGC’s plants. See Nuclear
Regulation below.
Regulatory
Accounting
The
Utilities and ATSI recognize, as regulatory assets, costs which the FERC, PUCO,
PPUC and NJBPU have authorized for recovery from customers in future periods or
for which authorization is probable. Without the probability of such
authorization, costs currently recorded as regulatory assets would have been
charged to income as incurred. All regulatory assets are expected to be
recovered from customers under the Utilities' respective transition and
regulatory plans. Based on those plans, the Utilities continue to bill and
collect cost-based rates for their transmission and distribution services, which
remain regulated; accordingly, it is appropriate that the Utilities continue the
application of regulatory accounting to those operations.
FirstEnergy
accounts for the effects of regulation through the application of regulatory
accounting to its operating utilities since their rates:
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·
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are
established by a third-party regulator with the authority to set rates
that bind customers;
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can
be charged to and collected from
customers.
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An
enterprise meeting all of these criteria capitalizes costs that would otherwise
be charged to expense (regulatory assets) if the rate actions of its regulator
make it probable that those costs will be recovered in future revenue.
Regulatory accounting is applied only to the parts of the business that meet the
above criteria. If a portion of the business applying regulatory accounting no
longer meets those requirements, previously recorded net regulatory assets are
removed from the balance sheet in accordance with GAAP.
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:
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·
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restructuring
the electric generation business and allowing the Utilities' customers to
select a competitive electric generation supplier other than the
Utilities;
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·
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establishing
or defining the PLR obligations to customers in the Utilities' service
areas;
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·
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providing
the Utilities with the opportunity to recover potentially stranded
investment (or transition costs) not otherwise recoverable in a
competitive generation market;
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itemizing
(unbundling) the price of electricity into its component elements –
including generation, transmission, distribution and stranded costs
recovery charges;
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·
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continuing
regulation of the Utilities' transmission and distribution systems;
and
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·
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requiring
corporate separation of regulated and unregulated business
activities.
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Reliability
Initiatives
In 2005,
Congress amended the FPA 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 FPA 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
that could 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 Midwest ISO 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. Our MISO facilities are next due for the
periodic audit by ReliabilityFirst later this
year.
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
required 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 replied as requested on August 6, 2009.
JCP&L is not able at this time to predict what actions, if any, that the
NERC may take based on the data submittals 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 (out of approximately 20,000 reportable
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. The NERC approved FirstEnergy’s
mitigation plan on August 19, 2009, and submitted it to the FERC for approval on
August 19, 2009. FirstEnergy is not able at this time to predict what actions or
penalties, if any, that ReliabilityFirst will propose for this
self-reported violation.
Ohio
Regulatory Matters
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. On January 21, 2009, the PUCO granted the Ohio Companies’
application in part 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. The PUCO has not yet issued a substantive Entry on
Rehearing. 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 rate plan then
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 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 regulatory asset, 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.
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, four winning bidders reached separate
agreements with FES with the result that FES is now responsible for providing
77% of the Ohio Companies’ total load supply. The results of the CBP
were accepted by the PUCO on May 14, 2009. FES has also separately
contracted with numerous communities to provide retail generation service
through governmental aggregation programs.
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 totaled $305.1 million.
The applications were approved by the PUCO on August 19, 2009. Recovery of this
amount, together with carrying charges calculated as approved in the Amended
ESP, commenced on September 1, 2009, and 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 $140.1 million being recovered from
non-residential customers.
SB221
also requires electric distribution utilities to implement energy efficiency
programs. Under the provisions of SB221, the Ohio Companies are required to
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, with additional savings required through 2025. Utilities are also
required to reduce peak demand in 2009 by 1%, with an additional .75% reduction
each year thereafter through 2018. The PUCO may amend these benchmarks in
certain, limited circumstances, and the Ohio Companies have filed an application
with the PUCO seeking such amendments. As discussed below, on January 7, 2010,
the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon
the Ohio Companies meeting the revised benchmarks in a period of not more than
three years. The PUCO has not yet acted upon the application seeking
a reduction of the peak demand reduction requirements. The Ohio Companies are
presently involved in collaborative efforts related to energy efficiency,
including filing applications for approval with the PUCO, as well as other
implementation efforts arising out of the Supplemental Stipulation. On December
15, 2009, the Ohio Companies filed the required three year portfolio plan
seeking approval for the programs they intend to implement to meet the energy
efficiency and peak demand reduction requirements for the 2010-2012
period. The PUCO has set the matter for hearing on March 2, 2010. The
Ohio Companies expect that all costs associated with compliance will be
recoverable from customers.
In
October 2009, the PUCO issued additional Entries, modifying certain of its
previous rules that set out the manner in which electric utilities, including
the Ohio Companies, will be required to comply with benchmarks contained in
SB221 related to the employment of alternative energy resources, energy
efficiency/peak demand reduction programs as well as greenhouse gas reporting
requirements and changes to long term forecast reporting requirements.
Applications for rehearing filed in mid-November 2009 were granted on December
9, 2009 for the sole purpose of further consideration of the matters raised in
those applications. The PUCO has not yet issued a substantive Entry
on Rehearing. The rules implementing the requirements of SB221 went
into effect on December 10, 2009. The Ohio Companies, on October 27, 2009,
submitted an application to amend their 2009 statutory energy efficiency
benchmarks to zero. On January 7, 2010, the PUCO issued an Order granting the
Companies’ request to amend the energy efficiency benchmarks.
Additionally
under SB221, 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. In August and October 2009, the Ohio
Companies conducted RFPs to secure RECs. The RFPs sought renewable energy RECs,
including solar RECs and RECs generated in Ohio in order to meet the Ohio
Companies’ alternative energy requirements set forth in SB221. The RECs acquired
through these two RFPs will be used to help meet the renewable energy
requirements established under SB221 for 2009, 2010 and 2011. On
December 7, 2009, the Ohio Companies filed an application with the PUCO seeking
a force majeure determination regarding the Ohio Companies’ compliance with the
2009 solar energy resources benchmark, and seeking a reduction in the
benchmark. The PUCO has not yet ruled on that
application.
On
October 20, 2009, the Ohio Companies filed an MRO to procure electric generation
service for the period beginning June 1, 2011. The proposed MRO would
establish a CBP to secure generation supply for customers who do not shop with
an alternative supplier and would be similar, in all material respects, to the
CBP conducted in May 2009 in that it would procure energy, capacity and certain
transmission services on a slice of system basis. Enhancements to the May 2009
CBP, the MRO would include multiple bidding sessions and multiple products with
different delivery periods for generation supply features which are designed to
reduce potential price volatility and reduce supplier risk and encourage bidder
participation. A technical conference was held on October 29, 2009. Hearings
took place in December and the matter has been fully briefed. Pursuant to SB221,
the PUCO has 90 days from the date of the application to determine whether the
MRO meets certain statutory requirements. Although the Ohio Companies requested
a PUCO determination by January 18, 2010, on February 3, 2010, the PUCO
announced that its determination would be delayed. Under a determination that
such statutory requirements are met, the Ohio Companies would be able to
implement the MRO and conduct the CBP.
Pennsylvania
Regulatory Matters
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.
On
February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation
procurement plan covering the period January 1, 2011 through May 31,
2013. The plan is designed to provide adequate and reliable service via a
prudent mix of long-term, short-term and spot market generation supply, as
required by Act 129. The plan proposed a staggered procurement schedule,
which varies by customer class, through the use of a descending clock auction.
On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the
PPUC for the generation procurement plan covering the period January 1, 2011,
through May 31, 2013, reflecting the settlement on all but two issues. The
settlement plan is designed to provide adequate and reliable service as required
by Pennsylvania law through a prudent mix of long-term, short-term and
spot-market generation supply as required by Act 129. The settlement plan
proposes a staggered procurement schedule, which varies by customer class. On
September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the
settlement and adopted Met-Ed and Penelec’s positions on two reserved issues. On
November 6, 2009, the PPUC entered an Order approving the settlement and finding
in favor of Met-Ed and Penelec on the two reserved issues. Generation
procurement began in January 2010.
On May
22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider
for the period June 1, 2008, through May 31, 2009. The TSCs included a
component for 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. 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. On
August 11, 2009, the ALJ issued a Recommended Decision to the PPUC
approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints.
Exceptions by various interveners were filed and reply exceptions were filed by
Met-Ed and Penelec. On January 28, 2010, the PPUC adopted a motion
which denies the recovery of marginal transmission losses through the TSC for
the period of June 1, 2007 through March 31, 2008, and instructs Met-Ed and
Penelec to work with the parties and file a petition to retain any
over-collection, with interest, until 2011 for the purpose of providing
mitigation of future rate increases starting in 2011 for their
customers. Met-Ed and Penelec are now awaiting an order, which is
expected to be consistent with the motion. If so, Met-Ed and Penelec plan to
appeal such a decision to the Commonwealth Court of Pennsylvania. Although the
ultimate outcome of this matter cannot be determined at this time, it is the
belief of the companies that they should prevail in any such appeal and
therefore expect to fully recover the approximately $170.5 million
($138.7 million for Met-Ed and $31.8 million for Penelec) in marginal
transmission losses for the period prior to January 1, 2011.
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, subject to the
outcome of the proceeding related to the 2008 TSC filing described above. 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 would increase approximately 9.4% for the period June 2009 through May
2010.
Act 129
became effective in 2008 and addresses issues such as: energy efficiency and
peak load reduction; generation procurement; time-of-use rates; smart meters;
and alternative energy. Among other things Act 129 requires each Pennsylvania
utility to file with the PPUC an energy efficiency and peak load reduction plan
by July 1, 2009, setting forth the utilities’ plans to reduce energy
consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013,
respectively, and to reduce peak demand by a minimum of 4.5% by May 31,
2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with
the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a
supplemental filing on July 31, 2009, to revise the Total Resource Cost test
items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order.
Following an evidentiary hearing and briefing, the Pennsylvania Companies filed
revised EE&C Plans on September 21, 2009. In an October 28, 2009 Order,
the PPUC approved in part, and rejected in part, the Pennsylvania Companies'
filing. Following additional filings related to the plans, including
modifications as requested by the PPUC. The PPUC issued an order on January 28,
2010, approving, in part, and rejecting, in part the Pennsylvania Companies’
modified plans. The Pennsylvania Companies filed final plans and
tariff revisions on February 5, 2010 consistent with the minor revisions
required by the PPUC. The PPUC must approve or reject the plans
within 60 days.
Act 129
also required utilities to file by August 14, 2009 with the PPUC smart meter
technology procurement and installation plan to provide for the installation of
smart meter technology within 15 years. On August 14, 2009, Met-Ed, Penelec
and Penn jointly filed a Smart Meter Technology Procurement and Installation
Plan. Consistent with the PPUC’s rules, this plan proposes a 24-month assessment
period in which the Pennsylvania Companies will assess their needs, select the
necessary technology, secure vendors, train personnel, install and test support
equipment, and establish a cost effective and strategic deployment schedule,
which currently is expected to be completed in fifteen years. Met-Ed, Penelec
and Penn estimate assessment period costs at approximately $29.5 million, which
the Pennsylvania Companies, in their plan, proposed to recover through an
automatic adjustment clause. A Technical Conference and evidentiary hearings
were held in November 2009. Briefs were filed on December 11, 2009, and Reply
Briefs were filed on December 31, 2009. An Initial Decision was issued by the
presiding ALJ on January 28, 2010. The ALJ’s Initial Decision
approved the Smart Meter Plan as modified by the ALJ, including: ensuring that
the smart meters to be deployed include the capabilities listed in the
Commission’s Implementation Order; eliminating the provision of interest in the
1307(e) reconciliation; providing for the recovery of reasonable and prudent
costs minus resulting savings from installation and use of smart meters; and
reflecting that administrative start-up costs be expensed and the costs incurred
for research and development in the assessment period be
capitalized. Exceptions are due on February 17, 2010, and Reply
Exceptions are due on March 1. The Pennsylvania Companies expect the
PPUC to act on the plans in early 2010.
Legislation
addressing rate mitigation and the expiration of rate caps has been introduced
in both the 2008 and 2009 legislative sessions. The final form of such
legislation and its possible impact on the Pennsylvania Companies’ business and
operations are uncertain.
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
originally entered into with the PPUC pursuant to comprehensive electric utility
industry restructuring legislation (Customer Choice Act) adopted in
Pennsylvania in 1996. In the compliance filing, 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 -
$59 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. On August 14, 2009, the PPUC
approved Met-Ed and Penelec’s compliance filings.
By
Tentative Order entered September 17, 2009, the PPUC provided for an
additional 30-day comment period on whether “the Restructuring Settlement allows
NUG over-collection for select and isolated months to be used to reduce non-NUG
stranded costs when a cumulative NUG stranded cost balance
exists.” In response to the Tentative Order, the Office of
Small Business Advocate, Office of Consumer Advocate, York County Solid Waste
and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec
Industrial Customer Alliance filed comments objecting to the above accounting
method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments
on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial
Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply
comments by November 16, 2009, and reply comments were filed by the Office of
Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec
Industrial Customer Alliance. Met-Ed and Penelec are awaiting further
action by the Commission.
On
February 8, 2010, Penn filed with the PPUC a generation procurement plan
covering the period June 1, 2011 through May 31, 2013. The plan is designed
to provide adequate and reliable service through a prudent mix of long-term,
short-term and spot market generation supply, as required by Act 129. The
plan proposed a staggered procurement schedule, which varies by customer class,
through the use of a descending clock auction. The PPUC is required to issue an
order on the plan no later than November 8, 2010.
New
Jersey Regulatory Matters
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 December
30, 2009, the accumulated deferred cost balance totaled approximately $98
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. TMI-2 is a retired nuclear
facility owned by JCP&L. 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 New Jersey electric and
gas utilities in order to achieve the goals of the EMP. Such utility specific
plans are due to be filed with the NJBPU by July 1, 2010. At this time,
FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have
on their business or operations.
In
support of former New Jersey Governor Corzine'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. In addition, 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. The project
relating to expansion of the existing demand response programs was approved by
the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the
$11 million project related to energy efficiency programs intended to complement
those currently being offered was denied by the NJBPU on December 1, 2009.
Implementation of the remaining projects is dependent upon resolution of
regulatory issues between the NJBPU and JCP&L including recovery of the
costs associated with the proposal.
On
February 11, 2010, S&P downgraded the senior unsecured debt of FirstEnergy
Corp. to BB+. As a result, pursuant to the requirements of a
pre-existing NJBPU order, JCP&L filed, on February 17, 2010, a plan
addressing the mitigation of any effect of the downgrade and provided an
assessment of present and future liquidity necessary to assure JCP&L’s
continued payment to BGS suppliers. The order also provides that the
NJBPU should: 1) within 10 days of that filing, hold a public hearing to review
the plan and consider the available options and 2) within 30 days of that filing
issue an order with respect to the matter. At this time, the public
hearing has not been scheduled and FirstEnergy and JCP&L cannot determine
the impact, if any, these proceedings will have on their
operations.
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. 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. On
October 29, 2009, FirstEnergy, with another Company, filed an additional
settlement agreement with FERC to resolve their outstanding claims. FirstEnergy
is actively pursuing settlement agreements with other parties to the
case. On December 8, 2009, certain parties sought a writ of mandamus
from the DC Circuit Court of Appeals directing FERC to issue an order on the
Initial Decision. The Court agreed to hold this matter in abeyance based upon
FERC’s representation to use good faith efforts to issue a substantive ruling on
the initial decision no later than May 27, 2010. If FERC fails to
act, the case will be submitted for briefing in June. The outcome of this matter
cannot be predicted.
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 on the content of the compliance filings 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 (Opinion 494) 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, the FERC’s April 19, 2007, and January 31, 2008, orders were appealed
to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce
Commission, the PUCO and another party have also appealed these orders to the
Seventh Circuit Court of Appeals. The appeals of these parties and others were
consolidated for argument in the Seventh Circuit and the Seventh Circuit Court
of Appeals issued a decision on August 6, 2009. The court found that FERC had
not marshaled enough evidence to support its decision to allocate cost for new
500+kV facilities on a postage-stamp basis and, based on this finding, remanded
the rate design issue back to FERC. A request for rehearing and rehearing en
banc by two companies was denied by the Seventh Circuit on October 20,
2009. On October 28, 2009, the Seventh Circuit closed its case dockets and
returned the case to FERC for further action on the remand order. In an order
dated January 21, 2010, FERC set the matter for “paper hearings” – meaning that
FERC called for parties to submit comments or written testimony pursuant to the
schedule described in the order. FERC identified nine separate issues for
comments, and directed PJM to file the first round of comments on February 22,
2010, with other parties submitting responsive comments on April 8, 2010 and May
10, 2010.
The
FERC’s orders on PJM rate design prevented 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 postage-stamp basis
reduces the cost 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. On November 14,
2008, PJM submitted revisions to its tariff to incorporate cost responsibility
assignments for below 500 kV upgrades included in PJM’s RTEP process in
accordance with the settlement. The remaining merchant transmission cost
allocation issues were the subject of a hearing at the FERC in May 2008. On
November 19, 2009, FERC issued Opinion 503 agreeing that RTEP costs should be
allocated on a pro-rata basis to merchant transmission companies. On December
22, 2009, a request for a rehearing of FERC’s Opinion No. 503 was made. On
January 19, 2010, the FERC issued a procedural order noting that FERC would
address the rehearing requests in a future order.
RTO
Consolidation
On
August 17, 2009, FirstEnergy filed an application with the FERC requesting to
consolidate its transmission assets and operations into PJM. Currently,
FirstEnergy’s transmission assets and operations are divided between PJM and
MISO. The consolidation would make the transmission assets that are part of
ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of
FirstEnergy’s transmission assets in Pennsylvania and all of the transmission
assets in New Jersey already operate as a part of PJM. Key elements of the
filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the
means whereby capacity will be procured and administered as necessary to satisfy
the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and
also a request that ATSI’s transmission customers be excused from the costs for
regional transmission projects that were approved through PJM’s RTEP process
prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected
to be complete on June 1, 2011, to coincide with delivery of power under the
next competitive generation procurement process for the Ohio Companies and Penn.
To ensure a definitive ruling at the same time the FERC rules on its request to
integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related
complaint with the FERC on the issue of exempting the ATSI footprint from the
legacy RTEP costs.
On
September 4, 2009, the PUCO opened a case to take comments from Ohio’s
stakeholders regarding the RTO consolidation. FirstEnergy filed extensive
comments in the PUCO case on September 25, 2009, and reply comments on
October 13, 2009, and attended a public meeting on September 15, 2009
to answer questions regarding the RTO consolidation. Several parties have
intervened in the regulatory dockets at the FERC and at the PUCO. Certain
interveners have commented and protested particular elements of the proposed RTO
consolidation, including an exit fee to MISO, integration costs to PJM, and
cost-allocations of future transmission upgrades in PJM and MISO.
On
December 17, 2009, FERC issued an order approving, subject to certain future
compliance filings, ATSI’s move to PJM. FirstEnergy’s request to be exempted
from legacy RTEP costs was rejected and its complaint dismissed.
On
December 17, 2009, ATSI executed the PJM Consolidated Transmission Owners
Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM
Operating Agreement and the PJM Reliability Assurance Agreement. Execution of
these agreements committed ATSI and the Ohio Companies and Penn’s load to moving
into PJM on the schedule described in the application and approved in the FERC
Order (June 1, 2011).
On
January 15, 2010, the Ohio Companies and Penn submitted a compliance filing
describing the process whereby ATSI-zone load serving entities (LSEs) can “opt
out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13
Delivery Years. On January 16, 2010, FirstEnergy filed for clarification or
rehearing of certain issues associated with implementing the FRR
auctions on the proposed schedule. On January 19, 2010, FirstEnergy filed for
rehearing of FERC’s decision to impose the legacy RTEP costs on ATSI’s
transmission customers. Also on January 19, 2010, several parties, including the
PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the
rehearing parties asked FERC to rescind authorization for ATSI to enter PJM.
Instead, parties focused on questions of cost and cost allocation or on alleged
errors in implementing the move. On February 3, 2010, FirstEnergy
filed an answer to the January 19, 2010 rehearing request of other parties. On
February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the
filing describes communications protocols and performance deficiency penalties
for capacity suppliers that are taken in FRR auctions.
FirstEnergy
will conduct FRR auctions on March 15-19, 2010, for the 2011-12 and 2012-13
delivery years. LSE’s in the ATSI territory, including the Ohio Companies and
Penn, will participate in PJM’s next base residual auction for capacity
resources for the 2013-2014 delivery years. This auction will be conducted in
May of 2010. FirstEnergy expects to integrate into PJM effective June 1,
2011.
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. 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. It ordered changes included
making incremental improvements to RPM and 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; 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, 2009 Order.
PJM has
reconvened the CMEC and has scheduled a CMEC Long-Term Issues Symposium to
address near-term changes directed by the March 26, 2009 Order and other
long-term issues not addressed in the February 2009 settlement. PJM made a
compliance filing on September 1, 2009, incorporating tariff changes directed by
the March 26, 2009 Order. The tariff changes were approved by the FERC in an
order issued on October 30, 2009, and are effective November 1, 2009.
The CMEC continues to work to address additional compliance items directed by
the March 26, 2009 Order. On December 1, 2009, PJM informed FERC that PJM
would file a scarcity-pricing design with the FERC on April 1,
2010.
MISO-PJM
Billing Dispute
In
September 2009, PJM reported that it had discovered a modeling error in the
market-to-market power flow calculations between PJM and the MISO under the
Joint Operating Agreement. The error, which dates back to 2005, was a result of
the incorrect modeling of certain generation resources that have an impact on
power flows across the PJM-MISO border. FERC settlement discussions on this
issue have commenced, and FirstEnergy is participating in these discussions. The
next settlement conference is set for February 25, 2010. Although the
amount of the error is subject to dispute, PJM has estimated the magnitude of
the error to be approximately $77 million in total to all parties. Should a
payment by PJM to the MISO relating to the modeling error be required, the
method by which PJM would collect such payments from PJM participants, and how
MISO would allocate payments received to MISO participants, is uncertain at this
time.
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. The FERC conditionally approved
MISO’s Resource Adequacy proposal on March 26, 2008. 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 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
program was implemented as planned and became effective 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. On October 23, 2009, FERC issued an order approving a MISO
compliance filing that revised its tariff to provide for netting of demand
resources, but prohibiting the netting of behind-the-meter
generation.
FES
Sales to Affiliates
FES
supplied all of the power requirements for the Ohio Companies pursuant to a PSA
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. Rehearing was denied on July 31, 2009. On October 19, 2009, the FERC
accepted FirstEnergy’s revised tariffs.
On May
13-14, 2009, FES participated in a descending clock auction for PLR service
administered by the Ohio Companies and their consultant, CRA International. FES
won 51 tranches in the auction, and entered into a Master SSO Supply Agreement
to provide capacity, energy, ancillary services and transmission to the Ohio
Companies for a two-year period beginning June 1, 2009. Other winning
suppliers have assigned their Master SSO Supply Agreements to FES, five of which
were effective in June, two more in July, four more in August and ten more in
September, 2009. FES also supplies power used by Constellation to
serve an additional five tranches. As a result of these arrangements,
FES serves 77 tranches, or 77% of the PLR load of the Ohio
Companies.
On
November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial
requirements power purchase agreement for 2010. The Fourth Restated Partial
Requirements Agreement (PRA) continues to limit the amount of capacity resources
required to be supplied by FES to 3,544 MW, but requires FES to supply
essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010.
Under the Fourth Restated Partial Requirements Agreement, Met-Ed, Penelec, and
Waverly (Buyers) assigned 1,300 MW of existing energy purchases to FES to assist
it in supplying Buyers’ power supply requirements and managing congestion
expenses. FES can either sell the assigned power from the third party into
the market or use it to serve the Met-Ed/Penelec load. FES is responsible for
obtaining additional power supplies in the event of failure of supply of the
assigned energy purchase contracts. Prices for the power sold by FES under the
Fourth Restated Partial Requirements Agreement were increased to $42.77 and
$44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to
reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal
losses in excess of $208 million and $79 million, respectively, as billed
by PJM in 2010, and associated with delivery of power by FES under the Fourth
Restated Partial Requirements Agreement. The Fourth Restated Partial
Requirements Agreement terminates at the end of 2010.
The
Yards Creek Pumped Storage Project is a 400 MW hydroelectric project located in
Warren County, New Jersey. JCP&L owns an undivided 50% interest
in the project, and JCP&L operates the project. PSEG Fossil, LLC, a
subsidiary of Public Service Enterprise Group, owns the remaining interest in
the plant. The project was constructed in the early 1960s, and became
operational in 1965. Authorization to operate the project is by a
license issued by the FERC. The existing license expires on February
28, 2013.
FirstEnergy
and PSEG desire to renew the license and, to that end, on January 11, 2008,
JCP&L and PSEG Fossil submitted the initial documents necessary to obtain a
new license for the project. The process for relicensing (renewing
the license for) a hydroelectric project is described in FERC’s Integrated
Licensing Process (ILP) regulations. The ILP regulations call for
numerous environmental, operational, structural and safety and other studies to
be conducted as part of the relicensing process. Although some of
these studies were initiated in 2009, the bulk of the studies will be performed
in 2010 – all for the purpose of submitting the application for a new license on
February 28, 2011. The ILP regulations provide for opportunity for
public notice and comment as part of many of these study processes; meaning that
federal and state regulatory agencies, as well as members of the public, will
have amply opportunity to participate in the relicensing process. The
ILP regulations provide significant discretion for FERC to set a procedural
schedule to act on the license application; meaning that FirstEnergy is not able
at this time to predict when FERC will take final action in issuing the new
license for the Yards Creek project. To the extent, however that the
license proceedings extend beyond the February 28, 2013 expiration date for the
current license, the current license will be extended as necessary to permit
FERC to issue the new license.
Capital
Requirements
Our
capital spending for 2010 is expected to be approximately $1.65 billion
(excluding nuclear fuel), of which $241 million relates to Sammis AQC
system expenditures. Capital spending for 2011 and 2012 is expected to be
approximately $1.0 billion to $1.2 billion each year. Our capital
investments for additional nuclear fuel during 2010 are estimated to be
approximately $203 million.
Anticipated
capital expenditures for the Utilities, FES and FirstEnergy’s other subsidiaries
for 2010, excluding nuclear fuel, are shown in the following table. Such costs
include expenditures for the betterment of existing facilities and for the
construction of generating capacity, facilities for environmental compliance,
transmission lines, distribution lines, substations and other
assets.
|
|
2009
|
|
|
Capital
Expenditures
Forecast
|
|
|
|
Actual(1)
|
|
|
2010
|
|
|
|
(In
millions)
|
|
OE
|
|
$ |
131 |
|
|
$ |
116 |
|
Penn
|
|
|
23 |
|
|
|
19 |
|
CEI
|
|
|
111 |
|
|
|
108 |
|
TE
|
|
|
46 |
|
|
|
48 |
|
JCP&L
|
|
|
171 |
|
|
|
170 |
|
Met-Ed
|
|
|
100 |
|
|
|
102 |
|
Penelec
|
|
|
132 |
|
|
|
127 |
|
ATSI
|
|
|
34 |
|
|
|
49 |
|
FGCO
|
|
|
724 |
|
|
|
592 |
|
NGC
|
|
|
242 |
|
|
|
254 |
|
Other
subsidiaries
|
|
|
56 |
|
|
|
66 |
|
Total
|
|
$ |
1,770 |
|
|
$ |
1,651 |
|
|
|
|
|
|
|
|
|
|
(1) Excludes
nuclear fuel.
|
|
During
the 2010-2014 period, maturities of, and sinking fund requirements for,
long-term debt of FirstEnergy and its subsidiaries are:
|
|
Long-Term
Debt Redemption Schedule
|
|
|
|
2010
|
|
|
|
2011-2014 |
|
|
Total
|
|
|
|
(In
millions)
|
|
FirstEnergy
|
|
$ |
1 |
|
|
$ |
256 |
|
|
$ |
257 |
|
FES
|
|
|
52 |
|
|
|
300 |
|
|
|
352 |
|
OE
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
Penn
|
|
|
1 |
|
|
|
5 |
|
|
|
6 |
|
CEI(1)
|
|
|
- |
|
|
|
300 |
|
|
|
300 |
|
JCP&L
|
|
|
31 |
|
|
|
140 |
|
|
|
171 |
|
Met-Ed
|
|
|
100 |
|
|
|
400 |
|
|
|
500 |
|
Penelec
|
|
|
24 |
|
|
|
150 |
|
|
|
174 |
|
Other(2)
|
|
|
58 |
|
|
|
(28
|
) |
|
|
30 |
|
Total
|
|
$ |
268 |
|
|
$ |
1,523 |
|
|
$ |
1,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) CEI
has an additional $110 million due to associated companies in
2010-2014.
|
|
(2)
Includes elimination of certain intercompany debt.
|
|
The
following table displays operating lease commitments, net of capital trust cash
receipts for the 2010-2014 period.
|
|
Net
Operating Lease Commitments
|
|
|
|
2010
|
|
|
|
2011-2014 |
|
|
Total
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
OE
|
|
$ |
104 |
|
|
$ |
403 |
|
|
$ |
507 |
|
CEI(1)
|
|
|
(40 |
) |
|
|
(194 |
) |
|
|
(234 |
) |
TE
|
|
|
35 |
|
|
|
138 |
|
|
|
173 |
|
JCP&L
|
|
|
6 |
|
|
|
19 |
|
|
|
25 |
|
Met-Ed
|
|
|
7 |
|
|
|
13 |
|
|
|
20 |
|
Penelec
|
|
|
3 |
|
|
|
9 |
|
|
|
12 |
|
FESC
|
|
|
14 |
|
|
|
39 |
|
|
|
53 |
|
FGCO
|
|
|
199 |
|
|
|
888 |
|
|
|
1,087 |
|
NGC(2)
|
|
|
(103 |
) |
|
|
(414 |
) |
|
|
(517 |
) |
Total
|
|
$ |
225 |
|
|
$ |
901 |
|
|
$ |
1,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Reflects
CEI's investment in Shippingport that purchased lease obligations
bonds issued on behalf of lessors in Bruce Mansfield Units 1, 2 and 3
sale and leaseback transactions. Effective October 16, 2007, CEI and TE
assigned their leasehold interests in the Bruce Mansfield Plant to
FGCO.
|
|
(2)
Reflects NGC’s purchase of lessor equity interests in Beaver Valley Unit 2
and Perry in the second quarter of 2008.
|
|
FirstEnergy
expects its existing sources of liquidity to remain sufficient to meet its
anticipated obligations and those of its subsidiaries. FirstEnergy and its
subsidiaries' 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. FirstEnergy also expects
that borrowing capacity under credit facilities will continue to be available to
manage working capital requirements during those periods.
FirstEnergy
had approximately $1.2 billion of short-term indebtedness as of
December 31, 2009, comprised of $1.1 billion in borrowings under the
$2.75 billion revolving line of credit described below, $100 million
of other bank borrowings and $31 million of currently payable notes. Total
short-term bank lines of committed credit to FirstEnergy, FES and the Utilities
as of January 31, 2010 were approximately $3.4 billion.
FirstEnergy,
along with certain of its subsidiaries, are party to a $2.75 billion five-year
revolving credit facility. FirstEnergy has the ability to request an increase in
the total commitments available under this facility 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 annual facility fee is 0.125%.
As of
January 31, 2010, FES had a $100 million bank credit facility in addition
to a $1 billion credit limit associated with FirstEnergy's
$2.75 billion revolving credit facility. Also, an aggregate of
$515 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 January 31, 2010, is described in the following table.
Company
|
|
Type
|
|
Maturity
|
|
Commitment
|
|
|
Available
Liquidity
as of
January 31,
2010
|
|
|
|
|
|
|
|
(In
millions)
|
|
FirstEnergy(1)
|
|
Revolving
|
|
Aug.
2012
|
|
$ |
2,750 |
|
|
$ |
1,387 |
|
FirstEnergy
Solutions
|
|
Bank
line
|
|
Mar.
2011
|
|
|
100 |
|
|
|
- |
|
Ohio
and Pennsylvania Companies
|
|
Receivables
financing
|
|
Various(2)
|
|
|
515 |
|
|
|
308 |
|
|
|
|
|
Subtotal
|
|
$ |
3,365 |
|
|
$ |
1,695 |
|
|
|
|
|
Cash
|
|
|
- |
|
|
|
764 |
|
|
|
|
|
Total
|
|
$ |
3,365 |
|
|
$ |
2,459 |
|
|
(1)
|
FirstEnergy
Corp. and subsidiary borrowers.
|
|
(2)
|
$370 million
expires February 22, 2010; $145 million expires
December 17, 2010. The Ohio and Pennsylvania Companies have typically
renewed expiring receivables facilities on an annual basis and expect to
continue that practice as market conditions and the continued quality of
receivables permit.
|
FirstEnergy's
primary source of cash for continuing operations as a holding company is cash
from the operations of its subsidiaries. During 2009, the holding company
received $972 million of cash dividends on common stock from its
subsidiaries and paid $670 million in cash dividends to common
shareholders.
As of
December 31, 2009, the Ohio Companies and Penn had the aggregate capability to
issue approximately $1.4 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 $127 million and
$36 million, respectively, as of December 31, 2009. In April
2009, TE issued $300 million of new senior secured notes backed by FMBs.
Concurrently with that issuance, and in order to satisfy the limitation on
secured debt under its senior note indenture, TE issued an additional
$300 million of FMBs to secure $300 million of its outstanding unsecured
senior notes originally issued in November 2006. As a result, the provisions for
TE to incur additional secured debt do not apply. In August 2009 CEI issued
$300 million of FMBs. CEI restricted $150 million of the proceeds to
fund the redemption of $150 million of secured notes that were paid in
November 2009. Based upon FGCO's FMB indenture, net earnings and available
bondable property additions as of December 31, 2009, FGCO had the
capability to issue $2.2 billion of additional FMBs under the terms of that
indenture. Met-Ed and Penelec had the capability to issue secured debt of
approximately $379 million and $319 million, respectively, under
provisions of their senior note indentures as of December 31,
2009.
To the
extent that coverage requirements or market conditions restrict the
subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock,
they may seek other methods of financing. Such financings could include the sale
of preferred and/or preference stock or of such other types of securities as
might be authorized by applicable regulatory authorities which would not
otherwise be sold and could result in annual interest charges and/or dividend
requirements in excess of those that would otherwise be incurred.
On
September 22, 2008, 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 may utilize the shelf registration
statement to offer and sell unsecured, and in some cases, secured debt
securities.
Nuclear
Operating Licenses
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. On November 5, 2009, the NRC issued a renewed operating license
for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these
facilities were extended until 2036 and 2047 for Units 1 and 2,
respectively.
Each of
the nuclear units in the FES portfolio operates under a 40-year operating
license granted by the NRC. The following table summarizes the current operating
license expiration dates for FES’ nuclear facilities in service.
Station
|
In-Service Date
|
Current
License Expiration
|
Beaver
Valley Unit 1
|
1976
|
2036
|
Beaver
Valley Unit 2
|
1987
|
2047
|
Perry
|
1986
|
2026
|
Davis-Besse
|
1977
|
2017
|
Nuclear
Regulation
Under
NRC regulations, FirstEnergy must ensure that adequate funds will be available
to decommission its nuclear facilities. As of December 31, 2009,
FirstEnergy had approximately $1.9 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 obligation to fund the trusts
may increase. Disruptions in the capital markets and its effects on particular
businesses and the economy in general also affects the values of the nuclear
decommissioning trusts. On June 18, 2009, the NRC informed FENOC that its review
tentatively concluded that a shortfall existed in the decommissioning trust fund
for Beaver Valley Unit 1. On November 24, 2009, FENOC submitted a revised
decommissioning funding calculation using the NRC formula method based on the
renewed license for Beaver Valley Unit 1, which extended operations until 2036.
FENOC’s submittal demonstrated that there was a de minimis shortfall. On
December 11, 2009, the NRC’s review of FirstEnergy’s methodology for the
funding of decommissioning of this facility concluded that there was reasonable
assurance of adequate decommissioning funding at the time permanent termination
of operations is expected. FirstEnergy continues to evaluate the status of its
funding obligations for the decommissioning of these nuclear
facilities.
Nuclear
Insurance
The
Price-Anderson Act limits the public liability which can be assessed with
respect to a nuclear power plant to $12.6 billion (assuming 104 units
licensed to operate) for a single nuclear incident, which amount is covered by:
(i) private insurance amounting to $375 million; and (ii)
$12.2 billion provided by an industry retrospective rating plan required by
the NRC pursuant thereto. Under such retrospective rating plan, in the event of
a nuclear incident at any unit in the United States resulting in losses in
excess of private insurance, up to $118 million (but not more than
$18 million per unit per year in the event of more than one incident) must
be contributed for each nuclear unit licensed to operate in the country by the
licensees thereof to cover liabilities arising out of the incident. Based on
their present nuclear ownership and leasehold interests, FirstEnergy’s maximum
potential assessment under these provisions would be $470 million
(OE-$40 million, NGC-$408 million, and TE-$22 million) per
incident but not more than $70 million (OE-$6 million,
NGC-$61 million, and TE-$3 million) in any one year for each
incident.
In
addition to the public liability insurance provided pursuant to the
Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited
amounts for economic loss and property damage arising out of nuclear incidents.
FirstEnergy is a member of NEIL which provides coverage (NEIL I) for the
extra expense of replacement power incurred due to prolonged accidental outages
of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies,
renewable yearly, corresponding to their respective nuclear interests, which
provide an aggregate indemnity of up to approximately $560 million
(OE-$48 million, NGC-$486 million, TE-$26 million) for replacement
power costs incurred during an outage after an initial 20-week waiting period.
Members of NEIL I pay annual premiums and are subject to assessments if losses
exceed the accumulated funds available to the insurer. FirstEnergy’s present
maximum aggregate assessment for incidents at any covered nuclear facility
occurring during a policy year would be approximately $3 million
(NGC-$3 million).
FirstEnergy
is insured as to its respective nuclear interests under property damage
insurance provided by NEIL to the operating company for each plant. Under these
arrangements, up to $2.8 billion of coverage for decontamination costs,
decommissioning costs, debris removal and repair and/or replacement of property
is provided. FirstEnergy pays annual premiums for this coverage and is liable
for retrospective assessments of up to approximately $60 million
(OE-$6 million, NGC-$51 million, TE-$2 million, Met Ed, Penelec and
JCP&L- less than $1 million in total) during a policy
year.
FirstEnergy
intends to maintain insurance against nuclear risks as described above as long
as it is available. To the extent that replacement power, property damage,
decontamination, decommissioning, repair and replacement costs and other such
costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the
policy limits of the insurance in effect with respect to that plant, to the
extent a nuclear incident is determined not to be covered by FirstEnergy’s
insurance policies, or to the extent such insurance becomes unavailable in the
future, FirstEnergy would remain at risk for such costs.
The NRC
requires nuclear power plant licensees to obtain minimum property insurance
coverage of $1.1 billion or the amount generally available from private
sources, whichever is less. The proceeds of this insurance are required to be
used first to ensure that the licensed reactor is in a safe and stable condition
and can be maintained in that condition so as to prevent any significant risk to
the public health and safety. Within 30 days of stabilization, the licensee is
required to prepare and submit to the NRC a cleanup plan for approval. The plan
is required to identify all cleanup operations necessary to decontaminate the
reactor sufficiently to permit the resumption of operations or to commence
decommissioning. Any property insurance proceeds not already expended to place
the reactor in a safe and stable condition must be used first to complete those
decontamination operations that are ordered by the NRC. FirstEnergy is unable to
predict what effect these requirements may have on the availability of insurance
proceeds.
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
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.
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 $399 million for 2010-2012.
In
October 2007, PennFuture and three of its members filed a citizen suit under the
federal CAA, alleging violations of air pollution laws at the Bruce Mansfield
Plant, including opacity limitations, in the United States District Court for
the Western District of Pennsylvania. In July 2008, three additional complaints
were filed against FGCO in the U.S. 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 three 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
16, 2009, a settlement reached with PennFuture and one of the three individual
complainants was approved by the Court, which dismissed the claims of PennFuture
and of the settling individual. The other two non-settling individuals are now
represented by counsel handling the three cases filed in July 2008. FGCO
believes those claims are without merit and intends to defend itself against the
allegations made in those three 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 has completed.
In
December 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 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 PSD 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. Met-Ed
filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and
Connecticut’s Complaint in February and September of 2009,
respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and
Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s
motion to dismiss the claims for civil penalties on statute of limitations
grounds in order to allow the states to prove either that the application of the
discovery rule or the doctrine of equitable tolling bars application of the
statute of limitations.
In
January 2009, the EPA issued a NOV to Reliant alleging NSR 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 2009, NOV also alleged NSR violations at the Keystone and Shawville
Stations based on “modifications” dating back to 1984. JCP&L, as the former
owner of 16.67% of the Keystone Station, and Penelec, as former owner and
operator of the Shawville Station, are unable to predict the outcome of this
matter.
In June
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 PSD 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.
In
August 2009, the EPA issued a Finding of Violation and NOV alleging violations
of the CAA and Ohio regulations, including the PSD, NNSR, and Title V
regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating
plants. The EPA’s NOV alleges equipment replacements occurring during
maintenance outages dating back to 1990 triggered the pre-construction
permitting requirements under the PSD and NNSR programs. In September 2009,
FGCO received an information request pursuant to Section 114(a) of the CAA
requesting certain operating and maintenance information and planning
information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula
generating plants. On November 3, 2009, FGCO received a letter providing
notification that the EPA is evaluating whether certain scheduled
maintenance at the Eastlake generating plant may constitute a major
modification under the NSR provision of the CAA. On December 23, 2009, FGCO
received another information request regarding emission projections for the
Eastlake generating plant pursuant to Section 114(a) of the CAA. FGCO intends to
comply with the CAA, including EPA’s information requests, but, at this time, is
unable to predict the outcome of this matter. A June 2006 finding of
violation and NOV in which EPA alleged CAA violations at the Bay Shore
Generating Plant remains unresolved and FGCO is unable to predict the outcome of
such matter.
In
August 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 U.S. 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.” In
September 2008, the EPA, utility, mining and certain environmental advocacy
organizations petitioned the Court for a rehearing to reconsider its ruling
vacating CAIR. In December 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 U.S. 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 U.S. 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 in May 2008. In
October 2008, the EPA (and an industry group) petitioned the U.S. 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. On October 21, 2009, the EPA opened a 30-day comment period on a
proposed consent decree that would obligate the EPA to propose MACT regulations
for mercury and other hazardous air pollutants by March 16, 2011, and to
finalize the regulations by November 16, 2011. FGCO’s future cost of
compliance with MACT 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 December 23, 2009,
the Supreme Court of Pennsylvania affirmed the Commonwealth Court of
Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and
unenforceable” and enjoined the Commonwealth from continued implementation or
enforcement of that rule.
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, the December
2009 U.N. Climate Change Conference in Copenhagen did not reach a
consensus on a successor treaty to the Kyoto Protocol, but did take
note of the Copenhagen Accord, a non-binding political agreement
which recognized the scientific view that the increase in global
temperature should be below two degrees Celsius, included a commitment
by developed countries to provide funds, approaching $30
billion over the next three years with a goal of increasing to
$100 billion by 2020, and established the “Copenhagen Green Climate
Fund” to support mitigation, adaptation, and other climate-related activities in
developing countries. Once they have become a party to the Copenhagen Accord,
developed economies, such as the European Union, Japan, Russia, and the United
States, would commit to quantified economy-wide emissions targets from 2020,
while developing countries, including Brazil, China, and India, would agree to
take mitigation actions, subject to their domestic measurement, reporting, and
verification. 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. The Senate continues to consider a number of
measures to regulate GHG emissions. 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. In
December 2009, the EPA released its final “Endangerment and Cause or
Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s
finding concludes that the atmospheric concentrations of several key GHG
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 GHG and hence to the threat of climate change.
Although the EPA’s finding does not establish emission requirements for motor
vehicles, such requirements are expected to occur through further rulemakings.
Additionally, while the EPA’s endangerment findings do not specifically address
stationary sources, including electric generating plants EPA’s
expected establishment of emission requirements for motor vehicles would be
expected to support the establishment of future emission requirements by the EPA
for stationary sources. In September 2009, the EPA finalized a national GHG
emissions collection and reporting rule that will require FirstEnergy to measure
GHG emissions commencing in 2010 and submit reports commencing in 2011. Also in
September 2009, EPA proposed new thresholds for GHG emissions that define when
CAA permits under the NSR and Title V operating permits programs would be
required. EPA is proposing a major source emissions applicability threshold of
25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing
facilities under the Title V operating permits program and the Prevention of
Significant Determination (PSD) portion of NSR. EPA is also proposing a
significance level between 10,000 and 25,000 tpy CO2e to determine if existing
major sources making modifications that result in an increase of emissions above
the significance level would be required to obtain a PSD permit.
On
September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on
October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and
remanded lower court decisions that had dismissed complaints alleging damage
from GHG emissions on jurisdictional grounds. These cases involve common law
tort claims, including public and private nuisance, alleging that GHG emissions
contribute to global warming and result in property damages. While FirstEnergy
is not a party to either litigation, should the courts of appeals decisions be
affirmed or not subjected to further review, FirstEnergy and/or one or more of
its subsidiaries could be named in actions making similar
allegations.
FirstEnergy
cannot currently estimate the financial impact of climate change policies,
although potential legislative or regulatory programs restricting CO2 emissions,
or litigation alleging damages from GHG emissions, could require significant
capital and other expenditures or result in changes to its operations. 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. EPA is developing a new regulation under Section 316(b) of the Clean
Water Act consistent with the opinions of the Supreme Court and the Court of
Appeals which have created significant uncertainty about the specific nature,
scope and timing of the final performance standard. 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. 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. In December 2009, EPA provided to FGCO the findings of its
review of the Bruce Mansfield Plant’s coal combustion waste management
practices. EPA observed that the waste management structures and the
Plant “appeared to be well maintained and in good working order” and recommended
only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009,
in an advanced notice of public rulemaking, the EPA said that the large volumes
of coal combustion residuals produced by electric utilities pose significant
financial risk to the industry. Additional regulations of fossil-fuel
combustion waste products could have a significant impact on our management,
beneficial use, and disposal, of coal ash. 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 December 31, 2009, based
on estimates of the total costs of cleanup, the Utilities' proportionate
responsibility for such costs and the financial ability of other unaffiliated
entities to pay. Total liabilities of approximately $101 million (JCP&L
- $74 million, TE - $1 million, CEI - $1 million, FGCO -
$1 million and FirstEnergy - $24 million) have been accrued through
December 31, 2009. Included in the total are accrued liabilities of
approximately $67 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.
Fuel
Supply
FES
currently has long-term coal contracts with various terms to acquire
approximately 22.7 million tons of coal for the year 2010, approximately
109% of its 2010 coal requirements of 20.8 million tons. This contract coal is
produced primarily from mines located in Ohio, Pennsylvania, Kentucky, West
Virginia, Montana and Wyoming. The contracts expire at various times through
December 31, 2030. See “Environmental Matters” for factors pertaining to
meeting environmental regulations affecting coal-fired generating
units.
In July
2008, FEV entered into a joint venture with the Boich Companies, a Columbus,
Ohio-based coal company, to acquire a majority stake in the Bull Mountain Mine
Operations, now called Signal Peak, near Roundup, Montana. This joint venture is
part of FirstEnergy’s strategy to secure high-quality fuel supplies at
attractive prices to maximize the capacity of its fossil generating plants. In a
related transaction, FGCO entered into a 15-year agreement to purchase up to
10 million tons of bituminous western coal annually from the mine.
FirstEnergy also entered into agreements with the rail carriers associated with
transporting coal from the mine to its generating stations, and began taking
delivery of the coal in late 2009. The joint venture has the right to resell
Signal Peak coal tonnage not used at FirstEnergy facilities and has call rights
on such coal above certain levels.
FirstEnergy
has contracts for all uranium requirements through 2011 and a portion of uranium
material requirements through 2016. Conversion services contracts fully cover
requirements through 2011 and partially fill requirements through 2016.
Enrichment services are contracted for essentially all of the enrichment
requirements for nuclear fuel through 2017. A portion of enrichment requirements
is also contracted for through 2024. Fabrication services for fuel assemblies
are contracted for both Beaver Valley units and Davis Besse through 2013 and
through the current operating license period for Perry (through approximately
2026). The Davis-Besse fabrication contract also has an extension provision for
services for additional consecutive reload batches through the current operating
license period (approximately 2017). In addition to the existing commitments,
FirstEnergy intends to make additional arrangements for the supply of uranium
and for the subsequent conversion, enrichment, fabrication, and waste disposal
services.
On-site
spent fuel storage facilities are expected to be adequate for Perry through
2010; facilities at Beaver Valley Units 1 and 2 are expected to be adequate
through 2015 and 2010, respectively. Davis-Besse has adequate storage through
2017. After current on-site storage capacity at the plants is exhausted,
additional storage capacity will have to be obtained either through plant
modifications, interim off-site disposal, or permanent waste disposal
facilities. FENOC is currently taking actions to extend the spent fuel storage
capacity for Perry and Beaver Valley. Plant modifications to increase the
storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2
were submitted to the NRC for approval during the second quarter of 2009. The
NRC has requested additional information to complete the license review process
and this information will be provided in early 2010. Dry fuel storage is also
being pursued at Perry and Beaver Valley, with Perry implementation scheduled to
complete by the end of 2010 and Beaver Valley to be complete by the end of
2014.
The
Federal Nuclear Waste Policy Act of 1982 provided for the construction of
facilities for the permanent disposal of high-level nuclear wastes, including
spent fuel from nuclear power plants operated by electric utilities. NGC has
contracts with the DOE for the disposal of spent fuel for Beaver Valley,
Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for
underground disposal of spent nuclear fuel from nuclear power plants and high
level waste from U.S. defense programs. The DOE submitted the license
application for Yucca Mountain to the NRC on June 3, 2008. However, the current
Administration has stated the Yucca Mountain repository will not be completed
and a Federal review of potential alternative strategies will be performed.
FirstEnergy intends to make additional arrangements for storage capacity as a
contingency for the continuing delays with the DOE acceptance of spent fuel for
disposal.
Fuel oil
and natural gas are used primarily to fuel peaking units and/or to ignite the
burners prior to burning coal when a coal-fired plant is restarted. Fuel oil
requirements have historically been low and are forecasted to remain so;
requirements are expected to average approximately 5 million gallons per
year over the next five years. Due to the volatility of fuel oil prices,
FirstEnergy has adopted a strategy of either purchasing fixed-priced oil for
inventory or using financial instruments to hedge against price risk. Natural
gas is currently consumed primarily by peaking units, and no natural gas demand
is forecasted in 2010. First Energy purchased a partially completed combined
cycle combustion turbine plant in Fremont Ohio. Construction is scheduled to be
completed in late 2010 and generation is forecasted for 2011. Because of high
price volatility and the unpredictability of unit dispatch, natural gas futures
are purchased based on forecasted demand to hedge against price
movements.
System
Demand
The 2009
net maximum hourly demand for each of the Utilities was:
|
·
|
OE–5,156
MW on June 25, 2009;
|
|
·
|
Penn–879
MW on June 25, 2009;
|
|
·
|
CEI–3,843
MW on June 25, 2009;
|
|
·
|
TE–2,009
MW on June 25, 2009;
|
|
·
|
JCP&L–5,738
MW on August 10, 2009;
|
|
·
|
Met-Ed–2,839
MW on August 10, 2009; and
|
|
·
|
Penelec–2,679
MW on August 10, 2009.
|
Supply
Plan
Regulated
Commodity Sourcing
The
Utilities have a default service obligation to provide the required power supply
to non-shopping customers who have elected to continue to receive service under
regulated retail tariffs. The volume of these sales can vary depending on the
level of shopping that occurs. Supply plans vary by state and by service
territory. JCP&L’s default service supply is secured through a statewide
competitive procurement process approved by the NJBPU. The Ohio Utilities and
Penn’s default service supplies are provided through a competitive procurement
process approved by the PUCO and PPUC, respectively. The default service supply
for Met-Ed and Penelec is secured through a FERC-approved agreement with FES,
but will move to a competitive procurement process in 2011. If any unaffiliated
suppliers fail to deliver power to any one of the Utilities’ service areas, the
Utility serving that area may need to procure the required power in the market
in their role as a PLR.
Unregulated
Commodity Sourcing
FES has
retail and wholesale competitive load-serving obligations in Ohio, New Jersey,
Maryland, Pennsylvania, Michigan and Illinois serving both affiliated and
non-affiliated companies. FES provides energy products and services to customers
under various PLR, shopping, competitive-bid and non-affiliated contractual
obligations. In 2009, FES’ generation was used to serve two main obligations.
Affiliated companies utilized approximately 76% of FES’ total generation. Direct
retail customers utilized approximately 18% of FES' total generation.
Geographically, approximately 67% of FES’ obligation is located in the MISO
market area and 33% is located in the PJM market area.
FES
provides energy and energy related services, including the generation and sale
of electricity and energy planning and procurement through retail and wholesale
competitive supply arrangements. FES controls (either through ownership, lease,
affiliated power contracts or participation in OVEC) 14,346 MW of installed
generating capacity. FES supplies the power requirements of its competitive
load-serving obligations through a combination of subsidiary-owned generation,
non-affiliated contracts and spot market transactions.
Regional
Reliability
FirstEnergy’s
operating companies are located within MISO and PJM and operate under the
reliability oversight of a regional entity known as ReliabilityFirst. This regional entity
operates under the oversight of the NERC in accordance with a Delegation
Agreement approved by the FERC. ReliabilityFirst began operations under
the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by
the FERC as the ERO in the United States pursuant to Section 215 of the FPA and
ReliabilityFirst was
certified as a regional entity. ReliabilityFirst represents the
consolidation of the ECAR, Mid-Atlantic Area Council, and Mid-American
Interconnected Network reliability councils into a single regional reliability
organization.
Competition
As a
result of actions taken by state legislative bodies, major changes in the
electric utility business have occurred in portions of the United States,
including Ohio, New Jersey and Pennsylvania where FirstEnergy’s utility
subsidiaries operate. These changes have altered the way traditional integrated
utilities conduct their business. FirstEnergy has aligned its business units to
accommodate its retail strategy and participate in the competitive electricity
marketplace (see Management's Discussion and Analysis). FirstEnergy’s
Competitive Energy Services segment participates in deregulated energy markets
in Ohio, Pennsylvania, Maryland, Michigan, and Illinois through
FES.
In New
Jersey, JCP&L has procured electric generation supply to serve its BGS
customers since 2002 through a statewide auction process approved by the NJBPU.
The auction is designed to procure supply for BGS customers at a cost reflective
of market conditions. On May 1, 2008, the Governor of Ohio signed SB221
into law, which became effective July 31, 2008. The new law provides two
options for pricing generation in 2009 and beyond – through a negotiated rate
plan or a competitive bidding process (see PUCO Rate Matters above). In
Pennsylvania, all electric distribution companies will be required to secure
generation for customers in competitive markets by 2011.
FirstEnergy
remains focused on managing the transition to competitive markets for
electricity in Pennsylvania. On October 15, 2008, the Governor of
Pennsylvania signed House Bill 2200 into law, which became effective on
November 14, 2008, as Act 129 of 2008. The new law outlines a competitive
procurement process and sets targets for energy efficiency and conservation (see
PPUC Rate Matters above).
Research
and Development
The
Utilities, FES, and FENOC participate in the funding of EPRI, which was formed
for the purpose of expanding electric research and development (R&D) under
the voluntary sponsorship of the nation’s electric utility
industry - public, private and cooperative. Its goal is to mutually
benefit utilities and their customers by promoting the development of new and
improved technologies to help the utility industry meet present and future
electric energy needs in environmentally and economically acceptable ways. EPRI
conducts research on all aspects of electric power production and use, including
fuels, generation, delivery, energy management and conservation, environmental
effects and energy analysis. The majority of EPRI’s research and development
projects are directed toward practical solutions and their applications to
problems currently facing the electric utility industry.
FirstEnergy
participates in other initiatives with industry R&D consortiums and
universities to address technology needs for its various business units.
Participation in these consortiums helps the company address research needs in
areas such as plant operations and maintenance, major component reliability,
environmental controls, advanced energy technologies, and T&D System
infrastructure to improve performance, and develop new technologies for advanced
energy and grid applications.
Executive
Officers
|
|
|
|
Positions
Held During Past Five Years
|
|
|
|
|
|
|
|
|
|
A.
J. Alexander (A)(G)
|
|
58
|
|
President
and Chief Executive Officer
|
|
*-present
|
|
|
|
|
|
|
|
W.
D. Byrd (B)
|
|
55
|
|
Vice
President, Corporate Risk & Chief Risk Officer
|
|
2007-present
|
L.
M. Cavalier (B)
|
|
58
|
|
Senior
Vice President – Human Resources
Vice
President
|
|
2005-present
*-2005
|
|
|
|
|
|
|
|
M.
T. Clark (A)(B)(C)(D)(F)(G)
|
|
59
|
|
Executive
Vice President and Chief Financial Officer
Executive
Vice President – Strategic Planning & Operations
Senior
Vice President – Strategic Planning & Operations
|
|
2009-present
2008-2009
*-2008
|
|
|
|
|
|
|
|
D.
S. Elliott (B)(D)
|
|
55
|
|
President
– Pennsylvania Operations
|
|
2005-present
|
|
|
|
|
Executive
Vice President
|
|
2005-present
|
|
|
|
|
Senior
Vice President
|
|
*-2005
|
|
|
|
|
|
|
|
R.
R. Grigg (A)(B)(C)(D)(H)
|
|
61
|
|
Executive
Vice President and President-FirstEnergy Utilities
Executive
Vice President and Chief Operating Officer
|
|
2008-present
*-2008
|
|
|
|
|
|
|
|
J.
J. Hagan (G)
|
|
59
|
|
President
and Chief Nuclear Officer
Senior
Vice President and Chief Operating Officer
Senior
Vice President
|
|
2007-present
2005-2007
*-2005
|
|
|
|
|
|
|
|
C.
E. Jones (B)(C)(D)(I)
|
|
54
|
|
Senior
Vice President – Energy Delivery & Customer Service
President
– FirstEnergy Solutions
Senior
Vice President – Energy Delivery & Customer Service
|
|
2009-present
2007-2009
*-2007
|
C.
D. Lasky (F)
|
|
47
|
|
Vice
President – Fossil Operations
|
|
2008-present
|
|
|
|
|
Vice
President – Fossil Operations & Air Quality Compliance
|
|
2007-2008
|
|
|
|
|
Vice
President
|
|
*-2007
|
|
|
|
|
|
|
|
G.
R. Leidich (A)(B)
|
|
59
|
|
Executive
Vice President & President – FirstEnergy Generation
|
|
2008-present
|
|
|
|
|
Senior
Vice President – Operations (B)
President
and Chief Nuclear Officer (G)
|
|
2007-2008
*-2007
|
|
|
|
|
|
|
|
D.
C. Luff (B)
|
|
62
|
|
Senior
Vice President – Governmental Affairs
|
|
2007-present
|
|
|
|
|
Vice
President
|
|
*-2007
|
|
|
|
|
|
|
|
D.
M. Lynch (E)
|
|
55
|
|
President
– JCP&L
Regional
President
|
|
2009-present
*-2009
|
|
|
|
|
|
|
|
J.
F. Pearson (A)(B)(C)(D)(F)(G)
|
|
55
|
|
Vice
President and Treasurer
|
|
2006-present
|
|
|
|
|
Treasurer
Group
Controller – Strategic Planning and Operations
|
|
2005-2006
*-2005
|
|
|
|
|
|
|
|
D.
R. Schneider (F)
|
|
48
|
|
President
Senior
Vice President – Energy Delivery & Customer Service (B)
Vice
President (B)
Vice
President (F)
|
|
2009-present
2007-2009
2006-2007
*-2006
|
|
|
|
|
|
|
|
L.L.
Vespoli (A)(B)(C)(D)(F)(G)
|
|
50
|
|
Executive
Vice President and General Counsel
|
|
2008-present
|
|
|
|
|
Senior
Vice President and General Counsel
|
|
*-2008
|
|
|
|
|
|
|
|
H.
L. Wagner (A)(B)(C)(D)(F)(G)
|
|
57
|
|
Vice
President, Controller and Chief Accounting Officer
|
|
*-present
|
(A)
Denotes executive officer of FE Corp.
|
|
(F)
Denotes executive officer of FES.
|
(B)
Denotes executive officer of FE Service
|
|
(G)
Denotes executive officer of FENOC.
|
(C)
Denotes executive officers of OE, CEI and TE.
|
|
(H)
Retiring March 31, 2010.
|
(D)
Denotes executive officer of Met-Ed, Penelec and Penn.
(E)
Denotes executive officer of JCP&L
|
|
(I) Named
Senior Vice President and President,
FirstEnergy
Utilities, effective April 1, 2010
|
|
|
* Indicates
position held at least since January 1,
2005.
|
Employees
As of
December 31, 2009, FirstEnergy’s subsidiaries had a total of 13,379 employees
located in the United States as follows:
|
|
Total
|
|
|
Bargaining
Unit
|
|
|
|
Employees
|
|
|
Employees
|
|
FESC
|
|
|
2,910 |
|
|
|
284 |
|
OE
|
|
|
1,191 |
|
|
|
709 |
|
CEI
|
|
|
873 |
|
|
|
584 |
|
TE
|
|
|
396 |
|
|
|
294 |
|
Penn
|
|
|
200 |
|
|
|
147 |
|
JCP&L
|
|
|
1,432 |
|
|
|
1,092 |
|
Met-Ed
|
|
|
706 |
|
|
|
509 |
|
Penelec
|
|
|
902 |
|
|
|
632 |
|
ATSI
|
|
|
38 |
|
|
|
- |
|
FES
|
|
|
247 |
|
|
|
- |
|
FGCO
|
|
|
1,784 |
|
|
|
1,154 |
|
FENOC
|
|
|
2,700 |
|
|
|
1,014 |
|
Total
|
|
|
13,379 |
|
|
|
6,419 |
|
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. The parties are participating in the
federal court's mediation programs and have held private settlement discussions.
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.
FirstEnergy
Web Site
Each of
the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q,
Current Reports on Form 8-K, and amendments to those reports filed with or
furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 are also made available free of charge on or through
FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are
posted on the Web site as soon as reasonably practicable after they are
electronically filed with the SEC. Additionally, we routinely post important
information on our Web site and recognize our Web site is a channel of
distribution to reach public investors and as a means of disclosing material
non-public information for complying with disclosure obligations under SEC
Regulation FD. Information contained on FirstEnergy’s Web site shall not be
deemed incorporated into, or to be part of, this report.
ITEM
1A. RISK FACTORS
We
operate in a business environment that involves significant risks, many of which
are beyond our control. Management of each Registrant regularly evaluates the
most significant risks of the Registrant’s businesses and reviews those risks
with the FirstEnergy Board of Directors or appropriate Committees of the Board.
The following risk factors and all other information contained in this report
should be considered carefully when evaluating FirstEnergy and our subsidiaries.
These risk factors could affect our financial results and cause such results to
differ materially from those expressed in any forward-looking statements made by
or on behalf of us. Below, we have identified risks we currently consider
material. However, our business, financial condition, cash flows or results of
operations could be affected materially and adversely by additional risks not
currently known to us or that we deem immaterial at this time. Additional
information on risk factors is included in "Item 1. Business" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and in other sections of this Form 10-K that include forward-looking
and other statements involving risks and uncertainties that could impact our
business and financial results.
Risks Related to Business
Operations
Risks
Arising from the Reliability of Our Power Plants and Transmission and
Distribution Equipment
Operation
of generation, transmission and distribution facilities involves risk,
including, the risk of potential breakdown or failure of equipment or processes,
due to aging infrastructure, fuel supply or transportation disruptions,
accidents, labor disputes or work stoppages by employees, acts of terrorism or
sabotage, construction delays or cost overruns, shortages of or delays in
obtaining equipment, material and labor, operational restrictions resulting from
environmental limitations and governmental interventions, and performance below
expected levels. In addition, weather-related incidents and other natural
disasters can disrupt generation, transmission and distribution delivery
systems. Because our transmission facilities are interconnected with those of
third parties, the operation of our facilities could be adversely affected by
unexpected or uncontrollable events occurring on the systems of such third
parties.
Operation
of our power plants below expected capacity levels could result in lost revenues
and increased expenses, including higher maintenance costs. Unplanned outages of
generating units and extensions of scheduled outages due to mechanical failures
or other problems occur from time to time and are an inherent risk of our
business. Unplanned outages typically increase our operation and maintenance
expenses and may reduce our revenues as a result of selling fewer MWH or may
require us to incur significant costs as a result of operating our higher cost
units or obtaining replacement power from third parties in the open market to
satisfy our forward power sales obligations. Moreover, if we were
unable to perform under contractual obligations, penalties or liability for
damages could result. FES, FGCO and the Ohio Companies are exposed to losses
under their applicable sale-leaseback arrangements for generating facilities
upon the occurrence of certain contingent events that could render those
facilities worthless. Although we believe these types of events are unlikely to
occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under
those provisions of approximately $1.3 billion for FES, $800 million for OE and
an aggregate of $700 million for TE and CEI as co-lessees.
We
remain obligated to provide safe and reliable service to customers within our
franchised service territories. Meeting this commitment requires the expenditure
of significant capital resources. Failure to provide safe and reliable service
and failure to meet regulatory reliability standards due to a number of factors,
including, but not limited to, equipment failure and weather, could adversely
affect our operating results through reduced revenues and increased capital and
operating costs and the imposition of penalties/fines or other adverse
regulatory outcomes.
Changes
in Commodity Prices Could Adversely Affect Our Profit Margins
We
purchase and sell electricity in the competitive wholesale and retail markets.
Increases in the costs of fuel for our generation facilities (particularly coal,
uranium and natural gas) can affect our profit margins. Changes in the market
price of electricity, which are affected by changes in other commodity costs and
other factors, may impact our results of operations and financial position by
increasing the amount we pay to purchase power to supply PLR and default service
obligations in Ohio and Pennsylvania. In addition, the weakening
global economy could lead to lower international demand for coal, oil and
natural gas, which may lower fossil fuel prices and put downward pressure on
electricity prices
Electricity
and fuel prices may fluctuate substantially over relatively short periods of
time for a variety of reasons, including:
|
▪
|
changing
weather conditions or seasonality;
|
|
▪
|
changes
in electricity usage by our
customers;
|
|
▪
|
illiquidity
in wholesale power and other
markets;
|
|
▪
|
transmission
congestion or transportation constraints, inoperability or
inefficiencies;
|
|
▪
|
availability
of competitively priced alternative energy
sources;
|
|
▪
|
changes
in supply and demand for energy
commodities;
|
|
▪
|
changes
in power production capacity;
|
|
▪
|
outages
at our power production facilities or those of our
competitors;
|
|
▪
|
changes
in production and storage levels of natural gas, lignite, coal, crude oil
and refined products;
|
|
▪
|
changes
in legislation and regulation; and
|
|
▪
|
natural
disasters, wars, acts of sabotage, terrorist acts, embargoes and other
catastrophic events.
|
We
Are Exposed to Operational, Price and Credit Risks Associated With Selling and
Marketing Products in the Power Markets That We Do Not Always Completely Hedge
Against
We
purchase and sell power at the wholesale level under market-based tariffs
authorized by the FERC, and also enter into short-term agreements to sell
available energy and capacity from our generation assets. If we are unable to
deliver firm capacity and energy under these agreements, we may be required to
pay damages. These damages would generally be based on the difference between
the market price to acquire replacement capacity or energy and the contract
price of the undelivered capacity or energy. Depending on price volatility in
the wholesale energy markets, such damages could be significant. Extreme weather conditions,
unplanned power plant outages, transmission disruptions, and other factors could
affect our ability to meet our obligations, or cause increases in the market
price of replacement capacity and energy.
We
attempt to mitigate risks associated with satisfying our contractual power sales
arrangements by reserving generation capacity to deliver electricity to satisfy
our net firm sales contracts and, when necessary, by purchasing firm
transmission service. We also routinely enter into contracts, such as fuel and
power purchase and sale commitments, to hedge our exposure to fuel requirements
and other energy-related commodities. We may not, however, hedge the entire
exposure of our operations from commodity price volatility. To the extent we do
not hedge against commodity price volatility, our results of operations and
financial position could be negatively affected.
The
Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial
Losses That May Negatively Impact our Financial Results
We use a
variety of non-derivative and derivative instruments, such as swaps, options,
futures and forwards, to manage our commodity and financial market risks. In the
absence of actively quoted market prices and pricing information from external
sources, the valuation of some of these derivative instruments involves
management's judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of some of these contracts. Also, we could
recognize financial losses as a result of volatility in the market values of
these contracts or if a counterparty fails to perform.
Our
Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty
Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic
Losses Despite Such Policies
We
attempt to mitigate the market risk inherent in our energy, fuel and debt
positions. Procedures have been implemented to enhance and monitor compliance
with our risk management policies, including validation of transaction and
market prices, verification of risk and transaction limits, sensitivity analysis
and daily portfolio reporting of various risk measurement metrics. Nonetheless,
we cannot economically hedge all of our exposures in these areas and our risk
management program may not operate as planned. For example, actual electricity
and fuel prices may be significantly different or more volatile than the
historical trends and assumptions reflected in our analyses. Also, our power
plants might not produce the expected amount of power during a given day or time
period due to weather conditions, technical problems or other unanticipated
events, which could require us to make energy purchases at higher prices than
the prices under our energy supply contracts. In addition, the amount of fuel
required for our power plants during a given day or time period could be more
than expected, which could require us to buy additional fuel at prices less
favorable than the prices under our fuel contracts. As a result, we cannot
always predict the impact that our risk management decisions may have on us if
actual events lead to greater losses or costs than our risk management positions
were intended to hedge.
Our risk
management activities, including our power sales agreements with counterparties,
rely on projections that depend heavily on judgments and assumptions by
management of factors such as future market prices and demand for power and
other energy-related commodities. These factors become more difficult
to predict and the calculations become less reliable the further into the future
these estimates are made. Even when our policies and procedures are
followed and decisions are made based on these estimates, results of operations
may be diminished if the judgments and assumptions underlying those calculations
prove to be inaccurate.
We also
face credit risks from parties with whom we contract who could default in their
performance, in which cases we could be forced to sell our power into a
lower-priced market or make purchases in a higher-priced market than existed at
the time of executing the contract. Although we have established risk management
policies and programs, including credit policies to evaluate counterparty credit
risk, there can be no assurance that we will be able to fully meet our
obligations, that we will not be required to pay damages for failure to perform
or that we will not experience counterparty non-performance or that we will
collect for voided contracts. If counterparties to these arrangements fail to
perform, we may be forced to enter into alternative hedging arrangements or
honor underlying commitments at then-current market prices. In that event, our
financial results could be adversely affected.
Nuclear
Generation Involves Risks that Include Uncertainties Relating to Health and
Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear
Plant Decommissioning
We are
subject to the risks of nuclear generation, including but not limited to the
following:
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the
potential harmful effects on the environment and human health resulting
from unplanned radiological releases associated with the operation of our
nuclear facilities and the storage, handling and disposal of radioactive
materials;
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limitations
on the amounts and types of insurance commercially available to cover
losses that might arise in connection with our nuclear operations or those
of others in the United States;
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uncertainties
with respect to contingencies and assessments if insurance coverage is
inadequate; and
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uncertainties
with respect to the technological and financial aspects of decommissioning
nuclear plants at the end of their licensed operation including increases
in minimum funding requirements or costs of
completion.
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The NRC
has broad authority under federal law to impose licensing security and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines and/or
shut down a unit, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could necessitate substantial capital expenditures at nuclear plants,
including ours. Also, a serious nuclear incident at a nuclear
facility anywhere in the world could cause the NRC to limit or prohibit the
operation or relicensing of any domestic nuclear unit.
Our
nuclear facilities are insured under NEIL policies issued for each plant. Under
these policies, up to $2.8 billion of insurance coverage is provided for
property damage and decontamination and decommissioning costs. We have also
obtained approximately $2.0 billion of insurance coverage for replacement power
costs. Under these policies, we can be assessed a maximum of approximately $79
million for incidents at any covered nuclear facility occurring during a policy
year that are in excess of accumulated funds available to the insurer for paying
losses.
The
Price-Anderson Act limits the public liability that can be assessed with respect
to a nuclear power plant to $12.5 billion (assuming 104 units licensed to
operate in the United States) for a single nuclear incident, which amount is
covered by: (i) private insurance amounting to $300.0 million;
and (ii) $12.2 billion provided by an industry retrospective rating plan. Under
such retrospective rating plan, in the event of a nuclear incident at any unit
in the United States resulting in losses in excess of private insurance, up to
$117.5 million (but not more than $17.5 million per year) must be
contributed for each nuclear unit licensed to operate in the country by the
licensees thereof to cover liabilities arising out of the incident. Our maximum
potential exposure under these provisions would be $470.0 million per
incident but not more than $70.0 million in any one year.
Capital
Market Performance and Other Changes May Decrease the Value of Decommissioning
Trust Fund, Pension Fund Assets and Other Trust Funds Which Then Could Require
Significant Additional Funding
Our
financial statements reflect the values of the assets held in trust to satisfy
our obligations to decommission our nuclear generation facilities and under
pension and other post-retirement benefit plans. The value of certain of
the assets held in these trusts do not have readily determinable market
values. Changes in the estimates and assumptions inherent in the value of
these assets could affect the value of the trusts. If the value
of the assets held by the trusts declines by a material amount, our funding
obligation to the trusts could materially 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 assets that are held in trust to satisfy
future obligations to decommission our nuclear plants, to pay pensions to our
retired employees and to pay other funded obligations. These assets are subject
to market fluctuations and will yield uncertain returns, which may fall below
our projected return rates. Forecasting investment earnings and costs to
decommission nuclear generating stations, to pay future pensions and other
obligations requires significant judgment, and actual results may differ
significantly from current estimates. Capital market conditions that generate
investment losses or greater liability levels can negatively impact our results
of operations and financial position.
We
Could be Subject to Higher Costs and/or Penalties Related to Mandatory
Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized
Markets and the States in Which we do Business
As a
result of the EPACT, owners, operators, and users of the bulk electric system
are subject to mandatory reliability standards promulgated by the NERC and
approved by FERC as well as mandatory reliability standards imposed by each of
the states in which we operate. The standards are based on the functions that
need to be performed to ensure that the bulk electric system operates reliably.
Compliance with modified or new reliability standards may subject us to higher
operating costs and/or increased capital expenditures. If we were found not to
be in compliance with the mandatory reliability standards, we could be subject
to sanctions, including substantial monetary penalties.
Reliability
standards that were historically subject to voluntary compliance are now
mandatory and could subject us to potential civil penalties for violations which
could negatively impact our business. The FERC can now impose
penalties of $1.0 million per day for failure to comply with these mandatory
electric reliability standards.
In
addition to direct regulation by the FERC and the states, we are also subject to
rules and terms of participation imposed and administered by various RTOs
and ISOs. Although these entities are themselves ultimately regulated by the
FERC, they can impose rules, restrictions and terms of service that are
quasi-regulatory in nature and can have a material adverse impact on our
business. For example, the independent market monitors of ISOs and RTOs may
impose bidding and scheduling rules to curb the potential exercise of market
power and to ensure the market functions. Such actions may materially affect our
ability to sell, and the price we receive for, our energy and capacity. In
addition, the RTOs may direct our transmission owning affiliates to build new
transmission facilities to meet the reliability requirements of the RTO or to
provide new or expanded transmission service under the RTO tariffs.
We
Rely on Transmission and Distribution Assets That We Do Not Own or Control to
Deliver Our Wholesale Electricity. If Transmission is Disrupted Including Our
Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our
Ability to Sell and Deliver Power May Be Hindered
We
depend on transmission and distribution facilities owned and operated by
utilities and other energy companies to deliver the electricity we sell. If
transmission is disrupted (as a result of weather, natural disasters or other
reasons) or not operated efficiently by independent system operators, in
applicable markets, or if capacity is inadequate, our ability to sell and
deliver products and satisfy our contractual obligations may be hindered, or we
may be unable to sell products on the most favorable terms. In addition, in
certain of the markets in which we operate, we may be required to pay for
congestion costs if we schedule delivery of power between congestion zones
during periods of high demand. If we are unable to hedge or recover
for such congestion costs in retail rates, our financial results could be
adversely affected.
Demand
for electricity within our utilities’ service areas could stress available
transmission capacity requiring alternative routing or curtailing electricity
usage that may increase operating costs or reduce revenues with adverse
impacts to results of operations. In addition, as with all utilities, potential
concerns over transmission capacity could result in MISO, PJM or the FERC
requiring us to upgrade or expand our transmission system, requiring additional
capital expenditures.
The FERC
requires wholesale electric transmission services to be offered on an
open-access, non-discriminatory basis. Although these regulations are designed
to encourage competition in wholesale market transactions for electricity, it is
possible that fair and equal access to transmission systems will not be
available or that sufficient transmission capacity will not be available to
transmit electricity as we desire. We cannot predict the timing of industry
changes as a result of these initiatives or the adequacy of transmission
facilities in specific markets or whether independent system operators in
applicable markets will operate the transmission networks, and provide related
services, efficiently.
Disruptions
in Our Fuel Supplies Could Occur, Which Could Adversely Affect Our Ability to
Operate Our Generation Facilities and Impact Financial Results
We
purchase fuel from a number of suppliers. The lack of availability of fuel at
expected prices, or a disruption in the delivery of fuel which exceeds the
duration of our on-site fuel inventories, including disruptions as a result of
weather, increased transportation costs or other difficulties, labor relations
or environmental or other regulations affecting our fuel suppliers, could cause
an adverse impact on our ability to operate our facilities, possibly resulting
in lower sales and/or higher costs and thereby adversely affect our results of
operations. Operation of our coal-fired generation facilities is highly
dependent on our ability to procure coal. Although we have long-term contracts
in place for our coal and coal transportation needs, power generators in the
Midwest and the Northeast have experienced significant pressures on available
coal supplies that are either transportation or supply related. If prices for
physical delivery are unfavorable, our financial condition, results of
operations and cash flows could be materially adversely affected.
Temperature
Variations as well as Weather Conditions or other Natural Disasters Could Have a
Negative Impact on Our Results of Operations and Demand Significantly Below or
Above our Forecasts Could Adversely Affect our Energy Margins
Weather
conditions directly influence the demand for electric power. Demand for power
generally peaks during the summer months, with market prices also typically
peaking at that time. Overall operating results may fluctuate based on weather
conditions. In addition, we have historically sold less power, and consequently
received less revenue, when weather conditions are milder. Severe weather, such
as tornadoes, hurricanes, ice or snow storms, or droughts or other natural
disasters, may cause outages and property damage that may require us to incur
additional costs that are generally not insured and that may not be recoverable
from customers. The effect of the failure of our facilities to operate as
planned under these conditions would be particularly burdensome during a peak
demand period.
Customer
demand could change as a result of severe weather conditions or other
circumstances over which we have no control. We satisfy our electricity supply
obligations through a portfolio approach of providing electricity from our
generation assets, contractual relationships and market purchases. A significant
increase in demand could adversely affect our energy margins if we are required
under the terms of the default service tariffs to provide the energy supply to
fulfill this increased demand at capped rates, which we expect would remain
below the wholesale prices at which we would have to purchase the additional
supply if needed or, if we had available capacity, the prices at which we could
otherwise sell the additional supply. Accordingly, any significant change in
demand could have a material adverse effect on our results of operations and
financial position.
We
Are Subject to Financial Performance Risks Related to Regional and General
Economic Cycles and also Related to Heavy Manufacturing Industries such as
Automotive and Steel
Our
business follows the economic cycles of our customers. As our retail strategy is
centered around the sale of output from our generating plants generally where
that power will reach, therefore, we are more directly impacted by the economic
conditions in our primary markets (i.e., Western Pennsylvania,
Ohio, Maryland, New Jersey, Michigan and
Illinois). Declines in demand for electricity as a result of a
regional economic downturn would be expected to reduce overall electricity sales
and reduce our revenues. A decrease in electric generation sales volume has
been, and is expected to continue to be, influenced by circumstances in
automotive, steel and other heavy industries.
Increases
in Customer Electric Rates and the Impact of the Economic Downturn May Lead to a
Greater Amount of Uncollectible Customer Accounts
Our operations
are impacted by the economic conditions in our service territories and those
conditions could negatively impact the rate of delinquent customer accounts and
our collections of accounts receivable which could adversely impact our
financial condition, results of operations and cash flows.
The
Goodwill of One or More of Our Operating Subsidiaries May Become Impaired, Which
Would Result in Write-Offs of the Impaired Amounts
Goodwill
could become impaired at one or more of our operating subsidiaries. The actual
timing and amounts of any goodwill impairments in future years would depend on
many uncertainties, including changing interest rates, utility sector market
performance, our capital structure, market prices for power, results of future
rate proceedings, operating and capital expenditure requirements, the value of
comparable utility acquisitions, environmental regulations and other
factors.
We
Face Certain Human Resource Risks Associated with the Availability of Trained
and Qualified Labor to Meet Our Future Staffing Requirements
We must
find ways to retain our aging skilled workforce while recruiting new talent to
mitigate losses in critical knowledge and skills due to retirements. Mitigating
these risks could require additional financial commitments.
Significant
Increases in Our Operation and Maintenance Expenses, Including Our Health Care
and Pension Costs, Could Adversely Affect Our Future Earnings and
Liquidity
We
continually focus on limiting, and reducing where possible, our operation and
maintenance expenses. However, we expect cost pressures could increase as we
continue to implement our retail sales strategy. We expect to continue to face
increased cost pressures in the areas of health care and pension costs. We have
experienced significant health care cost inflation in the last few years, and we
expect our cash outlay for health care costs, including prescription drug
coverage, to continue to increase despite measures that we have taken and expect
to take requiring employees and retirees to bear a higher portion of the costs
of their health care benefits. The measurement of our expected future health
care and pension obligations and costs is highly dependent on a variety of
assumptions, many of which relate to factors beyond our control. These
assumptions include investment returns, interest rates, health care cost trends,
benefit design changes, salary increases, the demographics of plan participants
and regulatory requirements. If actual results differ materially from our
assumptions, our costs could be significantly increased.
Our Business
is Subject to the Risk that Sensitive Customer Data May be Compromised, Which
Could Result in an Adverse Impact to Our Reputation and/or Results of
Operations
Our
business requires access to sensitive customer data, including personal and
credit information, in the ordinary course of business. A security breach may
occur, despite security measures taken by us and required of vendors. If a
significant or widely publicized breach occurred, our business reputation may be
adversely affected, customer confidence may be diminished, or we may become
subject to legal claims, fines or penalties, any of which could have a negative
impact on our business and/or results of operations.
Acts
of War or Terrorism Could Negatively Impact Our Business
The
possibility that our infrastructure, such as electric generation, transmission
and distribution facilities, or that of an interconnected company, could be
direct targets of, or indirect casualties of, an act of war or terrorism, could
result in disruption of our ability to generate, purchase, transmit or
distribute electricity. Any such disruption could result in a decrease in
revenues and additional costs to purchase electricity and to replace or repair
our assets, which could have a material adverse impact on our results of
operations and financial condition.
Capital
Improvements and Construction Projects May Not be Completed Within Forecasted
Budget, Schedule or Scope Parameters
Our
business plan calls for extensive capital investments, including the
installation of environmental control equipment, as well as other initiatives.
We may be exposed to the risk of substantial price increases in the costs of
labor and materials used in construction. We have engaged numerous contractors
and entered into a large number of agreements to acquire the necessary materials
and/or obtain the required construction-related services. As a result, we are
also exposed to the risk that these contractors and other counterparties could
breach their obligations to us. Such risk could include our contractors’
inabilities to procure sufficient skilled labor as well as potential work
stoppages by that labor force. Should the counterparties to these arrangements
fail to perform, we may be forced to enter into alternative arrangements at
then-current market prices that may exceed our contractual prices, with
resulting delays in those and other projects. Although our agreements are
designed to mitigate the consequences of a potential default by the
counterparty, our actual exposure may be greater than these mitigation
provisions. This could have negative financial impacts such as incurring losses
or delays in completing construction projects.
Changes
in Technology May Significantly Affect Our Generation Business by Making Our
Generating Facilities Less Competitive
We
primarily generate electricity at large central facilities. This method results
in economies of scale and lower costs than newer technologies such as fuel
cells, microturbines, windmills and photovoltaic solar cells. It is possible
that advances in technologies will reduce their costs to levels that are equal
to or below that of most central station electricity production, which could
have a material adverse effect on our results of operations.
We
May Acquire Assets That Could Present Unanticipated Issues for our Business
in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated
Benefits of Those Acquisitions
Asset
acquisitions involve a number of risks and challenges, including: management
attention; integration with existing assets; difficulty in evaluating the
requirements associated with the assets prior to acquisition, operating costs,
potential environmental and other liabilities, and other factors beyond our
control; and an increase in our expenses and working capital
requirements. Any of these factors could adversely affect our ability
to achieve anticipated levels of cash flows or realize other anticipated
benefits from any such asset acquisition.
Ability
of Certain FirstEnergy Companies to Meet Their Obligations to Other FirstEnergy
Companies
Certain
of the FirstEnergy companies have obligations to other FirstEnergy companies
because of transactions involving energy, coal, other commodities, services, and
because of hedging transactions. If one FirstEnergy entity failed to perform
under any of these arrangements, other FirstEnergy entities could incur losses.
Their results of operations, financial position, or liquidity could be adversely
affected, resulting in the nondefaulting FirstEnergy entity being unable to meet
its obligations to unrelated third parties. Our hedging activities are generally
undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy
companies may therefore be more or less hedged than if they were to engage in
such transactions alone.
Risks Associated With our
Proposed Merger With Allegheny
We
May be Unable to Obtain the Approvals Required to Complete our Merger with
Allegheny or, in Order to do so, the Combined Company May be Required to Comply
With Material Restrictions or Conditions.
On
February 11, 2010, we announced the execution of a merger agreement with
Allegheny. Before the merger may be completed, shareholder approval will have to
be obtained by us and by Allegheny. In addition, various filings must be made
with the FERC and various state utility, regulatory, antitrust and other
authorities in the United States. These governmental authorities may impose
conditions on the completion, or require changes to the terms, of the merger,
including restrictions or conditions on the business, operations, or financial
performance of the combined company following completion of the merger. These
conditions or changes could have the effect of delaying completion of the merger
or imposing additional costs on or limiting the revenues of the combined company
following the merger, which could have a material adverse effect on the
financial results of the combined company and/or cause either us or Allegheny to
abandon the merger.
If Completed, Our Merger with
Allegheny May Not Achieve Its Intended Results.
We and
Allegheny entered into the merger agreement with the expectation that the merger
would result in various benefits, including, among other things, cost savings
and operating efficiencies relating to both the regulated utility operations and
the generation business. Achieving the anticipated benefits of the merger is
subject to a number of uncertainties, including whether the business of
Allegheny is integrated in an efficient and effective manner. Failure to achieve
these anticipated benefits could result in increased costs, decreases in the
amount of expected revenues generated by the combined company and diversion of
management's time and energy and could have an adverse effect on the combined
company's business, financial results and prospects.
We
Will be Subject to Business Uncertainties and Contractual Restrictions While the
Merger with Allegheny is Pending That Could Adversely Affect Our Financial
Results.
Uncertainty
about the effect of the merger with Allegheny on employees and customers may
have an adverse effect on us. Although we intend to take steps designed to
reduce any adverse effects, these uncertainties may impair our ability to
attract, retain and motivate key personnel until the merger is completed and for
a period of time thereafter, and could cause customers, suppliers and others
that deal with us to seek to change existing business
relationships.
Employee
retention and recruitment may be particularly challenging prior to the
completion of the merger, as employees and prospective employees may experience
uncertainty about their future roles with the combined company. If, despite our
retention and recruiting efforts, key employees depart or fail to accept
employment with us because of issues relating to the uncertainty and difficulty
of integration or a desire not to remain with the combined company, our
financial results could be affected.
The
pursuit of the merger and the preparation for the integration of Allegheny into
our company may place a significant burden on management and internal resources.
The diversion of management attention away from day-to-day business concerns and
any difficulties encountered in the transition and integration process could
affect our financial results.
In
addition, the merger agreement restricts us, without Allegheny‘s consent, from
making certain acquisitions and taking other specified actions until the merger
occurs or the merger agreement terminates. These restrictions may prevent us
from pursuing otherwise attractive business opportunities and making other
changes to our business prior to completion of the merger or termination of the
merger agreement.
Failure
to Complete Our Merger with Allegheny Could Negatively Impact Our Stock Price
and Our Future Business and Financial Results
If our
merger with Allegheny is not completed, our ongoing business and financial
results may be adversely affected and we will be subject to a number of risks,
including the following:
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We
may be required, under specified circumstances set forth in the Merger
Agreement, to pay Allegheny a termination fee of $350 million and/or
Allegheny’s reasonable out-of-pocket transaction expenses up to $45
million;
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we
will be required to pay costs relating to the merger, including legal,
accounting, financial advisory, filing and printing costs, whether or not
the merger is completed; and
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matters
relating to our merger with Allegheny (including integration planning) may
require substantial commitments of time and resources by our management,
which could otherwise have been devoted to other opportunities that may
have been beneficial to
us.
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We could
also be subject to litigation related to any failure to complete our merger with
Allegheny. If our merger is not completed, these risks may
materialize and may adversely affect our business, financial results and stock
price.
Risks Associated With
Regulation
Complex
and Changing Government Regulations Could Have a Negative Impact on Our Results
of Operations
We are
subject to comprehensive regulation by various federal, state and local
regulatory agencies that significantly influence our operating environment.
Changes in, or reinterpretations of, existing laws or regulations, or the
imposition of new laws or regulations, could require us to incur additional
costs or change the way we conduct our business, and therefore could have an
adverse impact on our results of operations.
Our
utility subsidiaries currently provide service at rates approved by one or more
regulatory commissions. Thus, the rates a utility is allowed to charge may or
may not be set to recover its expenses at any given time. Additionally, there
may also be a delay between the timing of when costs are incurred and when costs
are recovered. For example, we may be unable to timely recover the costs for our
energy efficiency investments, expenses and additional capital or lost revenues
resulting from the implementation of aggressive energy efficiency programs.
While rate regulation is premised on providing an opportunity to earn a
reasonable return on invested capital and recovery of operating expenses, there
can be no assurance that the applicable regulatory commission will determine
that all of our costs have been prudently incurred or that the regulatory
process in which rates are determined will always result in rates that will
produce full recovery of our costs in a timely manner. For example,
our utility subsidiaries’ ability to timely recover rates and charges associated
with integration of the ATSI footprint into PJM is uncertain.
Regulatory
Changes in the Electric Industry, Including a Reversal, Discontinuance or Delay
of the Present Trend Toward Competitive Markets, Could Affect Our Competitive
Position and Result in Unrecoverable Costs Adversely Affecting Our Business and
Results of Operations
As a
result of restructuring initiatives, changes in the electric utility business
have occurred, and are continuing to take place throughout the United States,
including Ohio, Pennsylvania and New Jersey. These changes have resulted, and
are expected to continue to result, in fundamental alterations in the way
utilities conduct their business.
Some
states that have deregulated generation service have experienced difficulty in
transitioning to market-based pricing. In some instances, state and federal
government agencies and other interested parties have made proposals to impose
rate cap extensions or otherwise delay market restructuring or even re-regulate
areas of these markets that have previously been deregulated. Although we expect
wholesale electricity markets to continue to be competitive, proposals to
re-regulate our industry may be made, and legislative or other action affecting
the electric power restructuring process may cause the process to be delayed,
discontinued or reversed in the states in which we currently, or may in the
future, operate. Such delays, discontinuations or reversals of electricity
market restructuring in the markets in which we operate could have an adverse
impact on our results of operations and financial condition.
The FERC
and the U.S. Congress propose changes from time to time in the structure and
conduct of the electric utility industry. If the restructuring, deregulation or
re-regulation efforts result in decreased margins or unrecoverable costs, our
business and results of operations would be adversely affected. We cannot
predict the extent or timing of further efforts to restructure, deregulate or
re-regulate our business or the industry.
The
Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to
Restrict or Control Such Rate Increases. This In Turn Could Create
Uncertainty Affecting Planning, Costs and Results of Operations and May
Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain
Adequate Liquidity and Address Capital Requirements
Increases
in utility rates, such as may follow a period of frozen or capped rates, can
generate pressure on legislators and regulators to take steps to control those
increases. Such efforts can include some form of rate increase moderation,
reduction or freeze. The public discourse and debate can increase uncertainty
associated with the regulatory process, the level of rates and revenues, and the
ability to recover costs. Such uncertainty restricts flexibility and resources,
given the need to plan and ensure available financial resources. Such
uncertainty also affects the costs of doing business. Such costs could
ultimately reduce liquidity, as suppliers tighten payment terms, and increase
costs of financing, as lenders demand increased compensation or collateral
security to accept such risks.
Our
Profitability is Impacted by Our Affiliated Companies’ Continued Authorization
to Sell Power at Market-Based Rates
The FERC
granted FES, FGCO and NGC authority to sell electricity at market-based rates.
These orders also granted them waivers of certain FERC accounting,
record-keeping and reporting requirements. The Utilities also have
market-based rate authority. The FERC’s orders that grant this
market-based rate authority reserve the right to revoke or revise that authority
if the FERC subsequently determines that these companies can exercise market
power in transmission or generation, create barriers to entry or engage in
abusive affiliate transactions. As a condition to the orders granting the
generating companies market-based rate authority, every three years they are
required to file a market power update to show that they continue to meet the
FERC’s standards with respect to generation market power and other criteria used
to evaluate whether entities qualify for market-based rates. FES, FGCO, NGC and
the Utilities renewed this authority for PJM in 2008 and MISO in 2009. FES,
FGCO, NGC and the Utilities must file to renew this authority for PJM in
2010. If any of these companies were to lose their market-based rate
authority, they would be required to obtain the FERC’s acceptance to sell power
at cost-based rates. FES, FGCO and NGC could also lose their waivers, and become
subject to the accounting, record-keeping and reporting requirements that are
imposed on utilities with cost-based rate schedules.
There
Are Uncertainties Relating to Our Participation in Regional Transmission
Organizations (RTOs)
RTO
rules could affect our ability to sell power produced by our generating
facilities to users in certain markets due to transmission constraints and
attendant congestion costs. The prices in day-ahead and real-time energy markets
and RTO capacity markets have been subject to price volatility. Administrative
costs imposed by RTOs, including the cost of administering energy markets, have
also increased. The rules governing the various regional power markets may also
change from time to time, which could affect our costs or revenues. To the
degree we incur significant additional fees and increased costs to participate
in an RTO, and we are limited with respect to recovery of such costs from retail
customers, we may suffer financial harm. While RTO rates for transmission
service are cost based, our revenues from customers to whom we currently provide
transmission services may not reflect all of the administrative and
market-related costs imposed under the RTO tariff. In addition, we may be
allocated a portion of the cost of transmission facilities built by others due
to changes in RTO transmission rate design. Finally, we may be required to
expand our transmission system according to decisions made by an RTO rather than
our internal planning process. As a member of an RTO, we are subject to certain
additional risks, including those associated with the allocation among members
of losses caused by unreimbursed defaults of other participants in that RTO’s
market, and those associated with complaint cases filed against the RTO that may
seek refunds of revenues previously earned by its members.
MISO
implemented an ancillary services market for operating reserves that would be
simultaneously co-optimized with MISO's existing energy markets. The
implementation of these and other new market designs has the potential to
increase our costs of transmission, costs associated with inefficient generation
dispatching, costs of participation in the market and costs associated with
estimated payment settlements.
Because
it remains unclear which companies will be participating in the various regional
power markets, or how RTOs will ultimately develop and operate, or what region
they will cover, we cannot fully assess the impact that these power markets or
other ongoing RTO developments may have.
A
Significant Delay in or Challenges to
Various Elements of ATSI’s Consolidation into PJM,
including but not Limited to, the Intervention
of Parties to the Regulatory Proceedings, Could have a
Negative Impact on Our Results of Operations and Financial
Condition
On December 17,
2009, FERC authorized, subject to certain conditions, FirstEnergy to consolidate
its transmission assets and operations that currently are located in MISO
into PJM; such consolidation to be effective on June 1, 2011. The consolidation
will make the transmission assets that are part of ATSI, whose footprint
includes the Ohio Companies and Penn, part of PJM. Consolidation on June 1, 2011
will coincide with delivery of power under the next competitive generation
procurement process for the Ohio Companies. On December 17, 2009, and after FERC
issued the order, ATSI executed and delivered to PJM those legal documents
necessary to implement its consolidation into PJM. On December 18, 2009, the
Ohio Companies and Penn executed and delivered to PJM those legal documents
necessary to follow ATSI into PJM. Currently, ATSI, the Ohio Companies and Penn
are expected to consolidate into PJM as planned on June 1, 2011
Certain
parties have objected to various aspects of the planned consolidation into
PJM. On September 4, 2009, the PUCO opened a case to take comments
from Ohio’s stakeholders regarding the RTO consolidation. Certain parties have
intervened and filed comments or protests in the FERC and PUCO dockets regarding
particular elements of the proposed RTO consolidation. The disputed elements
include, but are not limited to, recovery of integration costs to PJM and exit
fees to MISO and cost-allocations of transmission upgrades that originate under
the PJM and MISO tariffs. A ruling by FERC or the PUCO or any other
regulator with jurisdiction in favor of one or more of the
intervening or protesting parties (and against
FirstEnergy) on one or
more of the disputed issues could
result in a negative impact on our results of operations and financial
condition.
Energy
Conservation and Energy Price Increases Could Negatively Impact Our Financial
Results
A number
of regulatory and legislative bodies have introduced requirements and/or
incentives to reduce energy consumption by certain dates. Conservation programs
could impact our financial results in different ways. To the extent conservation
resulted in reduced energy demand or significantly slowed the growth in demand,
the value of our merchant generation and other unregulated business activities
could be adversely impacted. While we currently have energy efficiency riders in
place to recover the cost of these programs either at or near a current recovery
timeframe in all three states, currently only Ohio allows us to recover lost
revenues. In our regulated operations, conservation could negatively impact us
depending on the regulatory treatment of the associated impacts. Should we be
required to invest in conservation measures that result in reduced sales from
effective conservation, regulatory lag in adjusting rates for the impact of
these measures could have a negative financial impact. We could also be impacted
if any future energy price increases result in a decrease in customer
usage. Our results could be affected if we are unable to increase our
customer’s participation in our energy efficiency programs. We are
unable to determine what impact, if any, conservation and increases in energy
prices will have on our financial condition or results of
operations.
Our
Business and Activities are Subject to Extensive Environmental Requirements and
Could be Adversely Affected by such Requirements
We may
be forced to shut down facilities, either temporarily or permanently, if we are
unable to comply with certain environmental requirements, or if we make a
determination that the expenditures required to comply with such requirements
are uneconomical. In fact, we are exposed to the risk that such electric
generating plants would not be permitted to continue to operate if pollution
control equipment is not installed by prescribed deadlines.
The
EPA is Conducting NSR Investigations at a Number of our Generating Plants, the
Results of Which Could Negatively Impact our Results of Operations and Financial
Condition
In
August 2009, the EPA issued a Finding of Violation and NOV alleging violations
of the CAA and Ohio regulations, including the PSD, NNSR, and Title V
regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating
plants. The EPA’s NOV alleges equipment replacements occurring during
maintenance outages dating back to 1990 triggered the pre-construction
permitting requirements under the PSD and NNSR programs. In September 2009,
FGCO received an information request pursuant to Section 114(a) of the CAA
requesting certain operating and maintenance information and planning
information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula
generating plants. On November 3, 2009, FGCO received a letter providing
notification that the EPA is evaluating whether certain scheduled
maintenance at the Eastlake generating plant may constitute a major
modification under the NSR provision of the CAA. On December 23, 2009, FGCO
received another information request regarding emission projections for the
Eastlake generating plant pursuant to Section 114(a) of the CAA. FGCO intends to
comply with the CAA, including EPA’s information requests, but, at this time, is
unable to predict the outcome of this matter. A June 2006 finding of
violation and NOV in which EPA alleged CAA violations at the Bay Shore
Generating Plant remains unresolved and FGCO is unable to predict the outcome of
such matter.
In
August 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 Section 114(a) information request An adverse result
in the above referenced matters could have a negative impact on our results of
operations and financial condition.
Costs
of Compliance with Environmental Laws are Significant, and the Cost of
Compliance with Future Environmental Laws, Including Limitations on GHG Emissions,
Could Adversely Affect Cash Flow and Profitability
Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations. Compliance with these legal requirements
requires us to incur costs for environmental monitoring, installation of
pollution control equipment, emission fees, maintenance, upgrading, remediation
and permitting at our facilities. These expenditures have been significant in
the past and may increase in the future. If the cost of compliance with existing
environmental laws and regulations does increase, it could adversely affect our
business and results of operations, financial position and cash flows. Moreover,
changes in environmental laws or regulations may materially increase our costs
of compliance or accelerate the timing of capital expenditures. Because of the
deregulation of generation, we may not directly recover through rates additional
costs incurred for such compliance. Our compliance strategy, although reasonably
based on available information, may not successfully address future relevant
standards and interpretations. If we fail to comply with environmental laws and
regulations, even if caused by factors beyond our control or new interpretations
of longstanding requirements, that failure could result in the assessment of
civil or criminal liability and fines. In addition, any alleged violation of
environmental laws and regulations may require us to expend significant
resources to defend against any such alleged violations.
There
are a number of initiatives to reduce GHG emissions under consideration at the
federal, state and international level. Environmental advocacy groups, other
organizations and some agencies in the United States are focusing
considerable attention on carbon dioxide emissions from power generation
facilities and their potential role in climate change. Many states
and environmental groups have also challenged certain of the federal laws and
regulations relating to air emissions as not being sufficiently
strict. Also, claims have been made alleging that CO2 emissions from
power generating facilities constitute a public nuisance under federal and/or
state common law. Private individuals may seek to enforce
environmental laws and regulations against us and could allege personal injury
or property damage from exposure to hazardous materials. Recently the
courts have begun to acknowledge these claims and may order us to reduce GHG
emissions in the future. There is a growing consensus in the United States and
globally that GHG emissions are a major cause of global warming and that some
form of regulation will be forthcoming at the federal level with respect to GHG
emissions (including carbon dioxide) and such regulation could result in the
creation of substantial additional costs in the form of taxes or emission
allowances. As a result, it is possible that state and federal
regulations will be developed that will impose more stringent limitations on
emissions than are currently in effect. In December 2009, the EPA issued an
“endangerment and cause or contributing finding” for GHG under the CAA, which
will allow the EPA to craft rules that directly regulate
GHG. Although several bills have been introduced at the state and
federal level that would compel carbon dioxide emission reductions, none have
advanced through the legislature. Due to the uncertainty of control technologies
available to reduce greenhouse gas emissions including CO2, as well
as the unknown nature of potential compliance obligations should climate change
regulations be enacted, we cannot provide any assurance regarding the potential
impacts these future regulations would have on our operations. In addition, any
legal obligation that would require us to substantially reduce our emissions
could require extensive mitigation efforts and, in the case of carbon dioxide
legislation, would raise uncertainty about the future viability of fossil fuels,
particularly coal, as an energy source for new and existing electric generation
facilities. Until specific regulations are promulgated, the impact that any new
environmental regulations, voluntary compliance guidelines, enforcement
initiatives, or legislation may have on our results of operations, financial
condition or liquidity is not determinable.
The
EPA’s current CAIR and CAVR require significant reductions beginning in 2009 in
air emissions from coal-fired power plants and the states have been given
substantial discretion in developing their own rules to implement these
programs. On December 23, 2008, the United States Court of Appeals for the
District of Columbia remanded CAIR to EPA but allowed the current CAIR
regulations to remain in effect while EPA works to remedy flaws in the CAIR
regulations identified by the court in a July 11, 2008 opinion. As a result, the
ultimate requirements under CAIR may not be known for several years and may
differ significantly from the current CAIR regulations. If the EPA significantly
changes CAIR, or if the states elect to impose additional requirements on
individual units that are already subject to CAIR, the cost of compliance could
increase significantly and could have an adverse effect on future results of
operations, cash flows and financial condition.
The
EPA's final CAMR was vacated by the United States Court of Appeals for the
District Court of Columbia on February 8, 2008 because the EPA failed to
take the necessary steps to "de-list" coal-fired power plants from its hazardous
air pollution program and therefore could not promulgate a cap and trade air
emissions reduction program. On October 21, 2009, the EPA opened a 30-day
comment period on a proposed consent decree that would obligate the EPA to
propose MACT regulations for mercury and other hazardous air pollutants by
March 16, 2011, and to finalize the regulations by November 16, 2011.
FGCO’s future cost of compliance with MACT regulations may be substantial
and could have a material adverse effect on future results of operations, cash
flows and financial condition.
Various
water quality regulations, the majority of which are the result of the federal
Clean Water Act and its amendments, apply to our generating plants. In addition,
Ohio, New Jersey and Pennsylvania have water quality standards applicable to our
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.
There is
substantial uncertainty concerning the final form of federal and state
regulations to implement Section 316(b) of the Clean Water Act. On
January 26, 2007, the United States Court of Appeals for the Second Circuit
remanded back to the EPA portions of its rulemaking pursuant to Section 316(b).
The EPA subsequently suspended its 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 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. The EPA is
developing a new regulation under Section 316(b) of the Clean Water Act
consistent with the opinions of the Supreme Court and the Court of Appeals which
have created significant uncertainty about the specific nature, scope and timing
of the final performance standard. We may incur significant capital costs to
comply with the final regulations. If either the federal or state final
regulations require retrofitting of cooling water intake structures (cooling
towers) at any of our power plants, and if installation of such cooling towers
is not technically or economically feasible, we may be forced to take actions
which could adversely impact our results of operations and financial
condition.
Certain
fossil-fuel combustion waste products, such as coal ash, have been exempt from
hazardous waste disposal requirements pending the EPA's evaluation of the need
for future regulation. 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. On December 30, 2009, in
an advanced notice of public rulemaking, the EPA said that the large volumes of
coal combustion residuals produced by electric utilities pose significant
financial risk to the industry. Additional regulation of fossil-fuel
combustion waste products could have a significant impact on our management,
beneficial use, and disposal of coal ash and our cost of compliance could
increase significantly which could have a material adverse effect on future
results of operations, cash flows and financial condition.
The
Physical Risks Associated with Climate Change May Impact Our Results of
Operations and Cash Flows.
Physical
risks of climate change, such as more frequent or more extreme weather events,
changes in temperature and precipitation patterns, changes to ground and surface
water availability, and other related phenomena, could affect some, or all, of
our operations. Severe weather or other natural disasters could be destructive,
which could result in increased costs, including supply chain costs. An extreme
weather event within the Utilities’ service areas can also directly affect their
capital assets, causing disruption in service to customers due to downed wires
and poles or damage to other operating equipment. Finally, climate change could
affect the availability of a secure and economical supply of water in some
locations, which is essential for FirstEnergy’s and FES’s continued operation,
particularly the cooling of generating units.
Remediation
of Environmental Contamination at Current or Formerly Owned
Facilities
We are
subject to liability under environmental laws for the costs of remediating
environmental contamination of property now or formerly owned by us and of
property contaminated by hazardous substances that we may have generated
regardless of whether the liabilities arose before, during or after the time we
owned or operated the facilities. Remediation activities associated with our
former MGP operations are one source of such costs. We are currently involved in
a number of proceedings relating to sites where other hazardous substances have
been deposited and may be subject to additional proceedings in the future. We
also have current or previous ownership interests in sites associated with the
production of gas and the production and delivery of electricity for which we
may be liable for additional costs related to investigation, remediation and
monitoring of these sites. Citizen groups or others may bring litigation over
environmental issues including claims of various types, such as property damage,
personal injury, and citizen challenges to compliance decisions on the
enforcement of environmental requirements, such as opacity and other air quality
standards, which could subject us to penalties, injunctive relief and the cost
of litigation. We cannot predict the amount and timing of all future
expenditures (including the potential or magnitude of fines or penalties)
related to such environmental matters, although we expect that they could be
material.
In some
cases, a third party who has acquired assets from us has assumed the liability
we may otherwise have for environmental matters related to the transferred
property. If the transferee fails to discharge the assumed liability or disputes
its responsibility, a regulatory authority or injured person could attempt to
hold us responsible, and our remedies against the transferee may be limited by
the financial resources of the transferee.
Availability
and Cost of Emission Credits Could Materially Impact Our Costs of
Operations
We are
required to maintain, either by allocation or purchase, sufficient emission
credits to support our operations in the ordinary course of operating our power
generation facilities. These credits are used to meet our obligations imposed by
various applicable environmental laws. If our operational needs require more
than our allocated allowances of emission credits, we may be forced to purchase
such credits on the open market, which could be costly. If we are unable to
maintain sufficient emission credits to match our operational needs, we may have
to curtail our operations so as not to exceed our available emission credits, or
install costly new emissions controls. As we use the emissions credits that we
have purchased on the open market, costs associated with such purchases will be
recognized as operating expense. If such credits are available for purchase, but
only at significantly higher prices, the purchase of such credits could
materially increase our costs of operations in the affected
markets. Laws and regulations such as CAIR may, and are, being
revised and as CAIR is being rewritten it is creating uncertainty in many areas,
including but not limited to, the annual NOx emission allowances beyond
2010.
Mandatory
Renewable Portfolio Requirements Could Negatively Affect Our Costs
If
federal or state legislation mandates the use of renewable and alternative fuel
sources, such as wind, solar, biomass and geothermal, and such legislation would
not also provide for adequate cost recovery, it could result in significant
changes in our business, including renewable energy credit purchase costs,
purchased power and potentially renewable energy credit costs and capital
expenditures. We are unable to predict what impact, if any, these
changes may have on our financial condition or results of
operations.
We
Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos
or Other Regulated Substances at Some of our Facilities
We have
been named as a defendant in pending asbestos litigation involving multiple
plaintiffs and multiple defendants. In addition, asbestos and other regulated
substances are, and may continue to be, present at our facilities where suitable
alternative materials are not available. We believe that any remaining asbestos
at our facilities is contained. The continued presence of asbestos and other
regulated substances at these facilities, however, could result in additional
actions being brought against us.
The
Continuing Availability and Operation of Generating Units is Dependent on
Retaining the Necessary Licenses, Permits, and Operating Authority from
Governmental Entities, Including the NRC
We are
required to have numerous permits, approvals and certificates from the agencies
that regulate our business. We believe the necessary permits, approvals and
certificates have been obtained for our existing operations and that our
business is conducted in accordance with applicable laws; however, we are unable
to predict the impact on our operating results from future regulatory activities
of any of these agencies and we are not assured that any such permits, approvals
or certifications will be renewed.
Future
Changes in Financial Accounting Standards May Affect Our Reported Financial
Results
The SEC,
FASB or other authoritative bodies or governmental entities may issue new
pronouncements or new interpretations of existing accounting standards that may
require us to change our accounting policies. These changes are beyond our
control, can be difficult to predict and could materially impact how we report
our financial condition and results of operations. We could be required to apply
a new or revised standard retroactively, which could adversely affect our
financial position. The SEC has issued a roadmap for the transition by U.S.
public companies to the use of IFRS promulgated by the International Accounting
Standards Board. Under the SEC’s proposed roadmap, we could be required in 2014
to prepare financial statements in accordance with IFRS. The SEC expects to make
a determination in 2011 regarding the mandatory adoption of IFRS. We are
currently assessing the impact that this potential change would have on our
consolidated financial statements and we will continue to monitor the
development of the potential implementation of IFRS.
Increases
in Taxes and Fees.
Due to
the revenue needs of the United States and the states and jurisdictions in which
we operate, various tax and fee increases may be proposed or considered. We
cannot predict whether legislation or regulation will be introduced, the form of
any legislation or regulation, whether any such legislation or regulation will
be passed by the state legislatures or regulatory bodies. If enacted, these
changes could increase tax costs and could have a negative impact on our results
of operations, financial condition and cash flows.
Risks Associated With
Financing and Capital Structure
Interest
Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing
Costs, Our Ability to Access Capital and Our Requirement to Post
Collateral
We have
near-term exposure to interest rates from outstanding indebtedness indexed to
variable interest rates, and we have exposure to future interest rates to the
extent we seek to raise debt in the capital markets to meet maturing debt
obligations and fund construction or other investment opportunities. The recent
disruptions in capital and credit markets have resulted in higher interest rates
on new publicly issued debt securities, increased costs for certain of our
variable interest rate debt securities and failed remarketings (all of which
were eventually remarketed) of variable interest rate tax-exempt debt issued to
finance certain of our facilities. Continuation of these disruptions could
increase our financing costs and adversely affect our results of operations.
Also, interest rates could change as a result of economic or other events that
our risk management processes were not established to address. As a result, we
cannot always predict the impact that our risk management decisions may have on
us if actual events lead to greater losses or costs than our risk management
positions were intended to hedge. Although we employ risk management techniques
to hedge against interest rate volatility, significant and sustained increases
in market interest rates could materially increase our financing costs and
negatively impact our reported results of operations.
We rely
on access to bank and capital markets as sources of liquidity for cash
requirements not satisfied by cash from operations. A downgrade in our credit
ratings from the nationally recognized credit rating agencies, particularly to a
level below investment grade, could negatively affect our ability to access the
bank and capital markets, especially in a time of uncertainty in either of those
markets, and may require us to post cash collateral to support outstanding
commodity positions in the wholesale market, as well as available letters of
credit and other guarantees. A rating downgrade would also increase the fees we
pay on our various credit facilities, thus increasing the cost of our working
capital. A rating downgrade could also impact our ability to grow our businesses
by substantially increasing the cost of, or limiting access to, capital. On
February 11, 2010, S&P issued a report lowering FirstEnergy’s and its
subsidiaries’ credit ratings by one notch, while maintaining its stable outlook.
As a result, FirstEnergy may be required to post up to $48 million of
collateral. Moody's and Fitch affirmed the ratings and stable outlook of
FirstEnergy and its subsidiaries on February 11, 2010.
A rating
is not a recommendation to buy, sell or hold debt, inasmuch as such rating does
not comment as to market price or suitability for a particular investor. The
ratings assigned to our debt address the likelihood of payment of principal and
interest pursuant to their terms. A rating may be subject to revision or
withdrawal at any time by the assigning rating agency. Each rating should be
evaluated independently of any other rating that may be assigned to our
securities. Also, we cannot predict how rating agencies may modify
their evaluation process or the impact such a modification may have on our
ratings.
Our
credit ratings also govern the collateral provisions of certain contract
guarantees. Subsequent to the occurrence of a credit rating downgrade to
below investment grade or a “material adverse event,” the immediate posting of
cash collateral may be required. See Note 15(B) of the Notes to the Consolidated
Financial Statements for more information associated with a credit ratings
downgrade leading to the posting of cash collateral.
We
Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility
Subsidiaries’ Ability to Pay Dividends or Make Cash Payments to Us May Adversely
Affect Our Financial Condition
We are a
holding company and our investments in our subsidiaries are our primary assets.
Substantially all of our business is conducted by our subsidiaries.
Consequently, our cash flow is dependent on the operating cash flows of our
subsidiaries and their ability to upstream cash to the holding company. Our
utility subsidiaries are regulated by various state utility commissions that
generally possess broad powers to ensure that the needs of utility customers are
being met. Those state commissions could attempt to impose restrictions on the
ability of our utility subsidiaries to pay dividends or otherwise restrict cash
payments to us.
We
Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or
if Made, in What Amounts they May be Paid
Our
Board of Directors regularly evaluates our common stock dividend policy and
determines the dividend rate each quarter. The level of dividends will continue
to be influenced by many factors, including, among other things, our earnings,
financial condition and cash flows from subsidiaries, as well as general
economic and competitive conditions. We cannot assure common shareholders that
dividends will be paid in the future, or that, if paid, dividends will be at the
same amount or with the same frequency as in the past.
Disruptions
in the Capital and Credit Markets May Adversely Affect our Business, Including
the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our
Ability to Meet Long-Term Commitments, our Ability to Hedge Effectively our
Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets;
Each Could Adversely Affect our Results of Operations, Cash Flows and Financial
Condition
We rely
on the capital markets to meet our financial commitments and short-term
liquidity needs if internal funds are not available from our operations. We also
use letters of credit provided by various financial institutions to support our
hedging operations. Disruptions in the capital and credit markets, as have been
experienced during 2008, could adversely affect our ability to draw on our
respective credit facilities. Our access to funds under those credit facilities
is dependent on the ability of the financial institutions that are parties to
the facilities to meet their funding commitments. Those institutions may not be
able to meet their funding commitments if they experience shortages of capital
and liquidity or if they experience excessive volumes of borrowing requests
within a short period of time.
Longer-term
disruptions in the capital and credit markets as a result of uncertainty,
changing or increased regulation, reduced alternatives or failures of
significant financial institutions could adversely affect our access to
liquidity needed for our business. Any disruption could require us to take
measures to conserve cash until the markets stabilize or until alternative
credit arrangements or other funding for our business needs can be arranged.
Such measures could include deferring capital expenditures, changing hedging
strategies to reduce collateral-posting requirements, and reducing or
eliminating future dividend payments or other discretionary uses of
cash.
The
strength and depth of competition in energy markets depends heavily on active
participation by multiple counterparties, which could be adversely affected by
disruptions in the capital and credit markets. Reduced capital and liquidity and
failures of significant institutions that participate in the energy markets
could diminish the liquidity and competitiveness of energy markets that are
important to our business. Perceived weaknesses in the competitive strength of
the energy markets could lead to pressures for greater regulation of those
markets or attempts to replace those market structures with other mechanisms for
the sale of power, including the requirement of long-term contracts, which could
have a material adverse effect on our results of operations and cash
flows.
Questions
Regarding the Soundness of Financial Institutions or Counterparties Could
Adversely Affect Us
We have
exposure to many different financial institutions and counterparties and we
routinely execute transactions with counterparties in connection with our
hedging activities, including brokers and dealers, commercial banks, investment
banks and other institutions and industry participants. Many of these
transactions expose us to credit risk in the event that any of our lenders or
counterparties are unable to honor their commitments or otherwise default under
a financing agreement. We also deposit cash balances in short-term investments.
Our ability to access our cash quickly depends on the soundness of the financial
institutions in which those funds reside. Any delay in our ability to access
those funds, even for a short period of time, could have a material adverse
effect on our results of operations and financial condition.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM
2. PROPERTIES
The
Utilities’ (other than ATSI and JCP&L) and FGCO’s respective first mortgage
indentures constitute, in the opinion of their counsel, direct first liens on
substantially all of the respective Utilities’, FGCO’s and NGC's physical
property, subject only to excepted encumbrances, as defined in the first
mortgage indentures. See the “Leases” and “Capitalization” notes to the
respective financial statements for information concerning leases and financing
encumbrances affecting certain of the Utilities’, FGCO’s and NGC's
properties.
FirstEnergy
has access, either through ownership or lease, to the following generation
sources as of January 31, 2010, shown in the table below. Except for the
leasehold interests and OVEC participation referenced in the footnotes to the
table, substantially all of the generating units are owned by NGC (nuclear) and
FGCO (non-nuclear).
|
|
|
|
|
Net
|
|
|
|
|
|
|
Demonstrated
|
|
|
|
|
|
|
Capacity
|
|
|
|
|
|
|
|
|
Plant-Location
|
|
|
|
|
|
|
Coal-Fired Units
|
|
|
|
|
|
|
Ashtabula-
|
|
|
|
|
|
|
Ashtabula,
OH
|
|
|
5 |
|
|
|
244 |
|
Bay
Shore-
|
|
|
|
|
|
|
|
|
Toledo,
OH
|
|
|
1-4 |
|
|
|
631 |
|
R.
E. Burger-
|
|
|
|
|
|
|
|
|
Shadyside,
OH
|
|
|
3-5 |
|
|
|
406 |
|
Eastlake-Eastlake,
OH
|
|
|
1-5 |
|
|
|
1,233 |
|
Lakeshore-
|
|
|
|
|
|
|
|
|
Cleveland,
OH
|
|
|
18 |
|
|
|
245 |
|
Bruce
Mansfield-
|
|
|
1 |
|
|
|
830 |
(a) |
Shippingport,
PA
|
|
|
2 |
|
|
|
830 |
(b) |
|
|
|
3 |
|
|
|
830 |
(c) |
W.
H. Sammis - Stratton, OH
|
|
|
1-7 |
|
|
|
2,220 |
|
Kyger
Creek - Cheshire, OH
|
|
|
1-5 |
|
|
|
118 |
(d) |
Clifty
Creek - Madison, IN
|
|
|
1-6 |
|
|
|
142 |
(d) |
Total
|
|
|
|
|
|
|
7,729 |
|
|
|
|
|
|
|
|
|
|
Nuclear Units
|
|
|
|
|
|
|
|
|
Beaver
Valley-
|
|
|
1 |
|
|
|
911 |
|
Shippingport,
PA
|
|
|
2 |
|
|
|
904 |
(e) |
Davis-Besse-
|
|
|
|
|
|
|
|
|
Oak
Harbor, OH
|
|
|
1 |
|
|
|
908 |
|
Perry-
|
|
|
|
|
|
|
|
|
N.
Perry Village, OH
|
|
|
1 |
|
|
|
1,268 |
(f) |
Total
|
|
|
|
|
|
|
3,991 |
|
|
|
|
|
|
|
|
|
|
Oil/Gas
- Fired/
|
|
|
|
|
|
|
|
|
Pumped Storage Units
|
|
|
|
|
|
|
|
|
Richland
- Defiance, OH
|
|
|
1-6 |
|
|
|
432 |
|
Seneca
- Warren, PA
|
|
|
1-3 |
|
|
|
451 |
|
Sumpter
- Sumpter Twp, MI
|
|
|
1-4 |
|
|
|
340 |
|
West
Lorain - Lorain, OH
|
|
|
1-6 |
|
|
|
545 |
|
Yard’s
Creek - Blairstown
|
|
|
|
|
|
|
|
|
Twp.,
NJ
|
|
|
1-3 |
|
|
|
200 |
(g) |
Other
|
|
|
|
|
|
|
282 |
|
Total
|
|
|
|
|
|
|
2,250 |
|
Total
|
|
|
|
|
|
|
13,970 |
|
Notes:
|
(a)
|
Includes
FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest
of 6.175% (51 MW), which has been assigned to FGCO.
|
|
(b)
|
Includes
CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136
MW), respectively, which have been assigned to FGCO.
|
|
(c)
|
Includes
CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157
MW), respectively, which have been assigned to FGCO.
|
|
(d)
|
Represents
FGCO’s 11.5% entitlement based on its participation in
OVEC.
|
|
(e)
|
Includes
OE’s leasehold interest of 16.65% (151 MW) from
non-affiliates.
|
|
(f)
|
Includes
OE’s leasehold interest of 8.11% (103 MW) from
non-affiliates.
|
|
(g)
|
Represents
JCP&L’s 50% ownership interest.
|
The
above generating plants and load centers are connected by a transmission system
consisting of elements having various voltage ratings ranging from 23 kV to
500 kV. The Utilities’ overhead and underground transmission lines
aggregate 15,065 pole miles.
The
Utilities’ electric distribution systems include 119,024 miles of overhead
pole line and underground conduit carrying primary, secondary and street
lighting circuits. They own substations with a total installed transformer
capacity of 91,048,000 kV-amperes.
.
The
transmission facilities that are owned by ATSI are currently operated on an
integrated basis as part of MISO and are interconnected with facilities operated
by PJM. In December 2009, however, the FERC approved ATSI’s realignment into
PJM, subject to certain conditions. The transmission facilities of JCP&L,
Met-Ed and Penelec are physically interconnected and are operated on an
integrated basis as part of PJM
FirstEnergy’s
distribution and transmission systems as of December 31, 2009, consist of the
following:
|
|
|
|
|
|
|
|
Substation
|
|
|
|
Distribution
|
|
|
Transmission
|
|
|
Transformer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Miles)
|
|
|
(kV-amperes)
|
|
|
|
|
|
|
|
|
|
|
|
OE
|
|
|
30,465 |
|
|
|
550 |
|
|
|
9,503,000 |
|
Penn
|
|
|
5,945 |
|
|
|
44 |
|
|
|
1,057,000 |
|
CEI
|
|
|
25,366 |
|
|
|
2,144 |
|
|
|
7,830,000 |
|
TE
|
|
|
2,122 |
|
|
|
223 |
|
|
|
2,973,000 |
|
JCP&L
|
|
|
19,775 |
|
|
|
2,160 |
|
|
|
21,967,000 |
|
Met-Ed
|
|
|
15,128 |
|
|
|
1,422 |
|
|
|
10,353,000 |
|
Penelec
|
|
|
20,223 |
|
|
|
2,701 |
|
|
|
13,978,000 |
|
ATSI*
|
|
|
- |
|
|
|
5,821 |
|
|
|
23,387,000 |
|
Total
|
|
|
119,024 |
|
|
|
15,065 |
|
|
|
91,048,000 |
< |