FIRSTENERGY CORP
10-Qs and 10-Ks
PROXIES
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
|
||
|
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
|
||||
|
Registrant
|
Title
of Each Class
|
on
Which Registered
|
||
|
FirstEnergy
Corp.
|
Common
Stock, $0.10 par value
|
New
York Stock Exchange
|
SECURITIES
REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
|
Registrant
|
Title
of Each Class
|
|||
|
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
|
AS
OF JANUARY 31, 2010
|
|||
|
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
|
||
|
DOCUMENT
|
DOCUMENT
IS INCORPORATED
|
|
|
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
|
|
CO
2
|
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
|
i
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
|
|
NO
X
|
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
|
|
SO
2
|
Sulfur
Dioxide
|
|
SRECs
|
Solar
Renewable Energy Credits
|
|
TBC
|
Transition
Bond Charge
|
ii
GLOSSARY
OF TERMS, Cont'd.
|
TMI-2
|
Three
Mile Island Unit 2
|
|
TSC
|
Transmission
Service Charge
|
|
VERO
|
Voluntary
Enhanced Retirement Option
|
|
VIE
|
Variable
Interest Entity
|
iii
FORM
10-K TABLE OF CONTENTS
|
Page
|
||||||
|
Glossary
of Terms
|
i-iii
|
|||||
|
Part
I
|
||||||
|
Item
1.
|
Business
|
1-26
|
||||
|
The
Company
|
1-2
|
|||||
|
Utility
Regulation
|
2-13
|
|||||
|
State
Regulation
|
2
|
|||||
|
Federal
Regulation
|
3
|
|||||
|
Regulatory
Accounting
|
3-4
|
|||||
|
Reliability
Initiatives
|
4
|
|||||
|
Ohio
Regulatory Matters
|
4-6
|
|||||
|
Pennsylvania
Regulatory Matters
|
6-8
|
|||||
|
New
Jersey Regulatory Matters
|
8-9
|
|||||
|
FERC
Matters
|
9-13
|
|||||
|
Capital
Requirements
|
13-15
|
|||||
|
Nuclear
Operating Licenses
|
15-16
|
|||||
|
Nuclear
Regulation
|
16
|
|||||
|
Nuclear
Insurance
|
16-17
|
|||||
|
Environmental
Matters
|
17-21
|
|||||
|
Fuel
Supply
|
21-22
|
|||||
|
System
Demand
|
22-23
|
|||||
|
Supply
Plan
|
23
|
|||||
|
Regional
Reliability
|
23
|
|||||
|
Competition
|
23-24
|
|||||
|
Research
and Development
|
24
|
|||||
|
Executive
Officers
|
25
|
|||||
|
Employees
|
26
|
|||||
|
FirstEnergy
Web Site
|
26
|
|||||
|
Item
1A.
|
Risk
Factors
|
27-41
|
||||
|
Item
1B.
|
Unresolved
Staff Comments
|
41
|
||||
|
Item 2.
|
Properties
|
41-43
|
||||
|
Item 3.
|
Legal
Proceedings
|
43
|
||||
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
43
|
||||
|
Part
II
|
||||||
|
Item 5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
43-44
|
||||
|
Item 6.
|
Selected
Financial Data
|
44-45
|
||||
|
Item 7.
|
Management’s
Discussion and Analysis of Registrant and Subsidiaries
|
45-130
|
||||
|
FirstEnergy
Corp.
|
47-105
|
|||||
|
FirstEnergy
Solutions Corp.
|
106-110
|
|||||
|
Ohio
Edison Company
|
111-113
|
|||||
|
The
Cleveland Electric Illuminating Company
|
114-115
|
|||||
|
The
Toledo Edison Company
|
116-118
|
|||||
|
Jersey
Central Power & Light Company
|
119-122
|
|||||
|
Metropolitan
Edison Company
|
123-126
|
|||||
|
Pennsylvania
Electric Company
|
127-130
|
|||||
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
131
|
||||
|
Item 8.
|
Financial
Statements and Supplementary Data
|
132-186
|
||||
|
Management Reports
|
132-139
|
|||||
|
Report
of Independent Registered Public Accounting Firm.
|
140-147
|
|||||
iv
TABLE
OF CONTENTS (Cont'd)
|
Page
|
||
|
Financial
Statements
|
||
|
FirstEnergy Corp.
|
||
|
Consolidated
Statements of Income
|
148
|
|
|
Consolidated
Balance Sheets
|
149
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
150
|
|
|
Consolidated
Statements of Cash Flows
|
151
|
|
|
FirstEnergy Solutions
Corp.
|
||
|
Consolidated
Statements of Income
|
152
|
|
|
Consolidated
Balance Sheets
|
153
|
|
|
Consolidated
Statements of Capitalization
|
154
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
155
|
|
|
Consolidated
Statements of Cash Flows
|
156
|
|
|
Ohio Edison
Company
|
||
|
Consolidated
Statements of Income
|
157
|
|
|
Consolidated
Balance Sheets
|
158
|
|
|
Consolidated
Statements of Capitalization
|
159
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
160
|
|
|
Consolidated
Statements of Cash Flows
|
161
|
|
|
The Cleveland Electric
Illuminating Company
|
||
|
Consolidated
Statements of Income
|
162
|
|
|
Consolidated
Balance Sheets
|
163
|
|
|
Consolidated
Statements of Capitalization
|
164
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
165
|
|
|
Consolidated
Statements of Cash Flows
|
166
|
|
|
The Toledo Edison
Company
|
||
|
Consolidated
Statements of Income
|
167
|
|
|
Consolidated
Balance Sheets
|
168
|
|
|
Consolidated
Statements of Capitalization
|
169
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
170
|
|
|
Consolidated
Statements of Cash Flows
|
171
|
|
|
Jersey Central Power & Light
Company
|
||
|
Consolidated
Statements of Income
|
172
|
|
|
Consolidated
Balance Sheets
|
173
|
|
|
Consolidated
Statements of Capitalization
|
174
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
175
|
|
|
Consolidated
Statements of Cash Flows
|
176
|
|
|
Metropolitan Edison
Company
|
||
|
Consolidated
Statements of Income
|
177
|
|
|
Consolidated
Balance Sheets
|
178
|
|
|
Consolidated
Statements of Capitalization
|
179
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
180
|
|
|
Consolidated
Statements of Cash Flows
|
181
|
|
|
Pennsylvania Electric
Company
|
||
|
Consolidated
Statements of Income
|
182
|
|
|
Consolidated
Balance Sheets
|
183
|
|
|
Consolidated
Statements of Capitalization
|
184
|
|
|
Consolidated
Statements of Common Stockholders Equity
|
185
|
|
|
Consolidated
Statements of Cash Flows
|
186
|
|
v
TABLE
OF CONTENTS (Cont'd)
|
Page
|
|||
|
Combined
Notes to Consolidated Financial Statements
|
187-254
|
||
|
Item 9.
|
Changes
In and Disagreements with Accountants on Accounting and Financial
Disclosure
|
255
|
|
|
Item 9A.
|
Controls
and Procedures - FirstEnergy
|
255
|
|
|
Item 9A(T).
|
Controls
and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and
Penelec
|
255
|
|
|
Item
9B.
|
Other
Information
|
255
|
|
|
Part
III
|
|||
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
256
|
|
|
Item 11.
|
Executive
Compensation
|
256
|
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder
Matters
|
256
|
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
256
|
|
|
Item
14.
|
Principal
Accounting Fees and Services
|
256
|
|
|
Part
IV
|
|||
|
Item 15.
|
Exhibits,
Financial Statement Schedules
|
||
|
Report
of Independent Registered Public Accounting Firm on Financial Statement
Schedule
|
257-293
|
||
vi
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.
1
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.
2
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:
|
|
·
|
are
established by a third-party regulator with the authority to set rates
that bind customers;
|
|
|
·
|
are
cost-based; and
|
|
|
·
|
can
be charged to and collected from
customers.
|
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:
|
|
·
|
restructuring
the electric generation business and allowing the Utilities' customers to
select a competitive electric generation supplier other than the
Utilities;
|
|
|
·
|
establishing
or defining the PLR obligations to customers in the Utilities' service
areas;
|
|
|
·
|
providing
the Utilities with the opportunity to recover potentially stranded
investment (or transition costs) not otherwise recoverable in a
competitive generation market;
|
3
|
|
·
|
itemizing
(unbundling) the price of electricity into its component elements –
including generation, transmission, distribution and stranded costs
recovery charges;
|
|
|
·
|
continuing
regulation of the Utilities' transmission and distribution systems;
and
|
|
|
·
|
requiring
corporate separation of regulated and unregulated business
activities.
|
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 Reliability
First
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 Reliability
First
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. Reliability
First
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 Reliability
First
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.
4
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.
5
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.
6
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.
7
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:
8
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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.
9
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.
10
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.
11
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.
12
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.
|
||||||||
13
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%.
14
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.
15
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.
16
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 SO
2
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
SO
2
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 SO
2
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. NO
X
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 NO
X
reductions
at FirstEnergy's facilities. The EPA's NO
X
Transport
Rule imposes uniform reductions of NO
X
emissions
(an approximate 85% reduction in utility plant NO
X
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 NO
X
emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NO
X
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
NO
X
and SO
2
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.
17
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.
18
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 NO
X
and
SO
2
emissions in two phases (Phase I in 2009 for NO
X
, 2010 for
SO
2
and Phase II in 2015 for both NO
X
and
SO
2
),
ultimately capping SO
2
emissions
in affected states to 2.5 million tons annually and NO
X
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 “NO
X
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 SO
2
and
NO
X
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 CO
2
, 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.
19
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 CO
2
emissions
from automobiles as “air pollutants” under the CAA. Although this decision did
not address CO
2
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 CO
2
emissions,
or litigation alleging damages from GHG emissions, could require significant
capital and other expenditures or result in changes to its operations. The
CO
2
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-CO
2
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.
20
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.
21
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;
|
22
|
|
·
|
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 Reliability
First
. This regional entity
operates under the oversight of the NERC in accordance with a Delegation
Agreement approved by the FERC. Reliability
First
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
Reliability
First
was
certified as a regional entity. Reliability
First
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.
23
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.
24
Executive
Officers
|
Name
|
Age
|
Positions
Held During Past Five Years
|
Dates
|
|||
|
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.
|
25
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
|
|||||||
|
Employe
es
|
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.
26
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;
|
27
|
|
▪
|
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.
28
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.
29
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.
30
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.
31
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.
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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.
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.
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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.
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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.
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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.
36
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 CO
2
, 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.
37
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.
38
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.
39
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.
40
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).
41
|
Net
|
||||||||
|
Demonstrated
|
||||||||
|
Capacity
|
||||||||
|
Unit
|
(MW)
|
|||||||
|
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.
.
42
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
|
||||||||||||
|
Distri
bution
|
Transmission
|
Transformer
|
||||||||||
|
Lines
|
Lines
|
Capacity
|
||||||||||
|
(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 | |||||||||
|
|
*
|
Represents
transmission lines of 69kV and above located in the service areas of OE,
Penn, CEI and TE.
|
|
ITEM
3.
|
LEGAL
PROCEEDINGS
|
On February 16,
2010, a class action lawsuit was filed in Geauga County Court of Common Pleas
against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive
relief, as well as compensatory, incidental and consequential damages, on behalf
of a class of customers related to the reduction of a discount that had
previously been in place for residential customers with electric heating,
electric water heating, or load management systems. The reduction in the
discount was approved by the PUCO. The named-defendant companies intend to
assert all applicable defenses, including the lack of jurisdiction of the court
of common pleas, and to challenge any class certification.
Reference
is made to Note 15, Commitments, Guarantees and Contingencies, of
FirstEnergy’s Notes to Consolidated Financial Statements contained in
Item 8 for a description of certain legal proceedings involving
FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
|
ITEM
4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY
HOLDERS
|
None.
PART
II
|
ITEM
5.
|
MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED
STOCKHOLDER
|
MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
The
information required by Item 5 regarding FirstEnergy’s market information,
including stock exchange listings and quarterly stock market prices, dividends
and holders of common stock is included on page 1 of FirstEnergy’s 2009
Annual Report to Stockholders (Exhibit 13.1). Pursuant to General
Instruction I of Form 10-K, information for FES, OE, CEI, TE, JCP&L, Met-Ed
and Penelec is not required to be disclosed because they are wholly owned
subsidiaries.
Information
regarding compensation plans for which shares of FirstEnergy common stock may be
issued is incorporated herein by reference to FirstEnergy’s 2010 proxy statement
filed with the SEC pursuant to Regulation 14A under the Securities Exchange
Act of 1934.
43
The
table below includes information on a monthly basis regarding purchases made by
FirstEnergy of its common stock during the fourth quarter of 2009.
|
Period
|
||||||||||||||||
|
October
|
November
|
December
|
Fourth
Quarter
|
|||||||||||||
|
Total
Number of Shares Purchased
(a)
|
15,928 | 29,860 | 388,426 | 434,214 | ||||||||||||
|
Average
Price Paid per Share
|
$ | 45.84 | $ | 42.99 | $ | 43.28 | $ | 43.36 | ||||||||
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
- | - | - | - | ||||||||||||
|
Maximum
Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased
Under the Plans or Programs
|
- | - | - | - | ||||||||||||
|
(a)
|
Share
amounts reflect purchases on the open market to satisfy FirstEnergy's
obligations to deliver common stock under its 2007 Incentive Plan,
Deferred Compensation Plan for Outside Directors, Executive Deferred
Compensation Plan, Savings Plan and Stock Investment Plan. In addition,
such amounts reflect shares tendered by employees to pay the exercise
price or withholding taxes under the 2007 Incentive Plan and the Executive
Deferred Compensation Plan, and any shares that may have been purchased as
part of publicly announced
plans.
|
|
ITEM
6.
|
SELECTED
FINANCIAL DATA
|
FIRSTENERGY
CORP.
SELECTED
FINANCIAL DATA
|
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
|
(In
millions, except per share amounts)
|
||||||||||||||||||||
|
Revenues
|
$ | 12,967 | $ | 13,627 | $ | 12,802 | $ | 11,501 | $ | 11,358 | ||||||||||
|
Income
From Continuing Operations
|
$ | 1,006 | $ | 1,342 | $ | 1,309 | $ | 1,258 | $ | 879 | ||||||||||
|
Earnings
Available to FirstEnergy Corp.
|
$ | 1,006 | $ | 1,342 | $ | 1,309 | $ | 1,254 | $ | 861 | ||||||||||
|
Basic
Earnings per Share of Common Stock:
|
||||||||||||||||||||
|
Income
from continuing operations
|
$ | 3.31 | $ | 4.41 | $ | 4.27 | $ | 3.85 | $ | 2.68 | ||||||||||
|
Earnings
per basic share
|
$ | 3.31 | $ | 4.41 | $ | 4.27 | $ | 3.84 | $ | 2.62 | ||||||||||
|
Diluted
Earnings per Share of Common Stock:
|
||||||||||||||||||||
|
Income
from continuing operations
|
$ | 3.29 | $ | 4.38 | $ | 4.22 | $ | 3.82 | $ | 2.67 | ||||||||||
|
Earnings
per diluted share
|
$ | 3.29 | $ | 4.38 | $ | 4.22 | $ | 3.81 | $ | 2.61 | ||||||||||
|
Dividends
Declared per Share of Common Stock
(1)
|
$ | 2.20 | $ | 2.20 | $ | 2.05 | $ | 1.85 | $ | 1.705 | ||||||||||
|
Total
Assets
|
$ | 34,304 | $ | 33,521 | $ | 32,311 | $ | 31,196 | $ | 31,841 | ||||||||||
|
Capitalization
as of December 31:
|
||||||||||||||||||||
|
Total
Equity
|
$ | 8,557 | $ | 8,315 | $ | 9,007 | $ | 9,069 | $ | 9,225 | ||||||||||
|
Preferred
Stock
|
- | - | - | - | 184 | |||||||||||||||
|
Long-Term
Debt and Other Long-Term
|
||||||||||||||||||||
|
Obligations
|
11,908 | 9,100 | 8,869 | 8,535 | 8,155 | |||||||||||||||
|
Total
Capitalization
|
$ | 20,465 | $ | 17,415 | $ | 17,876 | $ | 17,604 | $ | 17,564 | ||||||||||
|
Weighted Average
Number of Basic
|
||||||||||||||||||||
|
Shares
Outstanding
|
304 | 304 | 306 | 324 | 328 | |||||||||||||||
|
Weighted Average
Number of Diluted
|
||||||||||||||||||||
|
Shares
Outstanding
|
306 | 307 | 310 | 327 | 330 | |||||||||||||||
|
(1)
|
Dividends declared in 2009 and
2008 include four quarterly dividends of $0.55 per
share. Dividends declared in 2007 include three
quarterly
payments of
$0.50 per share in 2007 and one quarterly payment of $0.55 per share in
2008. Dividends declared in 2006 include three quarterly
payments of $0.45 per share
in 2006 and one quarterly payment of $0.50 per share in 2007.
Dividends declared in 2005 include two quarterly
payments of $0.4125 per share in
2005, one quarterly payment of $0.43 per share in 2005 and one
quarterly payment of $0.45 per share in 2006
Dividends declared in 2004 include
four quarterly dividends of $0.375 per share paid in 2004 and a
quarterly dividend of $0.4125 per share paid
in
2005.
|
44
PRICE
RANGE OF COMMON STOCK
The
common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under
the symbol "FE" and is traded on other registered exchanges.
|
2009
|
2008
|
|||||||||||||||
|
First
Quarter High-Low
|
$ | 53.63 | $ | 35.63 | $ | 78.51 | $ | 64.44 | ||||||||
|
Second
Quarter High-Low
|
$ | 43.29 | $ | 35.26 | $ | 83.49 | $ | 69.20 | ||||||||
|
Third
Quarter High-Low
|
$ | 47.82 | $ | 36.73 | $ | 84.00 | $ | 63.03 | ||||||||
|
Fourth
Quarter High-Low
|
$ | 47.77 | $ | 41.57 | $ | 66.69 | $ | 41.20 | ||||||||
|
Yearly
High-Low
|
$ | 53.63 | $ | 35.26 | $ | 84.00 | $ | 41.20 | ||||||||
|
Prices
are from http://finance.yahoo.com.
|
||||||||||||||||
SHAREHOLDER
RETURN
The
following graph shows the total cumulative return from a $100 investment on
December 31, 2004 in FirstEnergy’s common stock compared with the total
cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies
and the S&P 500.
HOLDERS
OF COMMON STOCK
There
were 110,712 and 110,365 holders of 304,835,407 shares of FirstEnergy's common
stock as of December 31, 2009 and January 31, 2010, respectively.
Information regarding retained earnings available for payment of cash dividends
is given in Note 12 to the consolidated financial statements.
ITEM
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND
SUBSIDIARIES
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.
45
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.
|
|
|
·
|
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.
46
FIRSTENERGY
CORP.
MANAGEMENT'S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Earnings
available to FirstEnergy Corp. in 2009 were $1.01 billion, or basic
earnings of $3.31 per share of common stock ($3.29 diluted), compared with
earnings available to FirstEnergy Corp. of $1.34 billion, or basic earnings
of $4.41 per share of common stock ($4.38 diluted), in 2008 and
$1.31 billion, or basic earnings of $4.27 per share ($4.22 diluted), in
2007.
|
Change
in Basic Earnings Per Share From Prior Year
|
2009
|
2008
|
||||||
|
Basic
Earnings Per Share – Prior Year
|
$ | 4.41 | $ | 4.27 | ||||
|
Non-core
asset sales/impairments
|
0.47 | 0.02 | ||||||
|
Litigation
settlement
|
(0.03 | ) | 0.03 | |||||
|
Trust
securities impairment
|
0.16 | (0.20 | ) | |||||
|
Saxton
decommissioning regulatory asset – 2007
|
- | (0.05 | ) | |||||
|
Regulatory
charges
|
(0.55 | ) | - | |||||
|
Derivative
mark-to-market adjustment
|
(0.42 | ) | - | |||||
|
Organizational
restructuring
|
(0.14 | ) | - | |||||
|
Debt
redemption premiums
|
(0.31 | ) | - | |||||
|
Income
tax resolution
|
0.68 | - | ||||||
|
Revenues
|
(1.85 | ) | 1.61 | |||||
|
Fuel
and purchased power
|
(0.09 | ) | (1.24 | ) | ||||
|
Amortization
of regulatory assets, net
|
(0.02 | ) | (0.44 | ) | ||||
|
Investment
income
|
0.20 | 0.08 | ||||||
|
Interest
expense
|
(0.14 | ) | 0.04 | |||||
|
Reduced
common shares outstanding
|
- | 0.03 | ||||||
|
Transmission
expenses
|
0.73 | (0.02 | ) | |||||
|
Other
expenses
|
0.21 | 0.28 | ||||||
|
Basic
Earnings Per Share
|
$ | 3.31 | $ | 4.41 | ||||
Financial
Matters
Proposed
Merger with Allegheny Energy, Inc.
On
February 10, 2010, we entered into a Merger Agreement with Allegheny the
consummation of which will result, among other things, in our becoming an
electric utility holding company for:
|
|
·
|
generation
subsidiaries owning or controlling approximately 24,000 MWs of generating
capacity from a diversified mix of regional coal, nuclear, natural gas,
oil and renewable power,
|
|
|
·
|
ten
regulated electric distribution subsidiaries providing electric service to
more than six million customers in Pennsylvania, Ohio, Maryland, New
Jersey, New York, Virginia and West Virginia, and
|
|
|
·
|
transmission
subsidiaries owning over 20,000 miles of high-voltage lines connecting the
Midwest and Mid-Atlantic.
|
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. We
anticipate that the necessary approvals will be obtained within 12 to 14 months.
The Merger Agreement contains certain termination rights for both us 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 us with the SEC in
connection with the merger.
47
Financing
Activities
In 2009,
we issued approximately $3.7 billion of long-term debt (excluding PCRBs) --
$2.2 billion for our Energy Delivery Services Segment and $1.5 billion
for our Competitive Energy Services Segment. The primary use of the proceeds
related to the repayment of long-term debt of $1.9 billion and short-term
borrowings of $1.2 billion (primarily from the $2.75 billion revolver), to
finance capital expenditures and for other general corporate purposes, including
the Utilities’ and ATSI’s voluntary contribution of $500 million to the pension
plan. As a result, we extended the maturity schedule of long-term debt to an
average of 14.5 years, an increase of two years from 2008. Additionally,
throughout 2009, FGCO and NGC remarketed and issued $940 million of PCRBs, of
which $776 million was placed in fixed rate modes.
Rating
Agency Actions
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 (see Note 15(B)). Moody's and Fitch affirmed the ratings
and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010.
These rating agency actions were taken in response to the announcement of the
proposed merger with Allegheny.
Previously,
on June 17, 2009, Moody’s had issued a report affirming FirstEnergy’s Baa3 and
FES’ Baa2 credit ratings and maintained its stable outlook and, on July 9, 2009,
S&P had reaffirmed its since-lowered ratings on FirstEnergy and its
subsidiaries, including a BBB corporate credit rating, and maintained its then
current stable outlook.
In
addition, on August 3, 2009, Moody’s upgraded the senior secured debt ratings of
FirstEnergy’s seven regulated utilities as follows: CEI and TE were each
upgraded to Baa1 from Baa2, and JCP&L, Met-Ed, OE, Penelec and Penn were
each upgraded to A3 from Baa1.
Sumpter
Plant Sale
On
December 17, 2009, FirstEnergy announced that its FGCO subsidiary reached an
agreement in principle to sell its 340 MW Sumpter Plant in Sumpter,
Michigan, resulting in an impairment charge in 2009 of approximately
$6 million ($4 million, after tax). The sale is expected to close in
first quarter of 2010
.
The plant, built in 2002 by FGCO, consists of four 85-MW natural gas combustion
turbines.
OVEC
Participation Interest Sale
On May
1, 2009, FGCO sold a 9% interest in the output from OVEC for $252 million
(214 MW from OVEC’s generating facilities in southern Indiana and Ohio). FGCO’s
remaining interest in OVEC was reduced to 11.5%. This transaction increased 2009
net income by $159 million.
Legacy
Power Contracts
During
2008, in anticipation of certain regulatory actions, FES entered into purchased
power contracts representing approximately 4.4 million MWH per year for
MISO delivery in 2010 and 2011. These contracts, which represented less than 10%
of FES's estimated Ohio load, were intended to cover potential short positions
that were anticipated in those years and qualified for the normal purchase
normal sale scope exception under accounting for derivatives and hedging. In the
fourth quarter of 2009, as FES determined that the short positions in 2010 and
2011 were not expected to materialize based on reductions in PLR obligations and
decreased demand due to economic conditions, the contracts were modified to
financially settle to avoid congestion and transmission expenses associated with
physical delivery. As a result of the modification, the fair value of the
contracts was recorded, resulting in a mark-to-market charge of approximately
$205 million ($129 million, after tax) to purchased power expense. For
all other purchased power contracts qualifying for the normal purchase normal
sale scope exception, FES expects to take physical delivery of the power over
the remaining term of the contracts.
Operational
Matters
Recessionary
Market Conditions and Weather Impacts
Customers'
demand for electricity produced and sold by FirstEnergy’s competitive
subsidiary, FES, along with the value of that electricity, has been impacted by
conditions in competitive power markets, macro and micro economic conditions,
and weather conditions in FirstEnergy’s service territories. Recessionary
economic conditions, particularly in the automotive and steel industries,
compounded by unusually mild regional summertime temperatures, adversely
affected FirstEnergy’s operations and revenues in 2009. Generation output for
2009 was 65.9 million MWH versus 2008 output of 82.4 million
MWH.
48
Customers’
demand for electricity affects FirstEnergy’s distribution, transmission and
generation revenues, the quantity of electricity produced, purchased power
expense and fuel expense. FirstEnergy has taken various actions and instituted a
number of changes in operating practices designed to mitigate the impact of
these external influences. These actions included employee severances, wage
reductions, employee and retiree benefit changes, reduced levels of overtime and
the use of fewer contractors. Any continuing recessionary economic conditions,
coupled with unusually mild weather patterns and the resulting impact on
electricity prices and demand could also adversely affect FirstEnergy's results
of operations and financial condition and could require further changes in
FirstEnergy’s operations.
FirstEnergy
Reorganization and Voluntary Enhanced Retirement Option
Beginning
March 3, 2009, FirstEnergy reduced its management and support staff by 348
employees during 2009. This staffing reduction resulted from an effort to
enhance efficiencies in response to the economic downturn. The reduction
represented approximately 4.5% of FirstEnergy’s non-union workforce. Total
one-time charges associated with the reorganization were approximately
$66 million ($41 million, after tax), or $0.14 per share of common
stock.
In June
2009, FirstEnergy offered a VERO, which provided additional benefits for
qualified employees who elected to retire. The VERO was accepted by 397
non-represented employees and 318 union employees.
PJM
Regional Transmission Organization (RTO) Integration
On
August 17, 2009, FirstEnergy filed an application with the FERC 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 move the transmission assets that are part of FirstEnergy's
ATSI subsidiary and are located within the footprint of the Ohio Companies and
Penn - into PJM. On December 17, 2009, a FERC order approving the
integration and outlining the terms required for the move was issued and on
December 18, 2009, ATSI announced that it signed an agreement to join PJM.
FirstEnergy plans to integrate its operations into PJM by June 1,
2011.
Beaver
Valley Power Station License Renewal
On
November 5, 2009, FENOC announced that the NRC approved a 20-year license
extension for Beaver Valley Power Station Units 1 and 2 until 2036 and 2047,
respectively. Beaver Valley is located in Shippingport, Pennsylvania and is
capable of generating 1,815 MW and is the 56th out of 104 nuclear reactors in
the United States to receive a license extension from the NRC.
Refueling
Outages
On
February 23, 2009, the Perry Plant began its 12
th
scheduled refueling and maintenance outage, in which 280 of the plant’s 748 fuel
assemblies were exchanged, safety inspections were conducted, and several
maintenance projects were completed, including replacement of the plant’s
recirculation pump motor. On May 13, 2009, the Perry Plant returned to
service.
On April
20, 2009, Beaver Valley Unit 1 began its 19th scheduled refueling and
maintenance outage. During the outage, 62 of the 157 fuel assemblies were
exchanged and safety inspections were conducted. Also, several projects were
completed to ensure continued safe and reliable operations, including
maintenance on the cooling tower and the replacement of a pump motor. On May 21,
2009, Beaver Valley Unit 1 returned to service.
On
October 12, 2009, Beaver Valley Unit 2 began a scheduled refueling and
maintenance outage. During the outage, 60 of the 157 fuel assemblies were
exchanged and safety inspections were conducted. In addition, numerous
improvement projects were completed to ensure continued safe and reliable
operations. On November 27, 2009, Beaver Valley Unit 2 returned to
service.
R.
E. Burger Plant
On April
1, 2009, FirstEnergy announced plans to retrofit Units 4 and 5 at its R.E.
Burger Plant to repower the units with biomass. Retrofitting the Burger Plant is
expected to help meet the renewable energy goals set forth in Ohio SB221, will
utilize much of the existing infrastructure currently in place, preserve
approximately 100 jobs and continue positive economic support to Belmont County,
Ohio. Once complete, the Burger Plant will be one of the largest biomass
facilities in the United States. The capital cost for retrofitting the Burger
Plant is estimated to be approximately $200 million, and once completed, is
expected to be capable of producing up to 312 MW of electricity.
49
Fremont
Energy Center
On
September 22, 2009, FirstEnergy announced that it expects to complete
construction of the Fremont Energy Center by the end of 2010. Originally
acquired by FGCO in January 2008, the Fremont Energy Center includes two natural
gas combined-cycle combustion turbines and a steam turbine capable of producing
544 MW of load-following capacity and 163 MW of peaking capacity. With the
accelerated construction schedule, the remaining cost to complete the project is
estimated to be approximately $150 million.
Norton
Energy Storage Project
On
November 23, 2009, FGCO announced that it purchased a 92-acre site in Norton,
Ohio, for approximately $35 million to develop a compressed-air electric
generating plant. The transaction includes rights to a 600-acre underground
cavern ideal for energy storage technology. With 9.6 million cubic meters of
storage, the Norton Energy Storage Project has the potential to be expanded to
up to 2,700 MW of capacity. The Norton Energy Storage Project is part of
FirstEnergy's overall environmental strategy, which includes continued
investment in renewable and low-emitting energy resources.
Labor
Agreements
On May
21, 2009, 517 Penelec employees, represented by the IBEW Local 459, elected to
strike. In response, on May 22, 2009, Penelec implemented its work-continuation
plan to use nearly 400 non-represented employees with previous line experience
and training drawn from Penelec and other FirstEnergy operations to perform
service reliability and priority maintenance work in Penelec’s service
territory. Penelec's IBEW Local 459 employees ratified a three-year contract
agreement on July 19, 2009, and returned to work on July 20,
2009.
On June
26, 2009, FirstEnergy announced that seven of its union locals, representing
about 2,600 employees, ratified contract extensions. The unions included
employees from Penelec, Penn, CEI, OE and TE, along with certain power plant
employees. On July 8, 2009, FirstEnergy announced that employees of Met-Ed
represented by IBEW Local 777 ratified a two-year contract. Union members had
been working without a contract since the previous agreement expired on
April 30, 2009. On December 7, 2009, FirstEnergy announced that
employees of its FGCO subsidiary represented by the IBEW Local 272 voted to
ratify a thirty-nine month labor agreement that runs through February of 2013.
IBEW Local 272 represents 374 of 513 employees at the Bruce Mansfield Plant in
Shippingport, Pennsylvania.
Smart
Grid Proposal
On
August 6, 2009, FirstEnergy filed an application for economic stimulus funding
with the DOE under the American Recovery and Reinvestment Act that proposed
investing $114 million on smart grid technologies to improve the
reliability and interactivity of its electric distribution infrastructure in its
three-state service area. The application requested $57 million, which
represents half of the funding needed for targeted projects in communities
served by the Utilities. On October 27, 2009, FirstEnergy received notice
from the DOE that its application was selected for award negotiations. However,
no assurance can be given that we will receive such an award. The remaining
investment would be expected to be recovered through customer rates. The project
was approved by the NJBPU on August 6, 2009. Approval by the PPUC and the
PUCO for the Pennsylvania portion and the Ohio portion, respectively, of the
project is pending.
Powering
our Communities Program
In
September 2009, FES introduced Powering Our Communities, an innovative program
that offers economic support to communities in the OE, CEI and TE service areas.
The program provides up-front economic support to Ohio residents and businesses
that agree to purchase electric generation supply from FES through governmental
aggregation programs. As of February 1, 2010, FES signed agreements with 57
area communities.
In
January 2010, FES, NOPEC and GEXA Energy, NOPEC's former generation supplier,
finalized agreements making FES the generation supplier for approximately
425,000 customers in the 160 Northeast Ohio communities served by NOPEC from
January 1, 2010 through December 31, 2019.
Regulatory
Matters - Ohio
Ohio
Regulatory Update
In
August 2009, the PUCO approved the applications to accelerate the recovery
of deferred costs, primarily for distribution investments, from up to 25 years
to 18 months. The principal amount plus carrying charges through August 31,
2009, for these deferrals was approximately $305 million. Accelerated
recovery began September 1, 2009, and will be collected in the 18
non-summer months through May 31, 2011, which is expected to save customers
approximately $320 million in carrying costs.
50
On
December 10, 2009, rules went into effect that set out the manner in which
Ohio’s electric utilities will be required to comply with benchmarks contained
in SB221 related to the employment of alternative energy resources, energy
efficiency/peak demand reduction programs, greenhouse gas reporting requirements
and changes to long term forecast reporting requirements. The rules restrict the
types of renewable energy resources and energy efficiency and peak reduction
programs that may be included toward meeting the statutory goals, which is
expected to significantly increase the cost of compliance for the Ohio
companies' customers. The Ohio Companies submitted an application to amend their
2009 statutory energy efficiency benchmarks to zero. In January 2010,
the PUCO approved the Ohio Companies’ request contingent upon their meeting
energy efficiency programs in 2010 – 2012.
On
December 15, 2009, FirstEnergy's Ohio Utilities filed three-year plans with the
PUCO to offer energy efficiency programs to their customers. The filing outlined
specific programs to make homes and businesses more energy efficient and reduce
peak energy use. The PUCO has set the matter for hearing on March 2,
2010.
In
October 2009, the Ohio Companies filed an MRO to procure electric generation for
the period beginning June 1, 2011, that would establish a CBP to secure
generation supply for customers who do not shop with an alternative
supplier.
In late
2009 the Ohio Companies conducted RFPs and secured RECs including solar RECs and
RECs generated in Ohio, in order to meet the Ohio Companies’ alternative energy
requirements established under SB221 for 2009, 2010 and 2011. As the Ohio
Companies were only able to procure a portion of their solar energy resource
requirements for 2009, on December 7, 2009, they filed an application with the
PUCO seeking approval for a force majeure determination to reduce the 2009 solar
energy resources requirement to the level of the RECs received through the RFPs.
Absent this regulatory relief, the Ohio Companies may not be able to meet their
2009 statutory renewable energy benchmarks, which may result in the assessment
of forfeiture by the PUCO. The PUCO has not yet ruled on that
application.
Regulatory
Matters - Pennsylvania
NUG
Statement Compliance Filing
On March
31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance
filing to the PPUC. Both Met-Ed and Penelec proposed to reduce their CTC rate
for certain customer classes with a corresponding increase in the generation
rate and 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. The PPUC approved the compliance filings
and the reduction in the CTC rate.
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, and others filed comments objecting to the above accounting
method utilized by Met-Ed and Penelec. After Met-Ed and Penelec filed reply
comments, the PPUC issued a Secretarial Letter on November 5, 2009 allowing
parties to file reply comments to Met-Ed and Penelec’s reply comments by
November 16, 2009. Reply comments were filed and the companies are awaiting
further action by the PPUC.
Act
129
In 2009,
the PPUC approved the company-specific energy consumption and peak demand
reductions that must be achieved under Act 129, which requires electric
distribution companies to reduce electricity consumption by 1% by May 31,
2011 and by 3% by May 31, 2013, and an annual system peak demand reduction
of 4.5% by May 31, 2013. Costs associated with achieving the reduction will
be recovered from customers. On July 1, 2009, Met-Ed, Penelec and Penn
filed energy efficiency and conservation plans, which approval is
pending.
Act 129
also required utilities to file with the PPUC a smart meter technology
procurement and installation plan to provide for the installation of smart meter
technology within 15 years. The plan filed by Met-Ed, Penelec, and Penn proposed
a 24-month period to assess their needs, select 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 15 years. Met-Ed, Penelec and Penn estimate assessment period costs
at approximately $29.5 million, which the Pennsylvania Companies proposed to
recover through an automatic adjustment clause. A decision is pending by the
presiding ALJ.
51
Transmission
Cost Recovery
In 2008,
the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the
period June 1, 2008, through May 31, 2009. 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 future TSCs by December 31, 2010. Various
intervenors filed complaints against those filings and the PPUC ordered an
investigation to review the reasonableness of Met-Ed’s TSC, while allowing
Met-Ed to implement the June 1, 2008 rider, subject to refund. In August
2009, the ALJ issued a Recommend Decision to the PPUC approving Met-Ed’s and
Penelec’s TSCs as filed and dismissing all complaints. 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. The Companies 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 ultimte 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 preceding related to the 2008 TSC filing described above.
Although the new TSC resulted in an approximate 1% decrease in monthly bills for
Penelec customers, 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. Under the proposal, monthly bills for Met-Ed’s
customers would increase approximately 9.4% for the period June 2009 through May
2010.
Default
Service Plan
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. A settlement agreement was later filed on all but two issues and on
November 6, 2009, the PPUC entered an Order approving the settlement and finding
in favor of Met-Ed and Penelec on the two issues reserved for litigation.
Generation procurement began in January 2010.
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 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. The PPUC must issue an order on
the plan no later than November 8, 2010.
Regulatory
Matters – New Jersey
Solar
Renewable Energy Proposal
On March
27, 2009, the NJBPU approved JCP&L’s proposal to help increase the pace of
solar energy project development by establishing long-term agreements to
purchase and sell SRECs, which will provide a stable basis for financing solar
generation projects. In 2009, JCP&L, in collaboration with
another New Jersey electric utility, announced an RFP to secure
SRECs. A total of 61 MW of solar generating capacity (42 for
JCP&L) will be solicited to help meet New Jersey Renewable Portfolio
Standards. The first solicitation was conducted in August 2009; subsequent
solicitations will occur over the next three years. The costs of this program
are expected to be fully recoverable through a per KWH rate approved by the
NJBPU and applied to all customers.
On
February 11, 2010, Standard and Poor’s 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, a
plan addressing the mitigation of any effect of the downgrade and which 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.
52
FIRSTENERGY’S
BUSINESS
We are a
diversified energy company headquartered in Akron, Ohio, that operates primarily
through two core business segments (see “Results of Operations”). Financial
information for each of FirstEnergy’s reportable segments is presented in the
following table. With the completion of transition to a fully competitive
generation market in Ohio in 2009, the former Ohio Transitional Generation
Services segment was combined with the Energy Delivery Services segment,
consistent with how management views the business. Disclosures for FirstEnergy’s
operating segments for 2008 and 2007 have been reclassified to conform to the
2009 presentation.
|
|
·
|
Energy Delivery Services
transmits and distributes electricity through our eight utility operating
companies, serving 4.5 million customers within 36,100 square miles
of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and
default service requirements in Ohio, Pennsylvania and New Jersey. Its
revenues are primarily derived from the delivery of electricity within our
service areas, cost recovery of regulatory assets and the sale of electric
generation service to retail customers who have not selected an
alternative supplier (default service) in its Ohio, Pennsylvania and New
Jersey franchise areas. Its results reflect the commodity costs of
securing electric generation from FES and from non-affiliated power
suppliers, the net PJM and MISO transmission expenses related to the
delivery of the respective generation loads, and the deferral and
amortization of certain fuel costs.
|
The
service areas of our utilities are summarized below:
|
Company
|
Area
Served
|
Customers
Served
|
||
|
OE
|
Central
and Northeastern Ohio
|
1,038,000
|
||
|
Penn
|
Western
Pennsylvania
|
160,000
|
||
|
CEI
|
Northeastern
Ohio
|
754,000
|
||
|
TE
|
Northwestern
Ohio
|
310,000
|
||
|
JCP&L
|
Northern,
Western and East
Central
New Jersey
|
1,095,000
|
||
|
Met-Ed
|
Eastern
Pennsylvania
|
551,000
|
||
|
Penelec
|
Western
Pennsylvania
|
590,000
|
||
|
ATSI
|
Service
areas of OE, Penn,
CEI
and TE
|
|
|
·
|
Competitive Energy
Services
supplies electric power to end-use customers through
retail and wholesale arrangements, including associated company power
sales to meet all or a portion of the PLR and default service requirements
of our Ohio and Pennsylvania utility subsidiaries and competitive retail
sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan.
This business segment owns or leases and operates 19 generating facilities
with a net demonstrated capacity of 13,710 MWs and also purchases
electricity to meet sales obligations. The segment's net income is
primarily derived from affiliated and non-affiliated electric generation
sales revenues less the related costs of electricity generation, including
purchased power and net transmission (including congestion) and ancillary
costs charged by PJM and MISO to deliver energy to the segment’s
customers.
|
PROPOSED
MERGER WITH ALLEGHENY
Proposed
Merger with Allegheny Energy, Inc.
On
February 10, 2010, we entered into a Merger Agreement with Allegheny the
consummation of which will result, among other things, in our becoming an
electric utility holding company for:
|
|
·
|
generation
subsidiaries owning or controlling approximately 24,000 MWs of generating
capacity from a diversified mix of regional coal, nuclear, natural gas,
oil and renewable power,
|
|
|
·
|
ten
regulated electric distribution subsidiaries providing electric service to
more than six million customers in Pennsylvania, Ohio, Maryland, New
Jersey, New York, Virginia and West Virginia, and
|
|
|
·
|
transmission
subsidiaries owning over 20,000 miles of high-voltage lines connecting the
Midwest and Mid-Atlantic.
|
53
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. We
anticipate that the necessary approvals will be obtained within 12 to 14 months.
The Merger Agreement contains certain termination rights for both us 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 us with the SEC in
connection with the merger.
Prior
to the merger, we and Allegheny will continue to operate as separate companies.
Accordingly, except for specific references to the pending merger, the
descriptions of our strategy and outlook and the risks and challenges we face,
and the discussion and analysis of our results of operations and financial
condition set forth below relate solely to FirstEnergy. Details
regarding the pending merger are discussed in Note 21 to the consolidated
financial statements.
STRATEGY
AND OUTLOOK
We
continue to focus on the primary objectives we have developed that support our
business fundamentals – safety, generation, reliability, transitioning to
competitive markets, managing our liquidity, and growing earnings. To achieve
these objectives, we are pursuing the following strategies:
|
|
§
|
strengthening
our safety focus;
|
|
|
§
|
maximizing
the utilization of our generating
fleet;
|
|
|
§
|
meeting
our transmission and distribution reliability
goals;
|
|
|
§
|
managing
the transition to competitive generation market prices in Ohio and
Pennsylvania;
|
|
|
§
|
executing
our direct-to-customer retail sales
strategy;
|
|
|
§
|
maintaining
adequate and ready access to cash resources;
and
|
|
|
§
|
achieving
our financial goals and commitments to
shareholders.
|
2009 was
a difficult year for the U.S. economy due to the ongoing effects of the
recession. In the region FirstEnergy serves, this was evidenced by reduced
sales, particularly in the industrial sector, and very soft wholesale market
power prices when compared to 2008. We responded, in part, by making adjustments
to both our operational and capital spending plans, as well as our financing
plans. Despite these challenges, we continued to make solid progress toward
achieving our overall operational and financial goals.
We began
implementation of our long-term strategic plans during the past several years.
Our gradual progression to competitive generation markets across our tri-state
service territory and other strategies to improve performance and deliver
consistent financial results is characterized by several important transition
periods:
2007
and 2008
In 2007,
we successfully transitioned Penn to market-based retail rates for generation
service through a competitive, wholesale power supply procurement process.
During 2007 we also completed comprehensive rate cases for Met-Ed and Penelec,
which better aligned their transmission and distribution rates with their rate
base and costs to serve customers. For generation service, Met-Ed and Penelec
received partial requirements for their PLR service from FES. Also during 2007,
the Ohio Companies filed an application for an increase in electric distribution
rates with the PUCO to support a distribution rate increase. In 2009, the PUCO
granted the Ohio Companies' application to increase electric distribution rates
by $136.6 million. These increases went into effect during
2009.
We
continued our successful “mining our assets” program, through which we increased
the net-generating capacity at several facilities through cost-effective unit
upgrades. In 2008, we achieved record generation output of 82.4 billion
KWH. Our generation growth strategy is to continue to implement low cost,
incremental upgrades to existing facilities, complemented by strategic asset
purchases, rather than making substantial investments in new coal or nuclear
baseload capacity with very long lead times to construct.
We made
several strategic investments in 2008, including the purchase of the partially
complete Fremont Energy Center, which includes two natural gas combined-cycle
combustion turbines and a steam turbine capable of producing 544 MW of
load-following capacity and 163 MW of peaking capacity. We expect to complete
construction by the end of 2010.
54
In
mid-2008, we also entered into a joint venture to acquire a majority stake in
the Signal Peak coal mining project. As part of that transaction, we also
entered into a 15-year agreement to purchase up to 10 million tons of coal
annually from the mine, securing a long-term western fuel supply at attractive
prices. The higher Btu content of Signal Peak coal versus Powder River Basin
coal is expected to help avoid fossil plant derates of approximately 170 MW
and help support our incremental generation expansion plans. The burning of
Signal Peak coal is also expected to improve the performance of some of our
older generating units, which will factor into our decision making process
regarding potential future plant shutdowns. Signal Peak began commercial
operation in December 2009. Although, we have experienced some issues with the
start-up of commercial operations, we believe those issues will be resolved and
Signal Peak is expected to achieve its production goals for the
year. In the fourth quarter of 2008, FES assigned two existing Powder
River Basin contracts to a third party in order to reduce its forecasted 2010
long coal position as a result of expected deliveries from Signal
Peak.
In July
2008, we filed both a comprehensive ESP and MRO with the PUCO. In November 2008,
the PUCO issued an order denying the MRO. In December 2008, the PUCO approved,
but substantially modified, our ESP. After determining that the plan no longer
maintained a reasonable balance between providing customers with continued rate
stability and a fair return on the Ohio Companies’ investments to serve
customers, we withdrew our application for the ESP as allowed by law (see
Regulatory Matters – Ohio).
2009
and 2010
In 2009,
our total generation output of 65.9 billion KWH reflected the economic realities
of the continued recession coupled with mild weather, particularly during the
summer months. Due to the continued implementation of our retail strategy, which
will concentrate on direct sales and governmental aggregation and de-emphasize
the wholesale market, we expect a significant increase in our generation output
in 2010. Distribution rate increases became effective for OE and TE in January
2009 and for CEI in May 2009, as a result of rate cases filed in 2007.
Transition cost recovery related to the Ohio Companies’ transition to a
competitive generation market ended for OE and TE on December 31, 2008.
Additionally, FES assumed their third party partial requirements contracts and
now expects to provide Met-Ed and Penelec with their complete PLR and default
service load through the end of 2010 when their current rate caps expire and
they transition to procuring their generation requirements at competitive market
prices.
On
February 19, 2009, the Ohio Companies filed an amended ESP application,
including a Stipulation and Recommendation that was signed by the Ohio
Companies, the Staff of the PUCO, and many of the intervening parties
representing a diverse range of interests and on February 26, 2009 filed a
Supplemental Stipulation supported by nearly every party in the case, which the
PUCO approved in March 2009 (see Regulatory Matters – Ohio). The Amended ESP
included a May 2009 auction to secure full requirements generation supply and
pricing for the Ohio Companies for the period June 1, 2009 through
May 31, 2011. The auction resulted in an average weighted wholesale price
for generation and transmission of 6.15 cents per KWH. FES was a successful
bidder for 51% of the Ohio Companies PLR load.
Following
the May 2009 auction, FES accelerated the execution of its retail strategy,
described above, to directly acquire and serve customers of the Ohio Companies,
including select large commercial and industrial customers. Through
December 31, 2009, FES entered into agreements with 60 area communities
under governmental aggregation programs, representing approximately 580,000
residential and small commercial customers inside of our Ohio franchise
territories. As of December 31, 2009, FES supplied 77% of the
PLR load.
In
August 2009, we filed an application with the FERC for approval to consolidate
our ATSI transmission assets and operations currently dedicated to MISO into
PJM. On December 17, 2009, FERC issued an order approving the integration
and outlining the terms required for the move, which is expected to be complete
by June 1, 2011. On December 18, 2009, ATSI announced it had signed an
agreement to join PJM. In December 2009, we also announced that an agreement in
principle had been reached to sell the 340-MW Sumpter Plant which is located in
MISO. The sale is expected to close in the first quarter of 2010.
Total
distribution sales in 2009 were 102 million MWH, down from 112 million MWH in
2008. This decrease was due to the effects of the recession, primarily in
reduced industrial sales, coupled with mild weather.
As we
look to 2010 and beyond, we expect to continue our focus on operational
excellence with an emphasis on continuous improvement in our core businesses to
position for success during the next phase of the market recovery. This includes
ongoing incremental investment in projects to increase our generation capacity
and energy production capability as well as programs to continue to improve
transmission and distribution system reliability and customer
service.
55
2011
and Beyond
Another
major transition period for FirstEnergy will begin in 2011 as the current cap on
Met-Ed’s and Penelec’s retail generation rates is expected to expire. Beginning
in 2011, Met-Ed and Penelec have approval from the PPUC to obtain their power
supply from the competitive wholesale market and fully recover their generation
costs through retail rates. As a result, FES plans to redeploy the power
currently sold to Met-Ed and Penelec primarily to retail customers located in
and near our generation footprint and into local regional auctions and RFPs for
PLR service, with the remainder available for sale in the wholesale
market.
In Ohio,
we filed an application for an MRO with the PUCO in October 2009, which would
establish generation rates for the Ohio Companies beginning June 1, 2011,
using a descending clock-style auction similar in all material respects to that
used in the May 2009 auction process. 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.
We will
continue our efforts to extract additional production capability from existing
generating plants as discussed under “Capital Expenditures Outlook” below and
maintain the financial and strategic flexibility necessary to thrive in the
competitive marketplace.
As
discussed above, our strategy is focused on maximizing the earnings potential
from our unregulated FES operations and maintaining stable earnings growth from
our regulated utility operations.
In
addition, if approvals for the pending merger with Allegheny have been obtained
and the merger is consummated in early to mid-2011 as we currently expect, the
work of integrating Allegheny and its operations and generation, transmission
and distribution assets with our own will begin in earnest. We expect
that those efforts will enhance our ability to achieve our strategic goals as
discussed above.
Financial
Outlook
In
response to the unprecedented volatility in the capital and credit markets that
began in late 2008 and our increased risk exposure to the commodity markets that
resulted from the outcome of the Ohio CBP, we carefully assessed our exposure to
counterparty credit risk, our access to funds in the capital and credit markets,
and market-related changes in the value of our postretirement benefit trusts,
nuclear decommissioning trusts and other investments. We have taken steps
to strengthen our liquidity position and provide additional flexibility to meet
our anticipated obligations and those of our subsidiaries.
These
actions included spending reductions of more than $600 million in 2009
compared to 2008 levels through measured and appropriate changes in capital and
operation and maintenance expenditures. In addition, we adjusted the
construction schedule for the $1.8 billion AQC project at our W.H. Sammis
Plant in order to delay certain costs from our 2009 budget while still targeting
our completion deadline by the end of 2010.
We
completed significant financing activities at our regulated utilities of $2.2
billion as well as issuing 5, 12 and 30-year unsecured senior notes totaling
$1.5 billion at FES. We also completed refinancing $518 million of variable rate
debt to fixed rate debt, and made a voluntary contribution of $500 million
in September 2009 to our pension plan. 2009 cash flow from operations was strong
at $2.5 billion
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
(see Note 15(B)). Moody's and Fitch affirmed the ratings and
stable outlook of FirstEnergy and its subsidiaries on February 11,
2010.
Our
financial strategy focuses on reducing debt, a minimum of $500 million
during 2010. We are also focusing on delivering consistent financial
results, improving financial strength and flexibility, deploying cash as
effectively as possible, and improving our current credit
metrics.
Positive
earnings drivers in 2010 are expected to include:
|
|
·
|
Increased
FES commodity margin from implementation of the retail strategy and the
restructuring of the PJM PLR
contracts;
|
|
|
·
|
Increased
distribution revenues from projected sales of 110 million MWH in 2010 vs.
102 million MWH in 2009, and a full year of both the distribution rate
increase and Delivery Service Improvement Rider in
Ohio;
|
56
|
|
·
|
A
full year of operation and maintenance cost savings that resulted from
2009 staffing adjustments, changes in our compensation structure, fossil
plant outage schedule changes and general cost-saving measures;
and
|
|
|
·
|
Reduced
costs from one less nuclear refueling outage in 2010 vs.
2009.
|
Negative
earnings drivers
in
2010 are expected to include:
|
|
·
|
Reduced
gains from sale of nuclear decommissioning trust investments in
2009;
|
|
|
·
|
Reduced
RTC margin for CEI:
|
|
|
·
|
The
absence of significant favorable tax settlements in 2010 compared to 2009;
and
|
|
|
·
|
Increased
benefit and financing costs, general taxes and depreciation
expense.
|
Our liquidity position remains strong,
with access to more than $
3.3
billion of liquidity, of which
approximately $2.5 billion was available as of January 31, 2010. We
intend to continue to fund our capital requirements through cash generated from
operations
.
A driver
for longer-term earnings growth is our continued effort to improve the
utilization and output of our generation fleet. During 2010 we plan to invest
approximately $646 million in our regulated energy delivery services
business
Positive
earnings drivers for 2011 could include:
|
|
·
|
The
December 31, 2010 expiration of FES’ contracts to serve Met-Ed and
Penelec’s generation requirements. In 2011, 100% of the generation output
at FES will be priced at market;
|
|
|
·
|
Potentially
increased distribution deliveries tied to an economic recovery;
and
|
|
|
·
|
Incremental
Signal Peak coal production and price
improvement
|
Negative
earnings drivers for 2011 could include:
|
|
·
|
Increased
nuclear fuel costs and coal contract pricing
adjustments;
|
|
|
·
|
Pressure
to maintain O&M cost reductions vs. 2010 with a potentially improving
economy
|
|
|
·
|
Increased
depreciation and general taxes and lower capitalized interest resulting
from completion of our Sammis AQC and Fremont construction
projects
|
Capital
Expenditures Outlook
Our
capital expenditure forecast for 2010 is approximately $1.65
billion.
Capital
expenditures for our competitive energy services business are expected to hold
steady from 2009 to 2010 at $467 million exclusive of Sammis AQC
project, the Burger Biomass conversion and Norton, and the Fremont facility.
That level spending plan includes $65 million for the Davis-Besse steam
generator replacement, expected to be completed in 2014. Other planned
expenditures provide for maintaining of critical generation assets, delivering
operational improvements to enhance reliability, and supporting our generation
to market strategy.
This is
the final year for work on the Sammis AQC project, which is expected to go in
service at the end of 2010
.
To date, this
initiative has cost just under $1.58 billion, with an additional $241 million
planned in 2010. Expenditures on the Burger Biomass conversion project get
underway in 2010 with $16 million planned. The project is expected to be
completed by December 2012. We plan to spend $150 million in 2010 on the Fremont
facility and anticipate that work will be completed by the end of the
year.
For our
regulated operations, capital expenditures are forecast to be $646 million in
2010, primarily in support of transmission and distribution reliability
.
The
spending plan also includes projects in Ohio and Pennsylvania for Energy
Efficiency and Advanced Metering initiatives, which are expected to be partially
reimbursed through federal stimulus funding.
57
The
anticipated 2010 capital spend for the Regional Transmission Expansion
initiative is $78 million. This initiative is focused on meeting NERC,
Reliability First Corporation, PJM and FirstEnergy planning criteria
.
In
addition, there are projects associated with the connection of new retail and
wholesale load delivery points, transition to PJM market, and projects
connecting new wholesale generation connection points.
For 2011
through 2014, we anticipate average annual capital expenditures of approximately
$1.2 billion, exclusive of any additional opportunities or new mandated
spending. Planned capital initiatives promote reliability, improve operations,
and support current environmental and energy efficiency proposals.
Actual
capital spending for 2009 and projected capital spending for 2010 is as
follows:
|
Projected
Capital Spending
by
Business Unit
|
2009
|
2010
|
||||||
|
(In
millions)
|
||||||||
|
Energy
Delivery
|
$ | 687 | $ | 646 | ||||
|
Nuclear
|
259 | 265 | ||||||
|
Fossil
|
199 | 186 | ||||||
|
FES
Other
|
9 | 16 | ||||||
|
Corporate
|
46 | 52 | ||||||
|
Sammis
AQC
|
437 | 241 | ||||||
|
Subtotal
|
$ | 1,637 | $ | 1,406 | ||||
|
Fremont
Facility
|
51 | 150 | ||||||
|
Burger
Biomass and Norton
|
38 | 17 | ||||||
|
Transmission
Expansion
|
44 | 78 | ||||||
|
Total
Capital
|
$ | 1,770 | $ | 1,651 | ||||
Environmental
Outlook
At
FirstEnergy, we continually strive to enhance environmental protection and
remain good stewards of our natural resources. We allocate significant resources
to support our environmental compliance efforts, and our employees share both a
commitment to and accountability for our environmental performance. Our
corporate focus on continuous improvement is integral to our environmental
performance.
Recent
action underscores our commitment to enhancing our environmental stewardship
throughout our entire organization as well as mitigating the company’s exposure
to existing and anticipated environmental laws and regulations.
In
April, 2009, we announced our intention to convert our R.E. Burger Plant in
Shadyside, Ohio from a facility that generates electricity by burning coal to
one that will utilize renewable biomass. When completed, Burger will be one of
the largest renewable facilities of its kind in the world. In September 2009, we
announced plans to complete construction of the Fremont Energy Center, a 707-MW
natural-gas fired peaking plant located in Fremont, Ohio, by the end of 2010.
And in November 2009, we purchased the rights to develop a compressed-air
electric generating plant in Norton, Ohio. This technology would essentially
operate like a large battery with the ability to store energy when there is low
demand and then use it when needed. This is especially important for the storage
of energy generated from intermittent renewable sources of energy – such as wind
and solar – as they do not always produce energy when demand is high. Together,
these three low-emitting projects (Burger, Fremont, and Norton) are part of our
overall environmental strategy, which includes continued investment in renewable
and low-emitting energy resources.
We have
spent more than $7 billion on environmental protection efforts since the Clean
Air Act became law in 1970, and these investments are making a difference. Since
1990, we have reduced emissions of nitrogen oxides (NOx) by more than 72% sulfur
dioxide (SO2) by more than 69% and mercury by about 47%. Also, our
CO2 emission rate, in pounds of CO2 per kWh, has dropped by 19 percent through
this period. Based on this progress, emission rates for our power plants are
significantly lower than the regional average.
To
further enhance our environmental performance, we have implemented our AQC plan.
The plan includes projects designed to ensure that all of the facilities in our
generation fleet are operated in compliance with all applicable emissions
standards and limits, including NOx SO2 and particulate. It also fulfills the
requirements imposed by the 2005 Sammis Consent Decree that resolved Sammis NSR
litigation. At the end of 2010, we will have invested approximately $1.8 billion
at our W.H. Sammis Plant in Stratton, Ohio, to further reduce emissions of SO2
and NOx. This multi-year environmental retrofit project, which began in 2006 and
is expected to be completed in 2010, is designed to reduce the plant’s SO2
emissions by 95% and NOx by at least 64%. This is one of the largest
environmental retrofit projects in the nation.
58
By
yearend, we expect approximately 70% of our generation fleet to be non emitting
or low emitting generation. Over 52% of our coal-fired generating
fleet will have full NOx and SO2 equipment controls thus significantly
decreasing our exposure to the volatile emission allowance market for NOx and
SO2 and potential future environmental requirements.
One of
the key issues facing our company and industry is global climate change related
mandates. Lawmakers at the state and federal level are exploring and
implementing a wide range of responses. We believe our generation fleet is very
well positioned to be successfully competitive in a carbon-constrained
economy. In addition, we believe the proposed merger with Allegheny,
if consummated, will enhance our environmental profile as it will result in our
having an even more diverse mix of fully-scrubbed baseload fossil, non-emitting
nuclear and renewable generation, including large-scale storage.
We have
taken aggressive steps over the past two decades that have increased our
generating capacity without adding to overall CO2 emissions. For example, since
1990, we have reconfigured our fleet by retiring nearly 700 megawatts of older,
coal-based generation and adding more than 1,800 megawatts of non-emitting
nuclear capacity. Through these and other actions, we have increased our
generating capacity by nearly 15% over the same period while avoiding some 350
million metric tons of CO2 emissions. Today, nearly 40% of our electricity is
generated without emitting CO2 – a key advantage that will help us meet the
challenge of future government climate change mandates. And with recent
announcements in 2009, including the expanded use of renewable energy, energy
storage and natural gas, our CO2 emission rate will decline even further in the
future.
Moreover,
we have taken a leadership role in pursuing new ventures and testing and
developing new technologies that show promise in achieving additional reductions
in CO2 emissions. These include:
|
|
·
|
Bringing
online 132.5 MW of wind generation in 2009 and we now sell over 1 million
MWh per year of wind generation.
|
|
|
·
|
Testing
of CO2 sequestration at our R.E. Burger Plant. The results of this testing
will help us gain a better understanding of the potential for geological
storage of CO2.
|
|
|
·
|
Supporting
afforestation
– growing forests
on non-forested land – and other efforts designed to remove CO2 from the
environment.
|
|
|
·
|
Participating
in the U.S. EPA’s SF6 (sulfur hexafluoride) Emissions Reduction
Partnership for Electric Power Systems since its inception in
1998. Since then, we have reduced emissions of SF6 by nearly 20
metric tons, resulting in an equivalent reduction of nearly 430,000 tons
of CO2.
|
|
|
·
|
Supporting
research to develop and evaluate cost effective sorbent materials for CO2
capture including work by Powerspan at the Burger Plant and the University
of Akron.
|
In
addition, we will remain actively engaged in the federal and state debate over
future environmental requirements and legislation, especially those dealing with
global climate change. We are committed to working with policy makers to develop
fair and reasonable legislation, with the goal of reducing global emissions
while minimizing the economic impact on our customers. Due to the
significant uncertainty as to the final form of any such legislation at both the
federal and state levels, it makes it difficult to determine the potential
impact and risks associated with GHG emissions requirements.
We also
have a long history of supporting research in distributed energy
resources. Distributed energy resources include fuel cells, solar and
wind systems or energy storage technologies located close to the customer or
direct control of customer loads to provide alternatives or enhancements to the
traditional electric power system. Through a partnership with EPRI, the Cuyahoga
Valley National Park, the Department of Defense and Case Western Reserve
University, two solid-oxide fuel cells were installed as part of a test program
to explore the technology and the environmental benefits of distributed
generation. We are also evaluating the impact of distributed energy storage on
the distribution system through analysis and field demonstrations of advanced
battery technologies. Integrated direct load control technology with two-way
communication capability is being installed on customers’ non-critical equipment
such as air conditioners in New Jersey and Pennsylvania to help manage peak
loading on the electric distribution system.
We are
equally committed internally to environmental performance throughout our entire
organization, including our newest facility, a “green” office building in Akron
that incorporates a wide range of innovative, environmentally sound features
(pictured below). In December, this building was awarded Gold Level
certification by the U.S. Green Building Council’s Leadership in Energy and
Environmental Design (LEED) program, making this campus the largest office
building in northeast Ohio to receive this highly-prized
designation.
59
Our
efforts to protect the environment combine innovative technologies with proven
and effective work processes. For example, we are expanding an environmental
management system that tracks thousands of environmental commitments and
provides up-to-date information to responsible parties on compliance issues and
deadlines. This system allows us to more efficiently maintain our compliance
with environmental standards.
The
company also uses a rigorous compliance assistance program. Company personnel
continually audit all of our facilities, from generating plants to office
buildings, and conduct a top-to-bottom review of the entire operation to check
on compliance with company environmental policy and environmental regulation in
addition to identifying best environmental practices.
Achieving
Our Vision
Our
success in these and other key areas will help us continue to achieve our vision
of being a leading regional energy provider, recognized for operational
excellence, outstanding customer service and our commitment to safety; the
choice for long-term growth, investment value and financial strength; and a
company driven by the leadership, skills, diversity and character of our
employees.
RISKS AND
CHALLENGES
In
executing our strategy, we face a number of industry and enterprise risks and
challenges, including:
|
|
·
|
risks
arising from the reliability of our power plants and transmission and
distribution equipment;
|
|
|
·
|
changes
in commodity prices could adversely affect our profit
margins;
|
|
|
·
|
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;
|
|
|
·
|
the
use of derivative contracts by us to mitigate risks could result in
financial losses that may negatively impact our financial
results;
|
|
|
·
|
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;
|
|
|
·
|
nuclear
generation involves risks that include uncertainties relating to health
and safety, additional capital costs, the adequacy of insurance coverage
and nuclear plant decommissioning;
|
|
|
·
|
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;
|
|
|
·
|
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;
|
|
|
·
|
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;
|
|
|
·
|
disruptions
in our fuel supplies could occur, which could adversely affect our ability
to operate our generation facilities and impact financial
results;
|
|
|
·
|
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;
|
|
|
·
|
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;
|
|
|
·
|
increases
in customer electric rates and the impact of the economic downturn may
lead to a greater amount of uncollectible customer
accounts;
|
|
|
·
|
the
goodwill of one or more of our operating subsidiaries may become impaired,
which would result in write-offs of the impaired
amounts;
|
60
|
|
·
|
we
face certain human resource risks associated with the availability of
trained and qualified labor to meet our future staffing
requirements;
|
|
|
·
|
significant
increases in our operation and maintenance expenses, including our health
care and pension costs, could adversely affect our future earnings and
liquidity;
|
|
|
·
|
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;
|
|
|
·
|
acts
of war or terrorism could negatively impact our
business;
|
|
|
·
|
capital
improvements and construction projects may not be completed within
forecasted budget, schedule or scope
parameters;
|
|
|
·
|
changes
in technology may significantly affect our generation business by making
our generating facilities less
competitive;
|
|
|
·
|
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;
|
|
|
·
|
ability
of certain FirstEnergy companies to meet their obligations to other
FirstEnergy companies;
|
|
|
·
|
ability
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;
|
|
|
·
|
if
completed, our merger with Allegheny may not achieve its intended
results;
|
|
|
·
|
we
will be subject to business uncertainties and contractual restrictions
while the merger with Allegheny is pending that could adversely affect our
financial results;
|
|
|
·
|
failure
to complete the merger with Allegheny could negatively impact our stock
price and our future business and financial
results;
|
|
|
·
|
complex
and changing government regulations could have a negative impact on our
results of operations;
|
|
|
·
|
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;
|
|
|
·
|
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;
|
|
|
·
|
our
profitability is impacted by our affiliated companies’ continued
authorization to sell power at market-based
rates;
|
|
|
·
|
there
are uncertainties relating to our participation in regional transmission
organizations;
|
|
|
·
|
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;
|
|
|
·
|
energy
conservation and energy price increases could negatively impact our
financial results;
|
|
|
·
|
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;
|
|
|
·
|
our
business and activities are subject to extensive environmental
requirements and could be adversely affected by such
requirements;
|
|
|
·
|
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;
|
61
|
|
·
|
the
physical risks associated with climate change may impact our results of
operations and cash flows;
|
|
|
·
|
remediation
of environmental contamination at current or formerly owned
facilities;
|
|
|
·
|
availability
and cost of emission credits could materially impact our costs of
operations;
|
|
|
·
|
mandatory
renewable portfolio requirements could negatively affect our
costs;
|
|
|
·
|
we
are and may become subject to legal claims arising from the presence of
asbestos or other regulated substances at some of our
facilities;
|
|
|
·
|
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;
|
|
|
·
|
future
changes in financial accounting standards may affect our reported
financial results;
|
|
|
·
|
increases
in taxes and fees;
|
|
|
·
|
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
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
cannot assure common shareholders that future dividend payments will be
made, or if made, in what amounts they may be
paid;
|
|
|
·
|
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
effectively hedge our generation portfolio, and the competitiveness and
liquidity of energy markets; each could adversely affect our results of
operations, cash flows and financial condition;
and
|
|
|
·
|
questions
regarding the soundness of financial institutions or counterparties could
adversely affect us.
|
RESULTS
OF OPERATIONS
The
financial results discussed below include revenues and expenses from
transactions among our business segments. With the completion of transition to a
fully competitive generation market in Ohio in 2009, the former Ohio
Transitional Generation Services segment was combined with the Energy Delivery
Services segment, consistent with how management views the business. Disclosures
for FirstEnergy’s operating segments for 2008 and 2007 have been reclassified to
conform to the 2009 presentation. A reconciliation of segment financial results
is provided in Note 16 to the consolidated financial statements. Earnings
available to FirstEnergy Corp. by major business segment were as
follows:
|
Increase
(Decrease)
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2009
vs 2008
|
2008
vs 2007
|
||||||||||||||||
|
(In
millions, except per share amounts)
|
||||||||||||||||||||
|
Earnings
Available to FirstEnergy Corp.
|
||||||||||||||||||||
|
By
Business Segment:
|
||||||||||||||||||||
|
Energy
delivery services
|
$ | 435 | $ | 916 | $ | 965 | $ | (481 | ) | $ | (49 | ) | ||||||||
|
Competitive
energy services
|
517 | 472 | 495 | 45 | (23 | ) | ||||||||||||||
|
Other
and reconciling adjustments*
|
54 | (46 | ) | (151 | ) | 100 | 105 | |||||||||||||
|
Total
|
$ | 1,006 | $ | 1,342 | $ | 1,309 | $ | (336 | ) | $ | 33 | |||||||||
|
Basic
Earnings Per Share:
|
$ | 3.31 | $ | 4.41 | $ | 4.27 | $ | (1.10 | ) | $ | 0.14 | |||||||||
|
Diluted
Earnings Per Share:
|
$ | 3.29 | $ | 4.38 | $ | 4.22 | $ | (1.09 | ) | $ | 0.16 | |||||||||
|
*
Consists primarily of interest
expense related to holding company debt, corporate support services
revenues and expenses, and elimination of intersegment
transactions.
|
||||||||||||||||||||
62
Summary
of Results of Operations – 2009 Compared with 2008
Financial
results for our major business segments in 2009 and 2008 were as
follows:
|
Energy
|
Competitive
|
Other
and
|
||||||||||||||
|
Delivery
|
Energy
|
Reconciling
|
FirstEnergy
|
|||||||||||||
|
2009 Financial Results
|
Services
|
Services
|
Adjustments
|
Consolidated
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||
|
External
|
||||||||||||||||
|
Electric
|
$ | 10,585 | $ | 1,447 | $ | - | $ | 12,032 | ||||||||
|
Other
|
559 | 441 | (82 | ) | 918 | |||||||||||
|
Internal*
|
- | 2,843 | (2,826 | ) | 17 | |||||||||||
|
Total
Revenues
|
11,144 | 4,731 | (2,908 | ) | 12,967 | |||||||||||
|
Expenses:
|
||||||||||||||||
|
Fuel
|
- | 1,153 | - | 1,153 | ||||||||||||
|
Purchased
power
|
6,560 | 996 | (2,826 | ) | 4,730 | |||||||||||
|
Other
operating expenses
|
1,424 | 1,357 | (84 | ) | 2,697 | |||||||||||
|
Provision
for depreciation
|
445 | 270 | 21 | 736 | ||||||||||||
|
Amortization
of regulatory assets
|
1,155 | - | - | 1,155 | ||||||||||||
|
Deferral
of new regulatory assets
|
(136 | ) | - | - | (136 | ) | ||||||||||
|
General
taxes
|
641 | 108 | 4 | 753 | ||||||||||||
|
Total
Expenses
|
10,089 | 3,884 | (2,885 | ) | 11,088 | |||||||||||
|
Operating
Income
|
1,055 | 847 | (23 | ) | 1,879 | |||||||||||
|
Other
Income (Expense):
|
||||||||||||||||
|
Investment
income
|
139 | 121 | (56 | ) | 204 | |||||||||||
|
Interest
expense
|
(472 | ) | (166 | ) | (340 | ) | (978 | ) | ||||||||
|
Capitalized
interest
|
3 | 60 | 67 | 130 | ||||||||||||
|
Total
Other Income (Expense)
|
(330 | ) | 15 | (329 | ) | (644 | ) | |||||||||
|
Income
Before Income Taxes
|
725 | 862 | (352 | ) | 1,235 | |||||||||||
|
Income
taxes
|
290 | 345 | (390 | ) | 245 | |||||||||||
|
Net
Income
|
435 | 517 | 38 | 990 | ||||||||||||
|
Less:
Noncontrolling interest income (loss)
|
- | - | (16 | ) | (16 | ) | ||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 435 | $ | 517 | $ | 54 | $ | 1,006 | ||||||||
|
*
|
Consistent
with the accounting for the effects of certain types of regulation,
internal revenues do not fully eliminate representing sales of RECs by FES
to the Ohio Companies.
|
63
|
2008
Financial Results
|
Energy
Delivery
Services
|
Competitive
Energy
Services
|
Other
and
Reconciling
Adjustments
|
FirstEnergy
Consolidated
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||
|
External
|
||||||||||||||||
|
Electric
|
$ | 11,360 | $ | 1,333 | $ | - | $ | 12,693 | ||||||||
|
Other
|
708 | 238 | (12 | ) | 934 | |||||||||||
|
Internal
|
- | 2,968 | (2,968 | ) | - | |||||||||||
|
Total
Revenues
|
12,068 | 4,539 | (2,980 | ) | 13,627 | |||||||||||
|
Expenses:
|
||||||||||||||||
|
Fuel
|
2 | 1,338 | - | 1,340 | ||||||||||||
|
Purchased
power
|
6,480 | 779 | (2,968 | ) | 4,291 | |||||||||||
|
Other
operating expenses
|
2,022 | 1,142 | (119 | ) | 3,045 | |||||||||||
|
Provision
for depreciation
|
417 | 243 | 17 | 677 | ||||||||||||
|
Amortization
of regulatory assets, net
|
1,053 | - | - | 1,053 | ||||||||||||
|
Deferral
of new regulatory assets
|
(316 | ) | - | - | (316 | ) | ||||||||||
|
General
taxes
|
646 | 109 | 23 | 778 | ||||||||||||
|
Total
Expenses
|
10,304 | 3,611 | (3,047 | ) | 10,868 | |||||||||||
|
Operating
Income
|
1,764 | 928 | 67 | 2,759 | ||||||||||||
|
Other
Income (Expense):
|
||||||||||||||||
|
Investment
income
|
171 | (34 | ) | (78 | ) | 59 | ||||||||||
|
Interest
expense
|
(411 | ) | (152 | ) | (191 | ) | (754 | ) | ||||||||
|
Capitalized
interest
|
3 | 44 | 5 | 52 | ||||||||||||
|
Total
Other Expense
|
(237 | ) | (142 | ) | (264 | ) | (643 | ) | ||||||||
|
Income
Before Income Taxes
|
1,527 | 786 | (197 | ) | 2,116 | |||||||||||
|
Income
taxes
|
611 | 314 | (148 | ) | 777 | |||||||||||
|
Net
Income
|
916 | 472 | (49 | ) | 1,339 | |||||||||||
|
Less:
Noncontrolling interest income (loss)
|
- | - | (3 | ) | (3 | ) | ||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 916 | $ | 472 | $ | (46 | ) | $ | 1,342 | |||||||
|
Changes
Between 2009 and
|
||||||||||||||||
|
2008
Financial Results Increase (Decrease)
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||
|
External
|
||||||||||||||||
|
Electric
|
$ | (775 | ) | $ | 114 | $ | - | $ | (661 | ) | ||||||
|
Other
|
(149 | ) | 203 | (70 | ) | (16 | ) | |||||||||
|
Internal*
|
- | (125 | ) | 142 | 17 | |||||||||||
|
Total
Revenues
|
(924 | ) | 192 | 72 | (660 | ) | ||||||||||
|
Expenses:
|
||||||||||||||||
|
Fuel
|
(2 | ) | (185 | ) | - | (187 | ) | |||||||||
|
Purchased
power
|
80 | 217 | 142 | 439 | ||||||||||||
|
Other
operating expenses
|
(598 | ) | 215 | 35 | (348 | ) | ||||||||||
|
Provision
for depreciation
|
28 | 27 | 4 | 59 | ||||||||||||
|
Amortization
of regulatory assets
|
102 | - | - | 102 | ||||||||||||
|
Deferral
of new regulatory assets
|
180 | - | - | 180 | ||||||||||||
|
General
taxes
|
(5 | ) | (1 | ) | (19 | ) | (25 | ) | ||||||||
|
Total
Expenses
|
(215 | ) | 273 | 162 | 220 | |||||||||||
|
Operating
Income
|
(709 | ) | (81 | ) | (90 | ) | (880 | ) | ||||||||
|
Other
Income (Expense):
|
||||||||||||||||
|
Investment
income
|
(32 | ) | 155 | 22 | 145 | |||||||||||
|
Interest
expense
|
(61 | ) | (14 | ) | (149 | ) | (224 | ) | ||||||||
|
Capitalized
interest
|
- | 16 | 62 | 78 | ||||||||||||
|
Total
Other Income (Expense)
|
(93 | ) | 157 | (65 | ) | (1 | ) | |||||||||
|
Income
Before Income Taxes
|
(802 | ) | 76 | (155 | ) | (881 | ) | |||||||||
|
Income
taxes
|
(321 | ) | 31 | (242 | ) | (532 | ) | |||||||||
|
Net
Income
|
(481 | ) | 45 | 87 | (349 | ) | ||||||||||
|
Less:
Noncontrolling interest income (loss)
|
- | - | (13 | ) | (13 | ) | ||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | (481 | ) | $ | 45 | $ | 100 | $ | (336 | ) | ||||||
|
*
|
Consistent
with the accounting for the effects of certain types of regulation,
internal revenues do not fully eliminate representing sales of RECs by FES
to the Ohio Companies.
|
64
|
|
Energy
Delivery Services – 2009 Compared to
2008
|
Net
income decreased $481 million to $435 million in 2009 compared to
$916 million in 2008, primarily due to lower revenues, increased purchased
power costs and decreased deferrals of new regulatory assets, partially offset
by lower other operating expenses.
Revenues –
The
decrease in total revenues resulted from the following sources:
|
Revenues
by Type of Service
|
2009
|
2008
|
Increase
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Distribution
services
|
$ | 3,420 | $ | 3,882 | $ | (462 | ) | |||||
|
Generation
sales:
|
||||||||||||
|
Retail
|
5,760 | 5,768 | (8 | ) | ||||||||
|
Wholesale
|
752 | 962 | (210 | ) | ||||||||
|
Total
generation sales
|
6,512 | 6,730 | (218 | ) | ||||||||
|
Transmission
|
1,023 | 1,268 | (245 | ) | ||||||||
|
Other
|
189 | 188 | 1 | |||||||||
|
Total
Revenues
|
$ | 11,144 | $ | 12,068 | $ | (924 | ) | |||||
The
decreases in distribution deliveries by customer class are summarized in the
following table:
|
Electric
Distribution KWH Deliveries
|
||||
|
Residential
|
(3.3)
|
%
|
||
|
Commercial
|
(4.4)
|
%
|
||
|
Industrial
|
(14.7)
|
%
|
||
|
Total
Distribution KWH Deliveries
|
(7.3)
|
%
|
||
The
lower revenues from distribution services were driven primarily by the
reductions in sales volume associated with milder weather and economic
conditions. The decrease in residential deliveries reflected reduced
weather-related usage compared to 2008, as cooling degree days and heating
degree days decreased by 17% and 1%, respectively. The decreases in distribution
deliveries to commercial and industrial customers were primarily due to economic
conditions in FirstEnergy's service territory. In the industrial sector, KWH
deliveries declined to major automotive customers by 20.2% and to steel
customers by 36.2%. Reduced revenues from transition charges for OE and TE that
ceased with the full recovery of related costs effective January 1, 2009
and the transition rate reduction for CEI effective June 1, 2009, were offset by
PUCO-approved distribution rate increases (see Regulatory Matters –
Ohio).
The
following table summarizes the price and volume factors contributing to the
$218 million decrease in generation revenues in 2009 compared to
2008:
|
Increase
|
||||
|
Sources
of Change in Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Retail:
|
||||
|
Effect
of 10.5% decrease in sales volumes
|
$
|
(603
|
)
|
|
|
Change
in prices
|
595
|
|||
|
(8
|
)
|
|||
|
Wholesale:
|
||||
|
Effect
of 14.9% decrease in sales volumes
|
(143
|
)
|
||
|
Change
in prices
|
(67
|
)
|
||
|
(210
|
)
|
|||
|
Net
Decrease in Generation Revenues
|
$
|
(218
|
)
|
|
The
decrease in retail generation sales volumes from 2008 was primarily due to the
weakened economic conditions and milder weather described above. Retail
generation prices increased for JCP&L and Penn during 2009 as a result of
their power procurement processes. For the Ohio Companies, average prices
increased primarily due to the higher fuel cost recovery riders that were
effective from January through May 2009. In addition, effective June 1, 2009,
the Ohio Companies’ transmission tariff ended and the recovery of transmission
costs is included in the generation rate established under the CBP.
65
Wholesale
generation sales decreased principally as a result of JCP&L selling less
available power from NUGs due to the termination of a NUG purchase contract in
October 2008. The decrease in wholesale prices reflected lower spot market
prices in PJM.
Transmission
revenues decreased $245 million primarily due to the termination of the
Ohio Companies’ current transmission tariff and lower MISO and PJM transmission
revenues, partially offset by higher transmission rates for Met-Ed and Penelec
resulting from the annual updates to their TSC riders (see Regulatory Matters).
The difference between transmission revenues accrued and transmission costs
incurred are deferred, resulting in no material effect on current period
earnings.
Expenses
–
Total
expenses increased by $215 million due to the following:
|
|
·
|
Purchased
power costs were $80
million higher in
2009 due to higher unit costs, partially offset by an increase in volumes
combined with higher NUG cost deferrals. The increased purchased power
costs from non-affiliates was due primarily to increased volumes for the
Ohio Companies as a result of their CBP, partially offset by lower volumes
for Met-Ed and Penelec due to the termination of a third-party supply
contract in December 2008 and for JCP&L due to the termination of a
NUG purchase contract in October 2008. Decreased purchased power costs
from FES were principally due to lower volumes for the Ohio Companies
following their CBP, partially offset by increased volumes for Met-Ed and
Penelec under their fixed-price partial requirements PSA with FES. Higher
unit costs from FES, which included a component for transmission under the
Ohio Companies’ CBP, partially offset the decreased
volumes.
|
|
|
The
following table summarizes the sources of changes in purchased power
costs:
|
Source
of Change in Purchased Power
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchases
from non-affiliates:
|
||||
|
Change
due to increased unit costs
|
$
|
58
|
||
|
Change
due to increased volumes
|
312
|
|||
|
370
|
||||
|
Purchases
from FES:
|
||||
|
Change
due to increased unit costs
|
583
|
|||
|
Change
due to decreased volumes
|
(725
|
)
|
||
|
(142
|
)
|
|||
|
Increase
in NUG costs deferred
|
(148
|
)
|
||
|
Net
Increase in Purchased Power Costs
|
$
|
80
|
||
|
|
·
|
Transmission
expenses were lower by $481 million in 2009, reflecting the change in the
transmission tariff under the Ohio Companies' CBP, reduced transmission
volumes and lower congestion costs.
|
|
|
·
|
Intersegment
cost reimbursements related to the Ohio Companies’ nuclear generation
leasehold interests increased by $114 million in 2009. Prior to
2009, a portion of OE’s and TE’s leasehold costs were recovered through
customer transition charges. Effective January 1, 2009, these
leasehold costs are reimbursed from the competitive energy services
segment.
|
|
|
·
|
Labor
and employee benefit expenses decreased by $39 million reflecting
changes to Energy Delivery's organizational and compensation structure and
increased resources dedicated to capital projects, partially offset by
higher pension expenses resulting from reduced pension plan asset values
at the end of 2008.
|
|
|
·
|
Storm-related
costs were $16 million lower in 2009 compared to the prior
year.
|
|
|
·
|
An
increase in other operating expenses of $40 million resulted from the
recognition of economic development and energy efficiency obligations in
accordance with the PUCO-approved
ESP.
|
|
|
·
|
Uncollectible
expenses were higher by $12 million in 2009 principally due to increased
bankruptcies.
|
|
|
·
|
A
$102 million increase in the amortization of regulatory assets was due
primarily to the ESP-related impairment of CEI’s regulatory assets ($216
million) and MISO/PJM transmission cost amortization in 2009, partially
offset by the cessation of transition cost amortization for OE and
TE.
|
66
|
|
·
|
A
$180 million decrease in the deferral of new regulatory assets was
principally due to the absence in 2009 of PJM transmission cost deferrals
and RCP distribution cost deferrals, partially offset by the PUCO-approved
deferral of purchased power costs for
CEI.
|
|
|
|
|
·
|
Depreciation
expense increased $28 million due to property additions since
2008.
|
|
|
·
|
General
taxes decreased $5 million due primarily to lower revenue-related
taxes in 2009.
|
Other
Expense –
Other
expense increased $93 million in 2009 compared to 2008. Lower investment
income of $32 million resulted primarily from repaid notes receivable from
affiliates. Higher interest expense (net of capitalized interest) of $61
million resulted from a
net increase in debt of $1.8 billion by the Utilities and ATSI during
2009.
Competitive
Energy Services – 2009 Compared to 2008
Net
income increased to $517 million in 2009 compared to $472 million in the same
period of 2008. The increase in net income includes FGCO's gain from the sale of
a 9% participation interest in OVEC, increased sales margins, and an increase in
investment income, offset by a mark-to-market adjustment relating to purchased
power contracts for delivery in 2010 and 2011.
Revenues
–
Total
revenues increased $192 million in 2009 compared to the same period in
2008. This increase primarily resulted from the OVEC sale and higher unit prices
on affiliated generation sales to the Ohio Companies and non-affiliated
customers, partially offset by lower sales volumes.
The
increase in reported segment revenues resulted from the following
sources:
|
Revenues
by Type of Service
|
2009
|
2008
|
Increase
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Non-Affiliated
Generation Sales:
|
||||||||||||
|
Retail
|
$ | 778 | $ | 615 | $ | 163 | ||||||
|
Wholesale
|
669 | 718 | (49 | ) | ||||||||
|
Total
Non-Affiliated Generation Sales
|
1,447 | 1,333 | 114 | |||||||||
|
Affiliated
Generation Sales
|
2,843 | 2,968 | (125 | ) | ||||||||
|
Transmission
|
73 | 150 | (77 | ) | ||||||||
|
Sale
of OVEC participation interest
|
252 | - | 252 | |||||||||
|
Other
|
116 | 88 | 28 | |||||||||
|
Total
Revenues
|
$ | 4,731 | $ | 4,539 | $ | 192 | ||||||
The
increase in non-affiliated retail revenues of $163 million resulted from
increased revenue in both the PJM and MISO markets. The increase in MISO retail
revenue is primarily the result of the acquisition of new customers, higher unit
prices and the inclusion of the transmission related component in retail rates
previously reported as transmission revenues. The increase in PJM retail revenue
resulted from the acquisition of new customers, higher sales volumes and unit
prices. The acquisition of new customers in MISO is primarily due to new
government aggregation contracts with 60 area communities in Ohio that will
provide discounted generation prices to approximately 580,000 residential and
small commercial customers. Lower non-affiliated wholesale revenues of $49
million resulted from decreased sales volumes in PJM partially offset by
increased capacity prices, increased sales volumes in MISO, and favorable
settlements on hedged transactions.
The
lower affiliated company wholesale generation revenues of $125 million were
due to lower sales volumes to the Ohio Companies combined with lower unit prices
to the Pennsylvania companies, partially offset by higher unit prices to the
Ohio Companies and increased sales volumes to the Pennsylvania Companies. The
lower sales volumes and higher unit prices to the Ohio Companies reflected the
results of the power procurement processes in the first half of 2009 (see
Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were
due to increased Met-Ed and Penelec generation sales requirements supplied by
FES partially offset by lower sales to Penn due to decreased default service
requirements in 2009 compared to 2008. Additionally, while unit prices for each
of the Pennsylvania Companies did not change, the mix of sales among the
companies caused the overall price to decline.
67
The
following tables summarize the price and volume factors contributing to changes
in revenues from generation sales:
|
Increase
|
||||
|
Source
of Change in Non-Affiliated Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Retail:
|
||||
|
Effect
of 8.6 % increase in sales volumes
|
$
|
53
|
||
|
Change
in prices
|
110
|
|||
|
163
|
||||
|
Wholesale:
|
||||
|
Effect
of 13.9 % decrease in sales volumes
|
(100
|
)
|
||
|
Change
in prices
|
51
|
|||
|
(49
|
)
|
|||
|
Net
Increase in Non-Affiliated Generation Revenues
|
$
|
114
|
||
|
Increase
|
||||
|
Source
of Change in Affiliated Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Ohio
Companies:
|
||||
|
Effect
of 36.3 % decrease in sales volumes
|
$
|
(837
|
)
|
|
|
Change
in prices
|
645
|
|||
|
(192
|
)
|
|||
|
Pennsylvania
Companies:
|
||||
|
Effect
of 14.7 % increase in sales volumes
|
97
|
|||
|
Change
in prices
|
(30
|
)
|
||
|
67
|
||||
|
Net
Decrease in Affiliated Generation Revenues
|
$
|
(125
|
)
|
|
Transmission
revenues decreased $77 million due primarily to reduced loads following the
expiration of the government aggregation programs in Ohio at the end of 2008 and
to the inclusion of the transmission-related component in the retail rates in
mid-2009. In 2009 FGCO sold 9% of its participation interest in OVEC resulting
in a $252 million ($158 million, after tax) gain. Other revenue increased
$28 million primarily due to income associated with NGC's acquisition of
equity interests in the Perry and Beaver Valley Unit 2 leases.
Expenses
-
Total
expenses increased $273 million in 2009 due to the following
factors:
|
|
·
|
Fossil
Fuel costs decreased $198 million due primarily to lower generation
volumes ($307 million) partially offset by higher unit prices
($109 million). Nuclear Fuel costs increased $13 million as
higher unit prices ($26 million) were partially offset by lower
generation ($13 million).
|
|
|
·
|
Purchased
power costs increased $217 million due to a mark-to-market adjustment
($205 million) relating to purchased power contracts for delivery in
2010 and 2011 and higher unit prices ($33 million) that resulted
primarily from higher capacity costs, partially offset by lower volumes
purchased ($21 million) due to FGCO's reduced participation interest in
OVEC.
|
|
|
·
|
Fossil
operating costs decreased $24 million due primarily to a reduction in
contractor, material and labor costs and increased resources dedicated to
capital projects, partially offset by higher employee
benefits.
|
|
|
·
|
Nuclear
operating costs increased $45 million due to an additional refueling
outage during the 2009 period and higher employee benefits, partially
offset by lower labor costs.
|
|
|
·
|
Transmission
expense increased $121 million due to transmission services charges
related to the load serving entity obligations in MISO, increased net
congestion and higher loss expenses in MISO and
PJM.
|
|
|
·
|
Other
expense increased $72 million due primarily to increased intersegment
billings for leasehold costs from the Ohio Companies and higher pension
costs.
|
|
|
·
|
Depreciation
expense increased $27 million due to NGC's increased ownership
interest in Beaver Valley Unit 2 and
Perry.
|
68
Other
Income (Expense) –
Total
other income in 2009 was $15
million compared to
total other expense in 2008 of $142 million, resulting primarily from a
$155 million increase from gains on the sale of nuclear decommissioning
trust investments. During 2009, the majority of the nuclear decommissioning
trust holdings were converted to more closely align with the liability being
funded.
Other
– 2009 Compared to 2008
Our
financial results from other operating segments and reconciling items resulted
in a $100 million increase in net income in 2009 compared to 2008. The
increase resulted primarily from $200 million of favorable tax settlements,
offset by debt redemption costs of $90 million and by the absence of the
gain from the sale of telecommunication assets ($19 million, net of taxes)
in 2008.
69
Summary
of Results of Operations – 2008 Compared with 2007
Financial
results for our major business segments in 2007 were as follows:
|
2007
Financial Results
|
Energy
Delivery
Services
|
Competitive
Energy
Services
|
Other
and Reconciling
Adjustments
|
FirstEnergy
Consolidated
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||
|
External
|
||||||||||||||||
|
Electric
|
$ | 10,628 | $ | 1,316 | $ | - | $ | 11,944 | ||||||||
|
Other
|
694 | 152 | 12 | 858 | ||||||||||||
|
Internal
|
- | 2,901 | (2,901 | ) | - | |||||||||||
|
Total
Revenues
|
11,322 | 4,369 | (2,889 | ) | 12,802 | |||||||||||
|
Expenses:
|
||||||||||||||||
|
Fuel
|
5 | 1,173 | - | 1,178 | ||||||||||||
|
Purchased
power
|
5,973 | 764 | (2,901 | ) | 3,836 | |||||||||||
|
Other
operating expenses
|
2,005 | 1,160 | (82 | ) | 3,083 | |||||||||||
|
Provision
for depreciation
|
404 | 204 | 30 | 638 | ||||||||||||
|
Amortization
of regulatory assets
|
1,019 | - | - | 1,019 | ||||||||||||
|
Deferral
of new regulatory assets
|
(524 | ) | - | - | (524 | ) | ||||||||||
|
General
taxes
|
627 | 107 | 20 | 754 | ||||||||||||
|
Total
Expenses
|
9,509 | 3,408 | (2,933 | ) | 9,984 | |||||||||||
|
Operating
Income
|
1,813 | 961 | 44 | 2,818 | ||||||||||||
|
Other
Income (Expense):
|
||||||||||||||||
|
Investment
income
|
241 | 16 | (137 | ) | 120 | |||||||||||
|
Interest
expense
|
(457 | ) | (172 | ) | (146 | ) | (775 | ) | ||||||||
|
Capitalized
interest
|
11 | 20 | 1 | 32 | ||||||||||||
|
Total
Other Expense
|
(205 | ) | (136 | ) | (282 | ) | (623 | ) | ||||||||
|
Income
Before Income Taxes
|
1,608 | 825 | (238 | ) | 2,195 | |||||||||||
|
Income
taxes
|
643 | 330 | (90 | ) | 883 | |||||||||||
|
Net
Income
|
965 | 495 | (148 | ) | 1,312 | |||||||||||
|
Less:
Noncontrolling interest income
|
- | - | 3 | 3 | ||||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 965 | $ | 495 | $ | (151 | ) | $ | 1,309 | |||||||
|
Changes
Between 2008 and
|
||||||||||||||||
|
2007
Financial Results Increase (Decrease)
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||
|
External
|
||||||||||||||||
|
Electric
|
$ | 732 | $ | 17 | $ | - | $ | 749 | ||||||||
|
Other
|
14 | 86 | (24 | ) | 76 | |||||||||||
|
Internal
|
- | 67 | (67 | ) | - | |||||||||||
|
Total
Revenues
|
746 | 170 | (91 | ) | 825 | |||||||||||
|
Expenses:
|
||||||||||||||||
|
Fuel
|
(3 | ) | 165 | - | 162 | |||||||||||
|
Purchased
power
|
507 | 15 | (67 | ) | 455 | |||||||||||
|
Other
operating expenses
|
17 | (18 | ) | (37 | ) | (38 | ) | |||||||||
|
Provision
for depreciation
|
13 | 39 | (13 | ) | 39 | |||||||||||
|
Amortization
of regulatory assets
|
34 | - | - | 34 | ||||||||||||
|
Deferral
of new regulatory assets
|
208 | - | - | 208 | ||||||||||||
|
General
taxes
|
19 | 2 | 3 | 24 | ||||||||||||
|
Total
Expenses
|
795 | 203 | (114 | ) | 884 | |||||||||||
|
Operating
Income
|
(49 | ) | (33 | ) | 23 | (59 | ) | |||||||||
|
Other
Income (Expense):
|
||||||||||||||||
|
Investment
income
|
(70 | ) | (50 | ) | 59 | (61 | ) | |||||||||
|
Interest
expense
|
46 | 20 | (45 | ) | 21 | |||||||||||
|
Capitalized
interest
|
(8 | ) | 24 | 4 | 20 | |||||||||||
|
Total
Other Expense
|
(32 | ) | (6 | ) | 18 | (20 | ) | |||||||||
|
Income
Before Income Taxes
|
(81 | ) | (39 | ) | 41 | (79 | ) | |||||||||
|
Income
taxes
|
(32 | ) | (16 | ) | (58 | ) | (106 | ) | ||||||||
|
Net
Income
|
(49 | ) | (23 | ) | 99 | 27 | ||||||||||
|
Less:
Noncontrolling interest income
|
- | - | (3 | ) | (3 | ) | ||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | (49 | ) | $ | (23 | ) | $ | 102 | $ | 30 | ||||||
70
Energy
Delivery Services – 2008 Compared to 2007
Net
income decreased $49 million to $916 million in 2008 compared to
$965 million in 2007, primarily due to increased purchased power costs,
decreased deferral of new regulatory assets and lower investment income,
partially offset by higher revenues.
Revenues
–
The
increase in total revenues resulted from the following sources:
|
Revenues
by Type of Service
|
2008
|
2007
|
Increase
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Distribution
services
|
$ | 3,882 | $ | 3,909 | $ | (27 | ) | |||||
|
Generation
sales:
|
||||||||||||
|
Retail
|
5,768 | 5,393 | 375 | |||||||||
|
Wholesale
|
962 | 694 | 268 | |||||||||
|
Total
generation sales
|
6,730 | 6,087 | 643 | |||||||||
|
Transmission
|
1,267 | 1,118 | 149 | |||||||||
|
Other
|
189 | 208 | (19 | ) | ||||||||
|
Total
Revenues
|
$ | 12,068 | $ | 11,322 | $ | 746 | ||||||
The
decreases in distribution deliveries by customer class are summarized in the
following table:
|
Electric
Distribution KWH Deliveries
|
|||||
|
Residential
|
(0.9
|
)%
|
|||
|
Commercial
|
(0.9
|
)%
|
|||
|
Industrial
|
(3.9
|
)%
|
|||
|
Total
Distribution KWH Deliveries
|
(1.9
|
)%
|
|||
The
decrease in electric distribution deliveries to residential and commercial
customers was primarily due to reduced summer usage resulting from milder
weather in 2008 compared to the same period of 2007, as cooling degree days
decreased by 14.6%; heating degree days increased by 2.5%. In the industrial
sector, a decrease in deliveries to automotive customers (18%) and steel
customers (4%) was partially offset by an increase in usage by refining
customers (3%).
The
following table summarizes the price and volume factors contributing to the
$643 million increase in generation revenues in 2008 compared to
2007:
|
Increase
|
||||
|
Sources
of Change in Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Retail:
|
||||
|
Effect
of 1.9% decrease in sales volumes
|
$
|
(103
|
)
|
|
|
Change
in prices
|
478
|
|||
|
375
|
||||
|
Wholesale:
|
||||
|
Effect
of 0.1% increase in sales volumes
|
1
|
|||
|
Change
in prices
|
267
|
|||
|
268
|
||||
|
Net
Increase in Generation Revenues
|
$
|
643
|
||
The
decrease in retail generation sales volumes was primarily due to milder weather
and economic conditions in the Utilities' service territories and an increase in
customer shopping for Penn, Penelec and JCP&L. The increase in retail
generation prices in 2008 was due to higher generation rates for JCP&L
resulting from the New Jersey BGS auctions effective June 1, 2007 and
June 1, 2008, and the Ohio Companies' fuel cost recovery riders that became
effective in January 2008. The increase in wholesale prices reflected higher
spot market prices for PJM market participants.
Transmission
revenues increased $149 million due to higher transmission rates for Met-Ed
and Penelec resulting from the annual update to their TSC riders in mid-2008 and
the Ohio Companies' PUCO-approved transmission tariff increases that became
effective July 1, 2007 and July 1, 2008. The difference between
transmission revenues accrued and transmission expenses incurred is deferred,
resulting in no material impact to current period earnings.
71
Expenses
–
The net
revenue increase discussed above was more than offset by a $795 million
increase in expenses due to the following:
|
|
·
|
Purchased
power costs were $507
million higher in
2008 due to higher unit costs and a decrease in the amount of NUG costs
deferred. The increase in unit costs from non-affiliates was primarily due
to higher costs for JCP&L resulting from the BGS auction process.
JCP&L is permitted to defer for future collection from customers the
amounts by which its costs of supplying BGS to non-shopping customers and
costs incurred under NUG agreements exceed amounts collected through BGS
and NUGC rates and market sales of NUG energy and capacity. Higher unit
costs from FES reflect the increases in the Ohio Companies' retail
generation rates, as provided for under the PSA then in effect with FES.
The decrease in purchase volumes was due to the lower retail generation
sales requirements described above.
|
The
following table summarizes the sources of changes in purchased power
costs:
|
Source
of Change in Purchased Power
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchases
from non-affiliates:
|
||||
|
Change
due to increased unit costs
|
$
|
456
|
||
|
Change
due to decreased volumes
|
(128
|
)
|
||
|
328
|
||||
|
Purchases
from FES:
|
||||
|
Change
due to increased unit costs
|
110
|
|||
|
Change
due to decreased volumes
|
(44
|
)
|
||
|
66
|
||||
|
Decrease
in NUG costs deferred
|
113
|
|||
|
Net
Increase in Purchased Power Costs
|
$
|
507
|
||
|
|
·
|
Other
operating expenses increased $17
million due
primarily to the net effect of the
following:
|
|
|
-
|
a
$69 million increase primarily for reduced intersegment credits associated
with the Ohio Companies' nuclear generation leasehold interests and
increased MISO transmission-related
expenses;
|
|
|
-
|
a
$15
million
decrease for contractor costs associated with vegetation management
activities, as more of that work performed in 2008 related to capital
projects;
|
|
|
-
|
a
$13 million decrease in uncollectible expense due primarily to the
recognition of higher uncollectible reserves in 2007 and enhanced
collection processes in 2008;
|
|
|
-
|
lower
labor costs charged to operating expense of $12 million, as a greater
proportion of labor was devoted to capital-related projects in 2008;
and
|
|
|
-
|
a
$6 million decline in regulatory program costs, including customer
rebates.
|
|
|
·
|
Amortization
of regulatory assets increased $34 million due primarily to higher
transition cost amortization for the Ohio Companies, partially offset by
decreases at JCP&L for regulatory assets that were fully recovered at
the end of 2007 and in the first half of
2008.
|
|
|
|
|
·
|
The
deferral of new regulatory assets during 2008 was $208 million lower
than in 2007. MISO transmission deferrals and RCP fuel deferrals decreased
$166 million, as more transmission and generation costs were recovered
from customers through PUCO-approved riders. Also contributing to the
decrease was the absence of the one-time deferral in 2007 of
decommissioning costs related to the Saxton nuclear research facility
($27 million) and lower PJM transmission cost deferrals ($32
million), partially offset by increased societal benefit deferrals
($15 million).
|
|
|
·
|
Higher
depreciation expense of $13 million resulted from additional capital
projects placed in service since
2007.
|
|
|
·
|
General
taxes increased $19 million due to higher gross receipts taxes,
property taxes and payroll taxes.
|
72
Other
Expense –
Other
expense increased $32 million in 2008 compared to 2007 due to lower
investment income of $70
million, resulting
primarily from the repayment of notes receivable from affiliates, partially
offset by lower interest expense (net of capitalized interest) of
$38 million. The interest expense declined for the Ohio Companies due to
their redemption of certain pollution control notes in the second half of
2007.
Competitive
Energy Services – 2008 Compared to 2007
Net
income for this segment was $472 million in 2008 compared to
$495 million in 2007. The $23 million reduction in net income reflects
a decrease in gross generation margin (revenue less fuel and purchased power)
and higher depreciation expense, which were partially offset by lower other
operating expenses.
Revenues
–
Total
revenues increased $170
million in 2008 compared
to 2007. This increase primarily resulted from higher unit prices on affiliated
generation sales to the Ohio Companies and increased non-affiliated wholesale
sales, partially offset by lower retail sales.
The
increase in reported segment revenues resulted from the following
sources:
|
Revenues
by Type of Service
|
2008
|
2007
|
Increase
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Non-Affiliated
Generation Sales:
|
||||||||||||
|
Retail
|
$ | 615 | $ | 712 | $ | (97 | ) | |||||
|
Wholesale
|
717 | 603 | 114 | |||||||||
|
Total
Non-Affiliated Generation Sales
|
1,332 | 1,315 | 17 | |||||||||
|
Affiliated
Generation Sales
|
2,968 | 2,901 | 67 | |||||||||
|
Transmission
|
150 | 103 | 47 | |||||||||
|
Other
|
89 | 50 | 39 | |||||||||
|
Total
Revenues
|
$ | 4,539 | $ | 4,369 | $ | 170 | ||||||
The
lower retail revenues reflect reduced commercial and industrial contract
renewals in the PJM market and the termination of certain government aggregation
programs in MISO. Higher non-affiliated wholesale revenues resulted from higher
capacity prices and increased sales volumes in PJM, partially offset by
decreased sales volumes in MISO.
The
increased affiliated company generation revenues were due to higher unit prices
for the Ohio Companies partially offset by lower unit prices for the
Pennsylvania Companies and decreased affiliated sales volumes. The higher unit
prices reflected fuel-related increases in the Ohio Companies’ retail generation
rates. While unit prices for each of the Pennsylvania Companies did not change,
the mix of sales among the companies caused the overall price to decline. The
reduction in PSA sales volumes to the Ohio and Pennsylvania Companies was due to
the milder weather and industrial sales changes discussed above and reduced
default service requirements in Penn’s service territory as a result of its RFP
process.
The
following tables summarize the price and volume factors contributing to changes
in revenues from generation sales:
|
Increase
|
||||
|
Source
of Change in Non-Affiliated Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Retail:
|
||||
|
Effect
of 15.8% decrease in sales volumes
|
$
|
(113
|
)
|
|
|
Change
in prices
|
16
|
|||
|
(97
|
)
|
|||
|
Wholesale:
|
||||
|
Effect
of 3.8% increase in sales volumes
|
23
|
|||
|
Change
in prices
|
91
|
|||
|
114
|
||||
|
Net
Increase in Non-Affiliated Generation Revenues
|
$
|
17
|
||
73
|
Increase
|
||||
|
Source
of Change in Affiliated Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Ohio
Companies:
|
||||
|
Effect
of 1.5% decrease in sales volumes
|
$
|
(34
|
)
|
|
|
Change
in prices
|
129
|
|||
|
95
|
||||
|
Pennsylvania
Companies:
|
||||
|
Effect
of 1.5% decrease in sales volumes
|
(10
|
)
|
||
|
Change
in prices
|
(18
|
)
|
||
|
(28
|
)
|
|||
|
Net
Increase in Affiliated Generation Revenues
|
$
|
67
|
||
Transmission
revenues increased $47 million due primarily to higher transmission rates
in MISO and PJM.
Expenses
–
Total
expenses increased $203 million in 2008 due to the following
factors:
|
|
·
|
Fossil
fuel costs increased $155 million due to higher unit prices
($163 million) partially offset by lower generation volume
($8 million). The increased unit prices primarily reflect increased
rates for existing eastern coal contracts, higher transportation
surcharges and emission allowance costs in 2008. Nuclear fuel expense was
$10 million higher as nuclear generation increased in
2008.
|
|
|
·
|
Purchased
power costs increased $15 million due primarily to higher spot market
and capacity prices, partially offset by reduced volume
requirements.
|
|
|
·
|
Fossil
operating costs decreased $22 million due to a gain on the sale of a
coal contract in the fourth quarter of 2008 ($20 million), reduced
scheduled outage activity ($17 million) and increased gains from
emission allowance sales ($7 million), partially offset by costs
associated with a cancelled electro-catalytic oxidation project
($13 million) and a $7 million increase in labor
costs.
|
|
|
·
|
Transmission
expense decreased $35 million due to reduced congestion
costs.
|
|
|
·
|
Other
operating costs increased $39 million due primarily to the assignment
of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO
in the fourth quarter of 2007 ($31 million) and reduced life
insurance investment values, partially offset by lower associated company
billings and employee benefit
costs.
|
|
|
·
|
Higher
depreciation expenses of $39 million were due to the assignment of
the Bruce Mansfield Plant leasehold interests to FGCO and NGC’s purchase
of certain lessor equity interests in Perry and Beaver Valley Unit
2.
|
Other
Expense –
Total
other expense in 2008 was $6
million higher than in
2007, principally due to a $50 million decrease in net earnings from
nuclear decommissioning trust investments due primarily to securities
impairments resulting from market declines during 2008, partially offset by a
decline in interest expense (net of capitalized interest) of $44 million
from the repayment of notes to affiliates since 2007.
Other
– 2008 Compared to 2007
Our
financial results from other operating segments and reconciling items resulted
in a $105 million increase in net income in 2008 compared to 2007. The
increase resulted primarily from a $19 million after-tax gain from the sale
of telecommunication assets, a $10 million after-tax gain from the
settlement of litigation relating to formerly-owned international assets, a
$41 million reduction in interest expense associated with the revolving
credit facility, and income tax adjustments associated with the favorable
settlement of tax positions taken on federal returns in prior years. These
increases were partially offset by the absence of the gain from the sale of
First Communications ($13 million, net of taxes) in 2007.
74
POSTRETIREMENT
BENEFITS
We
provide a noncontributory qualified defined benefit pension plan that covers
substantially all of our employees and non-qualified pension plans that cover
certain employees. The plans provide defined benefits based on years of service
and compensation levels. We also provide health care benefits, which include
certain employee contributions, deductibles, and co-payments, upon retirement to
employees hired prior to January 1, 2005, their dependents, and under
certain circumstances, their survivors. Our benefit plan assets and obligations
are remeasured annually using a December 31 measurement date. Adverse
market conditions during 2008 increased 2009 costs, which were partially offset
by the effects of a $500 million voluntary cash pension contribution and an
OPEB plan amendment in 2009 (see Note 3). Strengthened equity markets
during 2007 and a $300 million voluntary cash pension contribution made in
2007 contributed to the reductions in postretirement benefits expenses in 2008.
Pension and OPEB expenses are included in various cost categories and have
contributed to cost increases discussed above for 2009. The following table
reflects the portion of qualified and non-qualified pension and OPEB costs that
were charged to expense in the three years ended December 31,
2009:
|
Postretirement
Benefits Expense (Credits)
|
2009
|
2008
|
2007
|
||||||||||
|
(In
millions)
|
|||||||||||||
|
Pension
|
$ | 185 | $ | (23 | ) | $ | 6 | ||||||
|
OPEB
|
(40 | ) | (37 | ) | (41 | ) | |||||||
|
Total
|
$ | 145 | $ | (60 | ) | $ | (35 | ) | |||||
As of
December 31, 2009, our pension plan was underfunded and we currently
anticipate that additional cash contributions will be required in 2012 for the
2011 plan year. The overall actual investment result during 2009 was a gain of
13.6% compared to an assumed 9% return. Based on discount rates of 6% for
pension and 5.75% for OPEB, 2010 pre-tax net periodic pension and OPEB expense
will be approximately $89 million.
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. 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 its total generation and
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.
CAPITAL
RESOURCES AND LIQUIDITY
As of
January 31, 2010 we had commitments of approximately $3.4 billion
of liquidity including a $2.75 billion revolving credit facility, a
$100 million bank line available to FES and $515 million of accounts
receivable financing facilities through our Ohio and Pennsylvania utilities. We
expect our existing sources of liquidity to remain sufficient to meet our
anticipated obligations and those of our subsidiaries. Our 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, we expect to satisfy these
requirements with a combination of cash from operations and funds from the
capital markets as market conditions warrant. We also expect that borrowing
capacity under credit facilities will continue to be available to manage working
capital requirements during those periods.
75
As of
December 31, 2009, our net deficit in working capital (current assets less
current liabilities) was principally due to short-term borrowings
($1.2 billion) and the classification of certain variable interest rate
PCRBs as currently payable long-term debt. Currently payable long-term debt as
of December 31, 2009, included the following (in millions):
|
Currently
Payable Long-term Debt
|
||||
|
PCRBs
supported by bank LOCs
(1)
|
$
|
1,553
|
||
|
FGCO
and NGC unsecured PCRBs
(1)
|
15
|
|||
|
Met-Ed
unsecured notes
(2)
|
100
|
|||
|
Penelec
FMBs
(3)
|
24
|
|||
|
NGC
collateralized lease obligation bonds
|
45
|
|||
|
Sinking
fund requirements
|
34
|
|||
|
Other
notes
(3)
|
63
|
|||
|
$
|
1,834
|
|||
|
(1)
Interest
rate mode permits individual debt holders to put the respective debt back
to the issuer prior to maturity.
(2)
Mature
in March 2010.
(3)
Mature
in November 2010.
|
||||
Short-Term
Borrowings
We had
approximately $1.2 billion of short-term borrowings as of December 31, 2009
and $2.4 billion as of December 31, 2008. Our available liquidity as
of January 31, 2010, is summarized 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.
|
Revolving
Credit Facility
We have
the capability to request an increase in the total commitments available under
the $2.75 billion revolving credit facility (included in the borrowing
capability table above) up to a maximum of $3.25 billion, subject to the
discretion of each lender to provide additional commitments. Commitments under
the facility are available until August 24, 2012, unless the lenders agree,
at the request of the borrowers, to an unlimited number of additional one-year
extensions. Generally, borrowings under the facility must be repaid within 364
days. Available amounts for each borrower are subject to a specified sub-limit,
as well as applicable regulatory and other limitations.
The
following table summarizes the borrowing sub-limits for each borrower under the
facility, as well as the limitations on short-term indebtedness applicable to
each borrower under current regulatory approvals and applicable statutory and/or
charter limitations as of December 31, 2009:
76
|
Borrower
|
Revolving
Credit
Facility
Sub-Limit
|
Regulatory
and
Other
Short-Term
Debt
Limitations
|
||||||
|
(In
millions)
|
||||||||
|
FirstEnergy
|
$ | 2,750 | $ | - | (1) | |||
|
FES
|
1,000 | - | (1) | |||||
|
OE
|
500 | 500 | ||||||
|
Penn
|
50 | 33 | (2) | |||||
|
CEI
|
250 | (3) | 500 | |||||
|
TE
|
250 | (3) | 500 | |||||
|
JCP&L
|
425 | 411 | (2) | |||||
|
Met-Ed
|
250 | 300 | (2) | |||||
|
Penelec
|
250 | 300 | (2) | |||||
|
ATSI
|
50 | (4) | 50 | |||||
|
(1)
No
regulatory approvals, statutory or charter limitations
applicable.
(2)
Excluding
amounts which may be borrowed under the regulated companies' money
pool.
(3)
Borrowing
sub-limits for CEI and TE may be increased to up to $500 million by
delivering notice to the administrative agent that such borrower has
senior unsecured debt ratings of at least BBB by S&P and Baa2 by
Moody's.
(4)
The
borrowing sub-limit for ATSI may be increased up to $100 million by
delivering notice to the administrative agent that ATSI has received
regulatory approval to have short-term borrowings up to the same
amount.
|
||||||||
Under
the revolving credit facility, borrowers may request the issuance of LOCs
expiring up to one year from the date of issuance. The stated amount of
outstanding LOCs will count against total commitments available under the
facility and against the applicable borrower's borrowing sub-limit.
The
revolving credit facility contains financial covenants requiring each borrower
to maintain a consolidated debt to total capitalization ratio of no more than
65%, measured at the end of each fiscal quarter. As of December 31, 2009,
our debt to total capitalization ratios (as defined under the revolving credit
facility) were as follows:
|
Borrower
|
||||
|
FirstEnergy
(1)
|
61.5 | % | ||
|
FES
|
54.8 | % | ||
|
OE
|
51.3 | % | ||
|
Penn
|
35.5 | % | ||
|
CEI
|
59.7 | % | ||
|
TE
|
60.8 | % | ||
|
JCP&L
|
35.6 | % | ||
|
Met-Ed
|
41.2 | % | ||
|
Penelec
|
53.6 | % | ||
|
ATSI
|
48.8 | % | ||
|
(1)
|
As
of December 31, 2009, FirstEnergy could issue additional debt of
approximately $2.5 billion, or recognize a reduction in equity of
approximately $1.4 billion, and remain within the limitations of the
financial covenants required by its revolving credit
facility.
|
The
revolving credit facility does not contain provisions that either restrict the
ability to borrow or accelerate repayment of outstanding advances as a result of
any change in credit ratings. Pricing is defined in "pricing grids," whereby the
cost of funds borrowed under the facility is related to the credit ratings of
the company borrowing the funds.
FirstEnergy
Money Pools
FirstEnergy's
regulated companies also have the ability to borrow from each other and the
holding company to meet their short-term working capital requirements. A similar
but separate arrangement exists among FirstEnergy's unregulated companies. FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. Companies receiving a loan under the money pool
agreements must repay the principal amount of the loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from their respective pool and is based
on the average cost of funds available through the pool. The average interest
rate for borrowings in 2009 was 0.72% for the regulated companies' money pool
and 0.90% for the unregulated companies' money pool.
77
Pollution
Control Revenue Bonds
As of
December 31, 2009, our currently payable long-term debt included
approximately $1.6 billion (FES - $1.5 billion, Met-Ed -
$29 million and Penelec - $45 million) of variable interest rate
PCRBs, the bondholders of which are entitled to the benefit of irrevocable
direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly.
Bondholders can tender their PCRBs for mandatory purchase prior to maturity with
the purchase price payable from remarketing proceeds or, if the PCRBs are not
successfully remarketed, by drawings on the irrevocable direct pay LOCs. The
subsidiary obligor is required to reimburse the applicable LOC bank for any such
drawings or, if the LOC bank fails to honor its LOC for any reason, must itself
pay the purchase price.
The LOCs
for our variable interest rate PCRBs were issued by the following
banks:
|
Aggregate
LOC
|
Reimbursements
of
|
||||||
|
LOC
Bank
|
Amount
(3)
|
LOC
Termination Date
|
LOC
Draws Due
|
||||
|
(In
millions)
|
|||||||
|
CitiBank
N.A.
|
$ | 166 |
June
2014
|
June
2014
|
|||
|
The
Bank of Nova Scotia
|
284 |
Beginning
April 2011
|
Multiple
dates
(4)
|
||||
|
The
Royal Bank of Scotland
|
131 |
June
2012
|
6
months
|
||||
|
KeyBank
(1)
|
237 |
June
2010
|
6
months
|
||||
|
Wachovia
Bank
|
153 |
March
2014
|
March
2014
|
||||
|
Barclays
Bank
(2)
|
528 |
Beginning
December 2010
|
30
days
|
||||
|
PNC
Bank
|
70 |
Beginning
November 2010
|
180
days
|
||||
|
Total
|
$ | 1,569 | |||||
|
|
(1)
|
Supported
by four participating banks, with the LOC bank having 58% of the total
commitment.
|
|
|
(2)
|
Supported
by 18 participating banks, with no one bank having more than 14% of the
total commitment.
|
|
|
(3)
|
Includes
approximately $16 million of applicable interest
coverage.
|
|
|
(4)
|
Shorter
of 6 months or LOC termination date ($155 million) and shorter of one year
or LOC termination date ($129
million).
|
In 2009,
holders of approximately $434 million of LOC-supported PCRBs of OE and NGC
were notified that the applicable Wachovia Bank LOCs were set to expire. As a
result, these PCRBs were subject to mandatory purchase at a price equal to the
principal amount plus accrued and unpaid interest, which OE and NGC funded
through short-term borrowings. FGCO remarketed $100 million of those PCRBs,
which were previously held by OE and NGC and remarketed the remaining
$334 million of PCRBs, of which $170 million was remarketed in fixed
interest rate modes and secured by FMBs, thereby eliminating the need for
third-party credit support. Also during 2009, FGCO and NGC remarketed
approximately $329 million of other PCRBs supported by LOCs set to expire
in 2009. Those PCRBs were also remarketed in fixed interest rate modes and
secured by FMBs, thereby eliminating the need for third-party credit support.
FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with
amendments to existing LOC and reimbursement agreements supporting twelve other
series of PCRBs as described below and pledged FMBs to the applicable trustee
under six separate series of PCRBs. On August 14, 2009, $177 million
of non-LOC supported fixed rate PCRBs were issued and sold on behalf of FGCO to
pay a portion of the cost of acquiring, constructing and installing air quality
facilities at its W.H. Sammis Generating Station.
Long-Term
Debt Capacity
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.
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. On
June 16, 2009, FGCO issued a total of approximately $395.9 million
principal amount of FMBs, of which $247.7 million related to three new
refunding series of PCRBs and approximately $148.2 million related to
amendments to existing LOC and reimbursement agreements supporting two other
series of PCRBs. On June 30, 2009, FGCO issued a total of approximately
$52.1 million principal amount of FMBs related to three existing series of
PCRBs (repurchased in October 2009, as described above).
78
In June
2009, a new FMB indenture became effective for NGC. On June 16, 2009, NGC
issued a total of approximately $487.5 million principal amount of FMBs, of
which $107.5 million related to one new refunding series of PCRBs and
approximately $380 million related to amendments to existing LOC and
reimbursement agreements supporting seven other series of PCRBs. In addition, on
June 16, 2009, NGC issued an FMB in a principal amount of up to
$500 million in connection with NGC's delivery of a Surplus Margin Guaranty
of FES’ obligations to post and maintain collateral under the PSA entered into
by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction.
On June 30, 2009, NGC issued a total of approximately $273.3 million
principal amount of FMBs, of which approximately $92 million related to
three existing series of PCRBs ($29.6 million repurchased in October 2009,
as described above) and approximately $181.3 million related to amendments
to existing LOC and reimbursement agreements supporting three other series of
PCRBs. Based upon NGC’s FMB indenture, net earnings and available bondable
property additions, NGC had the capability to issue $294 million of
additional FMBs as of December 31, 2009.
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.
FirstEnergy's
access to capital markets and costs of financing are influenced by the ratings
of its securities. The following table displays FirstEnergy's, FES' and the
Utilities' securities ratings as of February 11, 2010. 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 (see Note
15(B)). Moody's and Fitch affirmed the ratings and stable outlook of FirstEnergy
and its subsidiaries on February 11, 2010.
|
Senior
Secured
|
Senior
Unsecured
|
|||
|
Issuer
|
S&P
|
Moodys
|
S&P
|
Moodys
|
|
FirstEnergy
Corp.
|
-
|
-
|
BB+
|
Baa3
|
|
FirstEnergy
Solutions
|
-
|
-
|
BBB-
|
Baa2
|
|
Ohio
Edison
|
BBB
|
A3
|
BBB-
|
Baa2
|
|
Cleveland
Electric Illuminating
|
BBB
|
Baa1
|
BBB-
|
Baa3
|
|
Toledo
Edison
|
BBB
|
Baa1
|
-
|
-
|
|
Pennsylvania
Power
|
BBB+
|
A3
|
-
|
-
|
|
Jersey
Central Power & Light
|
-
|
-
|
BBB-
|
Baa2
|
|
Metropolitan
Edison
|
BBB
|
A3
|
BBB-
|
Baa2
|
|
Pennsylvania
Electric
|
BBB
|
A3
|
BBB-
|
Baa2
|
|
ATSI
|
-
|
-
|
BBB-
|
Baa1
|
On
September 22, 2008, FirstEnergy, along with the Shelf Registrants, filed an
automatically effective shelf registration statement with the SEC for an
unspecified number and amount of securities to be offered thereon. The shelf
registration provides FirstEnergy the flexibility to issue and sell various
types of securities, including common stock, preferred stock, debt securities,
warrants, share purchase contracts, and share purchase units. The Shelf
Registrants have utilized, and may in the future utilize, the shelf registration
statement to offer and sell unsecured and, in some cases, secured debt
securities.
Changes
in Cash Position
As of
December 31, 2009, we had $874 million in cash and cash equivalents compared to
$545 million as of December 31, 2008. Cash and cash equivalents consist of
unrestricted, highly liquid instruments with an original or remaining maturity
of three months or less. As of December 31, 2009 and 2008, FirstEnergy had
approximately $12 million and $17 million, respectively, of restricted
cash included in other current assets on the Consolidated Balance
Sheet.
79
During
2009, we received $972 million of cash dividends from our subsidiaries and
paid $670 million in cash dividends to common shareholders. There are no
material restrictions on the payment of cash dividends by our subsidiaries. In
addition to paying dividends from retained earnings, each of our electric
utility subsidiaries has authorization from the FERC to pay cash dividends from
paid-in capital accounts, as long as its debt to total capitalization ratio
(without consideration of retained earnings) remains below 65%. CEI and TE are
the only utility subsidiaries currently precluded from that action.
Cash
Flows from Operating Activities
Our
consolidated net cash from operating activities is provided primarily by our
energy delivery services and competitive energy services businesses (see Results
of Operations above). Net cash provided from operating activities was
$2.5 billion in 2009, $2.2 billion in 2008 and $1.7 billion in
2007, as summarized in the following table:
|
2009
|
2008
|
2007
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Net
income
|
$ | 990 | $ | 1,339 | $ | 1,312 | ||||||
|
Non-cash
charges and other adjustments
|
2,281 | 1,405 | 670 | |||||||||
|
Pension
trust contribution
|
(500 | ) | - | (300 | ) | |||||||
|
Working
capital and other
|
(306 | ) | (520 | ) | 17 | |||||||
| $ | 2,465 | $ | 2,224 | $ | 1,699 | |||||||
Net cash
provided from operating activities increased by $241 million in 2009
primarily due to an increase in non-cash charges and other adjustments of
$876 million and an increase in working capital and other of $214,
partially offset by a $500 million pension trust contribution in 2009 and a
$349 million decrease in net income (see Results of Operations
above).
The
increase in non-cash charges and other adjustments is primarily due to higher
net amortization of regulatory assets ($282 million), including CEI’s
$216 million regulatory asset impairment, an increase in the provision for
depreciation ($59 million) and the modification of certain purchased power
contracts that resulted in a mark-to-market charge of approximately
$205 million (see Note 6). Also included in non-cash charges and other
adjustments was a $146 million charge relating to debt redemptions in 2009,
of which $123 million was related primarily to premiums paid and included
as a cash outflow in financing activities. The changes in working capital and
other primarily resulted from a $268 million decrease in prepaid taxes due
to decreased tax payments.
Net cash
provided from operating activities increased in 2008 compared to 2007 due to an
increase in non-cash charges primarily due to lower deferrals of new regulatory
assets and purchased power costs and higher deferred income taxes. The deferral
of new regulatory assets decreased primarily as a result of the Ohio Companies’
transmission and fuel recovery riders that became effective in July 2007 and
January 2008, respectively, and the absence of the deferral of decommissioning
costs related to the Saxton nuclear research facility in the first quarter of
2007. Lower deferrals of purchased power costs reflected an increase in the
market value of NUG power. The change in deferred income taxes is primarily due
to additional tax depreciation under the Economic Stimulus Act of 2008, the
settlement of tax positions taken on federal returns in prior years, and the
absence of deferred income taxes related to the Bruce Mansfield Unit 1 sale
and leaseback transaction in 2007. The changes in working capital and other
primarily resulted from changes in accrued taxes of $110 million and
prepaid taxes of $278 million, primarily due to increased tax payments.
Changes in materials and supplies of $131 million resulted from higher
fossil fuel inventories and were partially offset by changes in receivables of
$107 million.
Cash
Flows From Financing Activities
In 2009,
net cash provided from financing activities was $49 million compared to
$1.2 billion in 2008. The decrease was primarily due to increased long-term
debt redemptions ($1.6 billion) and increased repayments on short-term
borrowings ($2.7 billion), partially offset by increased long-term debt
issuances in 2009 ($3.3 billion). The increased long-term debt redemptions
were primarily due to the $1.2 billion tender offer for holding company
notes completed by FirstEnergy in September 2009, including approximately
$122 million of premiums and redemption expenses paid. The short-term
repayments in 2009 were primarily due to net repayments on the
$2.75 billion revolving credit facility (see Revolving Credit Facility
above) compared to net borrowings on the facility in 2008. The following table
summarizes security issuances (net of any discounts) and redemptions, including
premiums paid to debt holders as a result of the tender offer.
80
|
Securities
Issued or
|
||||||||||||
|
Redeemed
/ Repurchased
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
New
issues
|
||||||||||||
|
First
mortgage bonds
|
$ | 398 | $ | 592 | $ | - | ||||||
|
Pollution
control notes
|
940 | 692 | 427 | |||||||||
|
Senior
secured notes
|
297 | - | - | |||||||||
|
Unsecured
notes
|
2,997 | 83 | 1,093 | |||||||||
| $ | 4,632 | $ | 1,367 | $ | 1,520 | |||||||
|
Redemptions
|
||||||||||||
|
First
mortgage bonds
|
$ | 1 | $ | 126 | $ | 293 | ||||||
|
Pollution
control notes
|
884 | 698 | 436 | |||||||||
|
Senior
secured notes
|
217 | 35 | 188 | |||||||||
|
Unsecured
notes
|
1,508 | 175 | 153 | |||||||||
|
Common
stock
|
- | - | 969 | |||||||||
| $ | 2,610 | $ | 1,034 | $ | 2,039 | |||||||
|
Short-term
borrowings (repayments), net
|
$ | (1,246 | ) | $ | 1,494 | $ | (205 | ) | ||||
The
following table summarizes new debt issuances, excluding any premium or
discounts, (excluding PCRB issuances and refinancings of $940 million)
during 2009.
|
Issuing
Company
|
Issue
Date
|
Principal
(in
millions)
|
Type
|
Maturity
|
||||||
|
Met-Ed*
|
01/20/2009
|
$ | 300 |
7.70%
Senior Notes
|
2019 | |||||
|
JCP&L*
|
01/27/2009
|
$ | 300 |
7.35%
Senior Notes
|
2019 | |||||
|
TE*
|
04/24/2009
|
$ | 300 |
7.25%
Senior Secured Notes
|
2020 | |||||
|
Penn
|
06/30/2009
|
$ | 100 |
6.09%
FMB
|
2022 | |||||
|
FES
|
08/07/2009
|
$ | 400 |
4.80%
Senior Notes
|
2015 | |||||
| $ | 600 |
6.05%
Senior Notes
|
2021 | |||||||
| $ | 500 |
6.80%
Senior Notes
|
2039 | |||||||
|
CEI*
|
08/18/2009
|
$ | 300 |
5.50%
FMB
|
2024 | |||||
|
Penelec*
|
09/30/2009
|
$ | 250 |
5.20%
Senior Notes
|
2020 | |||||
| $ | 250 |
6.15%
Senior Notes
|
2038 | |||||||
|
ATSI
|
12/15/2009
|
$ | 400 |
5.25%
Senior Notes
|
2022 | |||||
|
*
Issued under the shelf registration statement referenced
above.
|
||||||||||
Cash
Flows from Investing Activities
Net cash
flows used in investing activities resulted principally from property additions.
Additions for the energy delivery services segment primarily include
expenditures related to transmission and distribution facilities. Capital
spending by the competitive energy services segment is principally
generation-related. The following table summarizes investing activities for the
three years ended December 31, 2009 by business segment:
81
|
Summary
of Cash Flows Provided from
|
Property
|
|||||||||||||||
|
(Used
for) Investing Activities
|
Additions
|
Investments
|
Other
|
Total
|
||||||||||||
|
Sources
(Uses)
|
(In
millions)
|
|||||||||||||||
|
2009
|
||||||||||||||||
|
Energy
delivery services
|
$ | (750 | ) | $ | 39 | $ | (46 | ) | $ | (757 | ) | |||||
|
Competitive
energy services
|
(1,262 | ) | (8 | ) | (19 | ) | (1,289 | ) | ||||||||
|
Other
|
(149 | ) | (3 | ) | 72 | (80 | ) | |||||||||
|
Inter-Segment
reconciling items
|
(42 | ) | (24 | ) | 7 | (59 | ) | |||||||||
|
Total
|
$ | (2,203 | ) | $ | 4 | $ | 14 | $ | (2,185 | ) | ||||||
|
2008
|
||||||||||||||||
|
Energy
delivery services
|
$ | (839 | ) | $ | (41 | ) | $ | (17 | ) | $ | (897 | ) | ||||
|
Competitive
energy services
|
(1,835 | ) | (14 | ) | (56 | ) | (1,905 | ) | ||||||||
|
Other
|
(176 | ) | 106 | (61 | ) | (131 | ) | |||||||||
|
Inter-Segment
reconciling items
|
(38 | ) | (12 | ) | - | (50 | ) | |||||||||
|
Total
|
$ | (2,888 | ) | $ | 39 | $ | (134 | ) | $ | (2,983 | ) | |||||
|
2007
|
||||||||||||||||
|
Energy
delivery services
|
$ | (814 | ) | $ | 53 | $ | (6 | ) | $ | (767 | ) | |||||
|
Competitive
energy services
|
(740 | ) | 1,300 | - | 560 | |||||||||||
|
Other
|
(21 | ) | 2 | (14 | ) | (33 | ) | |||||||||
|
Inter-Segment
reconciling items
|
(58 | ) | (15 | ) | - | (73 | ) | |||||||||
|
Total
|
$ | (1,633 | ) | $ | 1,340 | $ | (20 | ) | $ | (313 | ) | |||||
Net cash
used for investing activities in 2009 decreased by $798 million compared to
2008. The change was principally due to a $685 million decrease in property
additions, which reflects lower AQC system expenditures and the absence in 2009
of the purchase of certain lessor equity interests in Beaver Valley Unit 2
and Perry and the purchase of the partially-completed Fremont Energy Center. Net
cash used for other investing activities decreased primarily due to the
liquidation of restricted funds used for debt redemptions in 2009 combined with
decreased cash investments in the Signal Peak coal mining project in 2009 as
compared to 2008.
Net cash
used for investing activities in 2008 increased by $2.7 billion compared to
2007. The change was principally due to a $1.3 billion increase in property
additions and the absence of $1.3 billion of cash proceeds from the Bruce
Mansfield Unit 1 sale and leaseback transaction that occurred in the third
quarter of 2007. The increased property additions reflected the acquisitions
described above and higher planned AQC system expenditures in 2008. Cash used
for other investing activities increased primarily as a result of the 2008
investments in the Signal Peak coal mining project and future-year emission
allowances.
Our
capital spending for 2010 is expected to be approximately $1.7 billion
(excluding nuclear fuel), of which $241 million relates to 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 spending investments
for additional nuclear fuel during 2010 is estimated to be approximately
$170 million.
CONTRACTUAL
OBLIGATIONS
As of
December 31, 2009, our estimated cash payments under existing contractual
obligations that we consider firm obligations are as follows:
| 2011- | 2013- | |||||||||||||||||||
|
Contractual
Obligations
|
Total
|
2010
|
2012 | 2014 |
Thereafter
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
Long-term
debt
|
$ | 13,753 | $ | 264 | $ | 433 | $ | 1,084 | $ | 11,972 | ||||||||||
|
Short-term
borrowings
|
1,181 | 1,181 | - | - | - | |||||||||||||||
|
Interest
on long-term debt
(1)
|
11,663 | 785 | 1,537 | 1,473 | 7,868 | |||||||||||||||
|
Operating
leases
(2)
|
3,485 | 225 | 442 | 459 | 2,359 | |||||||||||||||
|
Fuel
and purchased power
(3)
|
18,422 | 3,217 | 4,753 | 4,245 | 6,207 | |||||||||||||||
|
Capital
expenditures
|
999 | 335 | 376 | 245 | 43 | |||||||||||||||
|
Pension
funding
|
972 | - | 63 | 557 | 352 | |||||||||||||||
|
Other
(4)
|
283 | 232 | 3 | 2 | 46 | |||||||||||||||
|
Total
|
$ | 50,758 | $ | 6,239 | $ | 7,607 | $ | 8,065 | $ | 28,847 | ||||||||||
|
|
(1)
|
Interest
on variable-rate debt based on rates as of December 31,
2009.
|
|
|
(2)
|
See
Note 7 to the consolidated financial
statements.
|
|
|
(3)
|
Amounts
under contract with fixed or minimum quantities based on estimated annual
requirements.
|
|
|
(4)
|
Includes
amounts for capital leases (see Note 7) and contingent tax
liabilities (see Note 10).
|
82
Guarantees
and Other Assurances
As part
of normal business activities, we enter into various agreements on behalf of our
subsidiaries to provide financial or performance assurances to third parties.
These agreements include contract guarantees, surety bonds and LOCs. Some of the
guaranteed contracts contain collateral provisions that are contingent upon
either our or our subsidiaries’ credit ratings.
As of
December 31, 2009, our maximum exposure to potential future payments under
outstanding guarantees and other assurances approximated $4.2 billion, as
summarized below:
|
Maximum
|
||||
|
Guarantees
and Other Assurances
|
Exposure
|
|||
|
(In
millions)
|
||||
|
FirstEnergy
Guarantees of Subsidiaries:
|
||||
|
Energy
and energy-related contracts
(1)
|
$
|
382
|
||
|
LOC
(long-term debt) – interest coverage
(2)
|
6
|
|||
|
FirstEnergy
guarantee of OVEC obligations
|
300
|
|||
|
Other
(3)
|
296
|
|||
|
984
|
||||
|
Subsidiaries’
Guarantees:
|
||||
|
Energy
and energy-related contracts
|
54
|
|||
|
LOC
(long-term debt) – interest coverage
(2)
|
6
|
|||
|
FES’
guarantee of NGC’s nuclear property insurance
|
77
|
|||
|
FES’
guarantee of FGCO’s sale and leaseback obligations
|
2,464
|
|||
|
2,601
|
||||
|
Surety
Bonds:
|
101
|
|||
|
LOC
(long-term debt) – interest coverage
(2)
|
3
|
|||
|
LOC
(non-debt)
(4)(5)
|
502
|
|||
|
606
|
||||
|
Total
Guarantees and Other Assurances
|
$
|
4,191
|
||
|
|
(1)
|
Issued
for open-ended terms, with a 10-day termination right by
FirstEnergy.
|
|
|
(2)
|
Reflects
the interest coverage portion of LOCs issued in support of floating-rate
PCRBs with various maturities. The principal amount of floating-rate PCRBs
of $1.6 billion is reflected as currently payable long-term debt on
FirstEnergy’s consolidated balance
sheets.
|
|
|
(3)
|
Includes
guarantees of $80 million for nuclear decommissioning funding
assurances and $161 million supporting OE’s sale and leaseback
arrangement.
|
|
|
(4)
|
Includes
$167 million issued for various terms pursuant to LOC capacity
available under FirstEnergy’s revolving credit
facility.
|
|
|
(5)
|
Includes
approximately $200 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in
connection with the sale and leaseback of Perry Unit 1 by
OE.
|
We
guarantee energy and energy-related payments of our subsidiaries involved in
energy commodity activities principally to facilitate or hedge normal physical
transactions involving electricity, gas, emission allowances and coal. We also
provide guarantees to various providers of credit support for the financing or
refinancing by our subsidiaries of costs related to the acquisition of property,
plant and equipment. These agreements legally obligate us to fulfill the
obligations of those subsidiaries directly involved in energy and energy-related
transactions or financings where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, our guarantee enables the
counterparty's legal claim to be satisfied by our other assets. We believe the
likelihood is remote that such parental guarantees will increase amounts
otherwise paid by us to meet our obligations incurred in connection with ongoing
energy and energy-related activities.
While
these types of guarantees are normally parental commitments for the future
payment of subsidiary obligations, subsequent to the occurrence of a credit
rating downgrade to below investment grade, an acceleration of payment or
funding obligation, or “material adverse event,” the immediate posting of cash
collateral, provision of an LOC or accelerated payments may be required of the
subsidiary. 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. As of
December 31, 2009, our maximum exposure under these collateral provisions
was $648 million, including the $48 million related to the credit rating
downgrade by S&P on February 11, 2010, as shown below:
83
|
Collateral
Provisions
|
FES
|
Utilities
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Credit
rating downgrade to below investment grade
|
$ | 392 | $ | 115 | $ | 507 | ||||||
|
Acceleration
of payment or funding obligation
|
45 | 53 | 98 | |||||||||
|
Material
adverse event
|
43 | - | 43 | |||||||||
|
Total
|
$ | 480 | $ | 168 | $ | 648 | ||||||
Stress
case conditions of a credit rating downgrade or “material adverse event” and
hypothetical adverse price movements in the underlying commodity markets would
increase the total potential amount to $807 million, consisting of
$51 million due to “material adverse event” contractual clauses,
$98 million due to an acceleration of payment or funding obligation, and
$658 million due to a below investment grade credit rating.
Most of
our surety bonds are backed by various indemnities common within the insurance
industry. Surety bonds and related guarantees provide additional assurance to
outside parties that contractual and statutory obligations will be met in a
number of areas including construction contracts, environmental commitments and
various retail transactions.
In
addition to guarantees and surety bonds, FES’ contracts, including power
contracts with affiliates awarded through competitive bidding processes,
typically contain margining provisions which require the posting of cash or LOCs
in amounts determined by future power price movements. Based on FES’ power
portfolio as of December 31, 2009, and forward prices as of that date, FES had
$179 million outstanding in margining accounts. Under a hypothetical adverse
change in forward prices (95% confidence level change in forward prices over a
one year time horizon), FES would be required to post an additional
$129 million. Depending on the volume of forward contracts entered and
future price movements, FES could be required to post significantly higher
amounts for margining.
In
connection with FES’ obligations to post and maintain collateral under the
two-year PSA entered into by FES and the Ohio Companies following the CBP
auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an
amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC
FMB issued in favor of the Ohio Companies.
FES’
debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC,
pursuant to guarantees entered into on March 26, 2007. Similar guarantees were
entered into on that date pursuant to which FES guaranteed the debt obligations
of each of FGCO and NGC. Accordingly, present and future holders of indebtedness
of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC
regardless of whether their primary obligor is FES, FGCO or NGC.
OFF-BALANCE
SHEET ARRANGEMENTS
FES and
the Ohio Companies have obligations that are not included on our Consolidated
Balance Sheets related to sale and leaseback arrangements involving the Bruce
Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are
satisfied through operating lease payments. The total present value of these
sale and leaseback operating lease commitments, net of trust investments, was
$1.7 billion as of December 31, 2009, and December 31,
2008.
We have
equity ownership interests in certain businesses that are accounted for using
the equity method of accounting for investments. There are no undisclosed
material contingencies related to these investments. Certain guarantees that we
do not expect to have a material current or future effect on our financial
condition, liquidity or results of operations are disclosed under “Guarantees
and Other Assurances” above.
MARKET
RISK INFORMATION
We use
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations. Our Risk
Policy Committee, comprised of members of senior management, provides general
oversight for risk management activities throughout the company.
84
Commodity
Price Risk
FirstEnergy
is exposed to financial and market risks resulting from the fluctuation of
interest rates and commodity prices associated with electricity, energy
transmission, natural gas, coal, nuclear fuel and emission allowances. To manage
the volatility relating to these exposures, FirstEnergy uses a variety of
non-derivative and derivative instruments, including forward contracts, options,
futures contracts and swaps. The derivatives are used principally for hedging
purposes. Certain derivatives must be recorded at their fair value and marked to
market. The majority of FirstEnergy's derivative hedging contracts qualify for
the normal purchase and normal sale exception and are therefore excluded from
the tables below. Contracts that are not exempt from such treatment include
certain power purchase agreements with NUG entities that were structured
pursuant to the Public Utility Regulatory Policies Act of 1978 and certain
purchase power contracts (see Note 6). The NUG entities non-trading
contracts are adjusted to fair value at the end of each quarter, with a
corresponding regulatory asset recognized for above-market costs or regulatory
liability for below-market costs. The change in the fair value of commodity
derivative contracts related to energy production during 2009 is summarized in
the following table:
|
Increase
(Decrease) in the Fair Value of Derivative Contracts
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Change
in the Fair Value of Commodity Derivative Contracts:
|
||||||||||||
|
Outstanding
net liability as of January 1, 2009
|
$ | (304 | ) | $ | (41 | ) | $ | (345 | ) | |||
|
Additions/change
in value of existing contracts
|
(673 | ) | (1 | ) | (674 | ) | ||||||
|
Settled
contracts
|
347 | 27 | 374 | |||||||||
|
Outstanding
net liability as of December 31, 2009
(1)
|
$ | (630 | ) | $ | (15 | ) | $ | (645 | ) | |||
|
Net
Liabilities-Derivative Contracts as of December 31,
2009
|
$ | (630 | ) | $ | (15 | ) | $ | (645 | ) | |||
|
Impact
of Changes in Commodity Derivative Contracts
(2)
|
||||||||||||
|
Income
Statement effects (pre-tax)
|
$ | (204 | ) | $ | - | $ | (204 | ) | ||||
|
Balance
Sheet effects:
|
||||||||||||
|
OCI
(pre-tax)
|
$ | - | $ | 26 | $ | 26 | ||||||
|
Regulatory
asset (net)
|
$ | 122 | $ | - | $ | 122 | ||||||
|
|
(1)
|
Includes
$425 million of non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
|
|
(2)
|
Represents
the change in value of existing contracts, settled contracts and changes
in techniques/assumptions.
|
Derivatives
are included on the Consolidated Balance Sheet as of December 31, 2009 as
follows:
|
Balance
Sheet Classification
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Current-
|
||||||||||||
|
Other
assets
|
$ | - | $ | 3 | $ | 3 | ||||||
|
Other
liabilities
|
(108 | ) | (17 | ) | (125 | ) | ||||||
|
Non-Current-
|
||||||||||||
|
Other
deferred charges
|
218 | 11 | 229 | |||||||||
|
Other
noncurrent liabilities
|
(740 | ) | (12 | ) | (752 | ) | ||||||
|
Net
liabilities
|
$ | (630 | ) | $ | (15 | ) | $ | (645 | ) | |||
The
valuation of derivative contracts is based on observable market information to
the extent that such information is available. In cases where such information
is not available, FirstEnergy relies on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. FirstEnergy uses these results to develop estimates of
fair value for financial reporting purposes and for internal management decision
making (see Note 5). Sources of information for the valuation of commodity
derivative contracts as of December 31, 2009 are summarized by year in the
following table:
85
|
Source
of Information
|
|||||||||||||||||||||||||||||
|
-
Fair Value by Contract Year
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
||||||||||||||||||||||
|
(In
millions)
|
|||||||||||||||||||||||||||||
|
Prices
actively quoted
(1)
|
$ | (11 | ) | $ | - | $ | - | $ | - | $ | - | $ | - | $ | (11 | ) | |||||||||||||
|
Other
external sources
(2)
|
(369 | ) | (305 | ) | (139 | ) | (44 | ) | - | - | (857 | ) | |||||||||||||||||
|
Prices
based on models
|
- | - | - | - | 11 | 212 | 223 | ||||||||||||||||||||||
|
Total
(3)
|
$ | (380 | ) | $ | (305 | ) | $ | (139 | ) | $ | (44 | ) | $ | 11 | $ | 212 | $ | (645 | ) | ||||||||||
|
|
(1)
|
Exchange
traded.
|
|
|
(2)
|
Broker
quote sheets.
|
|
|
(3)
|
Includes
$425 million in non-hedge commodity derivative contracts (primarily
with NUGs), which are offset by a regulatory
asset.
|
FirstEnergy
performs sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on its derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of December 31, 2009. Based on derivative contracts held as of December 31,
2009, an adverse 10% change in commodity prices would decrease net income by
approximately $9 million after tax during the next
12 months.
Interest
Rate Risk
Our
exposure to fluctuations in market interest rates is reduced since a significant
portion of our debt has fixed interest rates, as noted in the table
below.
|
Comparison
of Carrying Value to Fair Value
|
||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
|||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
||||||||||||||||||||||||
|
(Dollars
in millions)
|
||||||||||||||||||||||||||||||||
|
Assets
|
||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
|
||||||||||||||||||||||||||||||||
|
and
Cash Equivalents:
|
||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 84 | $ | 79 | $ | 95 | $ | 118 | $ | 110 | $ | 1,834 | $ | 2,320 | $ | 2,413 | ||||||||||||||||
|
Average
interest rate
|
7.1 | % | 7.8 | % | 7.8 | % | 7.6 | % | 8.0 | % | 4.3 | % | 5.0 | % | ||||||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 202 | $ | 336 | $ | 97 | $ | 555 | $ | 529 | $ | 9,915 | $ | 11,634 | $ | 12,350 | ||||||||||||||||
|
Average
interest rate
|
5.7 | % | 6.7 | % | 7.7 | % | 5.9 | % | 5.4 | % | 6.5 | % | 6.5 | % | ||||||||||||||||||
|
Variable
rate
|
$ | 62 | $ | 2,057 | $ | 2,119 | $ | 2,152 | ||||||||||||||||||||||||
|
Average
interest rate
|
3.3 | % | 1.8 | % | 1.8 | % | ||||||||||||||||||||||||||
|
Short-term
Borrowings:
|
$ | 1,181 | $ | 1,181 | $ | 1,181 | ||||||||||||||||||||||||||
|
Average
interest rate
|
0.7 | % | 0.7 | % | ||||||||||||||||||||||||||||
We are
subject to the inherent interest rate risks related to refinancing maturing debt
by issuing new debt securities. As discussed in Note 7 to the consolidated
financial statements, our investments in capital trusts effectively reduce
future lease obligations, also reducing interest rate risk.
Interest
Rate Swap Agreements – Fair Value Hedges
FirstEnergy
uses fixed-for-floating interest rate swap agreements to hedge a portion of the
consolidated interest rate risk associated with the debt portfolio of its
subsidiaries. These derivatives are treated as fair value hedges of fixed-rate,
long-term debt issues, protecting against the risk of changes in the fair value
of fixed-rate debt instruments due to lower interest rates. Swap maturities,
call options, fixed interest rates and interest payment dates match those of the
underlying obligations. As of December 31, 2009, the debt underlying the
$250 million outstanding notional amount of interest rate swaps had a
weighted average fixed interest rate of 6.45%, which the swaps have converted to
a current weighted average variable rate of 5.4%. The fair value of the interest
rate swaps designated as fair value hedges was immaterial as of
December 31, 2009.
Forward
Starting Swap Agreements - Cash Flow Hedges
FirstEnergy
uses forward starting swap agreements to hedge a portion of the consolidated
interest rate risk associated with issuances of fixed-rate, long-term debt
securities of its subsidiaries. These derivatives are treated as cash flow
hedges, protecting against the risk of changes in future interest payments
resulting from changes in benchmark U.S. Treasury rates between the date of
hedge inception and the date of the debt issuance. During 2009, FirstEnergy
terminated forward swaps with a notional value of $2.8 billion and
recognized losses of approximately $18.5 million, of which the ineffective
portion recognized as an adjustment to interest expense was immaterial. The
remaining effective portions will be amortized to interest expense over the life
of the hedged debt.
86
|
December
31, 2009
|
December
31, 2008
|
||||||||||||||||||||||||
|
Notional
|
Maturity
|
Fair
|
Notional
|
Maturity
|
Fair
|
||||||||||||||||||||
|
Forward
Starting Swaps
|
Amount
|
Date
|
Value
|
Amount
|
Date
|
Value
|
|||||||||||||||||||
|
(In
millions)
|
|||||||||||||||||||||||||
|
Cash
flow hedges
|
$ | - | 2009 | - | 100 | 2009 | $ | (2 | ) | ||||||||||||||||
| 100 | 2010 | - | 100 | 2010 | (2 | ) | |||||||||||||||||||
| - | 2019 | - | 100 | 2019 | 1 | ||||||||||||||||||||
| $ | 100 | $ | - | $ | 300 | $ | (3 | ) | |||||||||||||||||
Equity
Price Risk
FirstEnergy
provides a noncontributory qualified defined benefit pension plan that covers
substantially all of its employees and non-qualified pension plans that cover
certain employees. The plan provides defined benefits based on years of service
and compensation levels. FirstEnergy also provides health care benefits (which
include certain employee contributions, deductibles, and co-payments) upon
retirement to employees hired prior to January 1, 2005, their dependents, and
under certain circumstances, their survivors. The benefit plan assets and
obligations are remeasured annually using a December 31 measurement date or
as significant triggering events occur. In 2009, FirstEnergy remeasured its
other postretirement benefit plans on May 31, 2009, and its qualified
defined pension plan on August 31, 2009, as discussed below.
FirstEnergy’s
other postretirement benefits plans were remeasured as of May 31, 2009 as a
result of a plan amendment announced on June 2, 2009, which reduced future
health care coverage subsidies paid by FirstEnergy on behalf of plan
participants. The remeasurement and plan amendment resulted in a
$48 million reduction in FirstEnergy’s net postretirement benefit cost
(including amounts capitalized) for 2009 (see Note 3). This reduction was
partially offset by an additional $13 million of net postretirement benefit
cost (including amounts capitalized) related to an additional liability created
by the VERO offered by FirstEnergy to qualified employees (see
Note 3).
On
September 2, 2009, FirstEnergy elected to remeasured its qualified defined
pension plan due to a $500 million voluntary contribution made by the
Utilities and ATSI. The remeasurement and voluntary contribution decreased
FirstEnergy’s accumulated other comprehensive income by approximately
$494 million ($304 million, net of tax) and reduced FirstEnergy’s net
postretirement benefit cost (including amounts capitalized) for 2009 by
$7 million (see Note 3). Increases in plan assets from investment
gains during 2009 resulted in an increase to the plans' funded status of $349
million
on and an
after-tax decrease to common stockholders' equity of $19 million. The overall
actual investment result during 2009 was a gain of 13.6% compared to an assumed
9% positive return. Based on a 6% discount rate, 2010 pre-tax net periodic
pension and OPEB expense will be approximately $89 million. As of
December 31, 2009, the pension plan was underfunded. FirstEnergy currently
estimates that additional cash contributions will be required beginning in
2012.
Nuclear
decommissioning trust funds have been established to satisfy NGC’s and our
Utilities’ nuclear decommissioning obligations. As of December 31, 2009,
approximately 16% of the funds were invested in equity securities and 84% were
invested in fixed income securities, with limitations related to concentration
and investment grade ratings. The equity securities are carried at their market
value of approximately $295 million as of December 31, 2009. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$29 million reduction in fair value as of December 31, 2009. The
decommissioning trusts of JCP&L and the Pennsylvania Companies are subject
to regulatory accounting, with unrealized gains and losses recorded as
regulatory assets or liabilities, since the difference between investments held
in trust and the decommissioning liabilities will be recovered from or refunded
to customers. NGC, OE and TE recognize in earnings the unrealized losses on
available-for-sale securities held in their nuclear decommissioning trusts as
other-than-temporary impairments. 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.
CREDIT
RISK
Credit
risk is the risk of an obligor's failure to meet the terms of any investment
contract, loan agreement or otherwise perform as agreed. Credit risk arises from
all activities in which success depends on issuer, borrower or counterparty
performance, whether reflected on or off the balance sheet. We engage in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.
87
We
maintain credit policies with respect to our counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of our credit program, we aggressively manage the
quality of our portfolio of energy contracts, evidenced by a current weighted
average risk rating for energy contract counterparties of BBB (S&P). As of
December 31, 2009, the largest credit concentration was with Morgan
Stanley, which is currently rated investment grade, representing 7.3% of our
total approved credit risk.
REGULATORY
MATTERS
Regulatory
assets that do not earn a current return totaled approximately $187 million as
of December 31, 2009 (JCP&L - $36 million, Met-Ed -
$114 million, and Penelec - $37 million). Regulatory assets not earning a
current return (primarily for certain regulatory transition costs and employee
postretirement benefits) are expected to be recovered by 2014 for JCP&L and
by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets
by company:
|
December
31,
|
December
31,
|
Increase
|
||||||||||
|
Regulatory
Assets
|
2009
|
2008
|
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
OE
|
$ | 465 | $ | 575 | $ | (110 | ) | |||||
|
CEI
|
546 | 784 | (238 | ) | ||||||||
|
TE
|
70 | 109 | (39 | ) | ||||||||
|
JCP&L
|
888 | 1,228 | (340 | ) | ||||||||
|
Met-Ed
|
357 | 413 | (56 | ) | ||||||||
|
Penelec
|
9 | - | (1) | 9 | ||||||||
|
ATSI
|
21 | 31 | (10 | ) | ||||||||
|
Total
|
$ | 2,356 | $ | 3,140 | $ | (784 | ) | |||||
|
|
(1)
|
Penelec
had net regulatory liabilities of approximately $137 million as of
December 31, 2008. These net regulatory liabilities are included in
Other Non-current Liabilities on the Consolidated Balance
Sheets.
|
Regulatory
assets by source are as follows:
|
December
31,
|
December
31,
|
Increase
|
||||||||||
|
Regulatory
Assets By Source
|
2009
|
2008
|
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Regulatory
transition costs
|
$ | 1,100 | $ | 1,452 | $ | (352 | ) | |||||
|
Customer
shopping incentives
|
154 | 420 | (266 | ) | ||||||||
|
Customer
receivables for future income taxes
|
329 | 245 | 84 | |||||||||
|
Loss
on reacquired debt
|
51 | 51 | - | |||||||||
|
Employee
postretirement benefits
|
23 | 31 | (8 | ) | ||||||||
|
Nuclear
decommissioning, decontamination
|
||||||||||||
|
and
spent fuel disposal costs
|
(162 | ) | (57 | ) | (105 | ) | ||||||
|
Asset
removal costs
|
(231 | ) | (215 | ) | (16 | ) | ||||||
|
MISO/PJM
transmission costs
|
148 | 389 | (241 | ) | ||||||||
|
Fuel
costs
|
369 | 214 | 155 | |||||||||
|
Distribution
costs
|
482 | 475 | 7 | |||||||||
|
Other
|
93 | 135 | (42 | ) | ||||||||
|
Total
|
$ | 2,356 | $ | 3,140 | $ | (784 | ) | |||||
Ohio
On June
7, 2007, the Ohio Companies filed an application for an increase in electric
distribution rates with the PUCO and, on August 6, 2007, updated their
filing. 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.
88
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
percent 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.
89
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. 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. As referenced above, on January 7, 2010, the PUCO issued an
Order granting the Ohio 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 and RECs generated in Ohio in order to meet the Ohio Companies’
alternative energy requirements as set forth in SB221 for 2009, 2010 and
2011. 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. However, unlike the May 2009
CBP, the MRO would include multiple bidding sessions and multiple products with
different delivery periods for generation supply designed to reduce potential
volatility and supplier risk and encourage bidder participation. A technical
conference was held on October 29, 2009. Hearings took place in December 2009
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
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 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 the 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.
90
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, as
required in connection with the PPUC’s January 2007 rate order. For Penelec’s
customers the new TSC resulted in an approximate 1% decrease in monthly bills,
reflecting projected PJM transmission costs as well as a reconciliation for
costs already incurred. The TSC for Met-Ed’s customers increased to recover the
additional PJM charges paid by Met-Ed in the previous year and to reflect
updated projected costs. In order to gradually transition customers to the
higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the
prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5
million of projected costs to a future TSC to be fully recovered by
December 31, 2010. Under this proposal, monthly bills for Met-Ed’s
customers 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 utilities 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 required 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 PPUC’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.
91
Legislation
addressing rate mitigation and the expiration of rate caps has been introduced
in the legislative session that ended in 2008; several bills addressing these
issues were introduced in the 2009 legislative session. The final form and
impact of such legislation is 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.
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 Pennsylvania Companies’ Restructuring Orders of 1998. On
August 14, 2009, the PPUC issued Secretarial Letters approving 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 PPUC.
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 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. The PPUC is required to issue an
order on the plan no later than November 8, 2010.
New
Jersey
JCP&L
is permitted to defer for future collection from customers the amounts by which
its costs of supplying BGS to non-shopping customers, costs incurred under NUG
agreements, and certain other stranded costs, exceed amounts collected through
BGS and NUGC rates and market sales of NUG energy and capacity. As of 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. 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:
92
|
|
·
|
maximize
energy efficiency to achieve a 20% reduction in energy consumption by
2020;
|
|
|
·
|
reduce
peak demand for electricity by 5,700 MW by
2020;
|
|
|
·
|
meet
30% of the state’s electricity needs with renewable energy by
2020;
|
|
|
·
|
examine
smart grid technology and develop additional cogeneration and other
generation resources consistent with the state’s greenhouse gas targets;
and
|
|
|
·
|
invest
in innovative clean energy technologies and businesses to stimulate the
industry’s growth in New Jersey.
|
On
January 28, 2009, the NJBPU adopted an order establishing the general process
and contents of specific EMP plans that must be filed by 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 BPU by July 1, 2010. At this time,
FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have
on their 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
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 including recovery of the costs associated with the
proposal.
FERC
Matters
Transmission
Service between MISO and PJM
On
November 18, 2004, the FERC issued an order eliminating the through and out rate
for transmission service between the MISO and PJM regions. The FERC’s intent was
to eliminate multiple transmission charges for a single transaction between the
MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission
owners within MISO and PJM to submit compliance filings containing a rate
mechanism to recover lost transmission revenues created by elimination of this
charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a
16-month transition period. The FERC issued orders in 2005 setting the SECA for
hearing. The presiding judge issued an initial decision on August 10, 2006,
rejecting the compliance filings made by MISO, PJM and the transmission owners,
and directing new compliance filings. This decision is subject to review and
approval by the FERC. 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.
93
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 costs 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 Regional Transmission
Expansion Planning 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, 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. To
ensure a definitive ruling at the same time FERC rules on its request to
integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related
complaint with FERC on the issue of exempting the ATSI footprint from the legacy
RTEP costs.
94
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 requests 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 Capacity Market Evolution Committee (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 FERC on April 1, 2010.
95
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
Power Supply Agreement that ended on December 31, 2008. On January 2,
2009, FES signed an agreement to provide 75% of the Ohio Companies’ power
requirements for the period January 5, 2009 through March 31, 2009.
Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’
power requirements for the period April 1, 2009 through May 31, 2009.
On March 4, 2009, the PUCO issued an order approving these two affiliate
sales agreements. FERC authorization for these affiliate sales was by means of a
December 23, 2008 waiver of restrictions on affiliate sales without prior
approval of the FERC. Rehearing was denied on July 31, 2009. On October 19,
2009, 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.
96
Reliability
Initiatives
In 2005,
Congress amended the Federal Power Act to provide for federally-enforceable
mandatory reliability standards. The mandatory reliability standards apply to
the bulk power system and impose certain operating, record-keeping and reporting
requirements on the Utilities and ATSI. The NERC is charged with establishing
and enforcing these reliability standards, although it has delegated day-to-day
implementation and enforcement of its responsibilities to eight regional
entities, including ReliabilityFirst Corporation. All of FirstEnergy’s
facilities are located within the ReliabilityFirst region. FirstEnergy actively
participates in the NERC and ReliabilityFirst stakeholder processes, and
otherwise monitors and manages its companies in response to the ongoing
development, implementation and enforcement of the reliability
standards.
FirstEnergy
believes that it is in compliance with all currently-effective and enforceable
reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst
and the FERC will continue to refine existing reliability standards as well as
to develop and adopt new reliability standards. The financial impact of
complying with new or amended standards cannot be determined at this time.
However, the 2005 amendments to the Federal Power Act provide that all prudent
costs incurred to comply with the new reliability standards be recovered in
rates. Still, any future inability on FirstEnergy’s part to comply with the
reliability standards for its bulk power system could result in the imposition
of financial penalties 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 a final report is expected in early
2009. FirstEnergy does not expect any material adverse financial impact as a
result of these audits.
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 Reliability
First
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. Reliability
First
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 Reliability
First
will propose for this
self-reported violation.
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 SO
2
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
SO
2
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.
97
FirstEnergy
complies with SO
2
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. NO
X
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 NO
X
reductions
at FirstEnergy's facilities. The EPA's NO
X
Transport
Rule imposes uniform reductions of NO
X
emissions
(an approximate 85% reduction in utility plant NO
X
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 NO
X
emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NO
X
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
NO
X
and SO
2
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.
98
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 NO
X
and
SO
2
emissions in two phases (Phase I in 2009 for NO
X
, 2010 for
SO
2
and Phase II in 2015 for both NO
X
and
SO
2
),
ultimately capping SO
2
emissions
in affected states to 2.5 million tons annually and NO
X
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 “NO
X
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 SO
2
and
NO
X
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.
99
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 CO
2
, 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 CO
2
emissions
from automobiles as “air pollutants” under the CAA. Although this decision did
not address CO
2
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 CO
2
emissions,
or litigation alleging damages from GHG emissions, could require significant
capital and other expenditures or result in changes to its operations. The
CO
2
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-CO
2
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.
100
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.
OTHER
LEGAL PROCEEDINGS
Power
Outages and Related Litigation
In July
1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in
power outages throughout the service territories of many electric utilities,
including JCP&L's territory. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages due to the outages.
101
After
various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, strict product liability, and
punitive damages were dismissed, leaving only the negligence and breach of
contract causes of actions. The class was decertified twice by the trial court,
and appealed both times by the Plaintiffs, with the results being that: (1) the
Appellate Division limited the class only to those customers directly impacted
by the outages of JCP&L transformers in Red Bank, NJ, based on a common
incident involving the failure of the bushings of two large transformers in the
Red Bank substation which resulted in planned and unplanned outages in the area
during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded
this matter back to the Trial Court to allow plaintiffs sufficient time to
establish a damage model or individual proof of damages. On March 31, 2009, the
trial court again granted JCP&L’s motion to decertify the class. On April
20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory
appeal to the trial court's decision to decertify the class, which was granted
by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate
brief on August 25, 2009, and JCP&L filed an opposition brief on
September 25, 2009. On or about October 13, 2009, Plaintiffs filed
their reply brief in further support of their appeal of the trial court's
decision decertifying the class. The Appellate Division heard oral argument on
January 5, 2010, before a three-judge panel. JCP&L is awaiting the
Court’s decision.
Nuclear
Plant Matters
In
August 2007, FENOC submitted an application to the NRC to renew the operating
licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional
20 years. 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.
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.
Other
Legal Matters
There
are various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to FirstEnergy's normal business operations pending against
FirstEnergy and its subsidiaries. The other potentially material items not
otherwise discussed above are described below.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded
that the call-out procedure violated the parties' collective bargaining
agreement. On September 9, 2005, the arbitration panel issued an opinion to
award approximately $16 million to the bargaining unit employees. A final order
identifying the individual damage amounts was issued on October 31, 2007
and the award appeal process was initiated. The union filed a motion with the
federal Court to confirm the award and JCP&L filed its answer and
counterclaim to vacate the award on December 31, 2007. JCP&L and the
union filed briefs in June and July of 2008 and oral arguments were held in the
fall. On February 25, 2009, the federal district court denied JCP&L’s
motion to vacate the arbitration decision and granted the union’s motion to
confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a
Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal
process could take as long as 24 months. 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
accrues legal liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably estimate the amount of such
costs. If it were ultimately determined that FirstEnergy or its subsidiaries
have legal liability or are otherwise made subject to liability based on the
above matters, it could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
102
CRITICAL
ACCOUNTING POLICIES
We
prepare our consolidated financial statements in accordance with GAAP.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Our more significant accounting policies are described
below.
Revenue
Recognition
We
follow the accrual method of accounting for revenues, recognizing revenue for
electricity that has been delivered to customers but not yet billed through the
end of the accounting period. The determination of electricity sales to
individual customers is based on meter readings, which occur on a systematic
basis throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled sales is recognized. The determination of unbilled sales requires
management to make estimates regarding electricity available for retail load,
transmission and distribution line losses, demand by customer class,
weather-related impacts and prices in effect for each customer
class.
Regulatory
Accounting
Our
energy delivery services segment is subject to regulation that sets the prices
(rates) we are permitted to charge our customers based on costs that the
regulatory agencies determine we are permitted to recover. At times, regulators
permit the future recovery through rates of costs that would be currently
charged to expense by an unregulated company. This ratemaking process results in
the recording of regulatory assets based on anticipated future cash inflows. We
regularly review these assets to assess their ultimate recoverability within the
approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future.
Pension and Other Postretirement
Benefits Accounting
Our
reported costs of providing noncontributory qualified and non-qualified defined
pension benefits and OPEB benefits other than pensions are dependent upon
numerous factors resulting from actual plan experience and certain
assumptions.
Pension
and OPEB costs are affected by employee demographics (including age,
compensation levels, and employment periods), the level of contributions we make
to the plans and earnings on plan assets. Pension and OPEB costs may also be
affected by changes to key assumptions, including anticipated rates of return on
plan assets, the discount rates and health care trend rates used in determining
the projected benefit obligations for pension and OPEB costs.
In
accordance with GAAP, changes in pension and OPEB obligations associated with
these factors may not be immediately recognized as costs on the income
statement, but generally are recognized in future years over the remaining
average service period of plan participants. GAAP delays recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
We
recognize the overfunded or underfunded status of our defined benefit pension
and other postretirement benefit plans on the balance sheet and recognize
changes in funded status in the year in which the changes occur through other
comprehensive income. The underfunded status of our qualified and non-qualified
pension and OPEB plans at December 31, 2009 is $1.3 billion.
In
selecting an assumed discount rate, we consider currently available rates of
return on high-quality fixed income investments expected to be available during
the period to maturity of the pension and other postretirement benefit
obligations. As of December 31, 2009, the assumed discount rates for pension and
OPEB were 6.0% and 5.75%, respectively. The assumed discount rates for both
pension and OPEB were 7.0% and 6.5% as of December 31, 2008, and 2007,
respectively.
Our
assumed rate of return on pension plan assets considers historical market
returns and economic forecasts for the types of investments held by our pension
trusts. In 2009 our qualified pension and OPEB plan assets actually earned
$570 million or 13.6% and lost $1.4 billion or 23.8% in 2008. Our qualified
pension and OPEB costs in 2009 and 2008 were computed using an assumed 9.0% rate
of return on plan assets which generated $379 million and $514 million
of expected returns on plan assets, respectively. The expected return of pension
and OPEB assets is based on the trusts’ asset allocation targets and the
historical performance of risk-based and fixed income securities. The gains or
losses generated as a result of the difference between expected and actual
returns on plan assets are deferred and amortized and will increase or decrease
future net periodic pension and OPEB cost, respectively.
103
Our
qualified and non-qualified pension and OPEB net periodic benefit cost was
$197 million in 2009 compared to credits of $116 million in 2008 and
$73 million in 2007. On September 2, 2009, the Utilities and ATSI made a
combined $500 million voluntary contribution to their qualified pension plan.
Due to the significance of the voluntary contribution, we elected to remeasure
our qualified pension plan as of August 31, 2009. On January 2, 2007, we made a
$300 million voluntary contribution to our pension plan. In addition, during
2006, we amended our OPEB plan, effective in 2008, to cap our monthly
contribution for many of the retirees and their spouses receiving subsidized
health care coverage. On June 2, 2009, we further amended our health care
benefits plan for all employees and retirees eligible that participate in that
plan. The amendment, which reduces future health care coverage subsidies paid by
FirstEnergy on behalf of participants, triggered a remeasurement of
FirstEnergy’s other postretirement benefit plans as of May 31, 2009. In the
third quarter of 2009, FirstEnergy also incurred a $13 million net
postretirement benefit cost (including amounts capitalized) related to a
liability created by the VERO offered by FirstEnergy to qualified employees. The
special termination benefits of the VERO included additional health care
coverage subsidies paid by FirstEnergy to those qualified employees who elected
to retire. A total of 715 employees accepted the VERO. We expect our 2010
qualified and non-qualified pension and OPEB costs (including amounts
capitalized) to be $138 million.
Health
care cost trends continue to increase and will affect future OPEB costs. The
2009 and 2008 composite health care trend rate assumptions were approximately
8.5-10% and 9-11%, respectively, gradually decreasing to 5% in later years. In
determining our trend rate assumptions, we included the specific provisions of
our health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in our health care plans, and
projections of future medical trend rates. The effect on our pension and OPEB
costs from changes in key assumptions are as follows:
|
Increase
in Costs from Adverse Changes in Key Assumptions
|
|||||||||||||||
|
Assumption
|
Adverse
Change
|
Pension
|
OPEB
|
Total
|
|||||||||||
|
(In
millions)
|
|||||||||||||||
|
Discount
rate
|
Decrease
by 0.25%
|
$ | 12 | $ | 1 | $ | 13 | ||||||||
|
Long-term
return on assets
|
Decrease
by 0.25%
|
$ | 11 | $ | 1 | $ | 12 | ||||||||
|
Health
care trend rate
|
Increase
by 1%
|
N/A | $ | 4 | $ | 4 | |||||||||
Emission
Allowances
We hold
emission allowances for SO
2
and
NO
X
in
order to comply with programs implemented by the EPA designed to regulate
emissions of SO
2
and
NO
X
produced by power plants. Emission allowances are either granted to us by the
EPA at zero cost or are purchased at fair value as needed to meet emission
requirements. Emission allowances are not purchased with the intent
of resale. Emission allowances eligible to be used in the current year are
recorded in materials and supplies inventory at the lesser of weighted average
cost or market value. Emission allowances eligible for use in future years are
recorded as other investments. We recognize emission allowance costs as fuel
expense during the periods that emissions are produced by our generating
facilities. Excess emission allowances that are not needed to meet
emission requirements may be sold and are reported as a reduction to other
operating expenses.
Long-Lived
Assets
We
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of such an asset may not be
recoverable
.
The recoverability of a long-lived asset is measured by comparing the
asset’s carrying value to the sum of undiscounted future cash flows expected to
result from the use and eventual disposition of the asset
.
If the
carrying value is greater than the undiscounted future cash flows of the
long-lived asset an impairment exists and a loss is recognized for the amount by
which the carrying value of the long-lived asset exceeds its estimated fair
value
.
Fair value is the price that would be received to sell an asset or paid
to transfer a liability in an orderly transaction between market participants at
the measurement date.
Asset
Retirement Obligations
We
recognize an ARO for the future decommissioning of our nuclear power plants and
future remediation of other environmental liabilities associated with all of our
long-lived assets. The ARO liability represents an estimate of the fair value of
our current obligation related to nuclear decommissioning and the retirement or
remediation of environmental liabilities of other assets. A fair value
measurement inherently involves uncertainty in the amount and timing of
settlement of the liability. We use an expected cash flow approach to measure
the fair value of the nuclear decommissioning and environmental remediation ARO.
This approach applies probability weighting to discounted future cash flow
scenarios that reflect a range of possible outcomes. The scenarios consider
settlement of the ARO at the expiration of the nuclear power plants' current
license and settlement based on an extended license term and expected
remediation dates.
104
Income
Taxes
We
record income taxes in accordance with the liability method of accounting.
Deferred income taxes reflect the net tax effect of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts recognized for tax purposes. Investment tax credits,
which were deferred when utilized, are being amortized over the recovery period
of the related property. Deferred income tax liabilities related to tax and
accounting basis differences and tax credit carryforward items are recognized at
the statutory income tax rates in effect when the liabilities are expected to be
paid. Deferred tax assets are recognized based on income tax rates expected to
be in effect when they are settled.
FirstEnergy
accounts for uncertainty in income taxes recognized in its financial statements.
We account for uncertain income tax positions using a benefit recognition model
with a two-step approach, a more-likely-than-not recognition criterion and a
measurement attribute that measures the position as the largest amount of tax
benefit that is greater than 50% likely of being ultimately realized upon
ultimate settlement. If it is not more likely than not that the benefit will be
sustained on its technical merits, no benefit will be recorded. Uncertain tax
positions that relate only to timing of when an item is included on a tax return
are considered to have met the recognition threshold. The Company recognizes
interest expense or income related to uncertain tax positions. That amount is
computed by applying the applicable statutory interest rate to the difference
between the tax position recognized and the amount previously taken or expected
to be taken on the tax return. FirstEnergy includes net interest and penalties
in the provision for income taxes.
Goodwill
In a
business combination, the excess of the purchase price over the estimated fair
values of the assets acquired and liabilities assumed is recognized as goodwill.
Based on the guidance provided by accounting standards for the recognition,
subsequent measurement, and subsequent recognition of goodwill, we evaluate
goodwill for impairment at least annually and make such evaluations more
frequently if indicators of impairment arise. In accordance with the accounting
standard, if the fair value of a reporting unit is less than its carrying value
(including goodwill), the goodwill is tested for impairment. If impairment is
indicated, we recognize a loss – calculated as the difference between the
implied fair value of a reporting unit's goodwill and the carrying value of the
goodwill. The forecasts used in our evaluations of goodwill reflect operations
consistent with our general business assumptions. Unanticipated changes in those
assumptions could have a significant effect on our future evaluations of
goodwill.
NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2009,
the FASB amended the derecognition guidance in the Transfers and Servicing Topic
of the FASB Accounting Standards Codification and eliminated the concept of a
QSPE. The amended guidance requires an evaluation of all existing QSPEs to
determine whether they must be consolidated. This standard is effective for
financial asset transfers that occur in fiscal years beginning after
November 15, 2009. FirstEnergy does not expect this standard to have a
material effect upon its financial statements.
In 2009,
the FASB amended the consolidation guidance applied to VIEs. This standard
replaces the quantitative approach previously required to determine which entity
has a controlling financial interest in a VIE with a qualitative approach. Under
the new approach, the primary beneficiary of a VIE is the entity that has both
(a) the power to direct the activities of the VIE that most significantly impact
the entity’s economic performance, and (b) the obligation to absorb losses of
the entity, or the right to receive benefits from the entity, that could be
significant to the VIE. This standard also requires ongoing reassessments of
whether an entity is the primary beneficiary of a VIE and enhanced disclosures
about an entity’s involvement in VIEs. The standard is effective for fiscal
years beginning after November 15, 2009. FirstEnergy does not expect this
standard to have a material effect upon its financial statements.
In 2010,
the FASB amended the Fair Value Measurements and Disclosures Topic of the FASB
Accounting Standards Codification to require additional disclosures about 1)
transfers of Level 1 and Level 2 fair value measurements, including the reason
for transfers, 2) purchases, sales, issuances and settlements in the roll
forward of activity in Level 3 fair value measurements, 3) additional
disaggregation to include fair value measurement disclosures for each class of
assets and liabilities and 4) disclosure of inputs and valuation techniques used
to measure fair value for both recurring and nonrecurring fair value
measurements. The amendment is effective for fiscal years beginning
after December 15, 2009, except for the disclosures about purchases, sales,
issuances and settlements in the roll forward of activity in Level 3 fair value
measurements, which is effective for fiscal years beginning after December 15,
2010. FirstEnergy does not expect this standard to have a material
effect upon its financial statements.
105
FIRSTENERGY
SOLUTIONS CORP.
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
FES is a
wholly owned subsidiary of FirstEnergy. FES provides energy-related products and
services, and through its subsidiaries, FGCO and NGC, owns or leases and
operates and maintains FirstEnergy's fossil and hydroelectric generation
facilities, and owns FirstEnergy's nuclear generation facilities, respectively.
FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the
nuclear generating facilities.
`
FES'
revenues have been primarily derived from the sale of electricity (provided from
FES' generating facilities and through purchased power arrangements) to
affiliated utility companies to meet all or a portion of their PLR and default
service requirements. These affiliated power sales included a full-requirements
PSA with OE, CEI and TE to supply each of their default service obligations
through December 31, 2008, at prices that considered their respective
PUCO-authorized billing rates. See Regulatory Matters – Ohio in the Combined
Notes to the Consolidated Financial Statements for a discussion of Ohio power
supply procurement issues for 2009 and beyond. On November 3, 2009, FES,
Met-Ed, Penelec and Waverly restated their partial requirements power purchase
agreement for 2010. Under the new agreement, Met-Ed, Penelec, and Waverly
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. FES also supplied, through May 31, 2009, a
portion of Penn's default service requirements at market-based rates as a result
of Penn's 2008 competitive solicitations. FES' revenues also include competitive
retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania,
New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater
portion of revenues in future years, depending upon FES' participation in its
Ohio and Pennsylvania utility affiliates' power procurement
arrangements.
The
demand for electricity produced and sold by FES, along with the price of that
electricity, is impacted by conditions in competitive power markets, global
economic activity, economic activity in the Midwest and Mid-Atlantic regions,
and weather conditions in FirstEnergy’s service territories. The 2009
recessionary economic conditions, particularly in the automotive and steel
industries, compounded by unusually mild regional summertime temperatures, have
adversely affected FES’ operations and revenues.
The
level of demand for electricity directly impacts FES’ generation revenues, the
quantity of electricity produced, purchased power expense and fuel expense.
FirstEnergy and FES have taken various actions and instituted a number of
changes in operating practices to manage the impact of these external
influences. These actions include employee severances, wage reductions, employee
and retiree benefit changes, reduced levels of overtime and the use of fewer
contractors. The continuation of recessionary economic conditions, coupled with
unusually mild weather patterns and the resulting impact on electricity prices
and demand, could impact FES’ future operating performance and financial
condition and may require further changes in FES’ operations.
For
additional information with respect to FES, please see the information contained
in FirstEnergy's Management Discussion and Analysis of Financial Condition and
Results of Operations above under the following subheadings, which information
is incorporated by reference herein: Capital Resources and Liquidity, Guarantees
and Other Assurances, Strategy and Outlook, Off-Balance Sheet Arrangements,
Regulatory Matters, Environmental Matters, Other Legal Proceedings and New
Accounting Standards and Interpretations.
Results of
Operations
Net
income increased to $577 million in 2009 from $506 million in 2008
primarily due to higher revenues (principally from the sale of a participation
interest in OVEC), lower fuel expense and increased investment income, partially
offset by higher purchased power, including a $205 million mark-to-market charge
related to certain purchased power contracts, and other operating
expenses.
Revenues
Revenues
increased by $210 million in 2009 compared to 2008 primarily due to
increases in revenues from retail generation sales and FGCO’s gain from the sale
of a 9% participation interest in OVEC, partially offset by lower affiliated
wholesale generation sales and decreased transmission revenues. The increase in
revenues in 2009 from 2008 is summarized below:
106
|
Revenues
by Type of Service
|
2009
|
2008
|
Increase
(Decrease)
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Non-Affiliated
Generation Sales:
|
||||||||||||
|
Retail
|
$ | 778 | $ | 615 | $ | 163 | ||||||
|
Wholesale
|
669 | 718 | (49 | ) | ||||||||
|
Total
Non-Affiliated Generation Sales
|
1,447 | 1,333 | 114 | |||||||||
|
Affiliated
Wholesale Generation Sales
|
2,843 | 2,968 | (125 | ) | ||||||||
|
Transmission
|
73 | 150 | (77 | ) | ||||||||
|
Sale
of OVEC participation interest
|
252 | - | 252 | |||||||||
|
Other
|
113 | 67 | 46 | |||||||||
|
Total
Revenues
|
$ | 4,728 | $ | 4,518 | $ | 210 | ||||||
The
increase in non-affiliated retail revenues of $163 million resulted from
increased revenue in both the PJM and MISO markets. The increase in MISO retail
revenue is primarily the result of the acquisition of new customers, higher unit
prices and the inclusion of the transmission-related component in retail prices
in Ohio beginning in June 2009. The increase in PJM retail revenue resulted from
the acquisition of new customers, higher sales volumes and unit prices. The
acquisition of new customers is primarily due to new government aggregation
contracts with 60 area communities in Ohio that will provide discounted
generation prices to approximately 580,000 residential and small commercial
customers. Lower non-affiliated wholesale revenues of $49 million resulted from
decreased sales volumes in PJM partially offset by increased capacity prices,
increased sales volumes in MISO, and favorable settlements on hedged
transactions.
The
lower affiliated company wholesale generation revenues of $125 million were
due to lower sales volumes to the Ohio Companies combined with lower unit prices
to the Pennsylvania Companies, partially offset by higher unit prices to the
Ohio Companies and increased sales volumes to the Pennsylvania Companies. The
lower sales volumes and higher unit prices to the Ohio Companies reflected the
results of the power procurement processes in the first half of 2009 (see
Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were
due to increased Met-Ed and Penelec generation sales requirements supplied by
FES partially offset by lower sales to Penn due to decreased default service
requirements in 2009 compared to 2008. Additionally, while unit prices for each
of the Pennsylvania Companies did not change, the mix of sales among the
companies caused the overall price to decline.
The
following tables summarize the price and volume factors contributing to changes
in revenues from non-affiliated and affiliated generation sales in 2009 compared
to 2008:
|
Increase
|
||||
|
Source
of Change in Non-Affiliated Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Retail:
|
||||
|
Effect
of 8.6% increase in sales volumes
|
$ | 53 | ||
|
Change
in prices
|
110 | |||
| 163 | ||||
|
Wholesale:
|
||||
|
Effect
of 13.9% decrease in sales volumes
|
(100 | ) | ||
|
Change
in prices
|
51 | |||
| (49 | ) | |||
|
Net
Increase in Non-Affiliated Generation Revenues
|
$ | 114 | ||
|
Increase
|
||||
|
Source
of Change in Affiliated Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Ohio
Companies:
|
||||
|
Effect
of 36.3% decrease in sales volumes
|
$
|
(837
|
)
|
|
|
Change
in prices
|
645
|
|||
|
(192
|
)
|
|||
|
Pennsylvania
Companies:
|
||||
|
Effect
of 14.7% increase in sales volumes
|
97
|
|||
|
Change
in prices
|
(30
|
)
|
||
|
67
|
||||
|
Net
Decrease in Affiliated Generation Revenues
|
$
|
(125
|
)
|
|
107
Transmission
revenues decreased $77 million due primarily to reduced loads following the
expiration of the government aggregation programs in Ohio at the end of 2008. In
2009 FGCO sold a 9% participation interest in OVEC resulting in a $252 million
($158 million, after tax) gain. Other revenue increased $46 million
primarily due to rental income associated with NGC's acquisition of equity
interests in the Perry and Beaver Valley Unit 2 leases.
Expenses
Total
expenses increased by $276 million in 2009 compared to 2008. The following
tables summarize the factors contributing to the changes in fuel and purchased
power costs in 2009 from 2008:
|
Source
of Change in Fuel and Purchased Power
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Fossil
Fuel:
|
||||
|
Change
due to increased unit costs
|
$
|
121
|
||
|
Change
due to volume consumed
|
(320
|
)
|
||
|
(199
|
)
|
|||
|
Nuclear
Fuel:
|
||||
|
Change
due to increased unit costs
|
23
|
|||
|
Change
due to volume consumed
|
(12
|
)
|
||
|
11
|
||||
|
Non-affiliated
Purchased Power:
|
||||
|
Power
contract mark-to-market adjustment
|
205
|
|||
|
Change
due to increased unit costs
|
93
|
|||
|
Change
due to volume purchased
|
(80
|
)
|
||
|
218
|
||||
|
Affiliated
Purchased Power:
|
||||
|
Change
due to increased unit costs
|
131
|
|||
|
Change
due to volume purchased
|
(10
|
)
|
||
|
121
|
||||
|
Net
Increase in Fuel and Purchased Power Costs
|
$
|
151
|
||
Fuel
costs decreased $188 million in 2009 compared to 2008 primarily resulting
from decreased coal consumption, reflecting lower generation, offset by higher
unit prices due to increased fuel costs associated with purchases of eastern
coal. Nuclear fuel costs increased slightly due to increased unit prices in 2009
compared to 2008.
Purchased
power costs from non-affiliates increased primarily as a result of a
mark-to-market charge of $205 million related to certain purchased power
contracts (see Note 6) and increased capacity costs, partially offset by reduced
volume requirements. Purchases from affiliated companies increased as a result
of increased unit costs, partially offset by lower volume
requirements.
Other
operating expenses increased $99
million in 2009 compared
to 2008 primarily due to increased transmission expenses reflecting TSC related
to the load serving entity obligations in MISO and increased net congestion and
transmission loss expenses in MISO and PJM. Also contributing to the increase
was higher employee benefit expenses and higher nuclear operating costs
associated with an additional refueling outage in 2009 compared to 2008. These
increases were partially offset by increased intercompany billings and lower
fossil operating costs primarily due to a reduction in contractor, material, and
labor costs, combined with more resources dedicated to capital
projects.
Depreciation
expense increased by $27 million in 2009 compared to 2008 primarily due to
NGC’s increased ownership interest in Beaver Valley Unit 2 and
Perry.
Other
Income (Expense)
Other
income of $40 million in 2009 compared to other expense of $119 million in 2008,
resulted primarily from a $155 million increase from gains on the sale of
nuclear decommissioning trust investments. During 2009, the majority of the
nuclear decommissioning trust holdings were converted to more closely align with
the liability being funded.
Market Risk
Information
FES uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations.
FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
provides general oversight to risk management activities.
108
Commodity
Price Risk
FES is
exposed to financial and market risks resulting from the fluctuation of interest
rates and commodity prices primarily due to fluctuations in electricity, energy
transmission, natural gas, coal, nuclear fuel and emission allowance prices. To
manage the volatility relating to these exposures, FES uses a variety of
non-derivative and derivative instruments, including forward contracts, options,
futures contracts and swaps. The derivatives are used principally for hedging
purposes. Certain derivatives must be recorded at their fair value and marked to
market. The majority of FES’ derivative contracts qualify for the normal
purchase and normal sale exception and are therefore excluded from the table
below. Contracts that are not exempt from such treatment include certain
purchased power contracts modified to financially settle as FES determined that
projected short positions in 2010 and 2011 were not expected to materialize
based on reductions in PLR obligations and decreased demand due to economic
conditions ($205 million). The change in the fair value of commodity
derivative contracts related to energy production during 2009 is summarized in
the following table:
|
Increase
(Decrease) in the Fair Value of Derivative Contracts
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Change
in the fair value of commodity derivative contracts:
|
||||||||||||
|
Outstanding
net liability as of January 1, 2009
|
$ | (1 | ) | $ | (41 | ) | $ | (42 | ) | |||
|
Additions/change
in value of existing contracts
|
(204 | ) | (1 | ) | (205 | ) | ||||||
|
Settled
contracts
|
- | 27 | 27 | |||||||||
|
Outstanding
net liability as of December 31, 2009
|
$ | (205 | ) | $ | (15 | ) | $ | (220 | ) | |||
|
Net
liabilities – derivative contacts as of December 31, 2009
|
$ | (205 | ) | $ | (15 | ) | $ | (220 | ) | |||
|
Impact
of changes in commodity derivative contracts
(*)
|
||||||||||||
|
Income
Statement effects (Pre-Tax)
|
$ | (205 | ) | $ | - | $ | (205 | ) | ||||
|
Balance
Sheet effects:
|
||||||||||||
|
OCI
(Pre-Tax)
|
$ | - | $ | 26 | $ | 26 | ||||||
|
|
(*)
|
Represents
the change in value of existing contracts, settled contracts and changes
in techniques/assumptions.
|
Derivatives
are included on the Consolidated Balance Sheet as of December 31, 2009 as
follows:
|
Balance
Sheet Classification
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Current-
|
||||||||||||
|
Other
assets
|
$ | - | $ | 3 | $ | 3 | ||||||
|
Other
liabilities
|
(108 | ) | (17 | ) | (125 | ) | ||||||
|
Non-Current-
|
||||||||||||
|
Other
deferred charges
|
- | 11 | 11 | |||||||||
|
Other
noncurrent liabilities
|
(97 | ) | (12 | ) | (109 | ) | ||||||
|
Net
liabilities
|
$ | (205 | ) | $ | (15 | ) | $ | (220 | ) | |||
The
valuation of derivative contracts is based on observable market information to
the extent that such information is available. FES uses these results to develop
estimates of fair value for financial reporting purposes and for internal
management decision making. Sources of information for the valuation of
commodity derivative contracts by year are summarized in the following
table:
|
Source
of Information
|
|||||||||||||||||||||||||||||
|
-
Fair Value by Contract Year
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
||||||||||||||||||||||
|
(In
millions)
|
|||||||||||||||||||||||||||||
|
Prices
actively quoted
(1)
|
$ | (11 | ) | $ | - | $ | - | $ | - | $ | - | $ | - | $ | (11 | ) | |||||||||||||
|
Other
external sources
(2)
|
(111 | ) | (98 | ) | - | - | - | - | (209 | ) | |||||||||||||||||||
|
Total
|
$ | (122 | ) | $ | (98 | ) | $ | - | $ | - | $ | $ | - | $ | (220 | ) | |||||||||||||
|
|
(1)
|
Exchange
traded.
|
|
|
(2)
|
Broker
quote sheets.
|
FES
performs sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on FES’ derivative instruments would not have had a material effect on its
consolidated financial position (assets, liabilities and equity) or cash flows
as of December 31, 2009. Based on derivative contracts held as of
December 31, 2009, an adverse 10% change in commodity prices would decrease
net income by approximately $9 million for the next
12 months.
109
Interest
Rate Risk
The
table below presents principal amounts and related weighted average interest
rates by year of maturity for FES’ investment portfolio and debt
obligations.
|
Comparison
of Carrying Value to Fair Value
|
||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
|||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
||||||||||||||||||||||||
|
(Dollars
in millions)
|
||||||||||||||||||||||||||||||||
|
Assets
|
||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
|
||||||||||||||||||||||||||||||||
|
and
Cash Equivalents:
|
||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 11 | $ | 1,043 | $ | 1,054 | $ | 1,057 | ||||||||||||||||||||||||
|
Average
interest rate
|
2.8 | % | 4.4 | % | 4.4 | % | ||||||||||||||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 53 | $ | 58 | $ | 68 | $ | 75 | $ | 99 | $ | 1,888 | $ | 2,241 | $ | 2,290 | ||||||||||||||||
|
Average
interest rate
|
9.0 | % | 8.9 | % | 9.0 | % | 9.0 | % | 7.3 | % | 6.0 | % | 6.4 | % | ||||||||||||||||||
|
Variable
rate
|
$ | 1,983 | $ | 1,983 | $ | 2,016 | ||||||||||||||||||||||||||
|
Average
interest rate
|
1.8 | % | 1.8 | % | ||||||||||||||||||||||||||||
|
Short-term
Borrowings:
|
$ | 109 | $ | 109 | $ | 109 | ||||||||||||||||||||||||||
|
Average
interest rate
|
1.8 | % | 1.8 | % | ||||||||||||||||||||||||||||
Fluctuations
in the fair value of NGC's decommissioning trust balances will eventually affect
earnings (immediately for other-than-temporary impairments and affecting OCI
initially for unrealized gains) based on authoritative guidance. As of
December 31, 2009, NGC’s decommissioning trust balance totaled
$1.1 billion, comprised primarily of debt instruments.
Credit
Risk
Credit
risk is the risk of an obligor's failure to meet the terms of any investment
contract, loan agreement or otherwise perform as agreed. Credit risk arises from
all activities in which success depends on issuer, borrower or counterparty
performance, whether reflected on or off the balance sheet. FES engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.
FES
maintains credit policies with respect to our counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of its credit program, FES aggressively manages the
quality of its portfolio of energy contracts, evidenced by a current weighted
average risk rating for energy contract counterparties of BBB (S&P). As of
December 31, 2009, the largest credit concentration was with AEP, which is
currently rated investment grade, representing 8.9% of FES’ total approved
credit risk.
110
OHIO
EDISON COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
OE is a
wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned
subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania,
providing regulated electric distribution services. They provide generation
services to those franchise customers electing to retain OE and Penn as their
power supplier. Until December 31, 2008, OE purchased power for delivery
and resale from a full requirements power sale agreement with its affiliate FES
at a fixed price that was reflected in rates approved by the PUCO. See
Regulatory Matters – Ohio in the Combined Notes to the Consolidated Financial
Statements for a discussion of Ohio power supply procurement issues for 2009 and
beyond.
For
additional information with respect to OE, please see the information contained
in FirstEnergy's Management Discussion and Analysis of Financial Condition and
Results of Operations above under the following subheadings, which information
is incorporated by reference herein: Capital Resources and Liquidity, Guarantees
and Other Assurances, Strategy and Outlook, Off-Balance Sheet Arrangements,
Regulatory Matters, Environmental Matters, Other Legal Proceedings and New
Accounting Standards and Interpretations.
Results of
Operations
Earnings
available to parent decreased to $122 million in 2009 from
$212 million in 2008. The decrease primarily resulted from lower electric
sales revenues and higher purchased power costs, partially offset by a decrease
in other operating costs.
Revenues
Revenues
decreased by $85 million, or 3.3%, in 2009 compared to 2008, primarily due
to decreases in distribution throughput and transmission revenues, partially
offset by increases in generation revenues.
Revenues
from distribution throughput decreased by $262 million in 2009 compared to
2008 due to lower average unit prices and lower KWH deliveries to all customer
classes. Milder weather-influenced usage in 2009 contributed to the decreased
KWH sales to residential customers (heating degree days decreased 3.3% and 1.4%
and cooling degree days decreased by 16.5% and 6.1% in OE’s and Penn’s service
territories, respectively). Reduced deliveries to commercial and industrial
customers reflect the weakened economy. Transition charges that ceased effective
January 1, 2009, with the full recovery of related costs, were partially
offset by a July 2008 increase to a PUCO-approved transmission rider and a
January 2009 distribution rate increase (see Regulatory Matters –
Ohio).
Changes
in distribution KWH deliveries and revenues in 2009 compared to 2008 are
summarized in the following tables.
|
Distribution
KWH Deliveries
|
Decrease
|
|||
|
Residential
|
(2.8
|
)%
|
||
|
Commercial
|
(4.2
|
)%
|
||
|
Industrial
|
(21.4
|
)%
|
||
|
Decrease
in Distribution Deliveries
|
(9.6
|
)%
|
||
|
Distribution
Revenues
|
Decrease
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(45
|
)
|
|
|
Commercial
|
(98
|
)
|
||
|
Industrial
|
(119
|
)
|
||
|
Decrease
in Distribution Revenues
|
$
|
(262
|
)
|
|
Transmission
revenues decreased $27 million in 2009 as compared to 2008 due to the
elimination of transmission revenues as part of the generation rate established
under OE's CBP, effective June 1, 2009.
111
Retail
generation revenues increased $92 million due to higher average prices. The
higher prices were partially offset by decreases in KWH sales, reflecting the
impact of increased customer shopping in the fourth quarter of 2009. Reduced
industrial and commercial KWH sales also reflected weakened economic conditions.
Average prices increased primarily due to an increase in OE's fuel cost recovery
rider that was effective from January through May 2009. Effective June 1,
2009, the transmission tariff ended and the recovery of transmission costs is
included in the generation rate established under OE’s CBP.
Changes
in retail generation sales and revenues in 2009 compared to 2008 are summarized
in the following tables:
|
Retail
Generation KWH Sales
|
Decrease
|
|||
|
Residential
|
(0.1 | )% | ||
|
Commercial
|
(1.5 | )% | ||
|
Industrial
|
(27.9 | )% | ||
|
Decrease
in Generation Sales
|
(9.2 | )% | ||
|
Retail
Generation Revenues - Changes
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Residential
|
$ | 56 | ||
|
Commercial
|
49 | |||
|
Industrial
|
(13 | ) | ||
|
Net
Increase in Generation Revenues
|
$ | 92 | ||
Wholesale
revenues increased by $116 million, primarily due to higher average unit
prices that were partially offset by a slight decrease in sales
volume.
Expenses
Total
expenses increased by $20 million in 2009 compared to 2008. The following
table presents changes from the prior year by expense category.
|
Expenses
– Changes
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchased
power costs
|
$ | 154 | ||
|
Other
operating costs
|
(105 | ) | ||
|
Provision
for depreciation
|
10 | |||
|
Amortization
of regulatory assets, net
|
(24 | ) | ||
|
General
taxes
|
(15 | ) | ||
|
Net
Increase in Expenses
|
$ | 20 | ||
Higher
purchased power costs reflect the results of OE’s power procurement process for
retail customers in 2009 (see Regulatory Matters – Ohio). The decrease in other
operating costs for 2009 was primarily due to lower transmission expenses
(included in the cost of power purchased from others beginning June 1,
2009), partially offset by costs associated with regulatory obligations for
economic development and energy efficiency programs under OE’s ESP. Higher
depreciation expense in 2009 reflected capital additions since the end of 2008.
Lower amortization of net regulatory assets was primarily due to the conclusion
of transition cost amortization and distribution reliability deferrals in 2008,
partially offset by lower MISO transmission cost deferrals in 2009. The decrease
in general taxes was primarily due to lower Ohio KWH taxes in 2009 as compared
to 2008 and a $7.1 million adjustment recognized in 2009 related to prior
periods.
Other
Expenses
Other
expenses increased by $17 million in 2009 compared to 2008 primarily due to
higher interest expense associated with the issuance of $300 million of FMBs by
OE in October 2008.
112
Interest Rate
Risk
OE’s
exposure to fluctuations in market interest rates is reduced since a significant
portion of its debt has fixed interest rates. The table below presents principal
amounts and related weighted average interest rates by year of maturity for OE’s
investment portfolio and debt obligations.
|
Comparison
of Carrying Value to Fair Value
|
|||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
||||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
|||||||||||||||||||||||||
|
(Dollars
in millions)
|
|||||||||||||||||||||||||||||||||
|
Assets
|
|||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
|
|||||||||||||||||||||||||||||||||
|
and
Cash Equivalents:
|
|||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 27 | $ | 29 | $ | 31 | $ | 37 | $ | 42 | $ | 106 | $ | 272 | $ | 301 | |||||||||||||||||
|
Average
interest rate
|
8.6 | % | 8.7 | % | 8.7 | % | 8.7 | % | 8.8 | % | 6.7 | % | 8.0 | % | |||||||||||||||||||
|
Liabilities
|
|||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
|||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 1 | $ | 1 | $ | 1,167 | $ | 1,169 | $ | 1,299 | |||||||||||||||||||||||
|
Average
interest rate
|
7.2 | % | 5.4 | % | 6.9 | % | 6.9 | % | |||||||||||||||||||||||||
|
Short-term
Borrowings:
|
$ | 94 | $ | 94 | $ | 94 | |||||||||||||||||||||||||||
|
Average
interest rate
|
0.7 | % | 0.7 | % | |||||||||||||||||||||||||||||
113
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
CEI is a
wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business
in northeastern Ohio, providing regulated electric distribution services. CEI
also provides generation services to those customers electing to retain CEI as
their power supplier. Until December 31, 2008, CEI purchased power for
delivery and resale from a full requirements power sale agreement with its
affiliate FES at a fixed price that was reflected in rates approved by the PUCO.
See Regulatory Matters – Ohio in the Combined Notes to the Consolidated
Financial Statements for a discussion of Ohio power supply procurement issues
for 2009 and beyond.
For
additional information with respect to CEI, please see the information contained
in FirstEnergy's Management Discussion and Analysis of Financial Condition and
Results of Operations above under the following subheadings, which information
is incorporated by reference herein: Capital Resources and Liquidity, Guarantees
and Other Assurances, Strategy and Outlook, Off-Balance Sheet Arrangements,
Regulatory Matters, Environmental Matters, Other Legal Proceedings and New
Accounting Standards and Interpretations.
Results
of Operations
CEI
experienced a loss applicable to parent of $13 million in 2009 compared to
earnings available to parent of $285 million in 2008. The loss in 2009
resulted primarily from regulatory charges related to the implementation of
CEI’s ESP, decreased revenues, and increased purchased power costs, partially
offset by higher deferrals of regulatory assets and lower operating
costs.
Revenues
Revenues
decreased by $140 million, or 7.7%, in 2009 compared to 2008, due primarily
to decreases in distribution and transmission revenues, partially offset by
increases in retail generation revenues.
Revenues
from distribution throughput decreased by $154 million in 2009, compared to
2008 due to a decrease in KWH deliveries and lower average unit prices for all
customer classes. The lower KWH deliveries in 2009 were due primarily to weaker
economic conditions, a decrease in cooling degree days of 14.5% and a decrease
in heating degree days of 3.9%. The lower average unit price was the result of
lower transition rates in 2009 (see Regulatory Matters – Ohio), partially offset
by a PUCO-approved distribution rate increase effective May 1,
2009.
Changes
in distribution KWH deliveries and revenues in 2009 compared to 2008 are
summarized in the following tables.
|
Distribution
KWH Deliveries
|
Decrease
|
|||
|
Residential
|
(3.2
|
)%
|
||
|
Commercial
|
(4.0
|
)%
|
||
|
Industrial
|
(14.7
|
)%
|
||
|
Decrease
in Distribution Deliveries
|
(8.6
|
)%
|
||
|
Distribution
Revenues
|
Decrease
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(56
|
)
|
|
|
Commercial
|
(36
|
)
|
||
|
Industrial
|
(62
|
)
|
||
|
Decrease
in Distribution Revenues
|
$
|
(154
|
)
|
|
Transmission
revenues decreased $21 million in 2009 as compared to 2008 due to the
elimination of transmission revenues as part of the generation rate established
under CEI’s CBP, effective June 1, 2009.
Retail
generation revenues increased $48 million in 2009 as compared to 2008 due
to higher average unit prices across all customer classes, partially offset by
decreased sales volume to all customer classes. Average prices increased due to
an increase in CEI’s fuel cost recovery rider that was effective from January
through May 2009. In addition, effective June 1, 2009, the transmission tariff
ended and the recovery of transmission costs is included in the generation rate
established under CEI’s CBP. Reduced industrial KWH sales, principally to major
automotive and steel customers, reflected weakened economic
conditions. Reduced sales due to increased customer shopping was
experienced in all sectors in the fourth quarter of 2009.
114
Changes
in retail generation sales and revenues in 2009 compared to 2008 are summarized
in the following tables:
|
Retail
KWH Sales
|
Decrease
|
|||
|
Residential
|
(14.1
|
)%
|
||
|
Commercial
|
(9.4
|
)%
|
||
|
Industrial
|
(20.5
|
)%
|
||
|
Other
|
(7.3
|
)%
|
||
|
Decrease
in Retail Sales
|
(15.8
|
)%
|
||
|
Retail
Generation Revenues
|
Increase
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
14
|
||
|
Commercial
|
17
|
|||
|
Industrial
|
15
|
|||
|
Other
|
2
|
|||
|
Increase
in Generation Revenues
|
$
|
48
|
||
Expenses
Total
expenses increased by $294 million in 2009 compared to 2008. The following
table presents the change from the prior year by expense category:
|
Expenses -
Changes
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchased
power costs
|
$
|
210
|
||
|
Other
operating costs
|
(98
|
)
|
||
|
Amortization
of regulatory assets
|
207
|
|||
|
Deferral
of new regulatory assets
|
(27
|
)
|
||
|
General
taxes
|
2
|
|||
|
Net
Increase in Expenses
|
$
|
294
|
||
Higher
purchased power costs reflect the results of CEI’s power procurement process for
retail customers in 2009 (see Regulatory Matters – Ohio). Other operating costs
decreased due to lower transmission expenses (included in the cost of purchased
power beginning June 1, 2009) and reduced labor and contractor costs,
partially offset by costs associated with regulatory obligations for economic
development and energy efficiency programs under CEI’s ESP, higher pension
expense and restructuring costs. Increased amortization of regulatory assets was
due primarily to the impairment of CEI’s Extended RTC regulatory asset of
$216 million in accordance with the PUCO-approved ESP. Decreased costs from
the increase in the deferral of new regulatory assets were due to CEI’s deferral
of purchased power costs as approved by the PUCO, partially offset by lower
deferrals of MISO transmission expenses and the absence of RCP distribution
deferrals that ceased at the end of 2008. The increase in general taxes was
primarily due to higher property taxes.
Interest Rate
Risk
CEI has
little exposure to fluctuations in market interest rates because most of its
debt has fixed interest rates. The table below presents principal amounts and
related weighted average interest rates by year of maturity for CEI’s investment
portfolio and debt obligations.
|
Comparison
of Carrying Value to Fair Value
|
||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
|||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
||||||||||||||||||||||||
|
(Dollars
in millions)
|
||||||||||||||||||||||||||||||||
|
Assets
|
||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
|
||||||||||||||||||||||||||||||||
|
and
Cash Equivalents:
|
||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 49 | $ | 53 | $ | 66 | $ | 75 | $ | 80 | $ | 66 | $ | 389 | $ | 432 | ||||||||||||||||
|
Average
interest rate
|
7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 7.8 | % | 7.7 | % | ||||||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 20 | $ | 22 | $ | 325 | $ | 26 | $ | 1,480 | $ | 1,873 | $ | 2,032 | ||||||||||||||||||
|
Average
interest rate
|
7.7 | % | 7.7 | % | 5.8 | % | 7.7 | % | 6.8 | % | 6.7 | % | ||||||||||||||||||||
|
Short-term
Borrowings:
|
$ | 340 | $ | 340 | $ | 340 | ||||||||||||||||||||||||||
|
Average
interest rate
|
1.1 | % | 1.1 | % | ||||||||||||||||||||||||||||
115
THE
TOLEDO EDISON COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
TE is a
wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in
northwestern Ohio, providing regulated electric distribution services. TE also
provides generation services to those customers electing to retain TE as their
power supplier. Until December 31, 2008, TE purchased power for delivery
and resale from a full requirements power sale agreement with its affiliate FES
at a fixed price that was reflected in rates approved by the PUCO. See
Regulatory Matters – Ohio in the Combined Notes to the Consolidated Financial
Statements for a discussion of Ohio power supply procurement issues for 2009 and
beyond.
For
additional information with respect to TE, please see the information contained
in FirstEnergy's Management Discussion and Analysis of Financial Condition and
Results of Operations above under the following subheadings, which information
is incorporated by reference herein: Capital Resources and Liquidity, Guarantees
and Other Assurances, Strategy and Outlook, Off-Balance Sheet Arrangements,
Regulatory Matters, Environmental Matters, Other Legal Proceedings and New
Accounting Standards and Interpretations.
Results of
Operations
Earnings
available to parent in 2009 decreased to $24
million from $75 million
in 2008. The decrease resulted primarily from lower electric sales revenues and
higher purchased power costs, partially offset by a decrease in the amortization
of net regulatory assets and lower other operating costs.
Revenues
Revenues
decreased $62 million, or 6.9%, in 2009 compared to 2008 due primarily to
lower distribution and wholesale generation revenues, partially offset by
increased retail generation revenues.
Revenues
from distribution throughput decreased $173 million in 2009 compared to
2008 due to lower average unit prices and lower KWH sales in all customer
classes that resulted primarily from adverse economic conditions. The effect of
transition charges that ceased effective January 1, 2009, with the full
recovery of related costs, was partially offset by a PUCO-approved distribution
rate increase (see Regulatory Matters – Ohio).
Changes
in distribution KWH deliveries and revenues in 2009 from 2008 are summarized in
the following tables.
|
Distribution
KWH Deliveries
|
Decrease
|
|||
|
Residential
|
(4.7
|
)%
|
||
|
Commercial
|
(9.4
|
)%
|
||
|
Industrial
|
(7.9
|
)%
|
||
|
Decrease
in Distribution Deliveries
|
(7.6
|
)%
|
||
|
Distribution
Revenues
|
Decrease
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(39
|
)
|
|
|
Commercial
|
(79
|
)
|
||
|
Industrial
|
(55
|
)
|
||
|
Decrease
in Distribution Revenues
|
$
|
(173
|
)
|
|
Wholesale
revenues decreased $6 million in 2009 as compared to 2008 primarily due to
the expiration of a sales agreement with AMP-Ohio at the end of 2008, partially
offset by higher revenues from associated sales to NGC from TE’s leasehold
interest in Beaver Valley Unit 2.
116
Retail
generation revenues increased $113 million in 2009 compared to 2008 due to
higher average prices across all customer classes and increased KWH sales to
commercial customers, partially offset by a decrease in KWH sales to residential
and industrial customers reflecting the impact of increased customer shopping in
the fourth quarter of 2009. Average prices increased primarily due to an
increase in TE's fuel cost recovery rider that was effective from January
through May 2009. In addition, effective June 1, 2009, the transmission
tariff ended and the recovery of transmission costs is included in the
generation rate established under TE’s CBP. Reduced industrial KWH sales,
principally to major automotive and steel customers, reflected weakened economic
conditions. Most of TE’s customers returned to PLR service in December 2008,
following the termination of certain government aggregation programs in TE’s
service territory, resulting in an increase in sales volume for commercial
customers.
Changes
in retail electric generation KWH sales and revenues in 2009 from 2008 are
summarized in the following tables.
|
Increase
|
||||
|
Retail
KWH Sales
|
(Decrease)
|
|||
|
Residential
|
(10.0
|
)%
|
||
|
Commercial
|
10.2
|
%
|
||
|
Industrial
|
(24.4
|
)%
|
||
|
Net
Decrease in Retail KWH Sales
|
(13.2
|
)%
|
||
|
Retail
Generation Revenues
|
Increase
|
|||
|
(In
millions
)
|
||||
|
Residential
|
$
|
25
|
||
|
Commercial
|
58
|
|||
|
Industrial
|
30
|
|||
|
Increase
in Retail Generation Revenues
|
$
|
113
|
||
Expenses
Total
expenses increased $5 million in 2009 from 2008. The following table
presents changes from the prior year by expense category.
|
Expenses
– Changes
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchased
power costs
|
$
|
116
|
||
|
Other
operating costs
|
(48
|
)
|
||
|
Provision
for depreciation
|
(2
|
)
|
||
|
Amortization
of regulatory assets, net
|
(56
|
)
|
||
|
General
taxes
|
(5
|
)
|
||
|
Net
Increase in Expenses
|
$
|
5
|
||
Higher
purchased power costs reflect the results of TE’s power procurement process for
retail customers in 2009 (see Regulatory Matters – Ohio). Other operating costs
decreased primarily due to reduced transmission expenses (included in the cost
of power purchased from others beginning June 1, 2009), partially offset by
costs associated with regulatory obligations for economic development and energy
efficiency programs under TE’s ESP. The decrease in net amortization of
regulatory assets is primarily due to the completion of transition cost
recovery, partially offset by lower MISO transmission cost deferrals in 2009.
The decrease in general taxes was primarily due to lower Ohio KWH taxes in 2009
as compared to 2008 resulting from lower KWH sales and a $3.5 million adjustment
recognized in 2009 related to prior periods, partially offset by increased
property taxes.
Other
Expense
Other
expense increased $6 million in 2009 compared to 2008, primarily due to higher
interest expense associated with the April 2009 issuance of $300 million senior
secured notes, partially offset by increased nuclear decommissioning trust
investment income.
117
Interest Rate
Risk
TE has
little exposure to fluctuations in market interest rates because most of its
debt has fixed interest rates. The table below presents principal amounts and
related weighted average interest rates by year of maturity for TE’s investment
portfolio and debt obligations.
|
Comparison
of Carrying Value to Fair Value
|
|||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
||||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
|||||||||||||||||||||||||
|
(Dollars
in millions)
|
|||||||||||||||||||||||||||||||||
|
Assets
|
|||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
and
Cash Equivalents:
|
|||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 18 | $ | 20 | $ | 22 | $ | 25 | $ | 26 | $ | 102 | $ | 213 | $ | 231 | |||||||||||||||||
|
Average
interest rate
|
7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 5.4 | % | 6.6 | % | |||||||||||||||||||
|
Liabilities
|
|||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
|||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 600 | $ | 600 | $ | 638 | |||||||||||||||||||||||||||
|
Average
interest rate
|
6.7 | % | 6.7 | % | |||||||||||||||||||||||||||||
|
Short-term
Borrowings:
|
$ | 226 | $ | 226 | $ | 226 | |||||||||||||||||||||||||||
|
Average
interest rate
|
0.7 | % | 0.7 | % | |||||||||||||||||||||||||||||
118
JERSE
Y CENTRAL POWER &
LIGHT COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
JCP&L
is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L
conducts business in New Jersey, providing regulated electric transmission and
distribution services. JCP&L also provides generation services to franchise
customers electing to retain JCP&L as their power supplier. JCP&L
procures electric supply to serve its BGS customers through a statewide auction
process approved by the NJBPU.
For
additional information with respect to JCP&L, please see the information
contained in FirstEnergy’s Management Discussion and Analysis of Financial
Condition and Results of Operations above under the following subheadings, which
information is incorporated by reference herein: Capital Resources and
Liquidity, Guarantees and Other Assurances, Strategy and Outlook, Regulatory
Matters, Environmental Matters, Other Legal Proceedings and New Accounting
Standards and Interpretations.
Results of
Operations
Net
income decreased to $170
million from $187
million in 2009. The
decrease was primarily due to lower revenues, partially offset by lower
purchased power costs and reduced amortization of regulatory
assets.
Revenues
Revenues
decreased by $480 million, or 14% in 2009, compared with 2008. The decrease
in revenues is primarily due to a decrease in wholesale generation revenues,
retail generation revenues, and distribution revenues.
Wholesale
generation revenues decreased $232
million in 2009 compared
to 2008 due to lower market prices ($174 million) and a decrease in sales volume
($58 million) primarily resulting from the termination of a NUG contract in
October 2008.
Retail
generation revenues decreased $193 million in 2009 compared to 2008 due to
lower retail generation KWH sales in all sectors, partially offset by higher
unit prices in the residential and commercial sectors. Lower sales to the
residential sector reflected milder weather in JCP&L’s service territory,
while the decrease in sales to the commercial sector was primarily due to an
increase in the number of shopping customers. Industrial sales were lower as a
result of weakened economic conditions.
Changes
in retail generation KWH sales and revenues by customer class in 2009 compared
to 2008 are summarized in the following tables:
|
Retail
Generation KWH Sales
|
Decrease
|
|||
|
Residential
|
(4.7
|
)%
|
||
|
Commercial
|
(23.9
|
)%
|
||
|
Industrial
|
(16.0
|
)%
|
||
|
Decrease
in Generation Sales
|
(13.0
|
)%
|
||
|
Retail
Generation Revenues
|
Decrease
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(11
|
)
|
|
|
Commercial
|
(165
|
)
|
||
|
Industrial
|
(17
|
)
|
||
|
Decrease
in Generation Revenues
|
$
|
(193
|
)
|
|
Distribution
revenues decreased $51 million in 2009 compared to 2008 due to lower KWH
deliveries, reflecting milder weather and weakened economic conditions in
JCP&L’s service territory, partially offset by an increase in composite unit
prices.
119
Changes
in distribution KWH deliveries and revenues by customer class in 2009 compared
to 2008 are summarized in the following tables:
|
Distribution
KWH Deliveries
|
Decrease
|
|||
|
Residential
|
(4.7
|
)%
|
||
|
Commercial
|
(4.0
|
)%
|
||
|
Industrial
|
(11.8
|
)%
|
||
|
Decrease
in Distribution Deliveries
|
(5.2
|
)%
|
||
|
Distribution
Revenues
|
Decrease
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(28
|
)
|
|
|
Commercial
|
(18
|
)
|
||
|
Industrial
|
(5
|
)
|
||
|
Decrease
in Distribution Revenues
|
$
|
(51
|
)
|
|
Expenses
Total
expenses decreased by $435 million in 2009 compared to 2008. The following
table presents changes from the prior year by expense category:
|
Expenses
- Changes
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchased
power costs
|
$
|
(424
|
)
|
|
|
Other
operating costs
|
8
|
|||
|
Provision
for depreciation
|
6
|
|||
|
Amortization
of regulatory assets
|
(21
|
)
|
||
|
General
taxes
|
(4
|
)
|
||
|
Net
decrease in expenses
|
$
|
(435
|
)
|
|
Purchased
power costs decreased in 2009 primarily due to the lower KWH sales requirements
discussed above, partially offset by higher retail unit prices. Other operating
costs increased in 2009 primarily due to higher expenses related to employee
benefits. Depreciation expense increased due to an increase in depreciable
property since 2008. Amortization of regulatory assets decreased in 2009
primarily due to the full recovery of certain regulatory assets in June 2008.
General taxes decreased principally as the result of lower Transitional Energy
Facility Assessment and sales taxes.
Other
Expenses
Other
expenses increased by $12
million in 2009 compared
to 2008 primarily due to higher interest expense associated with JCP&L's
$300 million Senior Notes issuance in January 2009.
Sale
of Investment
On April
17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to
Maxim Power Corp. for $20 million, as approved by an earlier order from the
NJBPU. The New Jersey Rate Counsel appealed the sale to the Appellate Division
of the Superior Court of New Jersey. On July 10, 2009, the Court upheld the
NJBPU’s order and the sale of the plant.
Market Risk
Information
JCP&L
uses various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations.
FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
provides general oversight to risk management activities.
120
Commodity
Price Risk
JCP&L
is exposed to market risk primarily due to fluctuations in electricity, energy
transmission and natural gas prices. To manage the volatility relating to these
exposures, JCP&L uses a variety of non-derivative and derivative
instruments, including forward contracts, options, futures contracts and swaps.
The derivatives are used principally for hedging purposes. The majority of
JCP&L’s derivative contracts must be recorded at their fair value and marked
to market. Power purchase agreements with NUG entities that were structured
pursuant to the Public Utility Regulatory Policies Act of 1978 are non-trading
contracts and are adjusted to fair value at the end of each quarter, with a
corresponding regulatory asset recognized for above-market costs or regulatory
liability for below-market costs. The change in the fair value of commodity
derivative contracts related to energy production during 2009 is summarized in
the following table:
|
Increase
(Decrease) in the Fair Value of Derivative Contracts
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Change
in the fair value of commodity derivative contracts:
|
||||||||||||
|
Outstanding
net liability as of January 1, 2009
|
$ | (510 | ) | $ | - | $ | (510 | ) | ||||
|
Additions/change
in value of existing contracts
|
(43 | ) | - | (43 | ) | |||||||
|
Settled
contracts
|
167 | - | 167 | |||||||||
|
Outstanding
net liability as of December 31, 2009
(1)
|
$ | (386 | ) | $ | - | $ | (386 | ) | ||||
|
Impact
of changes in commodity derivative contracts
(2)
|
||||||||||||
|
Income
Statement effects (Pre-Tax)
|
$ | - | $ | - | $ | - | ||||||
|
Balance
Sheet effects:
|
||||||||||||
|
OCI
(Pre-Tax)
|
$ | - | $ | - | $ | - | ||||||
|
Regulatory
Asset (net)
|
$ | (124 | ) | $ | - | $ | (124 | ) | ||||
|
|
(1)
|
Includes
$386 million in non-hedge commodity derivative contracts (primarily
with NUGs) that are subject to regulatory accounting and do not impact
earnings.
|
|
|
(2)
|
Represents
the change in value of existing contracts, settled contracts and changes
in techniques/assumptions.
|
Derivatives
are included on the Consolidated Balance Sheet as of December 31, 2009 as
follows:
|
Balance
Sheet Classification
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Non-Current-
|
||||||||||||
|
Other
deferred charges
|
$ | 13 | $ | - | $ | 13 | ||||||
|
Other
noncurrent liabilities
|
(399 | ) | - | (399 | ) | |||||||
|
Net
liabilities
|
$ | (386 | ) | $ | - | $ | (386 | ) | ||||
The
valuation of derivative contracts is based on observable market information to
the extent that such information is available. In cases where such information
is not available, JCP&L relies on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. JCP&L uses these results to develop estimates of
fair value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of commodity derivative
contracts as of December 31, 2009 are summarized by year in the following
table:
|
Source
of Information
|
|||||||||||||||||||||||||||||
|
-
Fair Value by Contract Year
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
||||||||||||||||||||||
|
(In
millions)
|
|||||||||||||||||||||||||||||
|
Other
external sources
(1)
|
$ | (157 | ) | $ | (110 | ) | $ | (45 | ) | $ | (41 | ) | $ | - | $ | - | $ | (353 | ) | ||||||||||
|
Prices
based on models
|
- | - | - | - | (27 | ) | (6 | ) | (33 | ) | |||||||||||||||||||
|
Total
(2)
|
$ | (157 | ) | $ | (110 | ) | $ | (45 | ) | $ | (41 | ) | $ | (27 | ) | $ | (6 | ) | $ | (386 | ) | ||||||||
|
|
(1)
|
Broker
quote sheets.
|
|
|
(2)
|
Includes
$386 million in non-hedge commodity derivative contracts (primarily
with NUGs) that are subject to regulatory accounting and do not impact
earnings.
|
JCP&L
performs sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
JCP&L’s consolidated financial position or cash flows as of
December 31, 2009. Based on derivative contracts held as of
December 31, 2009, an adverse 10% change in commodity prices would not have
a material effect on JCP&L’s net income for the next
12 months.
121
Interest
Rate Risk
JCP&L’s exposure
to fluctuations in market interest rates is reduced since a significant portion
of its debt has fixed interest rates. The table below presents principal amounts
and related weighted average interest rates by year of maturity for JCP&L’s
investment portfolio and debt obligations.
|
Comparison
of Carrying Value to Fair Value
|
||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
|||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
||||||||||||||||||||||||
|
Assets
|
(Dollars in millions) | |||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
and Cash
Equivalents:
|
||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 270 | $ | 270 | $ | 280 | ||||||||||||||||||||||||||
|
Average
interest rate
|
3.8 | % | 3.8 | % | ||||||||||||||||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 31 | $ | 32 | $ | 34 | $ | 36 | $ | 38 | $ | 1,669 | $ | 1,840 | $ | 1,950 | ||||||||||||||||
|
Average
interest rate
|
5.4 | % | 5.6 | % | 5.7 | % | 5.7 | % | 5.9 | % | 6.1 | % | 6.0 | % | ||||||||||||||||||
Equity Price Risk
Included in
JCP&L’s nuclear decommissioning trusts are marketable equity securities
carried at their market value of approximately $85 million as of
December 31, 2009. A hypothetical 10% decrease in prices quoted by stock
exchanges would result in a $9 million reduction in fair value as of
December 31, 2009 (see Note 5).
122
METROPOLITAN
EDISON COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
Met-Ed is a wholly
owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in
eastern Pennsylvania, providing regulated electric transmission and distribution
services. Met-Ed also provides generation service to those customers electing to
retain Met-Ed as their power supplier. On November 3, 2009, FES, Met-Ed,
Penelec and Waverly restated their partial requirements power purchase agreement
for 2010. Under the new agreement, Met-Ed, Penelec, and Waverly assigned 1,300
MW of existing energy purchases to FES to assist it in supplying Met-Ed's power
supply requirements and managing congestion expenses.
For additional
information with respect to Met-Ed, please see the information contained in
FirstEnergy's Management Discussion and Analysis of Financial Condition and
Results of Operations above under the following subheadings, which information
is incorporated by reference herein: Capital Resources and Liquidity, Guarantees
and Other Assurances, Strategy and Outlook, Regulatory Matters, Environmental
Matters, Other Legal Proceedings and New Accounting Standards and
Interpretations.
Results of
Operations
In 2009, Met-Ed
reported net income of $56 million compared to $88 million 2008. The
decrease was primarily due to decreased distribution throughput and generation
sales, and increased interest expense, partially offset by lower other operating
costs and higher transmission rates.
Revenues
Revenues increased
by $36 million, or 2.2%, in 2009 compared to 2008 principally due to higher
distribution and wholesale generation revenues, partially offset by a decrease
in retail generation and PJM transmission revenues.
Revenues from
distribution increased $88 million in 2009 compared to 2008 primarily due
to higher transmission rates, resulting from the annual update of Met-Ed’s TSC
rider effective June 1, 2009. Decreased KWH deliveries to commercial and
industrial customers reflecting the weakened economy, while decreased deliveries
to residential customers were the result of weather-related usage variations
from a 14.2% decrease in cooling degree days for 2009 compared to
2008.
Changes in
distribution KWH deliveries and revenues in 2009 compared to 2008 are summarized
in the following tables:
|
Distribution
KWH Deliveries
|
(Decrease)
|
|||
|
Residential
|
(2.7
|
)%
|
||
|
Commercial
|
(4.4
|
)%
|
||
|
Industrial
|
(10.3
|
)%
|
||
|
Decrease
in Distribution Deliveries
|
(5.3
|
)%
|
||
|
Distribution
Revenues
|
Increase
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
43
|
||
|
Commercial
|
28
|
|||
|
Industrial
|
17
|
|||
|
Increase
in Distribution Revenues
|
$
|
88
|
||
Wholesale revenues
increased by $15
million
in 2009 compared to 2008, primarily reflecting higher PJM spot market
prices.
In 2009, retail
generation revenues decreased $35
million
due to lower KWH sales in all customer classes with composite unit prices
increased slightly for residential and commercial customer classes and decreased
slightly for industrial customers. Lower KWH sales to commercial and industrial
customers were principally due to economic conditions in Met-Ed's service
territory. Lower KWH sales in the residential sector were due to decreased
weather-related usage as discussed above.
123
Changes in retail
generation sales and revenues in 2009 compared to 2008 are summarized in the
following tables:
|
Retail
Generation KWH Sales
|
(Decrease)
|
|||
|
Residential
|
(2.7
|
)%
|
||
|
Commercial
|
(4.4
|
)%
|
||
|
Industrial
|
(10.4
|
)%
|
||
|
Decrease
in Retail Generation Sales
|
(5.3
|
)%
|
||
|
Retail
Generation Revenues
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(7
|
)
|
|
|
Commercial
|
(10
|
)
|
||
|
Industrial
|
(18
|
)
|
||
|
Decrease
in Retail Generation Revenues
|
$
|
(35
|
)
|
|
Transmission service
revenues decreased by $31
million
in 2009 compared to 2008 primarily due to decreased revenues related to Met-Ed's
Financial Transmission Rights. Met-Ed defers the difference between transmission
revenues and net transmission costs incurred, resulting in no material effect to
current period earnings.
Expenses
Total operating
expenses increased by $84 million in 2009 compared to 2008. The following
table presents changes from the prior year by expense category:
|
Increase
|
||||
|
Expenses
– Changes
|
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchased
power costs
|
$
|
4
|
||
|
Other
operating costs
|
(152
|
)
|
||
|
Provision for
depreciation
|
7
|
|||
|
Amortization
of regulatory assets, net
|
223
|
|||
|
General
taxes
|
2
|
|||
|
Net
increase in expenses
|
$
|
84
|
||
Purchased power
costs increased by $4 million in 2009 compared to 2008 due to an increase in
unit costs, partially offset by reduced volumes purchased as a result of lower
KWH sales requirements. Other operating costs decreased $152 million in 2009 due
primarily to lower transmission expenses as a result of decreased congestion
costs and transmission loss expenses, partially offset by higher employee
benefit expenses. Depreciation expense increased generally due to an increase in
depreciable property since the end of 2008. The net amortization of regulatory
assets increased by $223 million in 2009 resulting from increased
transmission cost recovery. In 2009, general taxes increased due to higher gross
receipts taxes resulting from increased sales revenues.
Other Expense
Other expense
increased $17 million in 2009 resulting from to an increase in interest expense
from Met-Ed’s $300 million Senior Notes issuance in January 2009. In addition,
less interest income was earned in 2009 on stranded regulatory assets,
reflecting lower regulatory asset balances.
Commodity
Price Risk
Met-Ed is exposed to
market risk primarily due to fluctuations in electricity, energy transmission
and natural gas prices. To manage the volatility relating to these exposures,
Met-Ed uses a variety of non-derivative and derivative instruments, including
forward contracts, options, futures contracts and swaps. The derivatives are
used principally for hedging purposes. The majority of Met-Ed’s derivative
contracts must be recorded at their fair value and marked to market. Certain
derivative hedging contracts qualify for the normal purchase and normal sale
exception and are therefore excluded from the table below. Contracts that are
not exempt from such treatment include power purchase agreements with NUG
entities that were structured pursuant to the Public Utility Regulatory Policies
Act of 1978. These non-trading contracts are adjusted to fair value at the end
of each quarter, with a corresponding regulatory asset recognized for
above-market costs or regulatory liability for below-market costs. The change in
the fair value of commodity derivative contracts related to energy production
during 2009 is summarized in the following table:
124
|
Increase
(Decrease) in the Fair Value of Derivative Contracts
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Change
in the Fair Value of Commodity Derivative Contracts
|
||||||||||||
|
Outstanding
net liabilities as of January 1, 2009
|
$ | 164 | $ | - | $ | 164 | ||||||
|
Additions/Changes
in value of existing contracts
|
(205 | ) | - | (205 | ) | |||||||
|
Settled
contracts
|
83 | - | 83 | |||||||||
|
Net
Assets - Derivative Contracts as of December 31, 2009
(1)
|
$ | 42 | $ | - | $ | 42 | ||||||
|
Impact
of Changes in Commodity Derivative Contracts
(2)
|
||||||||||||
|
Income
Statement Effects (Pre-Tax)
|
$ | - | $ | - | $ | - | ||||||
|
Balance Sheet
Effects:
|
||||||||||||
|
Regulatory
Liability (net)
|
$ | 122 | $ | - | $ | 122 | ||||||
|
|
(1)
|
Includes
$42 million in non-hedge commodity derivative contracts (primarily
with NUGs) that are subject to regulatory accounting and do not impact
earnings.
|
|
|
(2)
|
Represents the
change in value of existing contracts, settled contracts and changes in
techniques/assumptions.
|
Derivatives are
included on the Consolidated Balance Sheet as of December 31, 2009 as
follows:
|
Non-Hedge
|
Hedge
|
Total
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Non-Current-
|
||||||||||||
|
Other deferred
charges
|
$ | 185 | $ | - | $ | 185 | ||||||
|
Other
noncurrent liabilities
|
(143 | ) | - | (143 | ) | |||||||
|
Net
assets
|
$ | 42 | $ | - | $ | 42 | ||||||
The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, Met-Ed relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. Met-Ed uses these results to develop estimates of fair value
for financial reporting purposes and for internal management decision making.
Sources of information for the valuation of commodity derivative contracts as of
December 31, 2009 are summarized by year in the following table:
|
Source
of Information
|
||||||||||||||||||||||||||||
|
-
Fair Value by Contract Year
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
|||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
Other external
sources
(1)
|
$ | (50 | ) | $ | (42 | ) | $ | (38 | ) | $ | 2 | $ | - | $ | - | $ | (128 | ) | ||||||||||
|
Prices based
on models
|
- | - | - | - | 25 | 145 | 170 | |||||||||||||||||||||
|
Total
(2)
|
$ | (50 | ) | $ | (42 | ) | $ | (38 | ) | $ | 2 | $ | 25 | $ | 145 | $ | 42 | |||||||||||
|
|
(1)
|
Broker quote
sheets.
|
|
|
(2)
|
Includes
$42 million in non-hedge commodity derivative contracts (primarily
with NUGs) that are subject to regulatory accounting and do not impact
earnings.
|
Met-Ed performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
Met-Ed’s consolidated financial position or cash flows as of December 31,
2009. Based on derivative contracts held as of December 31, 2009, an
adverse 10% change in commodity prices would not have a material effect on
Met-Ed’s net income for the next 12 months.
Interest
Rate Risk
Met-Ed’s exposure to
fluctuations in market interest rates is reduced since a significant portion of
its debt has fixed interest rates. The table below presents principal amounts
and related weighted average interest rates by year of maturity for Met-Ed’s
investment portfolio and debt obligations.
125
|
Comparison
of Carrying Value to Fair Value
|
||||||||||||||||||||||||||||||||
|
There
|
Fair
|
|||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
||||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||||||||
|
Assets
|
||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
and Cash
Equivalents:
|
||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 120 | $ | 120 | $ | 125 | ||||||||||||||||||||||||||
|
Average
interest rate
|
2.1 | % | 2.1 | % | ||||||||||||||||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 100 | $ | 150 | $ | 250 | $ | 314 | $ | 814 | $ | 881 | ||||||||||||||||||||
|
Average
interest rate
|
4.5 | % | 5.0 | % | 4.9 | % | 7.6 | % | 5.9 | % | ||||||||||||||||||||||
|
Variable
rate
|
$ | 28 | $ | 28 | $ | 28 | ||||||||||||||||||||||||||
|
Average
interest rate
|
0.2 | % | 0.2 | % | ||||||||||||||||||||||||||||
Equity
Price Risk
Included in Met-Ed’s
nuclear decommissioning trusts are marketable equity securities carried at their
market value of approximately $140 million as if December 31, 2009. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in an
$14 million reduction in fair value as of December 31, 2009 (see Note
5).
126
PENNSYLVANIA
ELECTRIC COMPANY
MANAGEMENT’S
NARRATIVE
ANALYSIS
OF RESULTS OF OPERATIONS
Penelec is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts business in
northern and south central Pennsylvania, providing regulated transmission and
distribution services. Penelec also provides generation services to those
customers electing to retain Penelec as their power supplier. On November 3,
2009, Penelec, Met-Ed and Waverly restated their partial requirements power
purchase agreement for 2010. Under the new agreement, Penelec, Met-Ed, and
Waverly assigned 1,300 MW of existing energy purchases to FES to assist it
in supplying Buyers’ power supply requirements and managing congestion
expenses.
For additional
information with respect to Penelec, please see the information contained in
FirstEnergy's Management Discussion and Analysis of Financial Condition and
Results of Operations above under the following subheadings, which information
is incorporated by reference herein: Capital Resources and Liquidity, Guarantees
and Other Assurances and Outlook: Capital Resources and Liquidity, Guarantees
and Other Assurances, Strategy and Outlook, Regulatory Matters, Environmental
Matters, Other Legal Proceedings and New Accounting Standards and
Interpretations.
Results of
Operations
Net income decreased
to $65 million in 2009, compared to $88 million in 2008. The decrease
was primarily due lower revenues and higher purchased power costs, partially
offset by lower other operating costs and decreased amortization of regulatory
assets.
Revenues
Revenues decreased
by $65 million, or 4.3%, in 2009 compared to 2008 primarily due to lower
transmission, retail generation and distribution revenues, partially offset by
higher wholesale generation revenues.
Transmission
revenues decreased by $44 million in 2009 compared to 2008, primarily due
to lower revenues related to Penelec’s Financial Transmission Rights. Penelec
defers the difference between transmission revenues and transmission costs
incurred, resulting in no material effect to current period
earnings.
In 2009, retail
generation revenues decreased $37 million primarily due to lower KWH sales
in all customer classes. Lower KWH sales to the commercial and industrial
customer classes were primarily due to weakened economic conditions in Penelec’s
service territory. Lower KWH sales to the residential customer class were due to
decreased weather-related usage, reflecting a 28.5% decrease in cooling degree
days in 2009 compared to 2008.
Changes in retail
generation sales and revenues in 2009 as compared to 2008 are summarized in the
following tables:
|
Retail
Generation KWH Sales
|
Decrease
|
|||
|
Residential
|
(1.9
|
)%
|
||
|
Commercial
|
(3.2
|
)%
|
||
|
Industrial
|
(13.7
|
)%
|
||
|
Decrease
in Retail Generation Sales
|
(5.9
|
)%
|
||
|
Retail
Generation Revenues
|
Decrease
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
(4
|
)
|
|
|
Commercial
|
(8
|
)
|
||
|
Industrial
|
(25
|
)
|
||
|
Decrease
in Retail Generation Revenues
|
$
|
(37
|
)
|
|
Revenues from
distribution throughput decreased $7 million in 2009 compared to 2008,
primarily due to decreased deliveries to the commercial and industrial sectors
reflecting the economic conditions in Penelec’s service area. Offsetting this
decrease was an increase in residential unit prices due to an increase in
transmission rates, resulting from the annual update of Penelec’s TSC rider
effective June 1, 2009.
127
Changes in
distribution KWH deliveries and revenues in 2009 as compared to 2008 are
summarized in the following tables:
|
Distribution
KWH Deliveries
|
Decrease
|
|||
|
Residential
|
(1.9
|
)%
|
||
|
Commercial
|
(3.2
|
)%
|
||
|
Industrial
|
(12.0
|
)%
|
||
|
Decrease
in Distribution Deliveries
|
(5.6
|
)%
|
||
|
Distribution
Revenues
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Residential
|
$
|
2
|
||
|
Commercial
|
(4
|
)
|
||
|
Industrial
|
(5
|
)
|
||
|
Net
Decrease in Distribution Revenues
|
$
|
(7
|
)
|
|
Wholesale revenues
increased $19 million in 2009 compared to the same period in 2008,
primarily reflecting higher KWH sales.
Expenses
Total operating
expenses decreased by $22 million in 2009 compared to 2008. The following
table presents changes from the prior year by expense category:
|
Expenses
- Changes
|
Increase
(Decrease)
|
|||
|
(In
millions)
|
||||
|
Purchased
power costs
|
$
|
11
|
||
|
Other
operating costs
|
(19
|
)
|
||
|
Provision for
depreciation
|
7
|
|||
|
Amortization
of regulatory assets, net
|
(15
|
)
|
||
|
General
taxes
|
(6
|
)
|
||
|
Net
Decrease in expenses
|
$
|
(22
|
)
|
|
Purchased power
costs increased by $11 million in 2009 compared to 2008, primarily due to
higher unit costs, partially offset by reduced volume as a result of lower KWH
sales requirements. Other operating costs decreased by $19 million in 2009
compared to 2008, principally due to reduced transmission and labor costs,
partially offset by higher pension and OPEB expenses. Depreciation expense
increased primarily due to an increase in depreciable property since
December 31, 2008. The net amortization of regulatory assets decreased by
$15 million in 2009 compared to 2008 primarily due to increased
transmission cost deferrals as a result of increased net congestion costs.
General taxes decreased in 2009 primarily due to lower gross receipts tax as a
result of the reduced KWH sales discussed above.
|
|
Other
Expense
|
In 2009, other
expense decreased by $8 million primarily due to lower interest expense on
borrowings from the regulated money pool and the Revolving Credit Facility,
partially offset by an increase in interest expense on long-term debt due to the
$500 million debt issuance on September 30, 2009.
Market
Risk Information
Penelec uses various
market risk sensitive instruments, including derivative contracts, to manage the
risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy
Committee, comprised of members of senior management, provides general oversight
to risk management activities.
128
Commodity
Price Risk
Penelec is exposed
to market risk primarily due to fluctuations in electricity, energy transmission
and natural gas prices. To manage the volatility relating to these exposures,
Penelec uses a variety of non-derivative and derivative instruments, including
forward contracts, options, futures contracts and swaps. The derivatives are
used principally for hedging purposes. The majority of Penelec’s derivative
contracts must be recorded at their fair value and marked to market. Power
purchase agreements with NUG entities that were structured pursuant to the
Public Utility Regulatory Policies Act of 1978 are non-trading contracts and are
adjusted to fair value at the end of each quarter, with a corresponding
regulatory asset recognized for above-market costs or regulatory liability for
below-market costs. The change in the fair value of commodity derivative
contracts related to energy production during 2009 is summarized in the
following table:
|
Increase
(Decrease) in the Fair Value of Derivative Contracts
|
Non-Hedge
|
Hedge
|
Total
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Change
in the Fair Value of Commodity Derivative Contracts
|
||||||||||||
|
Outstanding
net liabilities as of January 1, 2009
|
$ | 43 | $ | - | $ | 43 | ||||||
|
Additions/Changes
in value of existing contracts
|
(223 | ) | - | (223 | ) | |||||||
|
Settled
contracts
|
99 | - | 99 | |||||||||
|
Net Assets - Derivative
Contracts as of December 31, 2009
(1)
|
$ | (81 | ) | $ | - | $ | (81 | ) | ||||
|
Impact of Changes in Commodity
Derivative Contracts
(2)
|
||||||||||||
|
Income
Statement Effects (Pre-Tax)
|
$ | - | $ | - | $ | - | ||||||
|
Balance Sheet
Effects:
|
||||||||||||
|
Regulatory
Liability (net)
|
$ | 124 | $ | - | $ | 124 | ||||||
|
|
(1)
|
Includes
$81 million in non-hedge commodity derivative contracts (primarily
with NUGs) that are subject to regulatory accounting and do not impact
earnings.
|
|
|
(2)
|
Represents the
change in value of existing contracts, settled contracts and changes in
techniques/assumptions.
|
Derivatives are
included on the Consolidated Balance Sheet as of December 31, 2009 as
follows:
|
Non-Hedge
|
Hedge
|
Total
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Non-Current-
|
||||||||||||
|
Other deferred
charges
|
$ | 20 | $ | - | $ | 20 | ||||||
|
Other
noncurrent liabilities
|
(101 | ) | - | (101 | ) | |||||||
|
Net
assets
|
$ | (81 | ) | $ | - | $ | (81 | ) | ||||
The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, Penelec relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. Penelec uses these results to develop estimates of fair value
for financial reporting purposes and for internal management decision making.
Sources of information for the valuation of commodity derivative contracts as of
December 31, 2009 are summarized by year in the following table:
|
Source
of Information
|
||||||||||||||||||||||||||||
|
-
Fair Value by Contract Year
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
|||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
Other external
sources
(1)
|
$ | (51 | ) | $ | (55 | ) | $ | (56 | ) | $ | (5 | ) | $ | - | $ | - | $ | (167 | ) | |||||||||
|
Prices based
on models
|
- | - | - | - | 13 | 73 | 86 | |||||||||||||||||||||
|
Total
(2)
|
$ | (51 | ) | $ | (55 | ) | $ | (56 | ) | $ | (5 | ) | $ | 13 | $ | 73 | $ | (81 | ) | |||||||||
|
(1)
|
Broker quote
sheet.
|
|
(2)
|
Includes $81
m
i
llion in
non-hedge commodity derivative contracts (primarily with NUGs) that are
subject to regulatory accounting and do not impact
earnings.
|
Penelec performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
Penelec’s consolidated financial position or cash flows as of December 31,
2009. Based on derivative contracts held as of December 31, 2009, an
adverse 10% change in commodity prices would not have a material effect on
Penelec’s net income for the next 12 months.
129
Interest
Rate Risk
Penelec’s exposure
to fluctuations in market interest rates is reduced since a significant portion
of its debt has fixed interest rates. The table below presents principal amounts
and related weighted average interest rates by year of maturity for Penelec’s
investment portfolio and debt obligations.
|
Comparison
of Carrying Value to Fair Value
|
||||||||||||||||||||||||||||||||
|
There-
|
Fair
|
|||||||||||||||||||||||||||||||
|
Year
of Maturity
|
2010
|
2011
|
2012
|
2013
|
2014
|
after
|
Total
|
Value
|
||||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||||||||
|
Assets
|
||||||||||||||||||||||||||||||||
|
Investments
Other Than Cash
and Cash
Equivalents:
|
||||||||||||||||||||||||||||||||
|
Fixed
Income
|
$ | 166 | $ | 166 | $ | 171 | ||||||||||||||||||||||||||
|
Average
interest rate
|
3.0 | % | 3.0 | % | ||||||||||||||||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||||||
|
Long-term
Debt:
|
||||||||||||||||||||||||||||||||
|
Fixed
rate
|
$ | 24 | $ | 150 | $ | 925 | $ | 1,099 | $ | 1,132 | ||||||||||||||||||||||
|
Average
interest rate
|
5.4 | % | 5.1 | % | 5.9 | % | 5.8 | % | ||||||||||||||||||||||||
|
Variable
rate
|
$ | 45 | $ | 45 | $ | 45 | ||||||||||||||||||||||||||
|
Average
interest rate
|
0.3 | % | 0.3 | % | ||||||||||||||||||||||||||||
|
Short-term
Borrowings:
|
$ | 41 | $ | 41 | $ | 41 | ||||||||||||||||||||||||||
|
Average
interest rate
|
0.7 | % | 0.7 | % | ||||||||||||||||||||||||||||
Equity Price Risk
Included in Penelec’s
nuclear
decommissioning trusts are marketable equity securities carried at their market
value of approximately $70 million as of December 31, 2008. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$7 million reduction in fair value as of December 31, 2008 (see
Note 5).
130
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information required by ITEM 7A
relating to market risk is set forth in ITEM 7. Management Discussion and
Analysis of Financial Condition and Results of
Operations
.
131
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of FirstEnergy Corp. (Company) were prepared by management,
who takes responsibility for their integrity and objectivity. The statements
were prepared in conformity with accounting principles generally accepted in the
United States and are consistent with other financial information appearing
elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered
public accounting firm, has expressed an unqualified opinion on the Company’s
2009 consolidated financial statements.
The Company’s
internal auditors, who are responsible to the Audit Committee of the Company’s
Board of Directors, review the results and performance of operating units within
the Company for adequacy, effectiveness and reliability of accounting and
reporting systems, as well as managerial and operating controls.
The Company’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is
responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rule 13a-15(f) of the Securities Exchange
Act of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
The
effectiveness of the Company’s internal control over financial reporting, as of
December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which
appears on page 142.
132
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of FirstEnergy Solutions Corp. (Company) were prepared by
management, who takes responsibility for their integrity and objectivity. The
statements were prepared in conformity with accounting principles generally
accepted in the United States and are consistent with other financial
information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an
independent registered public accounting firm, has expressed an unqualified
opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
133
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of Ohio Edison Company (Company) were prepared by
management, who takes responsibility for their integrity and objectivity. The
statements were prepared in conformity with accounting principles generally
accepted in the United States and are consistent with other financial
information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an
independent registered public accounting firm, has expressed an unqualified
opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
134
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of The Cleveland Electric Illuminating Company (Company)
were prepared by management, who takes responsibility for their integrity and
objectivity. The statements were prepared in conformity with accounting
principles generally accepted in the United States and are consistent with other
financial information appearing elsewhere in this report. PricewaterhouseCoopers
LLP, an independent registered public accounting firm, has expressed an
unqualified opinion on the Company’s 2009 consolidated financial
statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
135
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of The Toledo Edison Company (Company) were prepared by
management, who takes responsibility for their integrity and objectivity. The
statements were prepared in conformity with accounting principles generally
accepted in the United States and are consistent with other financial
information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an
independent registered public accounting firm, has expressed an unqualified
opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
136
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of Jersey Central Power & Light Company (Company) were
prepared by management, who takes responsibility for their integrity and
objectivity. The statements were prepared in conformity with accounting
principles generally accepted in the United States and are consistent with other
financial information appearing elsewhere in this report. PricewaterhouseCoopers
LLP, an independent registered public accounting firm, has expressed an
unqualified opinion on the Company’s 2009 consolidated financial
statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
137
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of Metropolitan Edison Company (Company) were prepared by
management, who takes responsibility for their integrity and objectivity. The
statements were prepared in conformity with accounting principles generally
accepted in the United States and are consistent with other financial
information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an
independent registered public accounting firm, has expressed an unqualified
opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
138
MANAGEMENT
REPORTS
Management's
Responsibility for Financial Statements
The consolidated
financial statements of Pennsylvania Electric Company (Company) were prepared by
management, who takes responsibility for their integrity and objectivity. The
statements were prepared in conformity with accounting principles generally
accepted in the United States and are consistent with other financial
information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an
independent registered public accounting firm, has expressed an unqualified
opinion on the Company’s 2009 consolidated financial statements.
FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of the Company for
adequacy, effectiveness and reliability of accounting and reporting systems, as
well as managerial and operating controls.
FirstEnergy’s Audit
Committee consists of four independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held nine meetings in
2009.
Management's
Report on Internal Control Over Financial Reporting
Management is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria
set forth by the Committee of Sponsoring Organizations of the Treadway
Commission in
Internal Control –
Integrated Framework
, management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting under
the supervision of the chief executive officer and the chief financial officer.
Based on that evaluation, management concluded that the Company’s internal
control over financial reporting was effective as of December 31, 2009
.
This annual report
does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial
reporting.
139
Report
of Independent Registered Public Accounting Firm
To the Stockholders
and Board of Directors of FirstEnergy Corp.:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, common stockholders' equity, and cash flows present fairly, in all
material respects, the financial position of FirstEnergy Corp. and its
subsidiaries at December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2009 in conformity with accounting principles generally
accepted in the United States of America. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2009, based on criteria established in
Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's management is
responsible for these financial statements, for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in the accompanying
Management's Report on Internal Control Over Financial Reporting. Our
responsibility is to express opinions on these financial statements and on the
Company's internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
A company’s internal
control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial
reporting includes those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
140
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of
FirstEnergy Solutions Corp.:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of FirstEnergy
Solutions Corp. and its subsidiaries at December 31, 2009 and 2008, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2009 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18,
2010
|
141
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of Ohio
Edison Company:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of Ohio Edison Company
and its subsidiaries at December 31, 2009 and 2008, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2009 in conformity with accounting principles generally
accepted in the United States of America. These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
142
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of Directors of
The Cleveland
Electric Illuminating Company:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of The Cleveland
Electric Illuminating Company and its subsidiaries at December 31, 2009 and
2008, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2009 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in
accordance with
the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
143
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of The
Toledo Edison Company:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of The Toledo Edison
Company and its subsidiary at December 31, 2009 and 2008, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2009 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
144
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of Directors of
Jersey Central Power
& Light Company:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of Jersey Central Power
& Light Company and its subsidiaries at December 31, 2009 and 2008, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2009 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
145
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of
Metropolitan Edison Company:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of Metropolitan Edison
Company and its subsidiaries at December 31, 2009 and 2008, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2009 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
146
Report
of Independent Registered Public Accounting Firm
To the Stockholder
and Board of
Directors of
Pennsylvania Electric Company:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, and cash flows present
fairly, in all material respects, the financial position of Pennsylvania
Electric Company and its subsidiaries at December 31, 2009 and 2008, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2009 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
|
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February 18,
2010
|
147
FIRSTENERGY
CORP.
CONSOLIDATED
STATEMENTS OF INCOME
|
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions, except per share amounts)
|
||||||||||||
|
REVENUES:
|
||||||||||||
|
Electric
utilities
|
$ | 11,139 | $ | 12,061 | $ | 11,305 | ||||||
|
Unregulated
businesses
|
1,828 | 1,566 | 1,497 | |||||||||
|
Total
revenues*
|
12,967 | 13,627 | 12,802 | |||||||||
|
EXPENSES:
|
||||||||||||
|
Fuel
|
1,153 | 1,340 | 1,178 | |||||||||
|
Purchased
power
|
4,730 | 4,291 | 3,836 | |||||||||
|
Other
operating expenses
|
2,697 | 3,045 | 3,083 | |||||||||
|
Provision for
depreciation
|
736 | 677 | 638 | |||||||||
|
Amortization
of regulatory assets
|
1,155 | 1,053 | 1,019 | |||||||||
|
Deferral of
regulatory assets
|
(136 | ) | (316 | ) | (524 | ) | ||||||
|
General
taxes
|
753 | 778 | 754 | |||||||||
|
Total
expenses
|
11,088 | 10,868 | 9,984 | |||||||||
|
OPERATING
INCOME
|
1,879 | 2,759 | 2,818 | |||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||
|
Investment
income, net
|
204 | 59 | 120 | |||||||||
|
Interest
expense
|
(978 | ) | (754 | ) | (775 | ) | ||||||
|
Capitalized
interest
|
130 | 52 | 32 | |||||||||
|
Total other
expense
|
(644 | ) | (643 | ) | (623 | ) | ||||||
|
INCOME
BEFORE INCOME TAXES
|
1,235 | 2,116 | 2,195 | |||||||||
|
INCOME
TAXES
|
245 | 777 | 883 | |||||||||
|
NET
INCOME
|
990 | 1,339 | 1,312 | |||||||||
|
Noncontrolling
interest income (loss)
|
(16 | ) | (3 | ) | 3 | |||||||
|
EARNINGS
AVAILABLE TO FIRSTENERGY CORP.
|
$ | 1,006 | $ | 1,342 | $ | 1,309 | ||||||
|
BASIC
EARNINGS PER SHARE OF COMMON STOCK
|
$ | 3.31 | $ | 4.41 | $ | 4.27 | ||||||
|
WEIGHTED
AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
|
304 | 304 | 306 | |||||||||
|
DILUTED
EARNINGS PER SHARE OF COMMON STOCK
|
$ | 3.29 | $ | 4.38 | $ | 4.22 | ||||||
|
WEIGHTED
AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
|
306 | 307 | 310 | |||||||||
|
* Includes
$395 million, $432 million and $425 million of excise tax collections in
2009, 2008 and 2007, respectively.
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial statements.
|
||||||||||||
148
|
FIRSTENERGY CORP.
|
||||||||
|
CONSOLIDATED BALANCE SHEETS
|
||||||||
|
As of December 31,
|
2009
|
2008 | ||||||
|
(In millions)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT ASSETS:
|
||||||||
|
Cash and cash equivalents
|
$ | 874 | $ | 545 | ||||
|
Receivables-
|
||||||||
|
Customers (less accumulated provisions of $33 million
and
|
||||||||
|
$28 million, respectively, for uncollectible
accounts)
|
1,244 | 1,304 | ||||||
|
Other (less accumulated provisions of $7 million
and
|
||||||||
|
$9 million, respectively, for uncollectible
accounts)
|
153 | 167 | ||||||
|
Materials and supplies, at average
cost
|
647 | 605 | ||||||
|
Prepaid taxes
|
248 | 283 | ||||||
|
Other
|
154 | 149 | ||||||
| 3,320 | 3,053 | |||||||
|
PROPERTY, PLANT AND EQUIPMENT:
|
||||||||
|
In service
|
27,826 | 26,482 | ||||||
|
Less - Accumulated provision for
depreciation
|
11,397 | 10,821 | ||||||
| 16,429 | 15,661 | |||||||
|
Construction work in progress
|
2,735 | 2,062 | ||||||
| 19,164 | 17,723 | |||||||
|
INVESTMENTS:
|
||||||||
|
Nuclear plant decommissioning trusts
|
1,859 | 1,708 | ||||||
|
Investments in lease obligation bonds (Note
7)
|
543 | 598 | ||||||
|
Other
|
621 | 711 | ||||||
| 3,023 | 3,017 | |||||||
|
DEFERRED CHARGES AND OTHER ASSETS:
|
||||||||
|
Goodwill
|
5,575 | 5,575 | ||||||
|
Regulatory assets
|
2,356 | 3,140 | ||||||
|
Power purchase contract asset
|
200 | 434 | ||||||
|
Other
|
666 | 579 | ||||||
| 8,797 | 9,728 | |||||||
| $ | 34,304 | $ | 33,521 | |||||
|
LIABILITIES AND CAPITALIZATION
|
||||||||
|
CURRENT LIABILITIES:
|
||||||||
|
Currently payable long-term debt
|
$ | 1,834 | $ | 2,476 | ||||
|
Short-term borrowings (Note 14)
|
1,181 | 2,397 | ||||||
|
Accounts payable
|
829 | 794 | ||||||
|
Accrued taxes
|
314 | 333 | ||||||
|
Other
|
1,130 | 1,098 | ||||||
| 5,288 | 7,098 | |||||||
|
CAPITALIZATION:
|
||||||||
|
Common stockholders’ equity-
|
||||||||
|
Common stock, $0.10 par value, authorized 375,000,000
shares-
|
||||||||
|
304,835,407 outstanding
|
31 | 31 | ||||||
|
Other paid-in capital
|
5,448 | 5,473 | ||||||
|
Accumulated other comprehensive loss
|
(1,415 | ) | (1,380 | ) | ||||
|
Retained earnings
|
4,495 | 4,159 | ||||||
|
Total common stockholders' equity
|
8,559 | 8,283 | ||||||
|
Noncontrolling interest
|
(2 | ) | 32 | |||||
|
Total equity
|
8,557 | 8,315 | ||||||
|
Long-
term debt
and other long-term obligations
(Note 12(C))
|
11,908 | 9,100 | ||||||
| 20,465 | 17,415 | |||||||
|
NONCURRENT LIABILITIES:
|
||||||||
|
Accumulated deferred income taxes
|
2,468 | 2,163 | ||||||
|
Asset retirement obligations
|
1,425 | 1,335 | ||||||
|
Deferred gain on sale and leaseback
transaction
|
993 | 1,027 | ||||||
|
Power purchase contract liability
|
643 | 766 | ||||||
|
Retirement benefits
|
1,534 | 1,884 | ||||||
|
Lease market valuation liability
|
262 | 308 | ||||||
|
Other
|
1,226 | 1,525 | ||||||
| 8,551 | 9,008 | |||||||
|
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 7
and 15)
|
||||||||
| $ | 34,304 | $ | 33,521 | |||||
|
The accompanying Combined Notes to the Consolidated
Financial Statements are an integral part of these
|
||||||||
|
financial statements.
|
||||||||
149
FIRSTENERGY
CORP.
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
|
Accumulated
|
Unallocated
|
|||||||||||||||||||||||||||
|
Common
Stock
|
Other
|
Other
|
ESOP
|
|||||||||||||||||||||||||
|
Comprehensive
Income
|
Number
of Shares
|
Par
Value
|
Paid-In
Capital
|
Comprehensive
Income (Loss)
|
Retained
Earnings
|
Common
Stock
|
||||||||||||||||||||||
|
(Dollars
in millions)
|
||||||||||||||||||||||||||||
|
Balance,
January 1, 2007
|
319,205,517 | $ | 32 | $ | 6,466 | $ | (259 | ) | $ | 2,806 | $ | (10 | ) | |||||||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 1,309 | 1,309 | |||||||||||||||||||||||||
|
Unrealized
loss on derivative hedges, net
|
||||||||||||||||||||||||||||
|
of $8 million
of income tax benefits
|
(17 | ) | (17 | ) | ||||||||||||||||||||||||
|
Unrealized
gain on investments, net of
|
||||||||||||||||||||||||||||
|
$31 million of
income taxes
|
47 | 47 | ||||||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||||||
|
of $169
million of income taxes (Note 3)
|
179 | 179 | ||||||||||||||||||||||||||
|
Comprehensive
income
|
$ | 1,518 | ||||||||||||||||||||||||||
|
Stock options
exercised
|
(40 | ) | ||||||||||||||||||||||||||
|
Allocation of
ESOP shares
|
26 | 10 | ||||||||||||||||||||||||||
|
Restricted
stock units
|
23 | |||||||||||||||||||||||||||
|
Stock-based
compensation
|
2 | |||||||||||||||||||||||||||
|
Accounting for
uncertainty in income taxes
|
||||||||||||||||||||||||||||
|
cumulative
effect adjustment
|
(3 | ) | ||||||||||||||||||||||||||
|
Repurchase of
common stock
|
(14,370,110 | ) | (1 | ) | (968 | ) | ||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(625 | ) | ||||||||||||||||||||||||||
|
Balance,
December 31, 2007
|
304,835,407 | 31 | 5,509 | (50 | ) | 3,487 | - | |||||||||||||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 1,342 | 1,342 | |||||||||||||||||||||||||
|
Unrealized
loss on derivative hedges, net
|
||||||||||||||||||||||||||||
|
of $16 million
of income tax benefits
|
(28 | ) | (28 | ) | ||||||||||||||||||||||||
|
Change in
unrealized gain on investments, net of
|
||||||||||||||||||||||||||||
|
$86 million of
income tax benefits
|
(146 | ) | (146 | ) | ||||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||||||
|
of $697
million of income tax benefits (Note 3)
|
(1,156 | ) | (1,156 | ) | ||||||||||||||||||||||||
|
Comprehensive
income
|
$ | 12 | ||||||||||||||||||||||||||
|
Stock options
exercised
|
(36 | ) | ||||||||||||||||||||||||||
|
Restricted
stock units
|
(1 | ) | ||||||||||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(670 | ) | ||||||||||||||||||||||||||
|
Balance,
December 31, 2008
|
304,835,407 | 31 | 5,473 | (1,380 | ) | 4,159 | - | |||||||||||||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 1,006 | 1,006 | |||||||||||||||||||||||||
|
Unrealized
gain on derivative hedges, net
|
||||||||||||||||||||||||||||
|
of $24 million
of income taxes
|
27 | 27 | ||||||||||||||||||||||||||
|
Change in
unrealized gain on investments, net of
|
||||||||||||||||||||||||||||
|
$31 million of
income tax benefits
|
(43 | ) | (43 | ) | ||||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||||||
|
of $34 million
of income taxes (Note 3)
|
(19 | ) | (19 | ) | ||||||||||||||||||||||||
|
Comprehensive
income
|
$ | 971 | ||||||||||||||||||||||||||
|
Stock options
exercised
|
(3 | ) | ||||||||||||||||||||||||||
|
Restricted
stock units
|
7 | |||||||||||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||||||||||
|
Acquisition
adjustment of non-controlling
|
||||||||||||||||||||||||||||
|
interest (Note
8)
|
(30 | ) | ||||||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(670 | ) | ||||||||||||||||||||||||||
|
Balance,
December 31, 2009
|
304,835,407 | $ | 31 | $ | 5,448 | $ | (1,415 | ) | $ | 4,495 | $ | - | ||||||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
||||||||||||||||||||||||||||
150
FIRSTENERGY
CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 990 | $ | 1,339 | $ | 1,312 | ||||||
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
736 | 677 | 638 | |||||||||
|
Amortization
of regulatory assets
|
1,155 | 1,053 | 1,019 | |||||||||
|
Deferral of
regulatory assets
|
(136 | ) | (316 | ) | (524 | ) | ||||||
|
Nuclear fuel
and lease amortization
|
128 | 112 | 101 | |||||||||
|
Deferred
purchased power and other costs
|
(338 | ) | (226 | ) | (350 | ) | ||||||
|
Deferred
income taxes and investment tax credits, net
|
384 | 366 | (9 | ) | ||||||||
|
Investment
impairment
|
62 | 123 | 26 | |||||||||
|
Deferred rents
and lease market valuation liability
|
(52 | ) | (95 | ) | (99 | ) | ||||||
|
Stock based
compensation
|
20 | (64 | ) | (39 | ) | |||||||
|
Accrued
compensation and retirement benefits
|
22 | (140 | ) | (37 | ) | |||||||
|
Gain on asset
sales
|
(27 | ) | (72 | ) | (30 | ) | ||||||
|
Electric
service prepayment programs
|
(10 | ) | (77 | ) | (75 | ) | ||||||
|
Cash
collateral, net
|
30 | (31 | ) | (68 | ) | |||||||
|
Gain on sales
of investment securities held in trusts, net
|
(176 | ) | (63 | ) | (10 | ) | ||||||
|
Loss on debt
redemption
|
146 | - | - | |||||||||
|
Commodity
derivative transactions, net (Note 6)
|
229 | 5 | 6 | |||||||||
|
Pension trust
contributions
|
(500 | ) | - | (300 | ) | |||||||
|
Uncertain tax
positions
|
(210 | ) | (5 | ) | 19 | |||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
75 | (29 | ) | (136 | ) | |||||||
|
Materials and
supplies
|
(11 | ) | (52 | ) | 79 | |||||||
|
Prepayments
and other current assets
|
(19 | ) | (263 | ) | 10 | |||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
50 | 10 | 51 | |||||||||
|
Accrued
taxes
|
(103 | ) | (39 | ) | 48 | |||||||
|
Accrued
interest
|
67 | 4 | (8 | ) | ||||||||
|
Other
|
(47 | ) | 7 | 75 | ||||||||
|
Net cash
provided from operating activities
|
2,465 | 2,224 | 1,699 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
4,632 | 1,367 | 1,520 | |||||||||
|
Short-term
borrowings, net
|
- | 1,494 | - | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Common
stock
|
- | - | (969 | ) | ||||||||
|
Long-term
debt
|
(2,610 | ) | (1,034 | ) | (1,070 | ) | ||||||
|
Short-term
borrowings, net
|
(1,246 | ) | - | (205 | ) | |||||||
|
Common stock
dividend payments
|
(670 | ) | (671 | ) | (616 | ) | ||||||
|
Other
|
(57 | ) | 19 | (7 | ) | |||||||
|
Net cash
provided from (used for) financing activities
|
49 | 1,175 | (1,347 | ) | ||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(2,203 | ) | (2,888 | ) | (1,633 | ) | ||||||
|
Proceeds from
asset sales
|
21 | 72 | 42 | |||||||||
|
Proceeds from
sale and leaseback transaction
|
- | - | 1,329 | |||||||||
|
Sales of
investment securities held in trusts
|
2,229 | 1,656 | 1,294 | |||||||||
|
Purchases of
investment securities held in trusts
|
(2,306 | ) | (1,749 | ) | (1,397 | ) | ||||||
|
Cash
investments (Note 5)
|
60 | 60 | 72 | |||||||||
|
Other
|
14 | (134 | ) | (20 | ) | |||||||
|
Net cash used
for investing activities
|
(2,185 | ) | (2,983 | ) | (313 | ) | ||||||
|
Net increase
in cash and cash equivalents
|
329 | 416 | 39 | |||||||||
|
Cash and cash
equivalents at beginning of year
|
545 | 129 | 90 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 874 | $ | 545 | $ | 129 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 718 | $ | 667 | $ | 744 | ||||||
|
Income
taxes
|
$ | 173 | $ | 685 | $ | 710 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
151
FIRSTENERGY
SOLUTIONS CORP.
CONSOLIDATED
STATEMENTS OF INCOME
|
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
REVENUES:
|
||||||||||||
|
Electric sales
to affiliates (Note 18)
|
$ | 2,825,959 | $ | 2,968,323 | $ | 2,901,154 | ||||||
|
Electric sales
to non-affiliates
|
1,447,482 | 1,332,364 | 1,315,141 | |||||||||
|
Other
|
454,896 | 217,666 | 108,732 | |||||||||
|
Total
revenues
|
4,728,337 | 4,518,353 | 4,325,027 | |||||||||
|
EXPENSES:
|
||||||||||||
|
Fuel
|
1,127,463 | 1,315,293 | 1,087,010 | |||||||||
|
Purchased
power from affiliates (Note 18)
|
222,406 | 101,409 | 234,090 | |||||||||
|
Purchased
power from non-affiliates
|
996,383 | 778,882 | 764,090 | |||||||||
|
Other
operating expenses
|
1,183,225 | 1,084,548 | 1,041,039 | |||||||||
|
Provision for
depreciation
|
259,393 | 231,899 | 192,912 | |||||||||
|
General
taxes
|
86,915 | 88,004 | 87,098 | |||||||||
|
Total
expenses
|
3,875,785 | 3,600,035 | 3,406,239 | |||||||||
|
OPERATING
INCOME
|
852,552 | 918,318 | 918,788 | |||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||
|
Investment
income (loss)
|
125,226 | (22,678 | ) | 41,438 | ||||||||
|
Miscellaneous
income
|
6,670 | 1,698 | 11,438 | |||||||||
|
Interest
expense to affiliates (Note 18)
|
(10,106 | ) | (29,829 | ) | (65,501 | ) | ||||||
|
Interest
expense - other
|
(142,120 | ) | (111,682 | ) | (92,199 | ) | ||||||
|
Capitalized
interest
|
60,152 | 43,764 | 19,508 | |||||||||
|
Total other
income (expense)
|
39,822 | (118,727 | ) | (85,316 | ) | |||||||
|
INCOME
BEFORE INCOME TAXES
|
892,374 | 799,591 | 833,472 | |||||||||
|
INCOME
TAXES
|
315,290 | 293,181 | 304,608 | |||||||||
|
NET
INCOME
|
$ | 577,084 | $ | 506,410 | $ | 528,864 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
152
FIRSTENERGY
SOLUTIONS CORP.
CONSOLIDATED
BALANCE SHEETS
|
As
of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 12 | $ | 39 | ||||
|
Receivables-
|
||||||||
|
Customers
(less accumulated provisions of $12,041,000 and
$5,899,000,
|
||||||||
|
respectively,
for uncollectible accounts)
|
195,107 | 86,123 | ||||||
|
Associated
companies
|
318,561 | 378,100 | ||||||
|
Other (less
accumulated provisions of $6,702,000 and $6,815,000
|
||||||||
|
respectively,
for uncollectible accounts)
|
51,872 | 24,626 | ||||||
|
Notes
receivable from associated companies
|
805,103 | 129,175 | ||||||
|
Materials and
supplies, at average cost
|
539,541 | 521,761 | ||||||
|
Prepayments
and other
|
107,782 | 112,535 | ||||||
| 2,017,978 | 1,252,359 | |||||||
|
PROPERTY,
PLANT AND EQUIPMENT:
|
||||||||
|
In
service
|
10,357,632 | 9,871,904 | ||||||
|
Less -
Accumulated provision for depreciation
|
4,531,158 | 4,254,721 | ||||||
| 5,826,474 | 5,617,183 | |||||||
|
Construction
work in progress
|
2,423,446 | 1,747,435 | ||||||
| 8,249,920 | 7,364,618 | |||||||
|
INVESTMENTS:
|
||||||||
|
Nuclear plant
decommissioning trusts
|
1,088,641 | 1,033,717 | ||||||
|
Long-term
notes receivable from associated companies
|
- | 62,900 | ||||||
|
Other
|
22,466 | 61,591 | ||||||
| 1,111,107 | 1,158,208 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Accumulated
deferred income tax benefits
|
86,626 | 267,762 | ||||||
|
Lease
assignment receivable from associated companies
|
- | 71,356 | ||||||
|
Goodwill
|
24,248 | 24,248 | ||||||
|
Property
taxes
|
50,125 | 50,104 | ||||||
|
Unamortized
sale and leaseback costs
|
72,553 | 69,932 | ||||||
|
Other
|
138,231 | 96,434 | ||||||
| 371,783 | 579,836 | |||||||
| $ | 11,750,788 | $ | 10,355,021 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 1,550,927 | $ | 2,024,898 | ||||
|
Short-term
borrowings-
|
||||||||
|
Associated
companies
|
9,237 | 264,823 | ||||||
|
Other
|
100,000 | 1,000,000 | ||||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
466,078 | 472,338 | ||||||
|
Other
|
245,363 | 154,593 | ||||||
|
Accrued
taxes
|
83,158 | 79,766 | ||||||
|
Other
|
359,057 | 248,439 | ||||||
| 2,813,820 | 4,244,857 | |||||||
|
CAPITALIZATION
(See Consolidated Statements of Capitalization):
|
||||||||
|
Common
stockholder's equity
|
3,514,571 | 2,944,423 | ||||||
|
Long-term debt
and other long-term obligations
|
2,711,652 | 571,448 | ||||||
| 6,226,223 | 3,515,871 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Deferred gain
on sale and leaseback transaction
|
992,869 | 1,026,584 | ||||||
|
Accumulated
deferred investment tax credits
|
58,396 | 62,728 | ||||||
|
Asset
retirement obligations
|
921,448 | 863,085 | ||||||
|
Retirement
benefits
|
204,035 | 194,177 | ||||||
|
Property
taxes
|
50,125 | 50,104 | ||||||
|
Lease market
valuation liability
|
262,200 | 307,705 | ||||||
|
Other
|
221,672 | 89,910 | ||||||
| 2,710,745 | 2,594,293 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 & 15)
|
||||||||
| $ | 11,750,788 | $ | 10,355,021 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
153
|
FIRSTENERGY
SOLUTIONS CORP.
|
|||||||||
|
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
|||||||||
|
As
of December 31,
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
|||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
|||||||||
|
Common stock,
without par value, authorized 750 shares,
|
|||||||||
|
7 shares
outstanding
|
$ | 1,468,423 | $ | 1,464,229 | |||||
|
Accumulated
other comprehensive loss (Note 2(F))
|
(103,001 | ) | (91,871 | ) | |||||
|
Retained
earnings (Note 12(A))
|
2,149,149 | 1,572,065 | |||||||
|
Total
|
3,514,571 | 2,944,423 | |||||||
|
LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):
|
|||||||||
|
Secured
notes:
|
|||||||||
| FirstEnergy Solutions Corp. | |||||||||
|
5.150% due
2009-2015
|
21,950 | 22,868 | |||||||
|
FirstEnergy
Generation Corp.
|
|||||||||
|
5.700% due
2014
|
50,000 | - | |||||||
| * |
0.220% due
2017
|
28,525 | 28,525 | ||||||
| ** |
5.625% due
2018
|
141,260 | 141,260 | ||||||
| * |
0.230% due
2019
|
90,140 | 90,140 | ||||||
| * |
5.250% due
2023
|
50,000 | - | ||||||
| ** |
4.750% due
2029
|
100,000 | 100,000 | ||||||
| ** |
4.750% due
2029
|
6,450 | 6,450 | ||||||
| * |
0.220% due
2041
|
56,600 | 56,600 | ||||||
| 522,975 | 422,975 | ||||||||
|
FirstEnergy Nuclear Generation Corp.
|
|||||||||
|
8.830% due
2009-2016
|
4,514 | 5,007 | |||||||
|
8.890% due
2009-2016
|
77,445 | 82,680 | |||||||
|
9.000% due
2009-2017
|
206,453 | 234,635 | |||||||
|
9.120% due
2009-2016
|
61,455 | 68,311 | |||||||
|
12.000% due
2009-2017
|
1,072 | 1,174 | |||||||
| * |
0.330% due
2033
|
46,500 | 46,500 | ||||||
| * |
0.320% due
2033
|
54,600 | 54,600 | ||||||
| * |
0.350% due
2033
|
26,000 | 26,000 | ||||||
| * |
0.280% due
2033
|
99,100 | 99,100 | ||||||
| * |
0.280% due
2033
|
8,000 | 8,000 | ||||||
| ** |
5.750% due
2033
|
62,500 | 62,500 | ||||||
| ** |
5.875% due
2033
|
107,500 | 107,500 | ||||||
| * |
0.220% due
2034
|
7,200 | 7,200 | ||||||
| * |
0.230% due
2034
|
82,800 | 82,800 | ||||||
| * |
0.220% due
2035
|
72,650 | 72,650 | ||||||
| * |
0.270% due
2035
|
98,900 | 98,900 | ||||||
| * |
0.230% due
2035
|
60,000 | 60,000 | ||||||
| 1,076,689 | 1,117,557 | ||||||||
|
Total secured
notes
|
1,621,614 | 1,563,400 | |||||||
|
Unsecured
notes:
|
|||||||||
|
FirstEnergy
Solutions Corp.
|
|||||||||
|
4.800% due
2015
|
400,000 | - | |||||||
|
6.050% due
2021
|
600,000 | - | |||||||
|
6.800% due
2039
|
500,000 | - | |||||||
| 1,500,000 | - | ||||||||
|
FirstEnergy
Generation Corp.
|
|||||||||
| ** |
3.000% due
2018
|
2,805 | 2,805 | ||||||
| ** |
3.000% due
2018
|
2,985 | 2,985 | ||||||
|
5.700% due
2020
|
177,000 | - | |||||||
| * |
0.400% due
2023
|
234,520 | 234,520 | ||||||
| * |
4.350% due
2028
|
15,000 | 15,000 | ||||||
| * |
7.125% due
2028
|
25,000 | 25,000 | ||||||
| * |
0.280% due
2040
|
43,000 | 43,000 | ||||||
| * |
0.230% due
2041
|
129,610 | 129,610 | ||||||
| * |
0.280% due
2041
|
26,000 | 26,000 | ||||||
| ** |
3.000% due
2047
|
46,300 | 46,300 | ||||||
| 702,220 | 525,220 | ||||||||
|
FirstEnergy
Nuclear Generation Corp.
|
|||||||||
|
5.390% due to
associated companies 2025
|
- | 62,900 | |||||||
| * |
7.250% due
2032
|
23,000 | 23,000 | ||||||
| * |
7.250% due
2032
|
33,000 | 33,000 | ||||||
| * |
0.210% due
2033
|
135,550 | 135,550 | ||||||
| * |
0.240% due
2033
|
15,500 | 15,500 | ||||||
| ** |
3.000% due
2033
|
20,450 | 20,450 | ||||||
| ** |
3.000% due
2033
|
9,100 | 9,100 | ||||||
| ** |
0.220% due
2035
|
163,965 | 163,965 | ||||||
| 400,565 | 463,465 | ||||||||
|
Total
unsecured notes
|
2,602,785 | 988,685 | |||||||
|
Capital lease
obligations (Note 7)
|
40,110 | 44,319 | |||||||
|
Net
unamortized discount on debt
|
(1,930 | ) | (58 | ) | |||||
|
Long-term debt
due within one year
|
(1,550,927 | ) | (2,024,898 | ) | |||||
|
Total
long-term debt and other long-term obligations
|
2,711,652 | 571,448 | |||||||
|
TOTAL
CAPITALIZATION
|
$ | 6,226,223 | $ | 3,515,871 | |||||
|
* Denotes
variable rate issue with applicable year-end interest rate
shown.
** Denotes
remarketed notes in 2009.
|
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
154
FIRSTENERGY
SOLUTIONS CORP.
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
|
Accumulated
|
||||||||||||||||||||
|
Common
Stock
|
Other
|
|||||||||||||||||||
|
Comprehensive
|
Number
|
Carrying
|
Comprehensive
|
Retained
|
||||||||||||||||
|
Income
|
of
Shares
|
Value
|
Income
(Loss)
|
Earnings
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||||||
|
Balance,
January 1, 2007
|
8 | 1,050,302 | 111,723 | 697,338 | ||||||||||||||||
|
Net
income
|
$ | 528,864 | 528,864 | |||||||||||||||||
|
Net unrealized
loss on derivative instruments, net
|
||||||||||||||||||||
|
of $3,337,000
of income tax benefits
|
(5,640 | ) | (5,640 | ) | ||||||||||||||||
|
Unrealized
gain on investments, net of
|
||||||||||||||||||||
|
$26,645,000 of
income taxes
|
41,707 | 41,707 | ||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $604,000 of
income taxes (Note 3)
|
(7,136 | ) | (7,136 | ) | ||||||||||||||||
|
Comprehensive
income
|
$ | 557,795 | ||||||||||||||||||
|
Repurchase of
common stock
|
(1 | ) | (600,000 | ) | ||||||||||||||||
|
Equity
contribution from parent
|
700,000 | |||||||||||||||||||
|
Stock options
exercised, restricted stock units
|
||||||||||||||||||||
|
and other
adjustments
|
4,141 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
10,479 | |||||||||||||||||||
|
Accounting for
uncertainty in income taxes
|
||||||||||||||||||||
|
cumulative
effect adjustment
|
(547 | ) | ||||||||||||||||||
|
Cash dividends
declared on common stock
|
(117,000 | ) | ||||||||||||||||||
|
Balance,
December 31, 2007
|
7 | 1,164,922 | 140,654 | 1,108,655 | ||||||||||||||||
|
Net
income
|
$ | 506,410 | 506,410 | |||||||||||||||||
|
Net unrealized
loss on derivative instruments, net
|
||||||||||||||||||||
|
of $5,512,000
of income tax benefits
|
(9,200 | ) | (9,200 | ) | ||||||||||||||||
|
Change in
unrealized gain on investments, net of
|
||||||||||||||||||||
|
$82,014,000 of
income tax benefits
|
(137,689 | ) | (137,689 | ) | ||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $47,853,000
of income tax benefits (Note 3)
|
(85,636 | ) | (85,636 | ) | ||||||||||||||||
|
Comprehensive
income
|
$ | 273,885 | ||||||||||||||||||
|
Equity
contribution from parent
|
280,000 | |||||||||||||||||||
|
Stock options
exercised, restricted stock units
|
||||||||||||||||||||
|
and other
adjustments
|
13,262 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
6,045 | |||||||||||||||||||
|
Cash dividends
declared on common stock
|
(43,000 | ) | ||||||||||||||||||
|
Balance,
December 31, 2008
|
7 | 1,464,229 | (91,871 | ) | 1,572,065 | |||||||||||||||
|
Net
income
|
$ | 577,084 | 577,084 | |||||||||||||||||
|
Net unrealized
gain on derivative instruments, net
|
||||||||||||||||||||
|
of $6,766,000
of income taxes
|
11,329 | 11,329 | ||||||||||||||||||
|
Change in
unrealized gain on investments, net of
|
||||||||||||||||||||
|
$20,937,000 of
income tax benefits
|
(28,306 | ) | (28,306 | ) | ||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $8,472,000
of income taxes (Note 3)
|
5,847 | 5,847 | ||||||||||||||||||
|
Comprehensive
income
|
$ | 565,954 | ||||||||||||||||||
|
Restricted
stock units
|
866 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
3,328 | - | ||||||||||||||||||
|
Balance, December 31, 2009
|
7 | $ | 1,468,423 | $ | (103,001 | ) | $ | 2,149,149 | ||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
155
|
FIRSTENERGY
SOLUTIONS CORP.
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
||||||||||||
|
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
Income
|
$ | 577,084 | $ | 506,410 | $ | 528,864 | ||||||
|
Adjustments to
reconcile net income to net cash from
|
||||||||||||
|
operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
259,393 | 231,899 | 192,912 | |||||||||
|
Nuclear fuel
and lease amortization
|
130,486 | 111,978 | 100,720 | |||||||||
|
Deferred rents
and lease market valuation liability
|
(46,384 | ) | (43,263 | ) | 69 | |||||||
|
Deferred
income taxes and investment tax credits, net
|
219,962 | 116,626 | (334,545 | ) | ||||||||
|
Investment
impairment (Note 2(E))
|
57,073 | 115,207 | 22,817 | |||||||||
|
Accrued
compensation and retirement benefits
|
6,162 | 16,011 | 6,419 | |||||||||
|
Commodity
derivative transactions, net (Note 6)
|
228,705 | 5,100 | 5,930 | |||||||||
|
Gain on asset
sales
|
(10,649 | ) | (38,858 | ) | (12,105 | ) | ||||||
|
Gain on sales
of investment securities held in trusts, net
|
(158,112 | ) | (53,290 | ) | (9,883 | ) | ||||||
|
Cash
collateral, net
|
20,208 | (60,621 | ) | (31,059 | ) | |||||||
|
Pension trust
contributions
|
- | - | (64,020 | ) | ||||||||
|
Associated
company lease assignment
|
71,356 | - | - | |||||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
(34,429 | ) | 59,782 | (99,048 | ) | |||||||
|
Materials and
supplies
|
12,513 | (59,983 | ) | 56,407 | ||||||||
|
Prepayments
and other current assets
|
(26,046 | ) | (12,302 | ) | (13,812 | ) | ||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
67,855 | 34,467 | (104,599 | ) | ||||||||
|
Accrued
taxes
|
6,059 | (90,568 | ) | 61,119 | ||||||||
|
Accrued
interest
|
46,441 | 1,398 | 1,143 | |||||||||
|
Other
|
(53,388 | ) | 12,935 | (13,012 | ) | |||||||
|
Net cash
provided from operating activities
|
1,374,289 | 852,928 | 294,317 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
2,438,402 | 618,375 | 427,210 | |||||||||
|
Equity
contributions from parent
|
- | 280,000 | 700,000 | |||||||||
|
Short-term
borrowings, net
|
- | 700,759 | - | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Common
stock
|
- | - | (600,000 | ) | ||||||||
|
Long-term
debt
|
(709,156 | ) | (462,540 | ) | (1,536,411 | ) | ||||||
|
Short-term
borrowings, net
|
(1,155,586 | ) | - | (458,321 | ) | |||||||
|
Common stock
dividend payments
|
- | (43,000 | ) | (117,000 | ) | |||||||
|
Other
|
(21,790 | ) | (5,147 | ) | (5,199 | ) | ||||||
|
Net cash
provided from (used for) financing activities
|
551,870 | 1,088,447 | (1,589,721 | ) | ||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(1,222,933 | ) | (1,835,629 | ) | (738,709 | ) | ||||||
|
Proceeds from
asset sales
|
18,371 | 23,077 | 12,990 | |||||||||
|
Proceeds from
sale and leaseback transaction
|
- | - | 1,328,919 | |||||||||
|
Sales of
investment securities held in trusts
|
1,379,154 | 950,688 | 655,541 | |||||||||
|
Purchases of
investment securities held in trusts
|
(1,405,996 | ) | (987,304 | ) | (697,763 | ) | ||||||
|
Loan
repayments from (loans to) associated companies
|
(675,928 | ) | (36,391 | ) | 734,862 | |||||||
|
Other
|
(18,854 | ) | (55,779 | ) | (436 | ) | ||||||
|
Net cash
provided from (used for) investing activities
|
(1,926,186 | ) | (1,941,338 | ) | 1,295,404 | |||||||
|
Net change in
cash and cash equivalents
|
(27 | ) | 37 | - | ||||||||
|
Cash and cash
equivalents at beginning of year
|
39 | 2 | 2 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 12 | $ | 39 | $ | 2 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 38,446 | $ | 92,103 | $ | 136,121 | ||||||
|
Income
taxes
|
$ | 96,045 | $ | 196,963 | $ | 613,814 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
156
OHIO
EDISON COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In thousands)
|
||||||||||||
|
REVENUES
(Note 18):
|
||||||||||||
|
Electric
sales
|
$ | 2,418,292 | $ | 2,487,956 | $ | 2,375,306 | ||||||
|
Excise and
gross receipts tax collections
|
98,630 | 113,805 | 116,223 | |||||||||
|
Total
revenues
|
2,516,922 | 2,601,761 | 2,491,529 | |||||||||
|
EXPENSES
(Note 18):
|
||||||||||||
|
Purchased
power from affiliates
|
991,405 | 1,203,314 | 1,261,439 | |||||||||
|
Purchased
power from non-affiliates
|
481,406 | 114,972 | 98,344 | |||||||||
|
Other
operating costs
|
461,142 | 565,893 | 567,726 | |||||||||
|
Provision for
depreciation
|
89,289 | 79,444 | 77,405 | |||||||||
|
Amortization
of regulatory assets, net
|
93,694 | 117,733 | 14,252 | |||||||||
|
General
taxes
|
171,082 | 186,396 | 181,104 | |||||||||
|
Total
expenses
|
2,288,018 | 2,267,752 | 2,200,270 | |||||||||
|
OPERATING
INCOME
|
228,904 | 334,009 | 291,259 | |||||||||
|
OTHER
INCOME (EXPENSE) (Note 18):
|
||||||||||||
|
Investment
income
|
46,887 | 56,103 | 85,848 | |||||||||
|
Miscellaneous
income (expense)
|
2,654 | (4,525 | ) | 5,073 | ||||||||
|
Interest
expense
|
(90,669 | ) | (75,058 | ) | (83,343 | ) | ||||||
|
Capitalized
interest
|
844 | 414 | 266 | |||||||||
|
Total other
income (expense)
|
(40,284 | ) | (23,066 | ) | 7,844 | |||||||
|
INCOME
BEFORE INCOME TAXES
|
188,620 | 310,943 | 299,103 | |||||||||
|
INCOME
TAXES
|
66,186 | 98,584 | 101,273 | |||||||||
|
NET
INCOME
|
122,434 | 212,359 | 197,830 | |||||||||
|
Noncontrolling
interest income
|
567 | 613 | 664 | |||||||||
|
EARNINGS
AVAILABLE TO PARENT
|
$ | 121,867 | $ | 211,746 | $ | 197,166 | ||||||
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. |
157
|
OHIO
EDISON COMPANY
|
||||||||
|
CONSOLIDATED
BALANCE SHEETS
|
||||||||
|
As
of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 324,175 | $ | 146,343 | ||||
|
Receivables-
|
||||||||
|
Customers
(less accumulated provisions of $5,119,000 and $6,065,000,
respectively,
|
||||||||
|
for
uncollectible accounts)
|
209,384 | 277,377 | ||||||
|
Associated
companies
|
98,874 | 234,960 | ||||||
|
Other (less
accumulated provisions of $18,000 and $7,000,
respectively,
|
||||||||
|
for
uncollectible accounts)
|
14,155 | 14,492 | ||||||
|
Notes
receivable from associated companies
|
118,651 | 222,861 | ||||||
|
Prepayments
and other
|
15,964 | 5,452 | ||||||
| 781,203 | 901,485 | |||||||
|
UTILITY
PLANT:
|
||||||||
|
In
service
|
3,036,467 | 2,903,290 | ||||||
|
Less -
Accumulated provision for depreciation
|
1,165,394 | 1,113,357 | ||||||
| 1,871,073 | 1,789,933 | |||||||
|
Construction
work in progress
|
31,171 | 37,766 | ||||||
| 1,902,244 | 1,827,699 | |||||||
|
OTHER
PROPERTY AND INVESTMENTS:
|
||||||||
|
Long-term
notes receivable from associated companies
|
- | 256,974 | ||||||
|
Investment in
lease obligation bonds (Note 7)
|
216,600 | 239,625 | ||||||
|
Nuclear plant
decommissioning trusts
|
120,812 | 116,682 | ||||||
|
Other
|
96,861 | 100,792 | ||||||
| 434,273 | 714,073 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Regulatory
assets
|
465,331 | 575,076 | ||||||
|
Pension assets
(Note 3)
|
19,881 | - | ||||||
|
Property
taxes
|
67,037 | 60,542 | ||||||
|
Unamortized
sale and leaseback costs
|
35,127 | 40,130 | ||||||
|
Other
|
39,881 | 33,710 | ||||||
| 627,257 | 709,458 | |||||||
| $ | 3,744,977 | $ | 4,152,715 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 2,723 | $ | 101,354 | ||||
|
Short-term
borrowings-
|
||||||||
|
Associated
companies
|
92,863 | - | ||||||
|
Other
|
807 | 1,540 | ||||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
102,763 | 131,725 | ||||||
|
Other
|
40,423 | 26,410 | ||||||
|
Accrued
taxes
|
81,868 | 77,592 | ||||||
|
Accrued
interest
|
25,749 | 25,673 | ||||||
|
Other
|
81,424 | 85,209 | ||||||
| 428,620 | 449,503 | |||||||
|
CAPITALIZATION
(See
Consolidated Statements of Capitalization):
|
||||||||
|
Common
stockholder's equity
|
1,021,110 | 1,294,054 | ||||||
|
Noncontrolling
interest
|
6,442 | 7,106 | ||||||
|
Total
equity
|
1,027,552 | 1,301,160 | ||||||
|
Long-term debt
and other long-term obligations
|
1,160,208 | 1,122,247 | ||||||
| 2,187,760 | 2,423,407 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Accumulated
deferred income taxes
|
660,114 | 653,475 | ||||||
|
Accumulated
deferred investment tax credits
|
11,406 | 13,065 | ||||||
|
Asset
retirement obligations
|
85,926 | 80,647 | ||||||
|
Retirement
benefits
|
174,925 | 308,450 | ||||||
|
Other
|
196,226 | 224,168 | ||||||
| 1,128,597 | 1,279,805 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 and 15)
|
||||||||
| $ | 3,744,977 | $ | 4,152,715 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
158
|
OHIO
EDISON COMPANY
|
||||||||
|
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
||||||||
|
As
of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
||||||||
|
Common stock,
without par value, 175,000,000 shares authorized,
|
||||||||
|
60 shares
outstanding
|
$ | 1,154,797 | $ | 1,224,416 | ||||
|
Accumulated
other comprehensive loss (Note 2(F))
|
(163,577 | ) | (184,385 | ) | ||||
|
Retained
earnings (Note 12(A))
|
29,890 | 254,023 | ||||||
|
Total
|
1,021,110 | 1,294,054 | ||||||
|
NONCONTROLLING
INTEREST
|
6,442 | 7,106 | ||||||
|
LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):
|
||||||||
|
Ohio
Edison Company-
|
||||||||
|
First
mortgage bonds:
|
||||||||
|
8.250% due
2018
|
25,000 | 25,000 | ||||||
|
8.250% due
2038
|
275,000 | 275,000 | ||||||
|
Total
|
300,000 | 300,000 | ||||||
|
Secured
notes:
|
||||||||
|
7.156%
weighted average interest rate due 2009-2010
|
1,257 | 1,324 | ||||||
|
Total
|
1,257 | 1,324 | ||||||
|
Unsecured
notes:
|
||||||||
|
* 3.000%
due 2014
|
- | 50,000 | ||||||
|
5.450% due 2015
|
150,000 | 150,000 | ||||||
|
6.400% due 2016
|
250,000 | 250,000 | ||||||
|
* 1.500%
due 2023
|
- | 50,000 | ||||||
|
6.875% due 2036
|
350,000 | 350,000 | ||||||
|
Total
|
750,000 | 850,000 | ||||||
|
Pennsylvania
Power Company-
|
||||||||
|
First
mortgage bonds:
|
||||||||
|
9.740% due
2009-2019
|
9,773 | 10,747 | ||||||
|
6.090% due
2022
|
100,000 | - | ||||||
|
7.625% due
2023
|
6,500 | 6,500 | ||||||
|
Total
|
116,273 | 17,247 | ||||||
|
Secured
notes
:
|
||||||||
|
5.400% due
2013
|
1,000 | 1,000 | ||||||
|
Total
|
1,000 | 1,000 | ||||||
|
Unsecured
notes:
|
||||||||
|
5.390% due
2010 to associated company
|
- | 62,900 | ||||||
|
Total
|
- | 62,900 | ||||||
|
Capital lease
obligations (Note 7)
|
6,884 | 4,219 | ||||||
|
Net
unamortized discount on debt
|
(12,483 | ) | (13,089 | ) | ||||
|
Long-term debt
due within one year
|
(2,723 | ) | (101,354 | ) | ||||
|
Total
long-term debt and other long-term obligations
|
1,160,208 | 1,122,247 | ||||||
|
TOTAL
CAPITALIZATION
|
$ | 2,187,760 | $ | 2,423,407 | ||||
|
* Denotes
variable rate issue with applicable year-end interest rate
shown.
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
159
|
OHIO EDISON COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S
EQUITY
|
||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||
|
Common Stock
|
Other
|
|||||||||||||||||||
|
Comprehensive
|
Number
|
Carrying
|
Comprehensive
|
Retained
|
||||||||||||||||
|
Income
|
of Shares
|
Value
|
Income (Loss)
|
Earnings
|
||||||||||||||||
|
(Dollars in thousands)
|
||||||||||||||||||||
|
Balance, January 1, 2007
|
80 | $ | 1,708,441 | $ | 3,208 | $ | 260,736 | |||||||||||||
|
Earnings available to parent
|
$ | 197,166 | 197,166 | |||||||||||||||||
|
Unrealized gain on investments, net
of
|
||||||||||||||||||||
|
$2,784,000 of income taxes
|
3,874 | 3,874 | ||||||||||||||||||
|
Pension and other postretirement benefits,
net
|
||||||||||||||||||||
|
of $37,820,000 of income taxes (Note
3)
|
41,304 | 41,304 | ||||||||||||||||||
|
Comprehensive income available to
parent
|
$ | 242,344 | ||||||||||||||||||
|
Restricted stock units
|
129 | |||||||||||||||||||
|
Stock-based compensation
|
17 | |||||||||||||||||||
|
Repurchase of common stock
|
(20 | ) | (500,000 | ) | ||||||||||||||||
|
Consolidated tax benefit allocation
|
11,925 | |||||||||||||||||||
|
Accounting for uncertainty in income
taxes
|
||||||||||||||||||||
|
cumulative effect adjustment
|
(625 | ) | ||||||||||||||||||
|
Cash dividends declared on common
stock
|
(150,000 | ) | ||||||||||||||||||
|
Balance, December 31, 2007
|
60 | 1,220,512 | 48,386 | 307,277 | ||||||||||||||||
|
Earnings available to parent
|
$ | 211,746 | 211,746 | |||||||||||||||||
|
Change in unrealized gain on investments, net
of
|
||||||||||||||||||||
|
$5,702,000 of income tax benefits
|
(10,370 | ) | (10,370 | ) | ||||||||||||||||
|
Pension and other postretirement benefits,
net
|
||||||||||||||||||||
|
of $121,425,000 of income tax benefits (Note
3)
|
(222,401 | ) | (222,401 | ) | ||||||||||||||||
|
Comprehensive loss
|
$ | (21,025 | ) | |||||||||||||||||
|
Restricted stock units
|
(16 | ) | ||||||||||||||||||
|
Stock-based compensation
|
1 | |||||||||||||||||||
|
Consolidated tax benefit allocation
|
3,919 | |||||||||||||||||||
|
Cash dividends declared on common
stock
|
(265,000 | ) | ||||||||||||||||||
|
Balance, December 31, 2008
|
60 | 1,224,416 | (184,385 | ) | 254,023 | |||||||||||||||
|
Earnings available to parent
|
$ | 121,867 | 121,867 | |||||||||||||||||
|
Change in unrealized gain on investments, net
of
|
||||||||||||||||||||
|
$4,196,000 of income tax benefits
|
(5,497 | ) | (5,497 | ) | ||||||||||||||||
|
Pension and other
postretirement benefits, net
|
||||||||||||||||||||
|
of $20,257,000 of income taxes (Note
3)
|
26,305 | 26,305 | ||||||||||||||||||
|
Comprehensive income available to
parent
|
$ | 142,675 | ||||||||||||||||||
|
Restricted stock units
|
81 | |||||||||||||||||||
|
Consolidated tax benefit allocation
|
4,300 | |||||||||||||||||||
|
Cash dividends declared on common
stock
|
(346,000 | ) | ||||||||||||||||||
|
Cash dividends declared as return of
capital
|
(74,000 | ) | ||||||||||||||||||
|
Balance, December 31, 2009
|
60 | $ | 1,154,797 | $ | (163,577 | ) | $ | 29,890 | ||||||||||||
|
The accompanying Combined Notes to the Consolidated
Financial Statements are an integral part of these financial
statements.
|
||||||||||||||||||||
160
|
OHIO
EDISON COMPANY
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
||||||||||||
|
For
the Years Ended December 31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 122,434 | $ | 212,359 | $ | 197,830 | ||||||
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
89,289 | 79,444 | 77,405 | |||||||||
|
Amortization
of regulatory assets, net
|
93,694 | 117,733 | 14,252 | |||||||||
|
Purchased
power cost recovery reconciliation
|
4,113 | - | - | |||||||||
|
Amortization
of lease costs
|
(8,211 | ) | (7,702 | ) | (7,425 | ) | ||||||
|
Deferred
income taxes and investment tax credits, net
|
41,178 | 16,125 | 423 | |||||||||
|
Accrued
compensation and retirement benefits
|
(13,729 | ) | 17,139 | (46,313 | ) | |||||||
|
Accrued
regulatory obligations
|
18,635 | - | - | |||||||||
|
Electric
service prepayment programs
|
(4,634 | ) | (42,215 | ) | (39,861 | ) | ||||||
|
Cash
collateral from suppliers
|
6,469 | - | - | |||||||||
|
Pension trust
contributions
|
(103,035 | ) | - | (20,261 | ) | |||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
139,679 | (61,926 | ) | (57,461 | ) | |||||||
|
Prepayments
and other current assets
|
(10,407 | ) | 5,937 | 3,265 | ||||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
(14,949 | ) | 14,166 | 15,649 | ||||||||
|
Accrued
taxes
|
(9,142 | ) | (8,983 | ) | (81,079 | ) | ||||||
|
Accrued
interest
|
76 | 3,295 | (2,334 | ) | ||||||||
|
Other
|
4,811 | 143 | 7,229 | |||||||||
|
Net cash
provided from operating activities
|
356,271 | 345,515 | 61,319 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
100,000 | 292,169 | - | |||||||||
|
Short-term
borrowings, net
|
92,130 | - | - | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Common
stock
|
- | - | (500,000 | ) | ||||||||
|
Long-term
debt
|
(101,680 | ) | (249,897 | ) | (112,497 | ) | ||||||
|
Short-term
borrowings, net
|
- | (51,761 | ) | (114,475 | ) | |||||||
|
Dividend
Payments-
|
||||||||||||
|
Common
stock
|
(420,000 | ) | (315,000 | ) | (100,000 | ) | ||||||
|
Other
|
(2,839 | ) | (4,435 | ) | (1,764 | ) | ||||||
|
Net cash used
for financing activities
|
(332,389 | ) | (328,924 | ) | (828,736 | ) | ||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(152,817 | ) | (182,512 | ) | (145,311 | ) | ||||||
|
Sales of
investment securities held in trusts
|
131,478 | 120,744 | 37,736 | |||||||||
|
Purchases of
investment securities held in trusts
|
(138,925 | ) | (127,680 | ) | (43,758 | ) | ||||||
|
Loan
repayments from (loans to) associated companies, net
|
102,314 | 373,138 | (79,115 | ) | ||||||||
|
Collection of
principal on long-term notes receivable
|
195,970 | 1,756 | 960,327 | |||||||||
|
Cash
investments
|
20,133 | (57,792 | ) | 37,499 | ||||||||
|
Other
|
(4,203 | ) | 1,366 | 59 | ||||||||
|
Net cash
provided from investing activities
|
153,950 | 129,020 | 767,437 | |||||||||
|
Net increase
(decrease) in cash and cash equivalents
|
177,832 | 145,611 | 20 | |||||||||
|
Cash and cash
equivalents at beginning of year
|
146,343 | 732 | 712 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 324,175 | $ | 146,343 | $ | 732 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 86,523 | $ | 67,508 | $ | 80,958 | ||||||
|
Income
taxes
|
$ | 20,530 | $ | 118,834 | $ | 133,170 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
161
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
||||||||||||
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
||||||||||||
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
REVENUES
(Note 18):
|
||||||||||||
|
Electric
sales
|
$ | 1,609,946 | $ | 1,746,309 | $ | 1,753,385 | ||||||
|
Excise tax
collections
|
66,192 | 69,578 | 69,465 | |||||||||
|
Total
revenues
|
1,676,138 | 1,815,887 | 1,822,850 | |||||||||
|
EXPENSES
(Note 18):
|
||||||||||||
|
Purchased
power from affiliates
|
734,592 | 766,270 | 738,709 | |||||||||
|
Purchased
power from non-affiliates
|
245,809 | 4,210 | 9,505 | |||||||||
|
Other
operating costs
|
161,407 | 259,438 | 350,825 | |||||||||
|
Provision for
depreciation
|
71,908 | 72,383 | 75,238 | |||||||||
|
Amortization
of regulatory assets
|
370,967 | 163,534 | 144,370 | |||||||||
|
Deferral of
new regulatory assets
|
(134,587 | ) | (107,571 | ) | (149,556 | ) | ||||||
|
General
taxes
|
145,324 | 143,058 | 141,551 | |||||||||
|
Total
expenses
|
1,595,420 | 1,301,322 | 1,310,642 | |||||||||
|
OPERATING
INCOME
|
80,718 | 514,565 | 512,208 | |||||||||
|
OTHER
INCOME (EXPENSE) (Note 18):
|
||||||||||||
|
Investment
income
|
31,194 | 34,392 | 57,724 | |||||||||
|
Miscellaneous
income (expense)
|
3,911 | (495 | ) | 9,773 | ||||||||
|
Interest
expense
|
(137,171 | ) | (125,976 | ) | (138,977 | ) | ||||||
|
Capitalized
interest
|
173 | 786 | 918 | |||||||||
|
Total other
expense
|
(101,893 | ) | (91,293 | ) | (70,562 | ) | ||||||
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
(21,175 | ) | 423,272 | 441,646 | ||||||||
|
INCOME
TAX EXPENSE (BENEFIT)
|
(10,183 | ) | 136,786 | 163,363 | ||||||||
|
NET
INCOME (LOSS)
|
(10,992 | ) | 286,486 | 278,283 | ||||||||
|
Noncontrolling
interest income
|
1,714 | 1,960 | 1,871 | |||||||||
|
EARNINGS
(LOSS) APPLICABLE TO PARENT
|
$ | (12,706 | ) | $ | 284,526 | $ | 276,412 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
162
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
||||||||
|
CONSOLIDATED
BALANCE SHEETS
|
||||||||
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 86,230 | $ | 226 | ||||
|
Receivables-
|
||||||||
|
Customers
(less accumulated provisions of $5,239,000 and
|
||||||||
|
$5,916,000,
respectively, for uncollectible accounts)
|
209,335 | 276,400 | ||||||
|
Associated
companies
|
98,954 | 113,182 | ||||||
|
Other
|
11,661 | 13,834 | ||||||
|
Notes
receivable from associated companies
|
26,802 | 19,060 | ||||||
|
Prepayments
and other
|
9,973 | 2,787 | ||||||
| 442,955 | 425,489 | |||||||
|
UTILITY
PLANT:
|
||||||||
|
In
service
|
2,310,074 | 2,221,660 | ||||||
|
Less -
Accumulated provision for depreciation
|
888,169 | 846,233 | ||||||
| 1,421,905 | 1,375,427 | |||||||
|
Construction
work in progress
|
36,907 | 40,651 | ||||||
| 1,458,812 | 1,416,078 | |||||||
|
OTHER
PROPERTY AND INVESTMENTS:
|
||||||||
|
Investment in
lessor notes (Note 7)
|
388,641 | 425,715 | ||||||
|
Other
|
10,220 | 10,249 | ||||||
| 398,861 | 435,964 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Goodwill
|
1,688,521 | 1,688,521 | ||||||
|
Regulatory
assets
|
545,505 | 783,964 | ||||||
|
Pension assets
(Note 3)
|
13,380 | - | ||||||
|
Property
taxes
|
77,319 | 71,500 | ||||||
|
Other
|
12,777 | 10,818 | ||||||
| 2,337,502 | 2,554,803 | |||||||
| $ | 4,638,130 | $ | 4,832,334 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 117 | $ | 150,688 | ||||
|
Short-term
borrowings-
|
||||||||
|
Associated
companies
|
339,728 | 227,949 | ||||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
68,634 | 106,074 | ||||||
|
Other
|
17,166 | 7,195 | ||||||
|
Accrued
taxes
|
90,511 | 87,810 | ||||||
|
Accrued
interest
|
18,466 | 13,932 | ||||||
|
Other
|
45,440 | 40,095 | ||||||
| 580,062 | 633,743 | |||||||
|
CAPITALIZATION
(See
Consolidated Statements of Capitalization):
|
||||||||
|
Common
stockholder's equity
|
1,343,987 | 1,603,882 | ||||||
|
Noncontrolling
interest
|
20,592 | 22,555 | ||||||
|
Total
equity
|
1,364,579 | 1,626,437 | ||||||
|
Long-term debt
and other long-term obligations
|
1,872,750 | 1,591,586 | ||||||
| 3,237,329 | 3,218,023 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Accumulated
deferred income taxes
|
644,745 | 704,270 | ||||||
|
Accumulated
deferred investment tax credits
|
11,836 | 13,030 | ||||||
|
Retirement
benefits
|
69,733 | 128,738 | ||||||
|
Deferred
revenues - electric service programs
|
- | 3,510 | ||||||
|
Lease
assignment payable to associated companies (Note 7)
|
- | 40,827 | ||||||
|
Other
|
94,425 | 90,193 | ||||||
| 820,739 | 980,568 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 and 15)
|
||||||||
| $ | 4,638,130 | $ | 4,832,334 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
163
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
||||||||
|
Common stock,
without par value, 105,000,000 shares authorized,
|
||||||||
|
67,930,743
shares outstanding
|
$ | 884,897 | $ | 878,785 | ||||
|
Accumulated
other comprehensive loss (Note 2(F))
|
(138,158 | ) | (134,857 | ) | ||||
|
Retained
earnings (Note 12(A))
|
597,248 | 859,954 | ||||||
|
Total
|
1,343,987 | 1,603,882 | ||||||
|
NONCONTROLLING
INTEREST
|
20,592 | 22,555 | ||||||
|
LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):
|
||||||||
|
First mortgage
bonds-
|
||||||||
|
8.875% due
2018
|
300,000 | 300,000 | ||||||
|
5.500% due
2024
|
300,000 | - | ||||||
|
Total
|
600,000 | 300,000 | ||||||
|
Secured
notes-
|
||||||||
|
7.430% due
2009
|
- | 150,000 | ||||||
|
7.880% due
2017
|
300,000 | 300,000 | ||||||
|
Total
|
300,000 | 450,000 | ||||||
|
Unsecured
notes-
|
||||||||
|
5.650% due
2013
|
300,000 | 300,000 | ||||||
|
5.700% due
2017
|
250,000 | 250,000 | ||||||
|
5.950% due
2036
|
300,000 | 300,000 | ||||||
|
7.664% due to
associated companies 2009-2016 (Note 8)
|
123,008 | 141,210 | ||||||
|
Total
|
973,008 | 991,210 | ||||||
|
Capital lease
obligations (Note 7)
|
3,162 | 3,062 | ||||||
|
Net
unamortized discount on debt
|
(3,303 | ) | (1,998 | ) | ||||
|
Long-term debt
due within one year
|
(117 | ) | (150,688 | ) | ||||
|
Total
long-term debt and other long-term obligations
|
1,872,750 | 1,591,586 | ||||||
|
TOTAL
CAPITALIZATION
|
$ | 3,237,329 | $ | 3,218,023 | ||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
164
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
|
||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||
|
Common Stock
|
Other
|
|||||||||||||||||||
|
Comprehensive
|
Number
|
Carrying
|
Comprehensive
|
Retained
|
||||||||||||||||
|
Income
|
of Shares
|
Value
|
Income (Loss)
|
Earnings
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||||||
|
Balance,
January 1, 2007
|
67,930,743 | $ | 860,133 | $ | (104,431 | ) | $ | 713,201 | ||||||||||||
|
Earnings
available to parent
|
$ | 276,412 | 276,412 | |||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $30,705,000
of income taxes (Note 3)
|
35,302 | 35,302 | ||||||||||||||||||
|
Comprehensive
income
|
$ | 311,714 | ||||||||||||||||||
|
Restricted
stock units
|
184 | |||||||||||||||||||
|
Stock-based
compensation
|
10 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
13,209 | |||||||||||||||||||
|
Accounting for
uncertainty in income taxes
|
||||||||||||||||||||
|
cumulative
effect adjustment
|
(185 | ) | ||||||||||||||||||
|
Cash dividends declared on common
stock
|
(304,000 | ) | ||||||||||||||||||
|
Balance,
December 31, 2007
|
67,930,743 | 873,536 | (69,129 | ) | 685,428 | |||||||||||||||
|
Earnings
available to parent
|
$ | 284,526 | 284,526 | |||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $33,136,000
of income tax benefits (Note 3)
|
(65,728 | ) | (65,728 | ) | ||||||||||||||||
|
Comprehensive
income
|
$ | 218,798 | ||||||||||||||||||
|
Restricted
stock units
|
(1 | ) | ||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
5,249 | |||||||||||||||||||
|
Cash dividends
declared on common stock
|
(110,000 | ) | ||||||||||||||||||
|
Balance,
December 31, 2008
|
67,930,743 | 878,785 | (134,857 | ) | 859,954 | |||||||||||||||
|
Loss
applicable to parent
|
$ | (12,706 | ) | (12,706 | ) | |||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $1,923,000
of income tax benefits (Note 3)
|
(3,301 | ) | (3,301 | ) | ||||||||||||||||
|
Comprehensive
loss
|
$ | (16,007 | ) | |||||||||||||||||
|
Restricted
stock units
|
74 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
6,038 | |||||||||||||||||||
|
Cash dividends
declared on common stock
|
(250,000 | ) | ||||||||||||||||||
|
Balance, December 31, 2009
|
67,930,743 | $ | 884,897 | $ | (138,158 | ) | $ | 597,248 | ||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
165
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net income
(loss)
|
$ | (10,992 | ) | $ | 286,486 | $ | 278,283 | |||||
|
Adjustments to
reconcile net income (loss) to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
71,908 | 72,383 | 75,238 | |||||||||
|
Amortization
of regulatory assets
|
370,967 | 163,534 | 144,370 | |||||||||
|
Deferral of
new regulatory assets
|
(134,587 | ) | (107,571 | ) | (149,556 | ) | ||||||
|
Deferred rents
and lease market valuation liability
|
- | - | (357,679 | ) | ||||||||
|
Purchased
power cost recovery reconciliation
|
(5,086 | ) | - | - | ||||||||
|
Deferred
income taxes and investment tax credits, net
|
(51,839 | ) | 11,918 | (22,767 | ) | |||||||
|
Accrued
compensation and retirement benefits
|
8,514 | 1,563 | 3,196 | |||||||||
|
Electric
service prepayment programs
|
(3,510 | ) | (23,634 | ) | (24,443 | ) | ||||||
|
Pension trust
contributions
|
(89,789 | ) | - | (24,800 | ) | |||||||
|
Accrued
regulatory obligations
|
12,556 | - | - | |||||||||
|
Cash
collateral from suppliers
|
5,440 | - | - | |||||||||
|
Lease
assignment payments to associated company
|
(40,827 | ) | - | - | ||||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
65,603 | 66,963 | 209,426 | |||||||||
|
Prepayments
and other current assets
|
(7,186 | ) | (450 | ) | (152 | ) | ||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
(3,479 | ) | 13,787 | (316,638 | ) | |||||||
|
Accrued
taxes
|
2,533 | (3,149 | ) | (33,659 | ) | |||||||
|
Accrued
interest
|
4,534 | 37 | (5,138 | ) | ||||||||
|
Other
|
12,116 | 8,202 | 2,438 | |||||||||
|
Net cash
provided from (used for) operating activities
|
206,876 | 490,069 | (221,881 | ) | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
298,398 | 300,000 | 249,602 | |||||||||
|
Short-term
borrowings, net
|
93,577 | - | 277,581 | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Long-term
debt
|
(151,273 | ) | (213,319 | ) | (492,825 | ) | ||||||
|
Short-term
borrowings, net
|
- | (315,827 | ) | - | ||||||||
|
Dividend
Payments-
|
||||||||||||
|
Common
stock
|
(275,000 | ) | (185,000 | ) | (204,000 | ) | ||||||
|
Other
|
(6,427 | ) | (6,440 | ) | (6,312 | ) | ||||||
|
Net cash used
for financing activities
|
(40,725 | ) | (420,586 | ) | (175,954 | ) | ||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(103,243 | ) | (137,265 | ) | (149,131 | ) | ||||||
|
Loan
repayments from (loans to) associated companies, net
|
(7,741 | ) | 33,246 | 6,714 | ||||||||
|
Collection of
principal on long-term notes receivable
|
- | - | 486,634 | |||||||||
|
Investments in
lessor notes
|
37,074 | 37,707 | 56,179 | |||||||||
|
Other
|
(6,237 | ) | (3,177 | ) | (2,550 | ) | ||||||
|
Net cash
provided from (used for) investing activities
|
(80,147 | ) | (69,489 | ) | 397,846 | |||||||
|
Net increase
(decrease) in cash and cash equivalents
|
86,004 | (6 | ) | 11 | ||||||||
|
Cash and cash
equivalents at beginning of year
|
226 | 232 | 221 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 86,230 | $ | 226 | $ | 232 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 130,689 | $ | 122,834 | $ | 141,390 | ||||||
|
Income
taxes
|
$ | 29,358 | $ | 153,042 | $ | 186,874 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
166
THE
TOLEDO EDISON COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
REVENUES
(Note 18):
|
||||||||||||
|
Electric
sales
|
$ | 810,069 | $ | 865,016 | $ | 934,772 | ||||||
|
Excise tax
collections
|
23,839 | 30,489 | 29,173 | |||||||||
|
Total
revenues
|
833,908 | 895,505 | 963,945 | |||||||||
|
EXPENSES
(Note 18):
|
||||||||||||
|
Purchased
power from affiliates
|
392,825 | 410,885 | 392,430 | |||||||||
|
Purchased
power from non-affiliates
|
136,210 | 2,459 | 5,993 | |||||||||
|
Other
operating costs
|
142,203 | 190,441 | 279,047 | |||||||||
|
Provision for
depreciation
|
30,727 | 32,422 | 36,743 | |||||||||
|
Amortization
of regulatory assets, net
|
37,820 | 94,104 | 41,684 | |||||||||
|
General
taxes
|
47,815 | 52,324 | 50,640 | |||||||||
|
Total
expenses
|
787,600 | 782,635 | 806,537 | |||||||||
|
OPERATING
INCOME
|
46,308 | 112,870 | 157,408 | |||||||||
|
OTHER
INCOME (EXPENSE) (Note 18):
|
||||||||||||
|
Investment
income
|
24,388 | 22,823 | 27,713 | |||||||||
|
Miscellaneous
expense
|
(2,436 | ) | (7,820 | ) | (6,648 | ) | ||||||
|
Interest
expense
|
(36,512 | ) | (23,286 | ) | (34,135 | ) | ||||||
|
Capitalized
interest
|
169 | 164 | 640 | |||||||||
|
Total other
expense
|
(14,391 | ) | (8,119 | ) | (12,430 | ) | ||||||
|
INCOME
BEFORE INCOME TAXES
|
31,917 | 104,751 | 144,978 | |||||||||
|
INCOME
TAXES
|
7,939 | 29,824 | 53,736 | |||||||||
|
NET
INCOME
|
23,978 | 74,927 | 91,242 | |||||||||
|
Noncontrolling
interest income
|
21 | 12 | 3 | |||||||||
|
EARNINGS
AVAILABLE TO PARENT
|
$ | 23,957 | $ | 74,915 | $ | 91,239 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
167
THE
TOLEDO EDISON COMPANY
CONSOLIDATED
BALANCE SHEETS
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 436,712 | $ | 14 | ||||
|
Receivables-
|
||||||||
|
Customers
|
75 | 751 | ||||||
|
Associated
companies
|
90,191 | 61,854 | ||||||
|
Other (less
accumulated provisions of $208,000 and $203,000,
|
||||||||
|
respectively,
for uncollectible accounts)
|
20,180 | 23,336 | ||||||
|
Notes
receivable from associated companies
|
85,101 | 111,579 | ||||||
|
Prepayments
and other
|
7,111 | 1,213 | ||||||
| 639,370 | 198,747 | |||||||
|
UTILITY
PLANT:
|
||||||||
|
In
service
|
912,930 | 870,911 | ||||||
|
Less -
Accumulated provision for depreciation
|
427,376 | 407,859 | ||||||
| 485,554 | 463,052 | |||||||
|
Construction
work in progress
|
9,069 | 9,007 | ||||||
| 494,623 | 472,059 | |||||||
|
OTHER
PROPERTY AND INVESTMENTS:
|
||||||||
|
Investment in
lessor notes (Note 7)
|
124,357 | 142,687 | ||||||
|
Long-term
notes receivable from associated companies
|
- | 37,233 | ||||||
|
Nuclear plant
decommissioning trusts
|
73,935 | 73,500 | ||||||
|
Other
|
1,580 | 1,668 | ||||||
| 199,872 | 255,088 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Goodwill
|
500,576 | 500,576 | ||||||
|
Regulatory
assets
|
69,557 | 109,364 | ||||||
|
Property
taxes
|
23,658 | 22,970 | ||||||
|
Other
|
55,622 | 51,315 | ||||||
| 649,413 | 684,225 | |||||||
| $ | 1,983,278 | $ | 1,610,119 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 222 | $ | 34 | ||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
78,341 | 70,455 | ||||||
|
Other
|
8,312 | 4,812 | ||||||
|
Notes payable
to associated companies
|
225,975 | 111,242 | ||||||
|
Accrued
taxes
|
25,734 | 24,433 | ||||||
|
Lease market
valuation liability
|
36,900 | 36,900 | ||||||
|
Other
|
29,273 | 22,489 | ||||||
| 404,757 | 270,365 | |||||||
|
CAPITALIZATION
(See
Statements of Capitalization)
:
|
||||||||
|
Common
stockholder's equity
|
489,878 | 480,050 | ||||||
|
Noncontrolling
interest
|
2,696 | 2,675 | ||||||
|
Total
equity
|
492,574 | 482,725 | ||||||
|
Long-term debt
and other long-term obligations
|
600,443 | 299,626 | ||||||
| 1,093,017 | 782,351 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Accumulated
deferred income taxes
|
80,508 | 78,905 | ||||||
|
Accumulated
deferred investment tax credits
|
6,367 | 6,804 | ||||||
|
Lease market
valuation liability (Note 7)
|
236,200 | 273,100 | ||||||
|
Retirement
benefits
|
65,988 | 73,106 | ||||||
|
Asset
retirement obligations
|
32,290 | 30,213 | ||||||
|
Lease
assignment payable to associated companies
|
- | 30,529 | ||||||
|
Other
|
64,151 | 64,746 | ||||||
| 485,504 | 557,403 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 and 15)
|
||||||||
| $ | 1,983,278 | $ | 1,610,119 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
168
THE
TOLEDO EDISON COMPANY
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
||||||||
|
Common stock,
$5 par value, 60,000,000 shares authorized,
|
||||||||
|
29,402,054
shares outstanding
|
$ | 147,010 | $ | 147,010 | ||||
|
Other paid-in
capital
|
178,181 | 175,879 | ||||||
|
Accumulated
other comprehensive loss (Note 2(F))
|
(49,803 | ) | (33,372 | ) | ||||
|
Retained
earnings (Note 12(A))
|
214,490 | 190,533 | ||||||
|
Total
|
489,878 | 480,050 | ||||||
|
NONCONTROLLING
INTEREST
|
2,696 | 2,675 | ||||||
|
LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 12(C)):
|
||||||||
|
Secured
notes-
|
||||||||
|
7.25% due
2020
|
300,000 | - | ||||||
|
6.150% due
2037
|
300,000 | 300,000 | ||||||
|
Total
|
600,000 | 300,000 | ||||||
|
Capital lease
obligations (Note 7)
|
3,492 | 80 | ||||||
|
Net
unamortized discount on debt
|
(2,827 | ) | (420 | ) | ||||
|
Long-term debt
due within one year
|
(222 | ) | (34 | ) | ||||
|
Total
long-term debt and other long-term obligations
|
600,443 | 299,626 | ||||||
|
TOTAL
CAPITALIZATION
|
$ | 1,093,017 | $ | 782,351 | ||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
169
THE
TOLEDO EDISON COMPANY
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
|
Accumulated
|
||||||||||||||||||||||||
|
Common Stock
|
Other
|
Other
|
||||||||||||||||||||||
|
Comprehensive
|
Number
|
Par
|
Paid-In
|
Comprehensive
|
Retained
|
|||||||||||||||||||
|
Income
|
of Shares
|
Value
|
Capital
|
Income (Loss)
|
Earnings
|
|||||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||||||||||
|
Balance,
January 1, 2007
|
29,402,054 | $ | 147,010 | $ | 166,786 | $ | (36,804 | ) | $ | 204,423 | ||||||||||||||
|
Earnings
available to parent
|
$ | 91,239 | 91,239 | |||||||||||||||||||||
|
Unrealized
gain on investments, net
|
||||||||||||||||||||||||
|
of $1,089,000
of income taxes
|
1,901 | 1,901 | ||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $15,077,000
of income taxes (Note 3)
|
24,297 | 24,297 | ||||||||||||||||||||||
|
Comprehensive
income available to parent
|
$ | 117,437 | ||||||||||||||||||||||
|
Restricted
stock units
|
53 | |||||||||||||||||||||||
|
Stock-based
compensation
|
2 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
6,328 | |||||||||||||||||||||||
|
Accounting for
uncertainty in income taxes
|
||||||||||||||||||||||||
|
cumulative
effect adjustment
|
(44 | ) | ||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(120,000 | ) | ||||||||||||||||||||||
|
Balance,
December 31, 2007
|
29,402,054 | 147,010 | 173,169 | (10,606 | ) | 175,618 | ||||||||||||||||||
|
Earnings
available to parent
|
$ | 74,915 | 74,915 | |||||||||||||||||||||
|
Unrealized
gain on investments, net
|
||||||||||||||||||||||||
|
of $1,421,000
of income taxes
|
2,372 | 2,372 | ||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $11,630,000
of income tax benefits (Note 3)
|
(25,138 | ) | (25,138 | ) | ||||||||||||||||||||
|
Comprehensive
income available to parent
|
$ | 52,149 | ||||||||||||||||||||||
|
Restricted
stock units
|
47 | |||||||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
2,662 | |||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(60,000 | ) | ||||||||||||||||||||||
|
Balance,
December 31, 2008
|
29,402,054 | 147,010 | 175,879 | (33,372 | ) | 190,533 | ||||||||||||||||||
|
Earnings
available to parent
|
$ | 23,957 | 23,957 | |||||||||||||||||||||
|
Unrealized
gain on investments, net
|
||||||||||||||||||||||||
|
of $5,756,000
of income tax benefits
|
(9,425 | ) | (9,425 | ) | ||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $874,000 of
income tax benefits (Note 3)
|
(7,006 | ) | (7,006 | ) | ||||||||||||||||||||
|
Comprehensive
income available to parent
|
$ | 7,526 | ||||||||||||||||||||||
|
Restricted
stock units
|
71 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
2,231 | |||||||||||||||||||||||
|
Balance, December 31, 2009
|
29,402,054 | $ | 147,010 | $ | 178,181 | $ | (49,803 | ) | $ | 214,490 | ||||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
170
THE
TOLEDO EDISON COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 23,978 | $ | 74,927 | $ | 91,242 | ||||||
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
30,727 | 32,422 | 36,743 | |||||||||
|
Amortization
of regulatory assets, net
|
37,820 | 94,104 | 41,684 | |||||||||
|
Purchased
power cost recovery reconciliation
|
1,544 | - | - | |||||||||
|
Deferred rents
and lease market valuation liability
|
(37,839 | ) | (37,938 | ) | 265,981 | |||||||
|
Deferred
income taxes and investment tax credits, net
|
2,003 | (16,869 | ) | (26,318 | ) | |||||||
|
Accrued
compensation and retirement benefits
|
3,489 | 1,483 | 5,276 | |||||||||
|
Accrued
regulatory obligations
|
4,630 | - | - | |||||||||
|
Electric
service prepayment programs
|
(1,458 | ) | (11,181 | ) | (10,907 | ) | ||||||
|
Pension trust
contribution
|
(21,590 | ) | - | (7,659 | ) | |||||||
|
Cash
collateral from suppliers
|
2,794 | - | - | |||||||||
|
Lease
assignment payment to associated company
|
(30,529 | ) | - | - | ||||||||
|
Gain on sales
of investment securities held in trusts
|
(7,130 | ) | (626 | ) | (111 | ) | ||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
(18,872 | ) | 20,186 | (64,489 | ) | |||||||
|
Prepayments
and other current assets
|
(5,898 | ) | (348 | ) | (13 | ) | ||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
35,192 | (164,397 | ) | 8,722 | ||||||||
|
Accrued
taxes
|
(1,932 | ) | (5,812 | ) | (14,954 | ) | ||||||
|
Accrued
interest
|
3,625 | (17 | ) | (1,350 | ) | |||||||
|
Other
|
374 | (2,675 | ) | 5,296 | ||||||||
|
Net cash
provided from (used for) operating activities
|
20,928 | (16,741 | ) | 329,143 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
297,422 | - | - | |||||||||
|
Short-term
borrowings, net
|
114,733 | 97,846 | - | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Long-term
debt
|
(347 | ) | (3,860 | ) | (85,797 | ) | ||||||
|
Short-term
borrowings, net
|
- | - | (153,567 | ) | ||||||||
|
Dividend
Payments-
|
||||||||||||
|
Common
stock
|
(25,000 | ) | (70,000 | ) | (85,000 | ) | ||||||
|
Other
|
(351 | ) | (131 | ) | - | |||||||
|
Net cash
provided from (used for) financing activities
|
386,457 | 23,855 | (324,364 | ) | ||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(47,028 | ) | (57,385 | ) | (58,871 | ) | ||||||
|
Loan
repayments from associated companies, net
|
63,711 | 43,098 | 40,306 | |||||||||
|
Redemption of
lessor notes (Note 7)
|
18,330 | 11,959 | 14,847 | |||||||||
|
Sales of
investment securities held in trusts
|
168,580 | 37,931 | 44,682 | |||||||||
|
Purchases of
investment securities held in trusts
|
(170,996 | ) | (40,960 | ) | (47,853 | ) | ||||||
|
Other
|
(3,284 | ) | (1,765 | ) | 2,110 | |||||||
|
Net cash
provided from (used for) investing activities
|
29,313 | (7,122 | ) | (4,779 | ) | |||||||
|
Net change in
cash and cash equivalents
|
436,698 | (8 | ) | - | ||||||||
|
Cash and cash
equivalents at beginning of year
|
14 | 22 | 22 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 436,712 | $ | 14 | $ | 22 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 32,353 | $ | 22,203 | $ | 33,841 | ||||||
|
Income
taxes
|
$ | 1,350 | $ | 62,879 | $ | 73,845 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
171
JERSEY
CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
REVENUES
(Note 18):
|
||||||||||||
|
Electric
sales
|
$ | 2,943,590 | $ | 3,420,772 | $ | 3,191,999 | ||||||
|
Excise tax
collections
|
49,097 | 51,481 | 51,848 | |||||||||
|
Total
revenues
|
2,992,687 | 3,472,253 | 3,243,847 | |||||||||
|
EXPENSES
(Note 18):
|
||||||||||||
|
Purchased
power from non-affiliates
|
1,782,435 | 2,206,251 | 1,957,975 | |||||||||
|
Other
operating costs
|
309,791 | 302,894 | 325,814 | |||||||||
|
Provision for
depreciation
|
102,912 | 96,482 | 85,459 | |||||||||
|
Amortization
of regulatory assets
|
344,158 | 364,816 | 388,581 | |||||||||
|
General
taxes
|
63,078 | 67,340 | 66,225 | |||||||||
|
Total
expenses
|
2,602,374 | 3,037,783 | 2,824,054 | |||||||||
|
OPERATING
INCOME
|
390,313 | 434,470 | 419,793 | |||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||
|
Miscellaneous
income (expense)
|
5,272 | (1,037 | ) | 8,570 | ||||||||
|
Interest
expense (Note 18)
|
(116,851 | ) | (99,459 | ) | (96,988 | ) | ||||||
|
Capitalized
interest
|
543 | 1,245 | 3,789 | |||||||||
|
Total other
expense
|
(111,036 | ) | (99,251 | ) | (84,629 | ) | ||||||
|
INCOME
BEFORE INCOME TAXES
|
279,277 | 335,219 | 335,164 | |||||||||
|
INCOME
TAXES
|
108,778 | 148,231 | 149,056 | |||||||||
|
NET
INCOME
|
$ | 170,499 | $ | 186,988 | $ | 186,108 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
172
JERSEY
CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED
BALANCE SHEETS
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 27 | $ | 66 | ||||
|
Receivables-
|
||||||||
|
Customers
(less accumulated provisions of $3,506,000 and $3,230,000,
|
||||||||
|
respectively,
for uncollectible accounts)
|
300,991 | 340,485 | ||||||
|
Associated
companies
|
12,884 | 265 | ||||||
|
Other
|
21,877 | 37,534 | ||||||
|
Notes
receivable - associated companies
|
102,932 | 16,254 | ||||||
|
Prepaid
taxes
|
34,930 | 10,492 | ||||||
|
Other
|
12,945 | 18,066 | ||||||
| 486,586 | 423,162 | |||||||
|
UTILITY
PLANT:
|
||||||||
|
In
service
|
4,463,490 | 4,307,556 | ||||||
|
Less -
Accumulated provision for depreciation
|
1,617,639 | 1,551,290 | ||||||
| 2,845,851 | 2,756,266 | |||||||
|
Construction
work in progress
|
54,251 | 77,317 | ||||||
| 2,900,102 | 2,833,583 | |||||||
|
OTHER
PROPERTY AND INVESTMENTS:
|
||||||||
|
Nuclear fuel
disposal trust
|
199,677 | 181,468 | ||||||
|
Nuclear plant
decommissioning trusts
|
166,768 | 143,027 | ||||||
|
Other
|
2,149 | 2,145 | ||||||
| 368,594 | 326,640 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Regulatory
assets
|
888,143 | 1,228,061 | ||||||
|
Goodwill
|
1,810,936 | 1,810,936 | ||||||
|
Other
|
27,096 | 29,946 | ||||||
| 2,726,175 | 3,068,943 | |||||||
| $ | 6,481,457 | $ | 6,652,328 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 30,639 | $ | 29,094 | ||||
|
Short-term
borrowings-
|
||||||||
|
Associated
companies
|
- | 121,380 | ||||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
26,882 | 12,821 | ||||||
|
Other
|
168,093 | 198,742 | ||||||
|
Accrued
taxes
|
12,594 | 20,561 | ||||||
|
Accrued
interest
|
18,256 | 9,197 | ||||||
|
Other
|
111,156 | 133,091 | ||||||
| 367,620 | 524,886 | |||||||
|
CAPITALIZATION
(See
Consolidated Statements of Capitalization):
|
||||||||
|
Common
stockholder's equity
|
2,600,396 | 2,729,010 | ||||||
|
Long-term debt
and other long-term obligations
|
1,801,589 | 1,531,840 | ||||||
| 4,401,985 | 4,260,850 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Power purchase
contract liability
|
399,105 | 531,686 | ||||||
|
Accumulated
deferred income taxes
|
687,545 | 689,065 | ||||||
|
Nuclear fuel
disposal costs
|
196,511 | 196,235 | ||||||
|
Asset
retirement obligations
|
101,568 | 95,216 | ||||||
|
Retirement
benefits
|
150,603 | 190,182 | ||||||
|
Other
|
176,520 | 164,208 | ||||||
| 1,711,852 | 1,866,592 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 and 15)
|
||||||||
| $ | 6,481,457 | $ | 6,652,328 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
173
JERSEY
CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
||||||||
|
Common stock,
$10 par value, 16,000,000 shares authorized,
|
||||||||
|
13,628,447 and
14,421,637 shares outstanding, respectively
|
$ | 136,284 | $ | 144,216 | ||||
|
Other paid-in
capital
|
2,507,049 | 2,644,756 | ||||||
|
Accumulated
other comprehensive loss (Note 2(F))
|
(243,012 | ) | (216,538 | ) | ||||
|
Retained
earnings (Note 12(A))
|
200,075 | 156,576 | ||||||
|
Total
|
2,600,396 | 2,729,010 | ||||||
|
LONG-TERM
DEBT (Note 12(C)):
|
||||||||
|
Secured
notes-
|
||||||||
|
5.390% due
2008-2010
|
13,629 | 33,469 | ||||||
|
5.250% due
2008-2012
|
23,974 | 33,229 | ||||||
|
5.810% due
2010-2013
|
77,075 | 77,075 | ||||||
|
5.410% due
2012-2014
|
25,693 | 25,693 | ||||||
|
6.160% due
2013-2017
|
99,517 | 99,517 | ||||||
|
5.520% due
2014-2018
|
49,220 | 49,220 | ||||||
|
5.610% due
2018-2021
|
51,139 | 51,139 | ||||||
|
Total
|
340,247 | 369,342 | ||||||
|
Unsecured
notes-
|
||||||||
|
5.625% due
2016
|
300,000 | 300,000 | ||||||
|
5.650% due
2017
|
250,000 | 250,000 | ||||||
|
4.800% due
2018
|
150,000 | 150,000 | ||||||
|
7.350% due
2019
|
300,000 | - | ||||||
|
6.400% due
2036
|
200,000 | 200,000 | ||||||
|
6.150% due
2037
|
300,000 | 300,000 | ||||||
|
Total
|
1,500,000 | 1,200,000 | ||||||
|
Capital lease
obligations (Note 7)
|
108 | - | ||||||
|
Unamortized
discount on debt
|
(8,127 | ) | (8,408 | ) | ||||
|
Long-term debt
due within one year
|
(30,639 | ) | (29,094 | ) | ||||
|
Total
long-term debt
|
1,801,589 | 1,531,840 | ||||||
|
TOTAL
CAPITALIZATION
|
$ | 4,401,985 | $ | 4,260,850 | ||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
174
JERSEY
CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
|
Accumulated
|
||||||||||||||||||||||||
|
Common Stock
|
Other
|
Other
|
||||||||||||||||||||||
|
Comprehensive
|
Number
|
Par
|
Paid-In
|
Comprehensive
|
Retained
|
|||||||||||||||||||
|
Income
|
of Shares
|
Value
|
Capital
|
Income (Loss)
|
Earnings
|
|||||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||||||||||
|
Balance,
January 1, 2007
|
15,009,335 | 150,093 | 2,908,279 | (44,254 | ) | 145,480 | ||||||||||||||||||
|
Net
income
|
$ | 186,108 | 186,108 | |||||||||||||||||||||
|
Net unrealized
gain on derivative instruments,
|
||||||||||||||||||||||||
|
net of $11,000
of income taxes
|
293 | 293 | ||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $23,644,000
of income taxes (Note 3)
|
24,080 | 24,080 | ||||||||||||||||||||||
|
Comprehensive
income
|
$ | 210,481 | ||||||||||||||||||||||
|
Restricted
stock units
|
198 | |||||||||||||||||||||||
|
Stock-based
compensation
|
3 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
4,637 | |||||||||||||||||||||||
|
Repurchase of
common stock
|
(587,698 | ) | (5,877 | ) | (119,123 | ) | ||||||||||||||||||
|
Cash dividends
declared on common stock
|
(94,000 | ) | ||||||||||||||||||||||
|
Purchase
accounting fair value adjustment
|
(138,053 | ) | ||||||||||||||||||||||
|
Balance,
December 31, 2007
|
14,421,637 | 144,216 | 2,655,941 | (19,881 | ) | 237,588 | ||||||||||||||||||
|
Net
income
|
$ | 186,988 | 186,988 | |||||||||||||||||||||
|
Net unrealized
gain on derivative instruments
|
276 | 276 | ||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of
$131,317,000 of income tax benefits (Note 3)
|
(196,933 | ) | (196,933 | ) | ||||||||||||||||||||
|
Comprehensive
loss
|
$ | (9,669 | ) | |||||||||||||||||||||
|
Restricted
stock units
|
3 | |||||||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
4,065 | |||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(268,000 | ) | ||||||||||||||||||||||
|
Purchase
accounting fair value adjustment
|
(15,254 | ) | ||||||||||||||||||||||
|
Balance,
December 31, 2008
|
14,421,637 | 144,216 | 2,644,756 | (216,538 | ) | 156,576 | ||||||||||||||||||
|
Net
income
|
$ | 170,499 | 170,499 | |||||||||||||||||||||
|
Net unrealized
gain on derivative instruments
|
||||||||||||||||||||||||
|
net of $11,000
of income taxes
|
288 | 288 | ||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $13,025,000
of income tax benefits (Note 3)
|
(26,762 | ) | (26,762 | ) | ||||||||||||||||||||
|
Comprehensive
income
|
$ | 144,025 | ||||||||||||||||||||||
|
Restricted
stock units
|
99 | |||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(127,000 | ) | ||||||||||||||||||||||
|
Repurchase of
common stock
|
(793,190 | ) | (7,932 | ) | (137,806 | ) | ||||||||||||||||||
|
Balance, December 31, 2009
|
13,628,447 | $ | 136,284 | $ | 2,507,049 | $ | (243,012 | ) | $ | 200,075 | ||||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
175
JERSEY
CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 170,499 | $ | 186,988 | $ | 186,108 | ||||||
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
102,912 | 96,482 | 85,459 | |||||||||
|
Amortization
of regulatory assets
|
344,158 | 364,816 | 388,581 | |||||||||
|
Deferred
purchased power and other costs
|
(148,308 | ) | (165,071 | ) | (203,157 | ) | ||||||
|
Deferred
income taxes and investment tax credits, net
|
42,800 | 12,834 | (30,791 | ) | ||||||||
|
Accrued
compensation and retirement benefits
|
12,915 | (35,791 | ) | (23,441 | ) | |||||||
|
Cash
collateral from (returned to) suppliers
|
(210 | ) | 23,106 | (31,938 | ) | |||||||
|
Pension trust
contributions
|
(100,000 | ) | - | (17,800 | ) | |||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
42,532 | 8,042 | (73,259 | ) | ||||||||
|
Materials and
supplies
|
- | 348 | (364 | ) | ||||||||
|
Prepayments
and other current assets
|
(24,333 | ) | (9,600 | ) | 14,417 | |||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
(24,677 | ) | 10,174 | (39,396 | ) | |||||||
|
Accrued
taxes
|
(14,265 | ) | 2,582 | 11,658 | ||||||||
|
Accrued
interest
|
9,059 | (121 | ) | (5,140 | ) | |||||||
|
Other
|
(11,246 | ) | (13,002 | ) | 5,369 | |||||||
|
Net cash
provided from operating activities
|
401,836 | 481,787 | 266,306 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
299,619 | - | 543,807 | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Long-term
debt
|
(29,094 | ) | (27,206 | ) | (325,337 | ) | ||||||
|
Short-term
borrowings, net
|
(121,380 | ) | (9,001 | ) | (56,159 | ) | ||||||
|
Common
stock
|
(150,000 | ) | - | (125,000 | ) | |||||||
|
Dividend
Payments-
|
||||||||||||
|
Common
stock
|
(127,000 | ) | (268,000 | ) | (94,000 | ) | ||||||
|
Other
|
(2,281 | ) | (80 | ) | (609 | ) | ||||||
|
Net cash used
for financing activities
|
(130,136 | ) | (304,287 | ) | (57,298 | ) | ||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(166,409 | ) | (178,358 | ) | (199,856 | ) | ||||||
|
Proceeds from
asset sales
|
- | 20,000 | - | |||||||||
|
Loan
repayments from (loans to) associated companies, net
|
(86,678 | ) | 2,173 | 6,029 | ||||||||
|
Sales of
investment securities held in trusts
|
397,333 | 248,185 | 195,973 | |||||||||
|
Purchases of
investment securities held in trusts
|
(413,693 | ) | (265,441 | ) | (212,263 | ) | ||||||
|
Restricted
funds
|
5,015 | (689 | ) | 783 | ||||||||
|
Other
|
(7,307 | ) | (3,398 | ) | 379 | |||||||
|
Net cash used
for investing activities
|
(271,739 | ) | (177,528 | ) | (208,955 | ) | ||||||
|
Net increase
(decrease) in cash and cash equivalents
|
(39 | ) | (28 | ) | 53 | |||||||
|
Cash and cash
equivalents at beginning of year
|
66 | 94 | 41 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 27 | $ | 66 | $ | 94 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 108,650 | $ | 99,731 | $ | 102,492 | ||||||
|
Income
taxes
|
$ | 95,764 | $ | 145,943 | $ | 156,073 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
176
METROPOLITAN
EDISON COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
REVENUES:
|
||||||||||||
|
Electric
sales
|
$ | 1,611,088 | $ | 1,573,781 | $ | 1,437,498 | ||||||
|
Gross receipts
tax collections
|
77,894 | 79,221 | 73,012 | |||||||||
|
Total
revenues
|
1,688,982 | 1,653,002 | 1,510,510 | |||||||||
|
EXPENSES
(Note 18):
|
||||||||||||
|
Purchased
power from affiliates
|
365,491 | 303,779 | 290,205 | |||||||||
|
Purchased
power from non-affiliates
|
536,054 | 593,203 | 494,284 | |||||||||
|
Other
operating costs
|
277,024 | 429,745 | 419,512 | |||||||||
|
Provision for
depreciation
|
51,006 | 44,556 | 42,798 | |||||||||
|
Amortization
of regulatory assets
|
129,296 | 131,542 | 123,410 | |||||||||
|
Deferral of
new regulatory assets
|
115,413 | (110,038 | ) | (124,821 | ) | |||||||
|
General
taxes
|
87,799 | 85,643 | 80,135 | |||||||||
|
Total
expenses
|
1,562,083 | 1,478,430 | 1,325,523 | |||||||||
|
OPERATING
INCOME
|
126,899 | 174,572 | 184,987 | |||||||||
|
OTHER
INCOME (EXPENSE) (Note 18):
|
||||||||||||
|
Interest
income
|
9,709 | 17,647 | 28,953 | |||||||||
|
Miscellaneous
income (expense)
|
4,033 | 105 | (339 | ) | ||||||||
|
Interest
expense
|
(56,683 | ) | (43,651 | ) | (51,022 | ) | ||||||
|
Capitalized
interest
|
159 | 258 | 1,154 | |||||||||
|
Total other
expense
|
(42,782 | ) | (25,641 | ) | (21,254 | ) | ||||||
|
INCOME
BEFORE INCOME TAXES
|
84,117 | 148,931 | 163,733 | |||||||||
|
INCOME
TAXES
|
28,594 | 60,898 | 68,270 | |||||||||
|
NET
INCOME
|
$ | 55,523 | $ | 88,033 | $ | 95,463 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
177
METROPOLITAN
EDISON COMPANY
CONSOLIDATED
BALANCE SHEETS
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 120 | $ | 144 | ||||
|
Receivables-
|
||||||||
|
Customers
(less accumulated provisions of $4,044,000 and $3,616,000,
|
||||||||
|
respectively,
for uncollectible accounts)
|
171,052 | 159,975 | ||||||
|
Associated
companies
|
29,413 | 17,034 | ||||||
|
Other
|
11,650 | 19,828 | ||||||
|
Notes
receivable from associated companies
|
97,150 | 11,446 | ||||||
|
Prepaid
taxes
|
15,229 | 6,121 | ||||||
|
Other
|
1,459 | 1,621 | ||||||
| 326,073 | 216,169 | |||||||
|
UTILITY
PLANT:
|
||||||||
|
In
service
|
2,162,815 | 2,065,847 | ||||||
|
Less -
Accumulated provision for depreciation
|
810,746 | 779,692 | ||||||
| 1,352,069 | 1,286,155 | |||||||
|
Construction
work in progress
|
14,901 | 32,305 | ||||||
| 1,366,970 | 1,318,460 | |||||||
|
OTHER
PROPERTY AND INVESTMENTS:
|
||||||||
|
Nuclear plant
decommissioning trusts
|
266,479 | 226,139 | ||||||
|
Other
|
890 | 976 | ||||||
| 267,369 | 227,115 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Goodwill
|
416,499 | 416,499 | ||||||
|
Regulatory
assets
|
356,754 | 412,994 | ||||||
|
Power purchase
contract asset
|
176,111 | 300,141 | ||||||
|
Other
|
36,544 | 31,031 | ||||||
| 985,908 | 1,160,665 | |||||||
| $ | 2,946,320 | $ | 2,922,409 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 128,500 | $ | 28,500 | ||||
|
Short-term
borrowings-
|
||||||||
|
Associated
companies
|
- | 15,003 | ||||||
|
Other
|
- | 250,000 | ||||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
40,521 | 28,707 | ||||||
|
Other
|
41,050 | 55,330 | ||||||
|
Accrued
taxes
|
11,170 | 16,238 | ||||||
|
Accrued
interest
|
17,362 | 6,755 | ||||||
|
Other
|
24,520 | 30,647 | ||||||
| 263,123 | 431,180 | |||||||
|
CAPITALIZATION
(See
Consolidated Statements of Capitalization)
:
|
||||||||
|
Common
stockholder's equity
|
1,057,918 | 1,004,064 | ||||||
|
Long-term debt
and other long-term obligations
|
713,873 | 513,752 | ||||||
| 1,771,791 | 1,517,816 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Accumulated
deferred income taxes
|
453,462 | 387,757 | ||||||
|
Accumulated
deferred investment tax credits
|
7,313 | 7,767 | ||||||
|
Nuclear fuel
disposal costs
|
44,391 | 44,328 | ||||||
|
Asset
retirement obligations
|
180,297 | 170,999 | ||||||
|
Retirement
benefits
|
33,605 | 145,218 | ||||||
|
Power purchase
contract liability
|
143,135 | 150,324 | ||||||
|
Other
|
49,203 | 67,020 | ||||||
| 911,406 | 973,413 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 and 15)
|
||||||||
| $ | 2,946,320 | $ | 2,922,409 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
178
METROPOLITAN
EDISON COMPANY
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
||||||||
|
Common stock,
without par value, 900,000 shares authorized,
|
||||||||
|
859,500 shares
outstanding
|
$ | 1,197,070 | $ | 1,196,172 | ||||
|
Accumulated
other comprehensive loss (Note 2(F))
|
(143,551 | ) | (140,984 | ) | ||||
|
Retained
earnings (Accumulated deficit) (Note 12(A))
|
4,399 | (51,124 | ) | |||||
|
Total
|
1,057,918 | 1,004,064 | ||||||
|
LONG-TERM
DEBT (Note 12(C)):
|
||||||||
|
First mortgage
bonds-
|
||||||||
|
5.950% due
2027
|
13,690 | 13,690 | ||||||
|
Total
|
13,690 | 13,690 | ||||||
|
Unsecured
notes-
|
||||||||
|
4.450% due
2010
|
100,000 | 100,000 | ||||||
|
4.950% due
2013
|
150,000 | 150,000 | ||||||
|
4.875% due
2014
|
250,000 | 250,000 | ||||||
|
7.700% due
2019
|
300,000 | - | ||||||
|
* 0.24%
due 2021
|
28,500 | 28,500 | ||||||
|
Total
|
828,500 | 528,500 | ||||||
|
Unamortized
premium on debt
|
183 | 62 | ||||||
|
Long-term debt
due within one year
|
(128,500 | ) | (28,500 | ) | ||||
|
Total
long-term debt
|
713,873 | 513,752 | ||||||
|
TOTAL
CAPITALIZATION
|
$ | 1,771,791 | $ | 1,517,816 | ||||
|
* Denotes
variable rate issue with applicable year-end interest rate
shown.
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
179
METROPOLITAN
EDISON COMPANY
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
|
Accumulated
|
Retained
|
|||||||||||||||||||
|
Common Stock
|
Other
|
Earnings
|
||||||||||||||||||
|
Comprehensive
|
Number
|
Carrying
|
Comprehensive
|
(Accumulated
|
||||||||||||||||
|
Income (Loss)
|
of Shares
|
Value
|
Income (Loss)
|
Deficit)
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||||||
|
Balance,
January 1, 2007
|
859,500 | $ | 1,276,075 | $ | (26,516 | ) | $ | (234,620 | ) | |||||||||||
|
Net
Income
|
$ | 95,463 | 95,463 | |||||||||||||||||
|
Net unrealized
gain on derivative instruments
|
335 | 335 | ||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $11,666,000
of income taxes (Note 3)
|
10,784 | 10,784 | ||||||||||||||||||
|
Comprehensive
income
|
$ | 106,582 | ||||||||||||||||||
|
Restricted
stock units
|
104 | |||||||||||||||||||
|
Stock-based
compensation
|
7 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
1,237 | - | ||||||||||||||||||
|
Purchase
accounting fair value adjustment
|
(74,237 | ) | ||||||||||||||||||
|
Balance,
December 31, 2007
|
859,500 | 1,203,186 | (15,397 | ) | (139,157 | ) | ||||||||||||||
|
Net
Income
|
$ | 88,033 | 88,033 | |||||||||||||||||
|
Net unrealized
gain on derivative instruments
|
335 | 335 | ||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $86,030,000
of income tax benefits (Note 3)
|
(125,922 | ) | (125,922 | ) | ||||||||||||||||
|
Comprehensive
loss
|
$ | (37,554 | ) | |||||||||||||||||
|
Restricted
stock units
|
9 | |||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
791 | |||||||||||||||||||
|
Purchase
accounting fair value adjustment
|
(7,815 | ) | ||||||||||||||||||
|
Balance,
December 31, 2008
|
859,500 | 1,196,172 | (140,984 | ) | (51,124 | ) | ||||||||||||||
|
Net
Income
|
$ | 55,523 | 55,523 | |||||||||||||||||
|
Net unrealized
gain on derivative instruments
|
335 | 335 | ||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||
|
of $2,784,000
of income taxes (Note 3)
|
(2,902 | ) | (2,902 | ) | ||||||||||||||||
|
Comprehensive
income
|
$ | 52,956 | ||||||||||||||||||
|
Restricted
stock units
|
55 | |||||||||||||||||||
|
Consolidated
tax benefit allocation
|
843 | |||||||||||||||||||
|
Balance, December 31, 2009
|
859,500 | $ | 1,197,070 | $ | (143,551 | ) | $ | 4,399 | ||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
180
METROPOLITAN
EDISON COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 55,523 | $ | 88,033 | $ | 95,463 | ||||||
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
51,006 | 44,556 | 42,798 | |||||||||
|
Amortization
(deferral) of regulatory assets
|
244,709 | 21,504 | (1,411 | ) | ||||||||
|
Deferred costs
recoverable as regulatory assets
|
(96,304 | ) | (25,132 | ) | (70,778 | ) | ||||||
|
Deferred
income taxes and investment tax credits, net
|
66,965 | 49,939 | 35,502 | |||||||||
|
Accrued
compensation and retirement benefits
|
5,876 | (23,244 | ) | (18,852 | ) | |||||||
|
Loss on sale
of investment
|
- | - | 5,432 | |||||||||
|
Cash
collateral from (to) suppliers
|
(4,580 | ) | - | 1,600 | ||||||||
|
Pension trust
contributions
|
(123,521 | ) | - | (11,012 | ) | |||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
(32,088 | ) | (24,282 | ) | (38,220 | ) | ||||||
|
Prepayments
and other current assets
|
(8,948 | ) | 8,223 | (926 | ) | |||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
(2,781 | ) | (12,512 | ) | (62,760 | ) | ||||||
|
Accrued
taxes
|
(5,001 | ) | 470 | 10,128 | ||||||||
|
Accrued
interest
|
10,607 | (23 | ) | (718 | ) | |||||||
|
Other
|
5,022 | 15,629 | 12,870 | |||||||||
|
Net cash
provided from (used for) operating activities
|
166,485 | 143,161 | (884 | ) | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
300,000 | 28,500 | - | |||||||||
|
Short-term
borrowings, net
|
- | - | 143,826 | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Long-term
debt
|
- | (28,568 | ) | (50,000 | ) | |||||||
|
Short-term
borrowings, net
|
(265,003 | ) | (20,324 | ) | - | |||||||
|
Other
|
(2,268 | ) | (266 | ) | (35 | ) | ||||||
|
Net cash
provided from (used for) financing activities
|
32,729 | (20,658 | ) | 93,791 | ||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(100,201 | ) | (110,301 | ) | (103,711 | ) | ||||||
|
Proceeds from
sale of investment
|
- | - | 4,953 | |||||||||
|
Sales of
investment securities held in trusts
|
67,973 | 181,007 | 184,619 | |||||||||
|
Purchases of
investment securities held in trusts
|
(77,738 | ) | (193,061 | ) | (196,140 | ) | ||||||
|
Loan
repayments from (loans to) associated companies, net
|
(85,704 | ) | 1,128 | 18,535 | ||||||||
|
Other
|
(3,568 | ) | (1,267 | ) | (1,158 | ) | ||||||
|
Net cash used
for investing activities
|
(199,238 | ) | (122,494 | ) | (92,902 | ) | ||||||
|
Net (decrease)
increase in cash and cash equivalents
|
(24 | ) | 9 | 5 | ||||||||
|
Cash and cash
equivalents at beginning of year
|
144 | 135 | 130 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 120 | $ | 144 | $ | 135 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
(Received) During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 41,809 | $ | 38,627 | $ | 44,501 | ||||||
|
Income
taxes
|
$ | (5,801 | ) | $ | 16,872 | $ | 30,741 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
181
PENNSYLVANIA
ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
REVENUES:
|
||||||||||||
|
Electric
sales
|
$ | 1,385,574 | $ | 1,443,461 | $ | 1,336,517 | ||||||
|
Gross receipts
tax collections
|
63,372 | 70,168 | 65,508 | |||||||||
|
Total
revenues
|
1,448,946 | 1,513,629 | 1,402,025 | |||||||||
|
EXPENSES
(Note 18):
|
||||||||||||
|
Purchased
power from affiliates
|
341,645 | 284,074 | 284,826 | |||||||||
|
Purchased
power from non-affiliates
|
544,490 | 591,487 | 505,528 | |||||||||
|
Other
operating costs
|
209,156 | 228,257 | 234,949 | |||||||||
|
Provision for
depreciation
|
61,317 | 54,643 | 49,558 | |||||||||
|
Amortization
of regulatory assets, net
|
56,572 | 71,091 | 46,761 | |||||||||
|
General
taxes
|
73,839 | 79,604 | 76,050 | |||||||||
|
Total
expenses
|
1,287,019 | 1,309,156 | 1,197,672 | |||||||||
|
OPERATING
INCOME
|
161,927 | 204,473 | 204,353 | |||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||
|
Miscellaneous
income
|
3,662 | 1,359 | 6,501 | |||||||||
|
Interest
expense (Note 18)
|
(54,605 | ) | (59,424 | ) | (54,840 | ) | ||||||
|
Capitalized
interest
|
98 | (591 | ) | 939 | ||||||||
|
Total other
expense
|
(50,845 | ) | (58,656 | ) | (47,400 | ) | ||||||
|
INCOME
BEFORE INCOME TAXES
|
111,082 | 145,817 | 156,953 | |||||||||
|
INCOME
TAXES
|
45,694 | 57,647 | 64,015 | |||||||||
|
NET
INCOME
|
$ | 65,388 | $ | 88,170 | $ | 92,938 | ||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
182
PENNSYLVANIA
ELECTRIC COMPANY
CONSOLIDATED
BALANCE SHEETS
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash and cash
equivalents
|
$ | 14 | $ | 23 | ||||
|
Receivables-
|
||||||||
|
Customers
(less accumulated provisions of $3,483,000 and $3,121,000,
|
||||||||
|
respectively,
for uncollectible accounts)
|
139,302 | 146,831 | ||||||
|
Associated
companies
|
77,338 | 65,610 | ||||||
|
Other
|
18,320 | 26,766 | ||||||
|
Notes
receivable from associated companies
|
14,589 | 14,833 | ||||||
|
Prepaid
taxes
|
18,946 | 16,310 | ||||||
|
Other
|
1,400 | 1,517 | ||||||
| 269,909 | 271,890 | |||||||
|
UTILITY
PLANT:
|
||||||||
|
In
service
|
2,431,737 | 2,324,879 | ||||||
|
Less -
Accumulated provision for depreciation
|
901,990 | 868,639 | ||||||
| 1,529,747 | 1,456,240 | |||||||
|
Construction
work in progress
|
24,205 | 25,146 | ||||||
| 1,553,952 | 1,481,386 | |||||||
|
OTHER
PROPERTY AND INVESTMENTS:
|
||||||||
|
Nuclear plant
decommissioning trusts
|
142,603 | 115,292 | ||||||
|
Non-utility
generation trusts
|
120,070 | 116,687 | ||||||
|
Other
|
289 | 293 | ||||||
| 262,962 | 232,272 | |||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||
|
Goodwill
|
768,628 | 768,628 | ||||||
|
Regulatory
assets
|
9,045 | - | ||||||
|
Power purchase
contract asset
|
15,362 | 119,748 | ||||||
|
Other
|
19,143 | 18,658 | ||||||
| 812,178 | 907,034 | |||||||
| $ | 2,899,001 | $ | 2,892,582 | |||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Currently
payable long-term debt
|
$ | 69,310 | $ | 145,000 | ||||
|
Short-term
borrowings-
|
||||||||
|
Associated
companies
|
41,473 | 31,402 | ||||||
|
Other
|
- | 250,000 | ||||||
|
Accounts
payable-
|
||||||||
|
Associated
companies
|
39,884 | 63,692 | ||||||
|
Other
|
41,990 | 48,633 | ||||||
|
Accrued
taxes
|
6,409 | 13,264 | ||||||
|
Accrued
interest
|
17,598 | 13,131 | ||||||
|
Other
|
22,741 | 31,730 | ||||||
| 239,405 | 596,852 | |||||||
|
CAPITALIZATION
(See
Consolidated Statements of Capitalization):
|
||||||||
|
Common
stockholder's equity
|
931,386 | 949,109 | ||||||
|
Long-term debt
and other long-term obligations
|
1,072,181 | 633,132 | ||||||
| 2,003,567 | 1,582,241 | |||||||
|
NONCURRENT
LIABILITIES:
|
||||||||
|
Regulatory
liabilities
|
- | 136,579 | ||||||
|
Accumulated
deferred income taxes
|
242,040 | 169,807 | ||||||
|
Retirement
benefits
|
174,306 | 172,718 | ||||||
|
Asset
retirement obligations
|
91,841 | 87,089 | ||||||
|
Power purchase
contract liability
|
100,849 | 83,600 | ||||||
|
Other
|
46,993 | 63,696 | ||||||
| 656,029 | 713,489 | |||||||
|
COMMITMENTS
AND CONTINGENCIES (Notes 7 and 15)
|
||||||||
| $ | 2,899,001 | $ | 2,892,582 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
183
PENNSYLVANIA
ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF CAPITALIZATION
|
As of December 31,
|
2009
|
2008
|
||||||
|
(In
thousands)
|
||||||||
|
COMMON
STOCKHOLDER'S EQUITY:
|
||||||||
|
Common stock,
$20 par value, 5,400,000 shares authorized,
|
||||||||
|
4,427,577
shares outstanding
|
$ | 88,552 | $ | 88,552 | ||||
|
Other paid-in
capital
|
913,437 | 912,441 | ||||||
|
Accumulated
other comprehensive income (loss) (Note 2(F))
|
(162,104 | ) | (127,997 | ) | ||||
|
Retained
earnings (Note 12(A))
|
91,501 | 76,113 | ||||||
|
Total
|
931,386 | 949,109 | ||||||
|
LONG-TERM
DEBT (Note 12(C)):
|
||||||||
|
First mortgage
bonds-
|
||||||||
|
5.350% due
2010
|
12,310 | 12,310 | ||||||
|
5.350% due
2010
|
12,000 | 12,000 | ||||||
|
Total
|
24,310 | 24,310 | ||||||
|
Unsecured
notes-
|
||||||||
|
6.125% due
2009
|
- | 100,000 | ||||||
|
7.770% due
2010
|
- | 35,000 | ||||||
|
5.125% due
2014
|
150,000 | 150,000 | ||||||
|
6.050% due
2017
|
300,000 | 300,000 | ||||||
|
6.625% due
2019
|
125,000 | 125,000 | ||||||
|
*
0.240% due 2020
|
20,000 | 20,000 | ||||||
|
5.200% due
2020
|
250,000 | - | ||||||
|
*
0.340% due 2025
|
25,000 | 25,000 | ||||||
|
6.150% due
2038
|
250,000 | - | ||||||
|
Total
|
1,120,000 | 755,000 | ||||||
|
Net
unamortized discount on debt
|
(2,819 | ) | (1,178 | ) | ||||
|
Long-term debt
due within one year
|
(69,310 | ) | (145,000 | ) | ||||
|
Total
long-term debt
|
1,072,181 | 633,132 | ||||||
|
TOTAL
CAPITALIZATION
|
$ | 2,003,567 | $ | 1,582,241 | ||||
|
* Denotes
variable rate issue with applicable year-end interest rate
shown.
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
184
PENNSYLVANIA
ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
|
Accumulated
|
||||||||||||||||||||||||
|
Common Stock
|
Other
|
Other
|
||||||||||||||||||||||
|
Comprehensive
|
Number
|
Par
|
Paid-In
|
Comprehensive
|
Retained
|
|||||||||||||||||||
|
Income (Loss)
|
of Shares
|
Value
|
Capital
|
Income (Loss)
|
Earnings
|
|||||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||||||||||
|
Balance,
January 1, 2007
|
$ | 5,290,596 | $ | 105,812 | $ | 1,189,434 | $ | (7,193 | ) | $ | 90,005 | |||||||||||||
|
Net
income
|
$ | 92,938 | 92,938 | |||||||||||||||||||||
|
Net unrealized
gain on investments, net
|
||||||||||||||||||||||||
|
of
$12,000 of income tax benefits
|
21 | 21 | ||||||||||||||||||||||
|
Net unrealized
gain on derivative instruments, net
|
||||||||||||||||||||||||
|
of $16,000 of
income taxes
|
49 | 49 | ||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $15,413,000
of income taxes (Note 3)
|
12,069 | 12,069 | ||||||||||||||||||||||
|
Comprehensive
income
|
$ | 105,077 | ||||||||||||||||||||||
|
Restricted
stock units
|
107 | |||||||||||||||||||||||
|
Stock-based
compensation
|
7 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
1,261 | |||||||||||||||||||||||
|
Repurchase of
common stock
|
(863,019 | ) | (17,260 | ) | (182,740 | ) | ||||||||||||||||||
|
Cash dividends
declared on common stock
|
(125,000 | ) | ||||||||||||||||||||||
|
Purchase
accounting fair value adjustment
|
(87,453 | ) | ||||||||||||||||||||||
|
Balance,
December 31, 2007
|
4,427,577 | 88,552 | 920,616 | 4,946 | 57,943 | |||||||||||||||||||
|
Net
income
|
$ | 88,170 | 88,170 | |||||||||||||||||||||
|
Net unrealized
gain on investments, net
|
9 | 9 | ||||||||||||||||||||||
|
of $13,000 of
income taxes
|
||||||||||||||||||||||||
|
Net unrealized
gain on derivative instruments, net
|
69 | 69 | ||||||||||||||||||||||
|
of $4,000 of
income tax benefits
|
||||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $90,822,000
of income tax benefits (Note 3)
|
(133,021 | ) | (133,021 | ) | ||||||||||||||||||||
|
Comprehensive
loss
|
$ | (44,773 | ) | |||||||||||||||||||||
|
Restricted
stock units
|
35 | |||||||||||||||||||||||
|
Stock-based
compensation
|
1 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
1,066 | |||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(70,000 | ) | ||||||||||||||||||||||
|
Purchase
accounting fair value adjustment
|
(9,277 | ) | ||||||||||||||||||||||
|
Balance,
December 31, 2008
|
4,427,577 | $ | 88,552 | $ | 912,441 | $ | (127,997 | ) | $ | 76,113 | ||||||||||||||
|
Net
income
|
$ | 65,388 | 65,388 | |||||||||||||||||||||
|
Change in
unrealized gain on investments, net
|
(2 | ) | (2 | ) | ||||||||||||||||||||
|
of $15,000 of
income taxes
|
||||||||||||||||||||||||
|
Net unrealized
gain on derivative instruments, net
|
72 | 72 | ||||||||||||||||||||||
|
of $7,000 of
income tax benefits
|
||||||||||||||||||||||||
|
Pension and
other postretirement benefits, net
|
||||||||||||||||||||||||
|
of $17,244,000
of income tax benefits (Note 3)
|
(34,177 | ) | (34,177 | ) | ||||||||||||||||||||
|
Comprehensive
income
|
$ | 31,281 | ||||||||||||||||||||||
|
Restricted
stock units
|
65 | |||||||||||||||||||||||
|
Consolidated
tax benefit allocation
|
931 | |||||||||||||||||||||||
|
Cash dividends
declared on common stock
|
(50,000 | ) | ||||||||||||||||||||||
|
Balance, December 31, 2009
|
4,427,577 | $ | 88,552 | $ | 913,437 | $ | (162,104 | ) | $ | 91,501 | ||||||||||||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
185
PENNSYLVANIA
ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For the Years Ended December
31,
|
2009
|
2008
|
2007
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 65,388 | $ | 88,170 | $ | 92,938 | ||||||
|
Adjustments to
reconcile net income to net cash from operating
activities-
|
||||||||||||
|
Provision for
depreciation
|
61,317 | 54,643 | 49,558 | |||||||||
|
Amortization
of regulatory assets, net
|
56,572 | 71,091 | 46,761 | |||||||||
|
Deferred costs
recoverable as regulatory assets
|
(100,990 | ) | (35,898 | ) | (71,939 | ) | ||||||
|
Deferred
income taxes and investment tax credits, net
|
63,065 | 95,227 | 10,713 | |||||||||
|
Accrued
compensation and retirement benefits
|
3,866 | (25,661 | ) | (20,830 | ) | |||||||
|
Pension trust
contribution
|
(60,000 | ) | - | (13,436 | ) | |||||||
|
Decrease
(increase) in operating assets-
|
||||||||||||
|
Receivables
|
22,891 | (74,338 | ) | 18,771 | ||||||||
|
Prepayments
and other current assets
|
(2,519 | ) | (16,313 | ) | 1,159 | |||||||
|
Increase
(decrease) in operating liabilities-
|
||||||||||||
|
Accounts
payable
|
3,114 | (1,966 | ) | (59,513 | ) | |||||||
|
Accrued
taxes
|
(6,855 | ) | (2,181 | ) | 4,743 | |||||||
|
Accrued
interest
|
4,467 | (36 | ) | 5,943 | ||||||||
|
Other
|
3,236 | 17,815 | 13,125 | |||||||||
|
Net cash
provided from operating activities
|
113,552 | 170,553 | 77,993 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
New
Financing-
|
||||||||||||
|
Long-term
debt
|
498,583 | 45,000 | 299,109 | |||||||||
|
Short-term
borrowings, net
|
- | 66,509 | 15,662 | |||||||||
|
Redemptions
and Repayments-
|
||||||||||||
|
Common
Stock
|
- | - | (200,000 | ) | ||||||||
|
Long-term
debt
|
(135,000 | ) | (45,556 | ) | - | |||||||
|
Short-term
borrowings, net
|
(239,929 | ) | - | - | ||||||||
|
Dividend
Payments-
|
||||||||||||
|
Common
stock
|
(85,000 | ) | (90,000 | ) | (70,000 | ) | ||||||
|
Other
|
(4,453 | ) | - | (2,210 | ) | |||||||
|
Net cash
provided from (used for) financing activities
|
34,201 | (24,047 | ) | 42,561 | ||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Property
additions
|
(124,262 | ) | (126,672 | ) | (94,991 | ) | ||||||
|
Loan
repayments from associated companies, net
|
244 | 1,480 | 3,235 | |||||||||
|
Sales of
investment securities held in trusts
|
84,400 | 117,751 | 175,222 | |||||||||
|
Purchases of
investment securities held in trusts
|
(98,467 | ) | (134,621 | ) | (199,375 | ) | ||||||
|
Other,
net
|
(9,677 | ) | (4,467 | ) | (4,643 | ) | ||||||
|
Net cash used
for investing activities
|
(147,762 | ) | (146,529 | ) | (120,552 | ) | ||||||
|
Net increase
(decrease) in cash and cash equivalents
|
(9 | ) | (23 | ) | 2 | |||||||
|
Cash and cash
equivalents at beginning of year
|
23 | 46 | 44 | |||||||||
|
Cash and cash
equivalents at end of year
|
$ | 14 | $ | 23 | $ | 46 | ||||||
|
SUPPLEMENTAL
CASH FLOW INFORMATION:
|
||||||||||||
|
Cash Paid
(Received) During the Year-
|
||||||||||||
|
Interest (net
of amounts capitalized)
|
$ | 48,265 | $ | 56,972 | $ | 44,503 | ||||||
|
Income
taxes
|
$ | (10,775 | ) | $ | 44,197 | $ | 2,996 | |||||
|
The
accompanying Combined Notes to the Consolidated Financial Statements are
an integral part of these financial
statements.
|
186
1. ORGANIZATION
AND BASIS OF PRESENTATION
FirstEnergy is a
diversified energy company that holds, directly or indirectly, all of the
outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a
wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and
its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its
subsidiaries follow GAAP and comply with the regulations, orders, policies and
practices prescribed by the SEC, FERC and, as applicable, the PUCO, PPUC and
NJBPU. The preparation of financial statements in conformity with GAAP requires
management to make periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates. The reported results of operations are not indicative of results of
operations for any future period. In preparing the financial statements,
FirstEnergy and its subsidiaries have evaluated events and transactions for
potential recognition or disclosure through February 18, 2010, the date the
financial statements were issued.
FirstEnergy and its
subsidiaries consolidate all majority-owned subsidiaries over which they
exercise control and, when applicable, entities for which they have a
controlling financial interest. Intercompany transactions and balances are
eliminated in consolidation unless otherwise prescribed by GAAP (see Note 16).
FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the
VIE's primary beneficiary. Investments in non-consolidated affiliates over which
FirstEnergy and its subsidiaries have the ability to exercise significant
influence, but not control (20-50% owned companies, joint ventures and
partnerships) are accounted for under the equity method. Under the equity
method, the interest in the entity is reported as an investment in the
Consolidated Balance Sheets and the percentage share of the entity’s earnings is
reported in the Consolidated Statements of Income. These footnotes combine
results of FE, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
Certain prior year
amounts have been reclassified to conform to the current year presentation.
Unless otherwise indicated, defined terms used herein have the meanings set
forth in the accompanying Glossary of Terms.
2. SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
(A) ACCOUNTING
FOR THE EFFECTS OF REGULATION
FirstEnergy accounts
for the effects of regulation through the application of regulatory accounting
to its operating utilities since their rates:
|
|
·
|
are
established by a third-party regulator with the authority to set rates
that bind customers;
|
|
|
·
|
are
cost-based; and
|
|
|
·
|
can be charged
to and collected from customers.
|
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.
187
Regulatory assets on
the Balance Sheets are comprised of the following:
|
Regulatory
Assets
|
FE
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
December 31,
2009
|
||||||||||||||||||||||||||||
|
Regulatory
transition costs
|
$ | 1,100 | $ | 73 | $ | 8 | $ | 8 | $ | 965 | $ | 116 | $ | (70 | ) | |||||||||||||
|
Customer
shopping incentives
|
154 | - | 154 | - | - | - | - | |||||||||||||||||||||
|
Customer
receivables for future income taxes
|
329 | 58 | 3 | 1 | 31 | 114 | 122 | |||||||||||||||||||||
|
Loss (Gain) on
reacquired debt
|
51 | 18 | 1 | (3 | ) | 22 | 8 | 5 | ||||||||||||||||||||
|
Employee
postretirement benefit costs
|
23 | - | 5 | 2 | 10 | 6 | - | |||||||||||||||||||||
|
Nuclear
decommissioning, decontamination
|
||||||||||||||||||||||||||||
|
and spent fuel
disposal costs
|
(162 | ) | - | - | - | (22 | ) | (83 | ) | (57 | ) | |||||||||||||||||
|
Asset removal
costs
|
(231 | ) | (23 | ) | (43 | ) | (17 | ) | (148 | ) | - | - | ||||||||||||||||
|
MISO/PJM
transmission costs
|
148 | (15 | ) | (15 | ) | (3 | ) | - | 187 | (6 | ) | |||||||||||||||||
|
Fuel
costs
|
369 | 115 | 222 | 32 | - | - | - | |||||||||||||||||||||
|
Distribution
costs
|
482 | 230 | 197 | 55 | - | - | - | |||||||||||||||||||||
|
Other
|
93 | 9 | 14 | (5 | ) | 30 | 9 | 15 | ||||||||||||||||||||
|
Total
|
$ | 2,356 | $ | 465 | $ | 546 | $ | 70 | $ | 888 | $ | 357 | $ | 9 | ||||||||||||||
|
December 31,
2008
*
|
||||||||||||||||||||||||||||
|
Regulatory
transition costs
|
$ | 1,452 | $ | 112 | $ | 80 | $ | 12 | $ | 1,236 | $ | 12 | $ | - | ||||||||||||||
|
Customer
shopping incentives
|
420 | - | 420 | - | - | - | - | |||||||||||||||||||||
|
Customer
receivables for future income taxes
|
245 | 68 | 4 | 1 | 59 | 113 | - | |||||||||||||||||||||
|
Loss (Gain) on
reacquired debt
|
51 | 20 | 1 | (3 | ) | 24 | 9 | - | ||||||||||||||||||||
|
Employee
postretirement benefit costs
|
31 | - | 7 | 3 | 13 | 8 | - | |||||||||||||||||||||
|
Nuclear
decommissioning, decontamination
|
||||||||||||||||||||||||||||
|
and spent fuel
disposal costs
|
(57 | ) | - | - | - | (2 | ) | (55 | ) | - | ||||||||||||||||||
|
Asset removal
costs
|
(215 | ) | (15 | ) | (36 | ) | (16 | ) | (148 | ) | - | - | ||||||||||||||||
|
MISO/PJM
transmission costs
|
389 | 31 | 19 | 20 | - | 319 | - | |||||||||||||||||||||
|
Fuel
costs
|
214 | 109 | 75 | 30 | - | - | - | |||||||||||||||||||||
|
Distribution
costs
|
475 | 222 | 198 | 55 | - | - | - | |||||||||||||||||||||
|
Other
|
135 | 28 | 16 | 7 | 46 | 7 | - | |||||||||||||||||||||
|
Total
|
$ | 3,140 | $ | 575 | $ | 784 | $ | 109 | $ | 1,228 | $ | 413 | $ | - | ||||||||||||||
|
|
*
|
Penelec had
net regulatory liabilities of approximately $137 million as of December
31, 2008. These net regulatory liabilities are included in Other
Non-Current Liabilities on the Consolidated Balance
Sheets.
|
Regulatory assets
that do not earn a current return (primarily for certain regulatory transition
costs and employee postretirement benefits) totaled approximately $187 million
as of December 31, 2009 (JCP&L - $36 million, Met-Ed - $114 million, and
Penelec - $37 million). Regulatory assets not earning a current return will be
recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.
Transition
Cost Amortization
JCP&L’s and
Met-Ed’s regulatory transition costs include the deferral of above-market costs
for power supplied from NUGs of $369 million for JCP&L (recovered through
NGC revenues) and $110 million for Met-Ed (recovered through CTC revenues).
Projected above-market NUG costs are adjusted to fair value at the end of each
quarter, with a corresponding offset to regulatory assets. Recovery of the
remaining regulatory transition costs is expected to continue pursuant to
various regulatory proceedings in New Jersey and Pennsylvania (see Note
11).
|
(B)
|
REVENUES
AND RECEIVABLES
|
The Utilities'
principal business is providing electric service to customers in Ohio,
Pennsylvania and New Jersey. The Utilities' retail customers are metered on a
cycle basis. Electric revenues are recorded based on energy delivered through
the end of the calendar month. An estimate of unbilled revenues is calculated to
recognize electric service provided from the last meter reading through the end
of the month. This estimate includes many factors, among which are historical
customer usage, load profiles, estimated weather impacts, customer shopping
activity and prices in effect for each class of customer. In each accounting
period, the Utilities accrue the estimated unbilled amount receivable as revenue
and reverse the related prior period estimate.
188
Receivables from
customers include sales to residential, commercial and industrial customers and
sales to wholesale customers. There was no material concentration of receivables
as of December 31, 2009 with respect to any particular segment of FirstEnergy's
customers. Billed and unbilled customer receivables as of December 31, 2009 and
2008 are shown below.
|
Customer
Receivables
|
FE
|
FES
|
OE
|
CEI
|
TE
(1)
|
JCP&L
|
Met-Ed
|
Penelec
|
||||||||||||||||||||||||
|
December 31,
2009
|
||||||||||||||||||||||||||||||||
|
Billed
|
$ | 725 | $ | 109 | $ | 101 | $ | 114 | $ | 1 | $ | 183 | $ | 110 | $ | 88 | ||||||||||||||||
|
Unbilled
|
519 | 86 | 108 | 95 | - | 118 | 61 | 51 | ||||||||||||||||||||||||
|
Total
|
$ | 1,244 | $ | 195 | $ | 209 | $ | 209 | $ | 1 | $ | 301 | $ | 171 | $ | 139 | ||||||||||||||||
|
December 31,
2008
|
||||||||||||||||||||||||||||||||
|
Billed
|
$ | 752 | $ | 84 | $ | 143 | $ | 150 | $ | 1 | $ | 179 | $ | 93 | $ | 86 | ||||||||||||||||
|
Unbilled
|
552 | 2 | 134 | 126 | - | 161 | 67 | 61 | ||||||||||||||||||||||||
|
Total
|
$ | 1,304 | $ | 86 | $ | 277 | $ | 276 | $ | 1 | $ | 340 | $ | 160 | $ | 147 | ||||||||||||||||
|
(1)
|
See Note 14
for a discussion of TE’s accounts receivable financing arrangement with
Centerior Funding Corporation.
|
|
(C)
|
EARNINGS
PER SHARE OF COMMON STOCK
|
Basic earnings per
share of common stock is computed using the weighted average of actual common
shares outstanding during the respective period as the denominator. The
denominator for diluted earnings per share of common stock reflects the weighted
average of common shares outstanding plus the potential additional common shares
that could result if dilutive securities and other agreements to issue common
stock were exercised. In 2007, FirstEnergy repurchased approximately 14.4
million shares, or 4.5%, of its outstanding common stock for $951 million
through an accelerated share repurchase program. The following table
reconciles basic and diluted earnings per share of common stock:
|
Reconciliation
of Basic and Diluted
|
|
|
|
|||||||||
|
Earnings
per Share of Common Stock
|
2009
|
2008
|
2007
|
|||||||||
|
|
(In
millions, except per share amounts)
|
|||||||||||
|
|
||||||||||||
|
Earnings
available to FirstEnergy Corp.
|
$ | 1,006 | $ | 1,342 | $ | 1,309 | ||||||
|
Average shares
of common stock outstanding – Basic
|
304 | 304 | 306 | |||||||||
|
Assumed
exercise of dilutive stock options and awards
|
2 | 3 | 4 | |||||||||
|
Average shares
of common stock outstanding – Diluted
|
306 | 307 | 310 | |||||||||
|
Basic earnings
per share of common stock:
|
$ | 3.31 | $ | 4.41 | $ | 4.27 | ||||||
|
Diluted
earnings per share of common stock:
|
$ | 3.29 | $ | 4.38 | $ | 4.22 | ||||||
|
(D)
|
PROPERTY,
PLANT AND EQUIPMENT
|
Property, plant and
equipment reflects original cost (except for nuclear generating assets which
were adjusted to fair value), including payroll and related costs such as taxes,
employee benefits, administrative and general costs, and interest costs incurred
to place the assets in service. The costs of normal maintenance, repairs and
minor replacements are expensed as incurred. FirstEnergy's recognizes
liabilities for planned major maintenance projects as they are incurred.
Property, plant and equipment balances as of December 31, 2009 and 2008 were as
follows:
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||||||||||
|
Property,
Plant and Equipment
|
Unregulated
|
Regulated
|
Total
|
Unregulated
|
Regulated
|
Total
|
||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||
|
In
service
|
$ | 10,935 | $ | 16,891 | $ | 27,826 | $ | 10,236 | $ | 16,246 | $ | 26,482 | ||||||||||||
|
Less
accumulated depreciation
|
(4,699 | ) | (6,698 | ) | (11,397 | ) | (4,403 | ) | (6,418 | ) | (10,821 | ) | ||||||||||||
|
Net plant in
service
|
$ | 6,236 | $ | 10,193 | $ | 16,429 | $ | 5,833 | $ | 9,828 | $ | 15,661 | ||||||||||||
FirstEnergy provides
for depreciation on a straight-line basis at various rates over the estimated
lives of property included in plant in service. The respective annual composite
rates for FirstEnergy’s subsidiaries’ electric plant in 2009, 2008, and 2007 are
shown in the following table:
189
|
Annual
Composite
|
||||||||||||
|
Depreciation
Rate
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
OE
|
3.1 | % | 3.1 | % | 2.9 | % | ||||||
|
CEI
|
3.3 | 3.5 | 3.6 | |||||||||
|
TE
|
3.3 | 3.6 | 3.9 | |||||||||
|
Penn
|
2.4 | 2.4 | 2.3 | |||||||||
|
JCP&L
|
2.4 | 2.3 | 2.1 | |||||||||
|
Met-Ed
|
2.5 | 2.3 | 2.3 | |||||||||
|
Penelec
|
2.6 | 2.5 | 2.3 | |||||||||
|
FGCO
|
4.6 | 4.7 | 4.0 | |||||||||
|
NGC
|
3.0 | 2.8 | 2.8 | |||||||||
Asset
Retirement Obligations
FirstEnergy
recognizes an ARO for the future decommissioning of its nuclear power plants and
future remediation of other environmental liabilities associated with all of its
long-lived assets. The fair value of an ARO is recognized in the period in which
it is incurred. The associated asset retirement costs are capitalized as part of
the carrying value of the long-lived asset and are depreciated over the life of
the related asset, as described further in Note 13.
|
(E)
|
ASSET
IMPAIRMENTS
|
Long-lived
Assets
FirstEnergy reviews
long-lived assets for impairment whenever events or changes in circumstances
indicate that the carrying amount of such an asset may not be recoverable. The
recoverability of the long-lived asset is measured by comparing the long-lived
asset’s carrying value to the sum of undiscounted future cash flows expected to
result from the use and eventual disposition of the asset. If the carrying value
is greater than the undiscounted future cash flows of the long-lived asset an
impairment exists and a loss is recognized for the amount by which the carrying
value of the long-lived asset exceeds its estimated fair value.
Goodwill
In a business
combination, the excess of the purchase price over the estimated fair values of
assets acquired and liabilities assumed is recognized as goodwill. Based on the
guidance provided by accounting standards for the recognition and subsequent
measurement of goodwill, we evaluate goodwill for impairment at least annually
and make such evaluations more frequently if indicators of impairment arise. If
the fair value of a reporting unit is less than its carrying value (including
goodwill), the goodwill is tested for impairment. If impairment is indicated a
loss is recognized– calculated as the difference between the implied fair value
of a reporting unit's goodwill and the carrying value of the
goodwill.
The forecasts used
in FirstEnergy's evaluations of goodwill reflect operations consistent with its
general business assumptions. Unanticipated changes in those assumptions could
have a significant effect on FirstEnergy's future evaluations of goodwill.
FirstEnergy's goodwill primarily relates to its energy delivery services
segment.
FirstEnergy’s 2009
annual review was completed as of July 31, with no impairment
indicated.
FirstEnergy’s 2008
annual review was completed in the third quarter of 2008 with no impairment
indicated. Due to the significant downturn in the U.S. economy during the fourth
quarter of 2008, goodwill was tested for impairment as of December 31, 2008. No
impairment was indicated for the former GPU companies. As discussed in Note
11(B) on February 19, 2009, the Ohio Companies filed an application for an
amended ESP, which substantially reflected terms proposed by the PUCO Staff on
February 2, 2009. Goodwill for the Ohio Companies was tested as of December 31,
2008, reflecting the projected results associated with the amended ESP. No
impairment was indicated for the Ohio Companies. The PUCO’s final decision did
not result in an additional impairment charge. During 2008, FirstEnergy adjusted
goodwill of the former GPU companies by $32 million due to the realization of
tax benefits that had been reserved under purchase accounting.
In 2007, FirstEnergy
adjusted goodwill for the former GPU companies by $290 million due to the
realization of tax benefits that had been reserved in purchase
accounting.
190
A summary of the
changes in goodwill for the three years ended December 31, 2009 is shown below
by operating segment, which represent aggregated reporting units (see Note 16 -
Segment Information):
|
Energy
|
Competitive
|
|||||||||||||||
|
Delivery
|
Energy
|
|||||||||||||||
|
Services
|
Services
|
Other
|
Consolidated
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Balance as of
January 1, 2007
|
$ | 5,873 | $ | 24 | $ | 1 | $ | 5,898 | ||||||||
|
Adjustments
related to GPU acquisition
|
(290 | ) | - | - | (290 | ) | ||||||||||
|
Other
|
- | - | (1 | ) | (1 | ) | ||||||||||
|
Balance as of
December 31, 2007
|
5,583 | 24 | - | 5,607 | ||||||||||||
|
Adjustments
related to GPU acquisition
|
(32 | ) | - | - | (32 | ) | ||||||||||
|
Balance as of
December 31, 2008 and 2009
|
$ | 5,551 | $ | 24 | $ | - | $ | 5,575 | ||||||||
A
summary of the changes in FES’ and the Utilities’ goodwill for the three years
ended December 31, 2009 is shown below.
|
Goodwill
|
FES
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||
|
Balance as of
January 1, 2007
|
$ | 24 | $ | 1,689 | $ | 501 | $ | 1,962 | $ | 496 | $ | 861 | ||||||||||||
|
Adjustments
related to GPU acquisition
|
- | - | - | (136 | ) | (72 | ) | (83 | ) | |||||||||||||||
|
Balance as of
December 31, 2007
|
24 | 1,689 | 501 | 1,826 | 424 | 778 | ||||||||||||||||||
|
Adjustments
related to GPU acquisition
|
- | - | - | (15 | ) | (8 | ) | (9 | ) | |||||||||||||||
|
Balance as of
December 31, 2008 and 2009
|
$ | 24 | $ | 1,689 | $ | 501 | $ | 1,811 | $ | 416 | $ | 769 | ||||||||||||
FirstEnergy, FES and
the Utilities, with the exception of Met-Ed as noted below, have no accumulated
impairment charge as of December 31, 2009. Met-Ed has an accumulated
impairment charge of $355 million, which was recorded in 2006.
Investments
At the end of each
reporting period, FirstEnergy evaluates its investments for impairment.
Investments classified as available-for-sale securities are evaluated to
determine whether a decline in fair value below the cost basis is other than
temporary. FirstEnergy first considers its intent and ability to hold the
investment until recovery and then considers, among other factors, the duration
and the extent to which the security's fair value has been less than its cost
and the near-term financial prospects of the security issuer when evaluating
investments for impairment. If the decline in fair value is determined to be
other than temporary, the cost basis of the investment is written down to fair
value. FirstEnergy recognizes in earnings the unrealized losses on
available-for-sale securities held in its nuclear decommissioning trusts since
the trust arrangements, as they are currently defined, do not meet the required
ability and intent to hold criteria in consideration of other-than-temporary
impairment. In 2009, 2008 and 2007, FirstEnergy recognized $62 million, $123
million and $26 million, respectively, of other-than-temporary impairments. The
fair value of FirstEnergy’s investments are disclosed in Note 5(B).
(F) COMPREHENSIVE
INCOME
Comprehensive income
includes net income as reported on the Consolidated Statements of Income and all
other changes in common stockholders' equity except those resulting from
transactions with stockholders and adjustments relating to noncontrolling
interests. Accumulated other comprehensive income (loss), net of tax, included
on FE's, FES' and the Utilities' Consolidated Balance Sheets as of December 31,
2009 and 2008, is comprised of the following:
|
Accumulated
Other Comprehensive Income (Loss)
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
Net liability
for unfunded retirement benefits
|
$ | (1,341 | ) | $ | (91 | ) | $ | (164 | ) | $ | (138 | ) | $ | (50 | ) | $ | (242 | ) | $ | (143 | ) | $ | (162 | ) | ||||||||
|
Unrealized
gain on investments
|
2 | 2 | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Unrealized
loss on derivative hedges
|
(76 | ) | (14 | ) | - | - | - | (1 | ) | (1 | ) | - | ||||||||||||||||||||
|
AOCL Balance,
December 31, 2009
|
$ | (1,415 | ) | $ | (103 | ) | $ | (164 | ) | $ | (138 | ) | $ | (50 | ) | $ | (243 | ) | $ | (144 | ) | $ | (162 | ) | ||||||||
|
Net liability
for unfunded retirement benefits
|
$ | (1,322 | ) | $ | (97 | ) | $ | (190 | ) | $ | (135 | ) | $ | (43 | ) | $ | (215 | ) | $ | (140 | ) | $ | (128 | ) | ||||||||
|
Unrealized
gain on investments
|
45 | 30 | 6 | - | 10 | - | - | - | ||||||||||||||||||||||||
|
Unrealized
loss on derivative hedges
|
(103 | ) | (25 | ) | - | - | - | (2 | ) | (1 | ) | - | ||||||||||||||||||||
|
AOCL Balance,
December 31, 2008
|
$ | (1,380 | ) | $ | (92 | ) | $ | (184 | ) | $ | (135 | ) | $ | (33 | ) | $ | (217 | ) | $ | (141 | ) | $ | (128 | ) | ||||||||
191
Other comprehensive
income (loss) reclassified to net income during the three years ended December
31, 2009, 2008 and 2007 was as follows:
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
2009
|
(In
millions)
|
|||||||||||||||||||||||||||||||
|
Pension and
other postretirement benefits
|
$ | (78 | ) | $ | (3 | ) | $ | (5 | ) | $ | (11 | ) | $ | (2 | ) | $ | (18 | ) | $ | (11 | ) | $ | (5 | ) | ||||||||
|
Gain on
investments
|
157 | 139 | 10 | - | 7 | - | - | - | ||||||||||||||||||||||||
|
Loss on
derivative hedges
|
(67 | ) | (27 | ) | - | - | - | - | - | - | ||||||||||||||||||||||
| 12 | 109 | 5 | (11 | ) | 5 | (18 | ) | (11 | ) | (5 | ) | |||||||||||||||||||||
|
Income taxes
(benefits) related to reclassification to net income
|
4 | 41 | 2 | (4 | ) | 2 | (8 | ) | (5 | ) | (2 | ) | ||||||||||||||||||||
|
Reclassification
to net income
|
$ | 8 | $ | 68 | $ | 3 | $ | (7 | ) | $ | 3 | $ | (10 | ) | $ | (6 | ) | $ | (3 | ) | ||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Pension and
other postretirement benefits
|
$ | 80 | $ | 7 | $ | 16 | $ | 1 | $ | - | $ | 14 | $ | 9 | $ | 14 | ||||||||||||||||
|
Gain on
investments
|
40 | 31 | 9 | - | 1 | - | - | - | ||||||||||||||||||||||||
|
Loss on
derivative hedges
|
(19 | ) | (3 | ) | - | - | - | - | - | - | ||||||||||||||||||||||
| 101 | 35 | 25 | 1 | 1 | 14 | 9 | 14 | |||||||||||||||||||||||||
|
Income taxes
related to reclassification to net income
|
41 | 14 | 10 | - | - | 6 | 4 | 6 | ||||||||||||||||||||||||
|
Reclassification
to net income
|
$ | 60 | $ | 21 | 15 | 1 | 1 | 8 | 5 | 8 | ||||||||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Pension and
other postretirement benefits
|
$ | 45 | $ | 5 | $ | 14 | $ | (5 | ) | $ | (2 | ) | $ | 8 | $ | 6 | $ | 11 | ||||||||||||||
|
Gain on
investments
|
10 | 10 | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Loss on
derivative hedges
|
(26 | ) | (12 | ) | - | - | - | - | - | - | ||||||||||||||||||||||
| 29 | 3 | 14 | (5 | ) | (2 | ) | 8 | 6 | 11 | |||||||||||||||||||||||
|
Income taxes
(benefits) related to reclassification to net
income
|
14 | 1 | 6 | (2 | ) | (1 | ) | 4 | 3 | 5 | ||||||||||||||||||||||
|
Reclassification
to net income
|
$ | 15 | $ | 2 | $ | 8 | $ | (3 | ) | $ | (1 | ) | $ | 4 | $ | 3 | $ | 6 | ||||||||||||||
3. PENSION
AND OTHER POSTRETIREMENT BENEFIT PLANS
FirstEnergy provides
a noncontributory qualified defined benefit pension plan that covers
substantially all of its employees and non-qualified pension plans that cover
certain employees. The plans provide defined benefits based on years of service
and compensation levels. FirstEnergy's funding policy is based on actuarial
computations using the projected unit credit method. On September 2, 2009, the
Utilities and ATSI made a combined $500 million voluntary contribution to their
qualified pension plan. Due to the significance of the voluntary contribution,
FirstEnergy elected to remeasure its qualified pension plan as of August 31,
2009. FirstEnergy estimates that additional cash contributions will not be
required by law before 2012.
FirstEnergy provides
a minimum amount of noncontributory life insurance to retired employees in
addition to optional contributory insurance. Health care benefits, which include
certain employee contributions, deductibles and co-payments, are also available
upon retirement to employees hired prior to January 1, 2005, their dependents
and, under certain circumstances, their survivors. FirstEnergy recognizes the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits. During 2006, FirstEnergy amended
the OPEB plan effective in 2008 to cap the monthly contribution for many of the
retirees and their spouses receiving subsidized health care coverage. During
2008, FirstEnergy further amended the OPEB plan effective in 2010 to limit the
monthly contribution for pre-1990 retirees. On June 2, 2009, FirstEnergy amended
its health care benefits plan for all employees and retirees eligible to
participate in that plan. The amendment, which reduces future health care
coverage subsidies paid by FirstEnergy on behalf of participants, triggered a
remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31,
2009. FirstEnergy also has obligations to former or inactive employees after
employment, but before retirement, for disability-related benefits.
Pension and OPEB
costs are affected by employee demographics (including age, compensation levels,
and employment periods), the level of contributions made to the plans and
earnings on plan assets. Pension and OPEB costs may also be affected by changes
in key assumptions, including anticipated rates of return on plan assets, the
discount rates and health care trend rates used in determining the projected
benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31
measurement date for its pension and OPEB plans. The fair value of the plan
assets represents the actual market value as of the measurement
date.
192
In the third quarter
of 2009, FirstEnergy incurred a $13 million net postretirement benefit cost
(including amounts capitalized) related to a liability created by the VERO
offered by FirstEnergy to qualified employees. The special termination benefits
of the VERO included additional health care coverage subsidies paid by
FirstEnergy to those qualified employees who elected to retire. A total of 715
employees accepted the VERO.
|
Obligations
and Funded Status
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||
|
As
of December 31
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Change
in benefit obligation
|
||||||||||||||||
|
Benefit
obligation as of January 1
|
$ | 4,700 | $ | 4,750 | $ | 1,189 | $ | 1,182 | ||||||||
|
Service
cost
|
91 | 87 | 12 | 19 | ||||||||||||
|
Interest
cost
|
317 | 299 | 64 | 74 | ||||||||||||
|
Plan
participants’ contributions
|
- | - | 29 | 25 | ||||||||||||
|
Plan
amendments
|
6 | 6 | (408 | ) | (20 | ) | ||||||||||
|
Special
termination benefits
|
- | - | 13 | - | ||||||||||||
|
Medicare
retiree drug subsidy
|
- | - | 20 | 2 | ||||||||||||
|
Actuarial
(gain) loss
|
648 | (152 | ) | 23 | 12 | |||||||||||
|
Benefits
paid
|
(370 | ) | (290 | ) | (119 | ) | (105 | ) | ||||||||
|
Benefit
obligation as of December 31
|
$ | 5,392 | $ | 4,700 | $ | 823 | $ | 1,189 | ||||||||
|
Change
in fair value of plan assets
|
||||||||||||||||
|
Fair value of
plan assets as of January 1
|
$ | 3,752 | $ | 5,285 | $ | 440 | $ | 618 | ||||||||
|
Actual return
on plan assets
|
508 | (1,251 | ) | 62 | (152 | ) | ||||||||||
|
Company
contributions
|
509 | 8 | 55 | 54 | ||||||||||||
|
Plan
participants’ contributions
|
- | - | 29 | 25 | ||||||||||||
|
Benefits
paid
|
(370 | ) | (290 | ) | (119 | ) | (105 | ) | ||||||||
|
Fair value of
plan assets as of December 31
|
$ | 4,399 | $ | 3,752 | $ | 467 | $ | 440 | ||||||||
|
Funded
Status
|
||||||||||||||||
|
Qualified
plan
|
$ | (787 | ) | $ | (774 | ) | ||||||||||
|
Non-qualified
plans
|
(206 | ) | (174 | ) | ||||||||||||
|
Funded
status
|
$ | (993 | ) | $ | (948 | ) | $ | (356 | ) | $ | (749 | ) | ||||
|
Accumulated
benefit obligation
|
$ | 5,036 | $ | 4,367 | ||||||||||||
|
Amounts
Recognized on the Balance Sheet
|
||||||||||||||||
|
Current
liabilities
|
$ | (10 | ) | $ | (8 | ) | $ | - | $ | - | ||||||
|
Noncurrent
liabilities
|
(983 | ) | (940 | ) | (356 | ) | (749 | ) | ||||||||
|
Net liability
as of December 31
|
$ | (993 | ) | $ | (948 | ) | $ | (356 | ) | $ | (749 | ) | ||||
|
Amounts
Recognized in
|
||||||||||||||||
|
Accumulated
Other Comprehensive Income
|
||||||||||||||||
|
Prior service
cost (credit)
|
$ | 67 | $ | 80 | $ | (1,145 | ) | $ | (912 | ) | ||||||
|
Actuarial
loss
|
2,486 | 2,182 | 756 | 801 | ||||||||||||
|
Net amount
recognized
|
$ | 2,553 | $ | 2,262 | $ | (389 | ) | $ | (111 | ) | ||||||
|
Assumptions
Used to Determine Benefit
|
||||||||||||||||
|
Obligations
as of December 31
|
||||||||||||||||
|
Discount
rate
|
6.00 | % | 7.00 | % | 5.75 | % | 7.00 | % | ||||||||
|
Rate of
compensation increase
|
5.20 | % | 5.20 | % | ||||||||||||
|
Allocation
of Plan Assets
|
||||||||||||||||
|
As
of December 31
|
||||||||||||||||
|
Equity
securities
|
39 | % | 47 | % | 51 | % | 56 | % | ||||||||
|
Bonds
|
49 | 38 | 46 | 38 | ||||||||||||
|
Real
estate
|
6 | 9 | 1 | 2 | ||||||||||||
|
Private
equities
|
5 | 3 | 1 | 1 | ||||||||||||
|
Cash
|
1 | 3 | 1 | 3 | ||||||||||||
|
Total
|
100 | % | 100 | % | 100 | % | 100 | % | ||||||||
193
|
Estimated
2010 Amortization of
|
||||||||
|
Net
Periodic Pension Cost from
|
Pension
|
Other
|
||||||
|
Accumulated
Other Comprehensive Income
|
Benefits
|
Benefits
|
||||||
|
(In
millions)
|
||||||||
|
Prior service
cost (credit)
|
$ | 13 | $ | (193 | ) | |||
|
Actuarial
loss
|
$ | 188 | $ | 60 | ||||
|
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||||||
|
Components
of Net Periodic Benefit Costs
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||||||||||||
|
|
(In
millions)
|
|||||||||||||||||||||||
|
Service
cost
|
$ | 91 | $ | 87 | $ | 88 | $ | 12 | $ | 19 | $ | 21 | ||||||||||||
|
Interest
cost
|
317 | 299 | 294 | 64 | 74 | 69 | ||||||||||||||||||
|
Expected
return on plan assets
|
(343 | ) | (463 | ) | (449 | ) | (36 | ) | (51 | ) | (50 | ) | ||||||||||||
|
Amortization
of prior service cost
|
13 | 13 | 13 | (175 | ) | (149 | ) | (149 | ) | |||||||||||||||
|
Amortization
of net actuarial loss
|
179 | 8 | 45 | 61 | 47 | 45 | ||||||||||||||||||
|
Net periodic
cost
|
$ | 257 | $ | (56 | ) | $ | (9 | ) | $ | (74 | ) | $ | (60 | ) | $ | (64 | ) | |||||||
FES’ and the
Utilities’ shares of the net pension and OPEB asset (liability) as of December
31, 2009 and 2008 are as follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||
|
Net
Pension and OPEB Asset (Liability)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
FES
|
$ | (361 | ) | $ | (193 | ) | $ | (19 | ) | $ | (124 | ) | ||||
|
OE
|
30 | (38 | ) | (74 | ) | (167 | ) | |||||||||
|
CEI
|
(13 | ) | (27 | ) | (59 | ) | (93 | ) | ||||||||
|
TE
|
(15 | ) | (12 | ) | (47 | ) | (59 | ) | ||||||||
|
JCP&L
|
(77 | ) | (128 | ) | (56 | ) | (58 | ) | ||||||||
|
Met-Ed
|
6 | (89 | ) | (28 | ) | (52 | ) | |||||||||
|
Penelec
|
(79 | ) | (64 | ) | (84 | ) | (103 | ) | ||||||||
FES’ and the
Utilities’ shares of the net periodic pension and OPEB costs for the three years
ended December 31, 2009 are as follows:
|
Pension
Benefits
|
Other
Benefits
|
|||||||||||||||||||||||
|
Net
Periodic Pension and OPEB Costs
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||||||||||||
|
|
(In
millions)
|
|||||||||||||||||||||||
|
FES
|
$ | 71 | $ | 15 | $ | 21 | $ | (15 | ) | $ | (7 | ) | $ | (10 | ) | |||||||||
|
OE
|
23 | (26 | ) | (16 | ) | (14 | ) | (7 | ) | (11 | ) | |||||||||||||
|
CEI
|
17 | (5 | ) | 1 | - | 2 | 4 | |||||||||||||||||
|
TE
|
6 | (3 | ) | - | 2 | 4 | 5 | |||||||||||||||||
|
JCP&L
|
31 | (15 | ) | (9 | ) | (6 | ) | (16 | ) | (16 | ) | |||||||||||||
|
Met-Ed
|
18 | (10 | ) | (7 | ) | (4 | ) | (10 | ) | (10 | ) | |||||||||||||
|
Penelec
|
16 | (13 | ) | (10 | ) | (4 | ) | (13 | ) | (13 | ) | |||||||||||||
|
Assumptions
Used
|
|
|
|
|
|
|
||||||||||||||||||
|
to
Determine Net Periodic Benefit Cost
|
Pension
Benefits
|
Other
Benefits
|
||||||||||||||||||||||
|
for
Years Ended December 31
|
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||||||||||||
|
Weighted-average
discount rate
|
7.00 | % | 6.50 | % | 6.00 | % | 7.00 | % | 6.50 | % | 6.00 | % | ||||||||||||
|
Expected
long-term return on plan assets
|
9.00 | % | 9.00 | % | 9.00 | % | 9.00 | % | 9.00 | % | 9.00 | % | ||||||||||||
|
Rate of
compensation increase
|
5.20 | % | 5.20 | % | 3.50 | % | ||||||||||||||||||
Accounting guidance
establishes a fair value hierarchy that prioritizes the inputs used to measure
fair value. The hierarchy gives the highest priority to unadjusted quoted market
prices in active markets for identical assets or liabilities (Level 1) and the
lowest priority to unobservable inputs (Level 3). The three levels of the fair
value hierarchy defined by accounting guidance are as follows:
Level 1 – Quoted
prices are available in active markets for identical assets or liabilities as of
the reporting date. Active markets are those where transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis. Level 1 assets include registered investment
companies, common stocks, publicly traded real estate investment trusts and
certain shorter duration, more liquid fixed income securities. Registered
investment companies and common stocks are stated at fair value as quoted on a
recognized securities exchange and are valued at the last reported sales price
on the last business day of the plan year. Real estate investment
trusts’ and certain fixed income securities’ market values are based on daily
quotes available on public exchanges as with other publicly traded equity and
fixed income securities.
194
Level 2 – Pricing
inputs are either directly or indirectly observable in the market as of the
reporting date, other than quoted prices in active markets included in Level 1.
Additionally, Level 2 includes those financial instruments that are valued using
models or other valuation methodologies based on assumptions that are observable
in the marketplace throughout the full term of the instrument, can be derived
from observable data or are supported by observable levels at which transactions
are executed in the marketplace. These models are primarily industry-standard
models that consider various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market and contractual
prices for the underlying instruments, as well as other relevant economic
measures. Level 2 investments include common collective trusts, certain real
estate investment trusts, and fixed income assets. Common collective trusts are
not available in an exchange and active market, however, the fair value is
determined based on the underlying investments as traded in an exchange and
active market.
Level 3 – Pricing
inputs include inputs that are generally less observable from objective sources.
These inputs may be used with internally developed methodologies that result in
management’s best estimate of fair value in addition to the use of independent
appraisers’ estimates of fair value on a periodic basis typically determined
quarterly, but no less than annually. Assets in this category include private
equity, limited partnership, certain real estate trusts and fixed income
securities. The fixed income securities’ market values are
based in part on quantitative models and on observing market value ascertained
through timely trades for securities’ that are similar in nature to the ones
being valued.
As of December 31,
2009, the pension investments measured at fair value were as
follows:
|
December
31, 2009
|
Asset | |||||||||||||||||||
|
Level
1
|
Level
2
|
Level
3
|
Total
|
Allocation
|
||||||||||||||||
|
Assets
|
(in
millions)
|
|||||||||||||||||||
|
Short-term
securities
|
$ | - | $ | 337 | $ | - | $ | 337 | 7 | % | ||||||||||
|
Common and
preferred stocks
|
578 | 994 | - | 1,572 | 36 | % | ||||||||||||||
|
Mutual
funds
|
159 | - | - | 159 | 4 | % | ||||||||||||||
|
Bonds
|
- | 1,928 | - | 1,928 | 44 | % | ||||||||||||||
|
Real
estate/other assets
|
1 | 4 | 378 | 383 | 9 | % | ||||||||||||||
| $ | 738 | $ | 3,263 | $ | 378 | $ | 4,379 | 100 | % | |||||||||||
The following table
provides a reconciliation of changes in the fair value of pension investments
classified as Level 3 in the fair value hierarchy during 2009:
|
Real
estate / Other assets
|
||||
|
(in
millions)
|
||||
|
Beginning
balance
|
$
|
416
|
||
|
Transfers
|
44
|
|||
|
Acquisitions/(Dispositions)
|
16
|
|||
|
Loss
|
(98
|
)
|
||
|
Ending
balance
|
$
|
378
|
||
As of December 31,
2009, the other postretirement benefit investments measured at fair value were
as follows:
|
December
31, 2009
|
Asset | |||||||||||||||||||
|
Level
1
|
Level
2
|
Level
3
|
Total
|
Allocation
|
||||||||||||||||
|
Assets
|
(in
millions)
|
|||||||||||||||||||
|
Short-term
securities
|
$ | - | $ | 19 | $ | - | $ | 19 | 4 | % | ||||||||||
|
Common and
preferred stocks
|
172 | 53 | - | 225 | 47 | % | ||||||||||||||
|
Mutual
funds
|
10 | 2 | - | 12 | 3 | % | ||||||||||||||
|
Bonds
|
- | 208 | - | 208 | 44 | % | ||||||||||||||
|
Real
estate/other assets
|
- | - | 11 | 11 | 2 | % | ||||||||||||||
| $ | 182 | $ | 282 | $ | 11 | $ | 475 | 100 | % | |||||||||||
The following table
provides a reconciliation of changes in the fair value of the other
postretirement benefit investments classified as Level 3 in the fair value
hierarchy during 2009:
|
Real
estate / Other assets
|
||||
|
(in
millions)
|
||||
|
Beginning
balance
|
$
|
12
|
||
|
Transfers
|
1
|
|||
|
Acquisitions/(Dispositions)
|
1
|
|||
|
Loss
|
(3
|
)
|
||
|
Ending
balance
|
$
|
11
|
||
195
In selecting an
assumed discount rate, FirstEnergy considers currently available rates of return
on high-quality fixed income investments expected to be available during the
period to maturity of the pension and other postretirement benefit obligations.
The assumed rates of return on pension plan assets consider historical market
returns and economic forecasts for the types of investments held by
FirstEnergy's pension trusts. The long-term rate of return is developed
considering the portfolio’s asset allocation strategy.
FirstEnergy
generally employs a total return investment approach whereby a mix of equities
and fixed income investments are used to maximize the long-term return on plan
assets for a prudent level of risk. Risk tolerance is established through
careful consideration of plan liabilities, plan funded status and corporate
financial condition. The investment portfolio contains a diversified blend of
equity and fixed-income investments. Equity investments are diversified across
U.S. and non-U.S. stocks, as well as growth, value, and small and large
capitalization funds. Other assets such as real estate and private equity are
used to enhance long-term returns while improving portfolio diversification.
Derivatives may be used to gain market exposure in an efficient and timely
manner; however, derivatives are not used to leverage the portfolio beyond the
market value of the underlying investments. Investment risk is measured and
monitored on a continuing basis through periodic investment portfolio reviews,
annual liability measurements, and periodic asset/liability
studies.
FirstEnergy’s target
asset allocations for its pension and OPEB portfolio for 2009 and 2008 are shown
in the following table:
|
Target
Asset Allocations
|
||||||||
|
2009
|
2008
|
|||||||
|
Equities
|
58 | % | 58 | % | ||||
|
Fixed
income
|
30 | % | 30 | % | ||||
|
Real
estate
|
8 | % | 8 | % | ||||
|
Private
equity
|
4 | % | 4 | % | ||||
|
Total
|
100 | % | 100 | % | ||||
|
Assumed
Health Care Cost Trend Rates As of December 31
|
2009
|
2008
|
||||||
|
Health care
cost trend rate assumed for next year
(pre/post-Medicare)
|
8.5-10 | % | 8.5-10 | % | ||||
|
Rate to which
the cost trend rate is assumed to decline (the ultimate trend
rate)
|
5 | % | 5 | % | ||||
|
Year that the
rate reaches the ultimate trend rate
(pre/post-Medicare)
|
2016-2018 | 2015-2017 | ||||||
Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plans. A one-percentage-point change in assumed health care cost
trend rates would have the following effects:
|
1-Percentage-
|
1-Percentage-
|
|||||||
|
Point
Increase
|
Point
Decrease
|
|||||||
|
(In
millions)
|
||||||||
|
Effect on
total of service and interest cost
|
$ | 3 | $ | (2 | ) | |||
|
Effect on
accumulated postretirement benefit obligation
|
$ | 20 | $ | (18 | ) | |||
Taking into account
estimated employee future service, FirstEnergy expects to make the following
pension benefit payments from plan assets and other benefit payments, net of the
Medicare subsidy and participant contributions:
|
Pension
|
Other
|
|||||||
|
Benefits
|
Benefits
|
|||||||
|
(In
millions)
|
||||||||
|
2010
|
$ | 316 | $ | 85 | ||||
|
2011
|
324 | 87 | ||||||
|
2012
|
336 | 58 | ||||||
|
2013
|
346 | 51 | ||||||
|
2014
|
364 | 53 | ||||||
|
Years 2015-
2019
|
1,999 | 273 | ||||||
196
4. STOCK-BASED
COMPENSATION PLANS
FirstEnergy has four
stock-based compensation programs – LTIP, EDCP, ESOP and DCPD. In 2001,
FirstEnergy also assumed responsibility for two stock-based plans as a result of
its acquisition of GPU. No further stock-based compensation can be awarded under
GPU’s Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR
Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan).
All options and restricted stock under both plans have been converted into
FirstEnergy options and restricted stock. Options under the GPU Plan became
fully vested on November 7, 2001, and will expire on or before June 1,
2010.
|
(A)
|
LTIP
|
FirstEnergy’s LTIP
includes four stock-based compensation programs – restricted stock, restricted
stock units, stock options and performance shares.
Under FirstEnergy’s
LTIP, total awards cannot exceed 29.1 million shares of common stock or their
equivalent. Only stock options, restricted stock and restricted stock units have
currently been designated to pay out in common stock, with vesting periods
ranging from two months to ten years. Performance share awards are currently
designated to be paid in cash rather than common stock and therefore do not
count against the limit on stock-based awards. As of December 31, 2009, 7.9
million shares were available for future awards.
FirstEnergy records
the actual tax benefit realized for tax deductions when awards are exercised or
distributed. Realized tax benefits during the years ended December 31, 2009,
2008, and 2007 were $9 million, $43 million, and $34 million, respectively. The
excess of the deductible amount over the recognized compensation cost is
recorded to stockholders’ equity and reported as an other financing activity
within the Consolidated Statements of Cash Flows.
Restricted
Stock and Restricted Stock Units
Eligible employees
receive awards of FirstEnergy common stock or stock units subject to
restrictions. Those restrictions lapse over a defined period of time or based on
performance. Dividends are received on the restricted stock and are reinvested
in additional shares. Restricted common stock grants under the LTIP were as
follows:
|
2009
|
2008
|
2007
|
||||||||||
|
Restricted
common shares granted
|
73,255 | 82,607 | 77,388 | |||||||||
|
Weighted
average market price
|
$ | 43.68 | $ | 68.98 | $ | 67.98 | ||||||
|
Weighted
average vesting period (years)
|
4.42 | 5.03 | 4.61 | |||||||||
|
Dividends
restricted
|
Yes
|
Yes
|
Yes
|
|||||||||
Vesting activity for
restricted common stock during the year was as follows (forfeitures were not
material):
|
Weighted
|
||||||||
|
Number
|
Average
|
|||||||
|
of
|
Grant-Date
|
|||||||
|
Restricted
Stock
|
Shares
|
Fair
Value
|
||||||
|
Nonvested as
of January 1, 2009
|
667,933 | $ | 49.54 | |||||
|
Nonvested as
of December 31, 2009
|
648,293 | 48.84 | ||||||
|
Granted in
2009
|
73,255 | 43.68 | ||||||
|
Vested in
2009
|
85,881 | 42.73 | ||||||
FirstEnergy grants
two types of restricted stock unit awards: discretionary-based and
performance-based. With the discretionary-based, FirstEnergy grants the right to
receive, at the end of the period of restriction, a number of shares of common
stock equal to the number of restricted stock units set forth in each agreement.
With the performance-based, FirstEnergy grants the right to receive, at the end
of the period of restriction, a number of shares of common stock equal to the
number of restricted stock units set forth in the agreement subject to
adjustment based on FirstEnergy’s stock performance.
|
2009
|
2008
|
2007
|
||||||||||
|
Restricted
common share units granted
|
533,399 | 450,683 | 412,426 | |||||||||
|
Weighted
average vesting period (years)
|
3.00 | 3.14 | 3.22 | |||||||||
197
Vesting activity for
restricted stock units during the year was as follows (forfeitures were not
material):
|
Weighted
|
||||||||
|
Number
|
Average
|
|||||||
|
of
|
Grant-Date
|
|||||||
|
Restricted
Stock Units
|
Shares
|
Fair
Value
|
||||||
|
Nonvested as
of January 1, 2009
|
1,011,054 | $ | 62.02 | |||||
|
Nonvested as
of December 31, 2009
|
1,031,050 | 60.10 | ||||||
|
Granted in
2009
|
533,399 | 41.40 | ||||||
|
Vested in
2009
|
457,536 | 42.53 | ||||||
Compensation expense
recognized in 2009, 2008 and 2007 for restricted stock and restricted stock
units, net of amounts capitalized, was approximately $25 million, $29 million
and $24 million, respectively.
Stock
Options
Stock options were
granted to eligible employees allowing them to purchase a specified number of
common shares at a fixed grant price over a defined period of time. Stock option
activities under FirstEnergy stock option programs for 2009 were as
follows:
|
Weighted
|
||||||||
|
Number
|
Average
|
|||||||
|
of
|
Exercise
|
|||||||
|
Stock
Option Activities
|
Options
|
Price
|
||||||
|
Balance,
January 1, 2009
|
3,266,408 | $ | 34.56 | |||||
|
(3,266,408
options exercisable)
|
||||||||
|
Options
granted
|
- | - | ||||||
|
Options
exercised
|
178,133 | 32.53 | ||||||
|
Options
forfeited
|
21,075 | 30.50 | ||||||
|
Balance,
December 31, 2009
|
3,067,200 | $ | 34.70 | |||||
|
(3,067,200
options exercisable)
|
||||||||
Options outstanding
by plan and range of exercise price as of December 31, 2009 were as
follows:
|
Options
Outstanding and Exercisable
|
||||||||||||||||
|
Weighted
|
||||||||||||||||
|
Range
of
|
Average
|
Remaining
|
||||||||||||||
|
Program
|
Exercise
Prices
|
Shares
|
Exercise
Price
|
Contractual
Life
|
||||||||||||
|
FE
Plan
|
$ | 19.31 - $29.87 | 1,040,749 | $ | 29.22 | 2.34 | ||||||||||
| $ | 30.17 - $39.46 | 2,010,104 | $ | 37.63 | 3.67 | |||||||||||
|
GPU
Plan
|
$ | 23.75 - $35.92 | 16,347 | $ | 23.75 | 0.42 | ||||||||||
|
Total
|
3,067,200 | $ | 34.70 | 3.20 | ||||||||||||
FirstEnergy reduced
its use of stock options beginning in 2005 and increased its use of
performance-based, restricted stock units. As a result, all unvested stock
options vested in 2008. No compensation expense was recognized for stock options
during 2009, and compensation expense in 2008 and 2007 was not material. Cash
received from the exercise of stock options in 2009, 2008 and 2007 was $7
million, $74 million and $88 million, respectively.
Performance
Shares
Performance shares
are share equivalents and do not have voting rights. The shares track the
performance of FirstEnergy's common stock over a three-year vesting period.
During that time, dividend equivalents are converted into additional shares. The
final account value may be adjusted based on the ranking of FirstEnergy stock
performance to a composite of peer companies. Compensation expense recognized
for performance shares during 2009, 2008 and 2007, net of amounts capitalized,
totaled approximately $3 million, $8 million and $20 million, respectively. Cash
used to settle performance shares in 2009, 2008 and 2007 was $15 million, $14
million and $10 million, respectively.
(B)
ESOP
An ESOP Trust funded
most of the matching contribution for FirstEnergy's 401(k) savings plan through
December 31, 2007. All employees eligible for participation in the 401(k)
savings plan are covered by the ESOP. Between 1990 and 1991, the ESOP borrowed
$200 million from OE and acquired 10,654,114 shares of OE's common stock
(subsequently converted to FirstEnergy common stock) through market purchases.
The ESOP loan was paid in full in 2008.
198
In 2008 and 2009,
shares of FirstEnergy common stock were purchased on the market and contributed
to participants’ accounts. Total ESOP-related compensation expenses in 2009,
2008 and 2007, net of amounts capitalized and dividends on common stock, were
$36 million, $40 million and $28 million, respectively.
(C)
EDCP
Under the EDCP,
covered employees can direct a portion of their compensation, including annual
incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy
stock account to receive vested stock units or into an unfunded retirement cash
account. An additional 20% premium is received in the form of stock units based
on the amount allocated to the FirstEnergy stock account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement (see Note 3). Interest is calculated on the cash allocated to
the cash account and the total balance will pay out in cash upon retirement. Of
the 1.3 million EDCP stock units authorized, 481,028 stock units were available
for future awards as of December 31, 2009. Compensation expense (income)
recognized on EDCP stock units, net of amounts capitalized, was not material in
2009, ($13) million in 2008 and $7 million in 2007, respectively.
|
(D)
|
DCPD
|
Under the DCPD,
directors can elect to allocate all or a portion of their cash retainers,
meeting fees and chair fees to deferred stock or deferred cash accounts. If the
funds are deferred into the stock account, a 20% match is added to the funds
allocated. The 20% match and any appreciation on it are forfeited if the
director leaves the Board within three years from the date of deferral for any
reason other than retirement, disability, death, upon a change in control, or
when a director is ineligible to stand for re-election. Compensation expense is
recognized for the 20% match over the three-year vesting period. Directors may
also elect to defer their equity retainers into the deferred stock account;
however, they do not receive a 20% match on that deferral. DCPD expenses
recognized in each of 2009, 2008 and 2007 were approximately $3 million. The net
liability recognized for DCPD of approximately $5 million as of December 31,
2009, 2008 and 2007 is included in the caption “Retirement benefits” on the
Consolidated Balance Sheets.
5. FAIR
VALUE OF FINANCIAL INSTRUMENTS
|
(A)
|
LONG-TERM
DEBT AND OTHER LONG-TERM
OBLIGATIONS
|
All borrowings with
initial maturities of less than one year are considered as short-term financial
instruments and are reported on the Consolidated Balance Sheets at cost (which
approximates their fair market value) under the caption "short-term borrowings."
The following table provides the approximate fair value and related carrying
amounts of long-term debt and other long-term obligations as of December 31,
2009 and 2008:
|
December 31,
2009
|
December 31,
2008
|
|||||||||||||||
|
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||
|
Value
|
Value
|
Value
|
Value
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
FirstEnergy
|
$ | 13,753 | $ | 14,502 | $ | 11,585 | $ | 11,146 | ||||||||
|
FES
|
4,224 | 4,306 | 2,552 | 2,528 | ||||||||||||
|
OE
|
1,169 | 1,299 | 1,232 | 1,223 | ||||||||||||
|
CEI
|
1,873 | 2,032 | 1,741 | 1,618 | ||||||||||||
|
TE
|
600 | 638 | 300 | 244 | ||||||||||||
|
JCP&L
|
1,840 | 1,950 | 1,569 | 1,520 | ||||||||||||
|
Met-Ed
|
842 | 909 | 542 | 519 | ||||||||||||
|
Penelec
|
1,144 | 1,177 | 779 | 721 | ||||||||||||
The fair values of
long-term debt and other long-term obligations reflect the present value of the
cash outflows relating to those securities based on the current call price, the
yield to maturity or the yield to call, as deemed appropriate at the end of each
respective period. The yields assumed were based on securities with similar
characteristics offered by corporations with credit ratings similar to those of
FES and the Utilities.
|
(B)
|
INVESTMENTS
|
All temporary cash
investments purchased with an initial maturity of three months or less are
reported as cash equivalents on the Consolidated Balance Sheets at cost, which
approximates their fair market value. Investments other than cash and cash
equivalents include held-to-maturity securities, available-for-sale securities,
and notes receivable.
199
FES and the
Utilities periodically evaluate their investments for other-than-temporary
impairment. They first consider their intent and ability to hold an equity
investment until recovery and then consider, among other factors, the duration
and the extent to which the security's fair value has been less than cost and
the near-term financial prospects of the security issuer when evaluating an
investment for impairment. For debt securities, FES and the Utilities consider
their intent to hold the security, the likelihood that they will be required to
sell the security before recovery of their cost basis, and the likelihood of
recovery of the security's entire amortized cost basis.
Available-For-Sale
Securities
FES and the
Utilities hold debt and equity securities within their nuclear decommissioning
trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are
considered as available-for-sale at fair market value. FES and the Utilities
have no securities held for trading purposes.
The following table
summarizes the cost basis, unrealized gains and losses and fair values of
investments in available-for-sale securities as of December 31, 2009 and
2008:
|
December 31,
2009
(1)
|
December 31,
2008
(2)
|
|||||||||||||||||||||||||||||||
|
Cost
|
Unrealized
|
Unrealized
|
Fair
|
Cost
|
Unrealized
|
Unrealized
|
Fair
|
|||||||||||||||||||||||||
|
Basis
|
Gains
|
Losses
|
Value
|
Basis
|
Gains
|
Losses
|
Value
|
|||||||||||||||||||||||||
|
Debt
securities
|
(In
millions)
|
|||||||||||||||||||||||||||||||
|
FirstEnergy
(3)
|
$ | 1,727 | $ | 22 | $ | - | $ | 1,749 | $ | 1,078 | $ | 56 | $ | - | $ | 1,134 | ||||||||||||||||
|
FES
|
1,043 | 3 | - | 1,046 | 401 | 28 | - | 429 | ||||||||||||||||||||||||
|
OE
|
55 | - | - | 55 | 86 | 9 | - | 95 | ||||||||||||||||||||||||
|
TE
|
72 | - | - | 72 | 66 | 8 | - | 74 | ||||||||||||||||||||||||
|
JCP&L
|
271 | 9 | - | 280 | 249 | 9 | - | 258 | ||||||||||||||||||||||||
|
Met-Ed
|
120 | 5 | - | 125 | 111 | 4 | - | 115 | ||||||||||||||||||||||||
|
Penelec
|
166 | 5 | - | 171 | 164 | 3 | - | 167 | ||||||||||||||||||||||||
|
Equity
securities
|
||||||||||||||||||||||||||||||||
|
FirstEnergy
|
$ | 252 | $ | 43 | $ | - | $ | 295 | $ | 589 | $ | 39 | $ | - | $ | 628 | ||||||||||||||||
|
FES
|
- | - | - | - | 355 | 25 | - | 380 | ||||||||||||||||||||||||
|
OE
|
- | - | - | - | 17 | 1 | - | 18 | ||||||||||||||||||||||||
|
JCP&L
|
74 | 11 | - | 85 | 64 | 2 | - | 66 | ||||||||||||||||||||||||
|
Met-Ed
|
117 | 23 | - | 140 | 101 | 9 | - | 110 | ||||||||||||||||||||||||
|
Penelec
|
61 | 9 | - | 70 | 51 | 2 | - | 53 | ||||||||||||||||||||||||
| (1) |
Excludes cash balances of $137
million at FirstEnergy, $43 million at FES, $3 million at JCP&L, $66
million at OE, $23 million at Penelec and $2 million at
TE.
|
|
Excludes cash balances of $244
million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4
million at OE and $1
million
at Met-Ed.
|
|
| (3) |
Includes fair values as of
December 31, 2009 and 2008 of $1,224 million and $953 million of
government obligations, $523 million and $175 million of corporate debt
and $1 million and $6 million of mortgage backed
securities.
|
Proceeds from the
sale of investments in available-for-sale securities, realized gains and losses
on those sales, and interest and dividend income for the three years ended
December 31 were as follows:
|
FirstEnergy
|
FES
|
OE
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
||||||||||||||||||||||
|
2009
|
(In
millions)
|
|||||||||||||||||||||||||||
|
Proceeds from
sales
|
$ | 2,229 | $ | 1,379 | $ | 132 | $ | 169 | $ | 397 | $ | 68 | $ | 84 | ||||||||||||||
|
Realized
gains
|
226 | 199 | 11 | 7 | 6 | 2 | 1 | |||||||||||||||||||||
|
Realized
losses
|
155 | 117 | 4 | 1 | 12 | 13 | 8 | |||||||||||||||||||||
|
Interest and
dividend income
|
60 | 27 | 4 | 2 | 14 | 7 | 6 | |||||||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||
|
Proceeds from
sales
|
$ | 1,657 | $ | 951 | $ | 121 | $ | 38 | $ | 248 | $ | 181 | $ | 118 | ||||||||||||||
|
Realized
gains
|
115 | 99 | 11 | 1 | 1 | 2 | 1 | |||||||||||||||||||||
|
Realized
losses
|
237 | 184 | 9 | - | 17 | 17 | 10 | |||||||||||||||||||||
|
Interest and
dividend income
|
76 | 37 | 5 | 3 | 14 | 9 | 8 | |||||||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||
|
Proceeds from
sales
|
$ | 1,295 | $ | 656 | $ | 38 | $ | 45 | $ | 196 | $ | 185 | $ | 175 | ||||||||||||||
|
Realized
gains
|
103 | 29 | 1 | 1 | 23 | 30 | 19 | |||||||||||||||||||||
|
Realized
losses
|
53 | 42 | 4 | 1 | 3 | 2 | 1 | |||||||||||||||||||||
|
Interest and
dividend income
|
80 | 42 | 4 | 3 | 13 | 8 | 10 | |||||||||||||||||||||
200
Unrealized
gains applicable to the decommissioning trusts of FES, OE and TE are recognized
in OCI as fluctuations in fair value will eventually impact earnings. The
decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to
regulatory accounting. Net unrealized gains and losses are recorded as
regulatory assets or liabilities since the difference between investments held
in trust and the decommissioning liabilities will be recovered from or refunded
to customers.
The
investment policy for the nuclear decommissioning trust funds restricts or
limits the ability to hold certain types of assets including private or direct
placements, warrants, securities of FirstEnergy, investments in companies owning
nuclear power plants, financial derivatives, preferred stocks, securities
convertible into common stock and securities of the trust fund's custodian or
managers and their parents or subsidiaries.
During
2009, 2008 and 2007, FirstEnergy recognized $176 million, $63 million and $10
million of net realized gains resulting from the sale of securities held in
nuclear decommissioning trusts.
Held-To-Maturity
Securities
The
following table provides the amortized cost basis, unrealized gains and losses,
and approximate fair values of investments in held-to-maturity securities
(excluding emission allowances, employee benefits, and equity method investments
of $264 million and $293 million that are not required to be disclosed) as
December 31, 2009 and 2008:
|
December 31,
2009
|
December 31,
2008
|
|||||||||||||||||||||||||||||||
|
Cost
|
Unrealized
|
Unrealized
|
Fair
|
Cost
|
Unrealized
|
Unrealized
|
Fair
|
|||||||||||||||||||||||||
|
Basis
|
Gains
|
Losses
|
Value
|
Basis
|
Gains
|
Losses
|
Value
|
|||||||||||||||||||||||||
|
Debt
securities
|
(In
millions)
|
|||||||||||||||||||||||||||||||
|
FirstEnergy
|
$ | 544 | $ | 72 | $ | - | $ | 616 | $ | 673 | $ | 14 | $ | 13 | $ | 674 | ||||||||||||||||
|
OE
|
217 | 29 | - | 246 | 240 | - | 13 | 227 | ||||||||||||||||||||||||
|
CEI
|
389 | 43 | - | 432 | 426 | 9 | - | 435 | ||||||||||||||||||||||||
Notes
Receivable
The
following table provides the approximate fair value and related carrying amounts
of notes receivable as of December 31, 2009 and 2008:
|
December 31,
2009
|
December 31,
2008
|
|||||||||||||||
|
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||
|
Value
|
Value
|
Value
|
Value
|
|||||||||||||
|
Notes
receivable
|
(In
millions)
|
|||||||||||||||
|
FirstEnergy
|
$ | 36 | $ | 35 | $ | 45 | $ | 44 | ||||||||
|
FES
|
2 | 1 | 75 | 74 | ||||||||||||
|
OE
|
- | - | 257 | 294 | ||||||||||||
|
TE
|
124 | 141 | 180 | 189 | ||||||||||||
The fair
value of notes receivable represents the present value of the cash inflows based
on the yield to maturity. The yields assumed were based on financial instruments
with similar characteristics and terms. The maturity dates range from 2010 to
2040.
|
(C)
|
RECURRING
FAIR VALUE MEASUREMENTS
|
Fair
value is the price that would be received for an asset or paid to transfer a
liability (exit price) in the principal or most advantageous market for the
asset or liability in an orderly transaction between willing market participants
on the measurement date. A fair value hierarchy has been established that
prioritizes the inputs used to measure fair value. The hierarchy gives the
highest priority to unadjusted quoted market prices in active markets for
identical assets or liabilities (Level 1) and the lowest priority to
unobservable inputs (Level 3). The three levels of the fair value hierarchy are
as follows:
Level 1
– Quoted prices are available in active markets for identical assets or
liabilities as of the reporting date. Active markets are those where
transactions for the asset or liability occur in sufficient frequency and volume
to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets
and liabilities primarily consist of exchange-traded derivatives and equity
securities listed on active exchanges that are held in various
trusts.
201
Level 2
– Pricing inputs are either directly or indirectly observable in the market as
of the reporting date, other than quoted prices in active markets included in
Level 1. FirstEnergy’s Level 2 assets and liabilities consist primarily of
investments in debt securities held in various trusts and commodity forwards.
Additionally, Level 2 includes those financial instruments that are valued using
models or other valuation methodologies based on assumptions that are observable
in the marketplace throughout the full term of the instrument and can be derived
from observable data or are supported by observable levels at which transactions
are executed in the marketplace. These models are primarily industry-standard
models that consider various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market and contractual
prices for the underlying instruments, as well as other relevant economic
measures. Instruments in this category include non-exchange-traded derivatives
such as forwards and certain interest rate swaps.
Level 3
– Pricing inputs include inputs that are generally less observable from
objective sources. These inputs may be used with internally developed
methodologies that result in management’s best estimate of fair value.
FirstEnergy develops its view of the future market price of key commodities
through a combination of market observation and assessment (generally for the
short term) and fundamental modeling (generally for the long term). Key
fundamental electricity model inputs are generally directly observable in the
market or derived from publicly available historic and forecast data. Some key
inputs reflect forecasts published by industry leading consultants who generally
employ similar fundamental modeling approaches. Fundamental model inputs and
results, as well as the selection of consultants, reflect the consensus of
appropriate FirstEnergy management. Level 3 instruments include those that may
be more structured or otherwise tailored to customers’ needs. FirstEnergy’s
Level 3 instruments consist exclusively of NUG contracts.
FirstEnergy
utilizes market data and assumptions that market participants would use in
pricing the asset or liability, including assumptions about risk and the risks
inherent in the inputs to the valuation technique. These inputs can be readily
observable, market corroborated, or generally unobservable. FirstEnergy
primarily applies the market approach for recurring fair value measurements
using the best information available. Accordingly, FirstEnergy maximizes the use
of observable inputs and minimizes the use of unobservable inputs.
The
following tables set forth financial assets and financial liabilities that are
accounted for at fair value by level within the fair value hierarchy as of
December 31, 2009 and 2008. Assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. FirstEnergy's assessment of the significance of a particular
input to the fair value measurement requires judgment and may affect the fair
valuation of assets and liabilities and their placement within the fair value
hierarchy levels. During 2009, there were no significant transfers in or out of
Level 1, Level 2, and Level 3.
|
Recurring Fair Value Measures as of December 31,
2009
|
||||||||||||||||||||||||||||
|
Level
1 – Assets
|
Level
1 - Liabilities
|
|||||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
Derivatives
|
Available-for-Sale
Securities
(1)
|
Other
Investments
|
Total
|
Derivatives
|
NUG
Contracts
(2)
|
Total
|
||||||||||||||||||||||
|
FirstEnergy
|
$ | - | $ | 294 | $ | - | $ | 294 | $ | 11 | $ | - | $ | 11 | ||||||||||||||
|
FES
|
- | - | - | - | 11 | - | 11 | |||||||||||||||||||||
|
OE
|
- | - | - | - | - | - | - | |||||||||||||||||||||
|
JCP&L
|
- | 87 | - | 87 | - | - | - | |||||||||||||||||||||
|
Met-Ed
|
- | 133 | - | 133 | - | - | - | |||||||||||||||||||||
|
Penelec
|
- | 74 | - | 74 | - | - | - | |||||||||||||||||||||
|
Level
2 - Assets
|
Level
2 - Liabilities
|
|||||||||||||||||||||||||||
|
Derivatives
|
Available-for-Sale
Securities
(1)
|
Other
Investments
|
Total
|
Derivatives
|
NUG
Contracts
(2)
|
Total
|
||||||||||||||||||||||
|
FirstEnergy
|
$ | 34 | $ | 1,864 | $ | 11 | $ | 1,909 | $ | 224 | $ | - | $ | 224 | ||||||||||||||
|
FES
|
15 | 1,072 | - | 1,087 | 224 | - | 224 | |||||||||||||||||||||
|
OE
|
- | 120 | - | 120 | - | - | - | |||||||||||||||||||||
|
TE
|
- | 72 | - | 72 | - | - | - | |||||||||||||||||||||
|
JCP&L
|
5 | 280 | - | 285 | - | - | - | |||||||||||||||||||||
|
Met-Ed
|
9 | 134 | - | 143 | - | - | - | |||||||||||||||||||||
|
Penelec
|
5 | 186 | - | 191 | - | - | - | |||||||||||||||||||||
|
Level
3 - Assets
|
Level
3 - Liabilities
|
|||||||||||||||||||||||||||
|
Derivatives
|
Available-for-Sale
Securities
(1)
|
NUG
Contracts
(2)
|
Total
|
Derivatives
|
NUG
Contracts
(2)
|
Total
|
||||||||||||||||||||||
|
FirstEnergy
|
$ | - | $ | - | $ | 200 | $ | 200 | $ | - | $ | 643 | $ | 643 | ||||||||||||||
|
JCP&L
|
- | - | 9 | 9 | - | 399 | 399 | |||||||||||||||||||||
|
Met-Ed
|
- | - | 176 | 176 | - | 143 | 143 | |||||||||||||||||||||
|
Penelec
|
- | - | 15 | 15 | - | 101 | 101 | |||||||||||||||||||||
|
(1)
|
Consists
of investments in nuclear decommissioning trusts, spent nuclear fuel
trusts and NUG trusts. Excludes $21 million of receivables, payables and
accrued income.
|
|
(2)
|
NUG
contracts are subject to regulatory accounting and do not impact
earnings.
|
202
|
Recurring Fair Value Measures as of
December 31, 2008
|
||||||||||||||||||||||||||||
|
Level
1 – Assets
|
Level
1 - Liabilities
|
|||||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
Derivatives
|
Available-for-Sale
Securities
(1)
|
Other
Investments
|
Total
|
Derivatives
|
NUG
Contracts
(2)
|
Total
|
||||||||||||||||||||||
|
FirstEnergy
|
$ | - | $ | 537 | $ | - | $ | 537 | $ | 25 | $ | - | $ | 25 | ||||||||||||||
|
FES
|
- | 290 | - | 290 | 25 | - | 25 | |||||||||||||||||||||
|
OE
|
- | 18 | - | 18 | - | - | - | |||||||||||||||||||||
|
JCP&L
|
- | 67 | - | 67 | - | - | - | |||||||||||||||||||||
|
Met-Ed
|
- | 104 | - | 104 | - | - | - | |||||||||||||||||||||
|
Penelec
|
- | 58 | - | 58 | - | - | - | |||||||||||||||||||||
|
Level
2 - Assets
|
Level
2 - Liabilities
|
|||||||||||||||||||||||||||
|
Derivatives
|
Available-for-Sale
Securities
(1)
|
Other
Investments
|
Total
|
Derivatives
|
NUG
Contracts
(2)
|
Total
|
||||||||||||||||||||||
|
FirstEnergy
|
$ | 40 | $ | 1,464 | $ | 83 | $ | 1,587 | $ | 31 | $ | - | $ | 31 | ||||||||||||||
|
FES
|
12 | 744 | - | 756 | 28 | - | 28 | |||||||||||||||||||||
|
OE
|
- | 98 | - | 98 | - | - | - | |||||||||||||||||||||
|
TE
|
- | 73 | - | 73 | - | - | - | |||||||||||||||||||||
|
JCP&L
|
7 | 255 | - | 262 | - | - | - | |||||||||||||||||||||
|
Met-Ed
|
14 | 121 | - | 135 | - | - | - | |||||||||||||||||||||
|
Penelec
|
7 | 174 | - | 181 | - | - | - | |||||||||||||||||||||
|
Level
3 - Assets
|
Level
3 - Liabilities
|
|||||||||||||||||||||||||||
|
Derivatives
|
Available-for-Sale
Securities
(1)
|
NUG
Contracts
(2)
|
Total
|
Derivatives
|
NUG
Contracts
(2)
|
Total
|
||||||||||||||||||||||
|
FirstEnergy
|
$ | - | $ | - | $ | 434 | $ | 434 | $ | - | $ | 766 | $ | 766 | ||||||||||||||
|
JCP&L
|
- | - | 14 | 14 | - | 532 | 532 | |||||||||||||||||||||
|
Met-Ed
|
- | - | 300 | 300 | - | 150 | 150 | |||||||||||||||||||||
|
Penelec
|
- | - | 120 | 120 | - | 84 | 84 | |||||||||||||||||||||
|
(1)
|
Consists
of investments in nuclear decommissioning trusts, spent nuclear fuel
trusts and NUG trusts. Excludes $5 million of receivables, payables and
accrued income.
|
|
(2)
|
NUG
contracts are subject to regulatory accounting and do not impact
earnings.
|
The
determination of the above fair value measures takes into consideration various
factors. These factors include nonperformance risk, including counterparty
credit risk and the impact of credit enhancements (such as cash deposits, LOCs
and priority interests). The impact of nonperformance risk was immaterial in the
fair value measurements.
The
following is a reconciliation of changes in the fair value of NUG contracts
classified as Level 3 in the fair value hierarchy for 2009 and 2008 (in
millions):
|
FirstEnergy
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||
|
Balance
as of January 1, 2009
|
$ | (332 | ) | $ | (518 | ) | $ | 150 | $ | 36 | ||||||
|
Settlements
(1)
|
358 | 168 | 88 | 102 | ||||||||||||
|
Purchases
|
- | - | - | - | ||||||||||||
|
Issuances
|
- | - | - | - | ||||||||||||
|
Sales
|
- | - | - | - | ||||||||||||
|
Unrealized
losses
(1)
|
(470 | ) | (41 | ) | (205 | ) | (224 | ) | ||||||||
|
Net
transfers to Level 3
|
- | - | - | - | ||||||||||||
|
Net
transfers from Level 3
|
- | - | - | - | ||||||||||||
|
Balance
as of December 31, 2009
|
$ | (444 | ) | $ | (391 | ) | $ | 33 | $ | (86 | ) | |||||
|
Balance
as of January 1, 2008
|
$ | (803 | ) | $ | (750 | ) | $ | (28 | ) | $ | (25 | ) | ||||
|
Settlements
(1)
|
278 | 232 | 34 | 12 | ||||||||||||
|
Unrealized
gains
(1)
|
193 | - | 144 | 49 | ||||||||||||
|
Net
transfers to (from) Level 3
|
- | - | - | - | ||||||||||||
|
Balance
as of December 31, 2008
|
$ | (332 | ) | $ | (518 | ) | $ | 150 | $ | 36 | ||||||
|
(1)
|
Changes
in fair value of NUG contracts are subject to regulatory accounting and do
not impact earnings.
|
203
6.
DERIVATIVE INSTRUMENTS
FirstEnergy
is exposed to financial risks resulting from fluctuating interest rates and
commodity prices, including prices for electricity, natural gas, coal and energy
transmission. To manage the volatility relating to these exposures, FirstEnergy
uses a variety of derivative instruments, including forward contracts, options,
futures contracts and swaps. The derivatives are used for risk management
purposes. In addition to derivatives, FirstEnergy also enters into master
netting agreements with certain third parties. FirstEnergy's Risk Policy
Committee, comprised of members of senior management, provides general
management oversight for risk management activities throughout FirstEnergy. The
Committee is responsible for promoting the effective design and implementation
of sound risk management programs and oversees compliance with corporate risk
management policies and established risk management practices.
FirstEnergy
accounts for derivative instruments on its Consolidated Balance Sheets at fair
value unless they meet the normal purchase and normal sales criteria.
Derivatives that meet those criteria are accounted for at cost under the accrual
method of accounting. The changes in the fair value of derivative instruments
that do not meet the normal purchase and normal sales criteria are included in
purchased power, other expense, unrealized gain (loss) on derivative hedges in
other comprehensive income (loss), or as part of the value of the hedged item. A
hypothetical 10% adverse shift (an increase or decrease depending on the
derivative position) in quoted market prices in the near term on its derivative
instruments would not have had a material effect on FirstEnergy’s consolidated
financial position (assets, liabilities and equity) or cash flows as of December
31, 2009. Based on derivative contracts held as of December 31, 2009, an adverse
10% change in commodity prices would decrease net income by approximately $9
million during the next 12 months.
Interest
Rate Risk
FirstEnergy
uses a combination of fixed-rate and variable-rate debt to manage interest rate
exposure. Fixed-to-floating interest rate swaps are used, which are typically
designated as fair value hedges, as a means to manage interest rate exposure. In
addition, FirstEnergy uses interest rate derivatives to lock in interest rate
levels in anticipation of future financings, which are typically designated as
cash-flow hedges.
Cash
Flow Hedges
Under
the revolving credit facility (see Note 14), FirstEnergy and its subsidiaries,
incur variable interest charges based on LIBOR. FirstEnergy currently holds a
swap with a notional value of $100 million to hedge against changes in
associated interest rates. This hedge will expire in January 2010 and is
accounted for as a cash flow hedge. As of December 31, 2009, the fair value of
the outstanding swap was immaterial.
FirstEnergy
uses forward starting swap agreements to hedge a portion of the consolidated
interest rate risk associated with issuances of fixed-rate, long-term debt
securities of its subsidiaries. These derivatives are treated as cash flow
hedges, protecting against the risk of changes in future interest payments
resulting from changes in benchmark U.S. Treasury rates between the date of
hedge inception and the date of the debt issuance. During 2009, FirstEnergy
terminated forward swaps with a notional value of $2.8 billion and recognized
losses of approximately $18.5 million; the ineffective portion recognized as an
adjustment to interest expense was immaterial. The remaining effective portions
will be amortized to interest expense over the life of the hedged
debt.
Interest
rate derivatives are included in "Other Noncurrent Liabilities" on FirstEnergy’s
Consolidated Balance Sheets. The effects of interest rate derivatives on the
Consolidated Statements of Income and Comprehensive Income during 2009 and 2008
were:
|
December 31
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
Effective
Portion
|
||||||||
|
Loss
Recognized in AOCL
|
$ | (18 | ) | $ | (44 | ) | ||
|
Loss
Reclassified from AOCL into Interest Expense
|
(40 | ) | (15 | ) | ||||
|
Ineffective
Portion
|
||||||||
|
Loss
Recognized in Interest Expense
|
- | (7 | ) | |||||
204
Total
unamortized losses included in AOCL associated with prior interest rate hedges
totaled $104 million ($62
million net of tax) as
of December 31, 2009. Based on current estimates, approximately $11 million will
be amortized to interest expense during the next twelve months. FirstEnergy’s
interest rate swaps do not include any contingent credit risk related
features.
Fair
Value Hedges
FirstEnergy
uses fixed-for-floating interest rate swap agreements to hedge a portion of the
consolidated interest rate risk associated with the debt portfolio of its
subsidiaries. These derivatives are treated as fair value hedges of fixed-rate,
long-term debt issues, protecting against the risk of changes in the fair value
of fixed-rate debt instruments due to lower interest rates. Swap maturities,
call options, fixed interest rates and interest payment dates match those of the
underlying obligations. As of December 31, 2009, the debt underlying the $250
million outstanding notional amount of interest rate swaps had a weighted
average fixed interest rate of 6.45%, which the swaps have converted to a
current weighted average variable rate of 5.4%. The gain or loss on the
derivative as well as the offsetting loss or gain on the hedged item
attributable to the hedged risk are recognized in earnings and were immaterial
in 2009.
Commodity
Derivatives
FirstEnergy
uses both physically and financially settled derivatives to manage its exposure
to volatility in commodity prices. Commodity derivatives are used for risk
management purposes to hedge exposures when it makes economic sense to do so,
including circumstances where the hedging relationship does not qualify for
hedge accounting. Derivatives that do not qualify under the normal purchase or
sales criteria or for hedge accounting as cash flow hedges are marked to market
through earnings. FirstEnergy’s risk policy does not allow derivatives to be
used for speculative or trading purposes. FirstEnergy hedges forecasted electric
sales and purchases and anticipated natural gas purchases using forwards and
options. Heating oil futures are used to hedge oil purchases and fuel surcharges
associated with rail transportation contracts. FirstEnergy’s hedge term is
typically two years. The effective portions of all cash flow hedges are
initially recorded in AOCL and are subsequently included in net income as the
underlying hedged commodities are delivered.
FirstEnergy
discontinues hedge accounting prospectively when it is determined that a
derivative is no longer effective in offsetting changes in the cash flows of a
hedged item, in the case of forward-starting hedges, or when it is no longer
probable that the forecasted transaction will occur. In 2009, FirstEnergy did
not discontinue hedge accounting for any cash flow hedge items.
During
2008, in anticipation of certain regulatory actions, FES entered into purchased
power contracts representing approximately 4.4 million MWH per year for MISO
delivery in 2010 and 2011. These contracts, which represented less than 10% of
FES's estimated Ohio load, were intended to cover potential short positions that
were anticipated in those years and qualified for the normal purchase normal
sale scope exception under accounting for Derivatives and Hedging. In the fourth
quarter of 2009, as FES determined that the short positions in 2010 and 2011
were not expected to materialize based on reductions in PLR obligations and
decreased demand due to economic conditions, the contracts were modified to
financially settle to avoid congestion and transmission expenses associated with
physical delivery. As a result of the modification, the fair value of the
contracts was recorded, resulting in a mark-to-market charge of approximately
$205 million ($129 million, after tax) to purchased power expense. For all other
purchased power contracts qualifying for the normal purchase normal sale scope
exception, the Company expects to take physical delivery of the power over the
remaining term of the contracts.
205
The
following tables summarize the fair value of commodity derivatives in
FirstEnergy’s Consolidated Balance Sheets:
|
Derivative
Assets
|
Derivative
Liabilities
|
||||||||||||||||
|
Fair
Value
|
Fair
Value
|
||||||||||||||||
|
December
31
|
December
31
|
December
31
|
December
31
|
||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||
|
Cash Flow
Hedges
|
(In
millions)
|
Cash Flow
Hedges
|
(In
millions)
|
||||||||||||||
|
Electricity
Forwards
|
Electricity
Forwards
|
||||||||||||||||
|
Current
Assets
|
$ | 3 | $ | 11 |
Current
Liabilities
|
$ | 7 | $ | 27 | ||||||||
|
Noncurrent
Assets
|
11 | - |
Noncurrent
Assets
|
12 | - | ||||||||||||
|
Natural Gas
Futures
|
Natural Gas
Futures
|
||||||||||||||||
|
Current
Assets
|
- | - |
Current
Liabilities
|
9 | 4 | ||||||||||||
|
Deferred
Charges
|
- | - |
Noncurrent
Liabilities
|
- | 5 | ||||||||||||
|
Other
|
Other
|
||||||||||||||||
|
Current
Assets
|
- | - |
Current
Liabilities
|
2 | 12 | ||||||||||||
|
Deferred
Charges
|
- | - |
Noncurrent
Liabilities
|
- | 4 | ||||||||||||
| $ | 14 | $ | 11 | $ | 30 | 52 | |||||||||||
|
Derivative
Assets
|
Derivative
Liabilities
|
||||||||||||||||
|
Fair
Value
|
Fair
Value
|
||||||||||||||||
|
December 31
2009
|
December 31
2008
|
December 31
2009
|
December 31
2008
|
||||||||||||||
|
Economic
Hedges
|
(In
millions)
|
Economic
Hedges
|
(In
millions)
|
||||||||||||||
|
NUG
Contracts
|
NUG
Contracts
|
||||||||||||||||
|
Power
Purchase
|
Power
Purchase
|
||||||||||||||||
|
Contract
Asset
|
$ | 200 | $ | 434 |
Contract
Liability
|
$ | 643 | $ | 766 | ||||||||
|
Other
|
Other
|
||||||||||||||||
|
Current
Assets
|
- | 1 |
Current
Liabilities
|
106 | 1 | ||||||||||||
|
Deferred
Charges
|
19 | 28 |
Noncurrent
Liabilities
|
97 | - | ||||||||||||
| $ | 219 | $ | 463 | $ | 846 | $ | 767 | ||||||||||
|
Total
Commodity Derivatives
|
$ | 233 | $ | 474 |
Total
Commodity Derivatives
|
$ | 876 | $ | 819 | ||||||||
Electricity
forwards are used to balance expected retail and wholesale sales with expected
generation and purchased power. Natural gas futures are entered into based on
expected consumption of natural gas, primarily used in FirstEnergy’s peaking
units. Heating oil futures are entered into based on expected consumption of oil
and the financial risk in FirstEnergy’s coal transportation contracts.
Derivative instruments are not used in quantities greater than forecasted needs.
The following table summarizes the volume of FirstEnergy’s outstanding
derivative transactions as of December 31, 2009.
|
Purchases
|
Sales
|
Net
|
Units
|
|||||
|
(In
thousands)
|
||||||||
|
Electricity
Forwards
|
11,684
|
(3,382)
|
8,302
|
MWH
|
||||
|
Heating
Oil Futures
|
4,620
|
-
|
4,620
|
Gallons
|
||||
|
Natural
Gas Futures
|
2,750
|
(2,250)
|
500
|
mmBtu
|
||||
The
effect of derivative instruments on the consolidated statements of income and
comprehensive income (loss) for December 31, 2009 and 2008, for instruments
designated in cash flow hedging relationships and not in hedging relationships,
respectively, are summarized in the following tables:
|
Derivatives in
Cash Flow Hedging Relationships
|
Electricity
|
Natural
Gas
|
Heating
Oil
|
|||||||||||||
|
Forwards
|
Futures
|
Futures
|
Total
|
|||||||||||||
|
December 31,
2009
|
(in
millions)
|
|||||||||||||||
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$ | 7 | $ | (9 | ) | $ | 1 | $ | (1 | ) | ||||||
|
Effective Gain (Loss)
Reclassified to:
(1)
|
||||||||||||||||
|
Purchased
Power Expense
|
(6 | ) | - | - | (6 | ) | ||||||||||
|
Fuel
Expense
|
- | (9 | ) | (12 | ) | (21 | ) | |||||||||
|
December 31,
2008
|
||||||||||||||||
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
$ | 3 | $ | (4 | ) | $ | (18 | ) | $ | (19 | ) | |||||
|
Effective Gain (Loss)
Reclassified to:
(1)
|
||||||||||||||||
|
Purchased
Power Expense
|
(6 | ) | - | - | (6 | ) | ||||||||||
|
Fuel
Expense
|
- | 4 | (2 | ) | 2 | |||||||||||
| (1) | The ineffective portion was immaterial. |
206
|
Derivatives Not in Hedging
Relationships
|
NUG
|
|||||||||||
|
Contracts
|
Other
|
Total
|
||||||||||
|
2009
|
(In
millions)
|
|||||||||||
|
Unrealized
Gain (Loss) Recognized in:
|
||||||||||||
|
Purchased
Power Expense
|
$ | - | $ | (204 | ) | $ | (204 | ) | ||||
|
Regulatory Assets
(1)
|
(470 | ) | - | (470 | ) | |||||||
| $ | (470 | ) | $ | (204 | ) | $ | (674 | ) | ||||
|
Realized Gain
(Loss) Reclassified to:
|
||||||||||||
|
Regulatory Assets
(1)
|
(348 | ) | - | (348 | ) | |||||||
| $ | (348 | ) | $ | - | $ | (348 | ) | |||||
|
2008
|
||||||||||||
|
Unrealized
Gain (Loss) Recognized in:
|
||||||||||||
|
Fuel Expense
(2)
|
$ | - | $ | 1 | $ | 1 | ||||||
|
Regulatory Assets
(1)
|
193 | 2 | 195 | |||||||||
| $ | 193 | $ | 3 | $ | 196 | |||||||
|
Realized Gain
(Loss) Reclassified to:
|
||||||||||||
|
Fuel Expense
(2)
|
$ | - | $ | 1 | $ | 1 | ||||||
|
Regulatory Assets
(1)
|
(267 | ) | - | (267 | ) | |||||||
| $ | (267 | ) | $ | 1 | $ | (266 | ) | |||||
| (1) |
Changes in the fair value of
NUG contracts are deferred for future recovery from (or refund to)
customers.
|
| (2) |
The realized gain (loss) is
reclassified upon termination of the derivative
instrument.
|
Total
unamortized losses included in AOCL associated with commodity derivatives were
$15 million ($9 million net of tax) as of December 31, 2009, as compared to $44
million ($27 million net of tax) as of December 31, 2008. The net of tax change
resulted from a $16 million decrease due to net hedge losses reclassified to
earnings during 2009. Based on current estimates, approximately $9 million
(after tax) of the net deferred losses on derivative instruments in AOCL as of
December 31, 2009 are expected to be reclassified to earnings during the next
twelve months as hedged transactions occur. The fair value of these derivative
instruments fluctuate from period to period based on various market
factors.
Many of
FirstEnergy’s commodity derivatives contain credit risk features. As of December
31, 2009, FirstEnergy posted $153 million of collateral related to net liability
positions and held $26 million of counterparties’ funds related to asset
positions. The collateral FirstEnergy has posted relates to both derivative and
non-derivative contracts. FirstEnergy’s largest derivative counterparties fully
collateralize all derivative transactions. Certain commodity derivative
contracts include credit risk-related contingent features that would require
FirstEnergy to post additional collateral if the credit rating for its debt were
to fall below investment grade. The aggregate fair value of derivative
instruments with credit risk-related contingent features that are in a liability
position on December 31, 2009 was $220 million, for which $127 million in
collateral has been posted. If FirstEnergy’s credit rating were to fall below
investment grade, it would be required to post $47 million of additional
collateral related to commodity derivatives.
|
LEASES
|
FirstEnergy
leases certain generating facilities, office space and other property and
equipment under cancelable and noncancelable leases.
In 1987,
OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley
Unit 2 and entered into operating leases on the portions sold for basic lease
terms of approximately 29 years. In that same year, CEI and TE also sold
portions of their ownership interests in Beaver Valley Unit 2 and Bruce
Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease
terms of approximately 30 years. During the terms of their respective leases,
OE, CEI and TE are responsible, to the extent of their leasehold interests, for
costs associated with the units including construction expenditures, operation
and maintenance expenses, insurance, nuclear fuel, property taxes and
decommissioning. They have the right, at the expiration of the respective basic
lease terms, to renew their respective leases. They also have the right to
purchase the facilities at the expiration of the basic lease term or any renewal
term at a price equal to the fair market value of the facilities. The basic
rental payments are adjusted when applicable federal tax law
changes.
207
On July
13, 2007, FGCO completed a sale and leaseback transaction for its 93.825%
undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net
demonstrated capacity. The purchase price of approximately $1.329 billion (net
after-tax proceeds of approximately $1.2 billion) for the undivided interest was
funded through a combination of equity investments by affiliates of AIG
Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts
and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85%
pass through certificates due 2034. A like principal amount of secured notes
maturing June 1, 2034 were issued by the lessor trusts to the pass through trust
that issued and sold the certificates. The lessor trusts leased the undivided
interest back to FGCO for a term of approximately 33 years under substantially
identical leases. FES has unconditionally and irrevocably guaranteed all of
FGCO’s obligations under each of the leases. This transaction, which is
classified as an operating lease for FES and FirstEnergy, generated tax capital
gains of approximately $815 million, all of which were offset by existing tax
capital loss carryforwards. Accordingly, FirstEnergy reduced its tax loss
carryforward valuation allowances in 2007, with a corresponding reduction to
goodwill (see Note 2(E)).
Effective
October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce
Mansfield Plant to FGCO and FGCO assumed all of CEI’s and TE’s obligations
arising under those leases. FGCO subsequently transferred the Unit 1 portion of
these leasehold interests, as well as FGCO’s leasehold interests under its July
13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly
formed wholly-owned subsidiary on December 17, 2007. The subsidiary assumed all
of the lessee obligations associated with the assigned interests. However, CEI
and TE remain primarily liable on the 1987 leases and related agreements. FGCO
remains primarily liable on the 2007 leases and related agreements, and FES
remains primarily liable as a guarantor under the related 2007 guarantees, as to
the lessors and other parties to the respective agreements. These assignments
terminate automatically upon the termination of the underlying
leases.
During
2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and
leaseback of the Perry Plant and approximately 43.5 MW of lessor equity
interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In
addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI
1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to
lease these MW under their respective sale and leaseback arrangements and the
related lease debt remains outstanding.
Rentals
for capital and operating leases for the three years ended December 31, 2009 are
summarized as follows:
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Operating
leases
|
$ | 236 | $ | 202 | $ | 146 | $ | 4 | $ | 64 | $ | 9 | $ | 7 | $ | 4 | ||||||||||||||||
|
Capital
leases
|
||||||||||||||||||||||||||||||||
|
Interest
element
|
1 | 2 | 1 | 1 | - | - | - | - | ||||||||||||||||||||||||
|
Other
(1)
|
6 | 10 | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Total
rentals
|
$ | 243 | $ | 214 | $ | 147 | $ | 5 | $ | 64 | $ | 9 | $ | 7 | $ | 4 | ||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Operating
leases
|
$ | 381 | $ | 173 | $ | 146 | $ | 5 | $ | 65 | $ | 8 | $ | 4 | $ | 4 | ||||||||||||||||
|
Capital
leases
|
||||||||||||||||||||||||||||||||
|
Interest
element
|
1 | 1 | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Other
(1)
|
6 | 8 | - | 1 | - | - | - | - | ||||||||||||||||||||||||
|
Total
rentals
|
$ | 388 | $ | 182 | $ | 146 | $ | 6 | $ | 65 | $ | 8 | $ | 4 | $ | 4 | ||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Operating
leases
|
$ | 376 | $ | 45 | $ | 145 | $ | 62 | $ | 101 | $ | 8 | $ | 4 | $ | 5 | ||||||||||||||||
|
Capital
leases
|
||||||||||||||||||||||||||||||||
|
Interest
element
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Other
|
1 | - | - | 1 | - | - | - | - | ||||||||||||||||||||||||
|
Total
rentals
|
$ | 377 | $ | 45 | $ | 145 | $ | 63 | $ | 101 | $ | 8 | $ | 4 | $ | 5 | ||||||||||||||||
| (1) |
Includes $6 million and $5
million
in 2009
and 2008, respectively, for wind purchased power agreements classified as
capital leases.
|
||||||||||||||||||||||||||||||||
The
future minimum capital lease payments as of December 31, 2009 are as follows
(TE, JCP&L, Met-Ed and Penelec have no material capital
leases):
208
|
Capital
Leases
|
FE
|
FES
|
OE
|
CEI
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
2010
|
$ | 2 | $ | 6 | $ | - | $ | 1 | ||||||||
|
2011
|
2 | 6 | - | 1 | ||||||||||||
|
2012
|
1 | 6 | 1 | 1 | ||||||||||||
|
2013
|
1 | 6 | - | 1 | ||||||||||||
|
2014
|
1 | 6 | - | 1 | ||||||||||||
|
Years
thereafter
|
3 | 18 | - | 3 | ||||||||||||
|
Total
minimum lease payments
|
10 | 48 | 1 | 8 | ||||||||||||
|
Executory
costs
|
- | - | - | - | ||||||||||||
|
Net
minimum lease payments
|
10 | 48 | 1 | 8 | ||||||||||||
|
Interest
portion
|
6 | 6 | - | 6 | ||||||||||||
|
Present
value of net minimum lease payments
|
4 | 42 | 1 | 2 | ||||||||||||
|
Less
current portion
|
- | 4 | - | - | ||||||||||||
|
Noncurrent
portion
|
$ | 4 | $ | 38 | $ | 1 | $ | 2 | ||||||||
The
present value of minimum lease payments for FirstEnergy does not include $9
million of capital lease obligations that were prepaid at December 31,
2009.
Established
by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on
behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and
leaseback transactions. Similarly, CEI and TE established Shippingport in 1997
to purchase the lease obligation bonds issued on behalf of lessors in their
Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and
Shippingport arrangements effectively reduce lease costs related to those
transactions (see Note
8
).
The
future minimum operating lease payments as of December 31, 2009 are as
follows:
|
Operating
Leases
|
FE
Lease Payments
|
FE
Capital Trusts
|
FE
Net
|
|||||||||
|
2010
|
$ | 341 | $ | 116 | $ | 225 | ||||||
|
2011
|
323 | 116 | 207 | |||||||||
|
2012
|
360 | 125 | 235 | |||||||||
|
2013
|
362 | 130 | 232 | |||||||||
|
2014
|
358 | 131 | 227 | |||||||||
|
Years
thereafter
|
2,482 | 123 | 2,359 | |||||||||
|
Total
minimum lease payments
|
$ | 4,226 | $ | 741 | $ | 3,485 | ||||||
|
Operating
Leases
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||
|
2010
|
$ | 199 | $ | 146 | $ | 4 | $ | 64 | $ | 6 | $ | 7 | $ | 3 | ||||||||||||||
|
2011
|
190 | 146 | 3 | 64 | 5 | 4 | 3 | |||||||||||||||||||||
|
2012
|
229 | 146 | 3 | 64 | 5 | 3 | 2 | |||||||||||||||||||||
|
2013
|
235 | 145 | 3 | 64 | 5 | 3 | 2 | |||||||||||||||||||||
|
2014
|
234 | 145 | 2 | 64 | 4 | 3 | 2 | |||||||||||||||||||||
|
Years
thereafter
|
2,133 | 305 | 5 | 140 | 49 | 35 | 20 | |||||||||||||||||||||
|
Total
minimum
lease payments
|
$ | 3,220 | $ | 1,033 | $ | 20 | $ | 460 | $ | 74 | $ | 55 | $ | 32 | ||||||||||||||
FirstEnergy
recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce
Mansfield Plant associated with the 1997 merger between OE and Centerior. The
unamortized above-market lease liability for Beaver Valley Unit 2 of $236
million as of December 31, 2009, of which $37 million is classified as current,
is being amortized by TE on a straight-line basis through the end of the lease
term in 2017. The unamortized above-market lease liability for the Bruce
Mansfield Plant of $308 million as of December 31, 2009, of which $46 million is
classified as current, is being amortized by FGCO on a straight-line basis
through the end of the lease term in 2016.
|
8.
|
VARIABLE
INTEREST ENTITIES
|
FirstEnergy
and its subsidiaries consolidate VIEs when they are determined to be the VIE's
primary beneficiary. FirstEnergy and its subsidiaries reflect the portion of
VIEs not owned by them in the caption noncontrolling interest within the
consolidated financial statements. The change in noncontrolling interest during
2009 is the result of net losses of the noncontrolling interests ($16 million),
the acquisition of additional interest in certain joint ventures and other
adjustments ($13 million), and distributions to owners ($5
million).
209
Mining
Operations
On July
16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus,
Ohio-based coal company, to acquire a majority stake in the Signal Peak mining
and coal transportation operations near Roundup, Montana. FEV made a $125
million equity investment in the joint venture, which acquired 80% of the mining
operations (Signal Peak Energy, LLC) and 100% of the transportation operations,
with FEV owning a 45% economic interest and an affiliate of the Boich Companies
owning a 55% economic interest in the joint venture. Both parties have a 50%
voting interest in the joint venture. FEV consolidates the mining and
transportation operations of this joint venture in its financial statements. In
March 2009, FEV agreed to pay a total of $8.5 million to affiliates of the Boich
Companies to purchase an additional 5% economic interest in the Signal Peak
mining and coal transportation operations. Voting interests remained unchanged
after the sale was completed in July 2009. Effective August 21, 2009, the joint
venture acquired the remaining 20% stake in the mining operations by issuing a
five-year note for $47.5 million. For both acquisitions, the difference between
the consideration paid and the adjustment to the noncontrolling interest
resulted in a charge to other paid in capital of approximately $30
million.
Trusts
FirstEnergy's
consolidated financial statements include PNBV and Shippingport, VIEs created in
1996 and 1997, respectively, to refinance debt originally issued in connection
with sale and leaseback transactions. PNBV and Shippingport financial data are
included in the consolidated financial statements of OE and CEI,
respectively.
PNBV was
established to purchase a portion of the lease obligation bonds issued in
connection with OE's 1987 sale and leaseback of its interests in the Perry Plant
and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes
issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV
includes a 3% equity interest by an unaffiliated third party and a 3% equity
interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was
established to purchase all of the lease obligation bonds issued in connection
with CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in
1987. CEI and TE used debt and available funds to purchase the notes issued by
Shippingport.
Loss
Contingencies
FES and
the Ohio Companies are exposed to losses under their applicable sale-leaseback
agreements upon the occurrence of certain contingent events that each company
considers unlikely to occur. The maximum exposure under these provisions
represents the net amount of casualty value payments due upon the occurrence of
specified casualty events that render the applicable plant worthless. Net
discounted lease payments would not be payable if the casualty loss payments are
made. The following table shows each company’s net exposure to loss based upon
the casualty value provisions mentioned above:
|
Maximum
Exposure
|
Discounted Lease Payments,
net
(1)
|
Net
Exposure
|
||||||||||
|
(in
millions)
|
||||||||||||
|
FES
|
$ | 1,348 | $ | 1,175 | $ | 173 | ||||||
|
OE
|
723 | 526 | 197 | |||||||||
|
CEI
|
665 | 75 | 590 | |||||||||
|
TE
|
665 | 382 | 283 | |||||||||
|
(1)
|
The
net present value of FirstEnergy’s consolidated sale and leaseback
operating lease commitments was $1.7
billion as of
December 31, 2009
|
|
|
(see
NGC lessor equity interest purchases described in Note 7).
|
See Note
7 for a discussion of CEI’s and TE’s assignment of their leasehold interests in
the Bruce Mansfield Plant to FGCO.
Power
Purchase Agreements
FirstEnergy
evaluated its power purchase agreements and determined that certain NUG entities
may be VIEs to the extent they own a plant that sells substantially all of its
output to the Utilities and the contract price for power is correlated with the
plant's variable costs of production. FirstEnergy, through its subsidiaries
JCP&L, Met-Ed and Penelec, maintains 26 long-term power purchase agreements
with NUG entities. The agreements were entered into pursuant to the Public
Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the
creation of, and has no equity or debt invested in, these
entities.
210
FirstEnergy
has determined that for all but eight of these entities, neither JCP&L,
Met-Ed nor Penelec have variable interests in the entities or the entities are
governmental or not-for-profit organizations not within the scope of
consolidation consideration for VIEs. JCP&L, Met-Ed or Penelec may hold
variable interests in the remaining eight entities, which sell their output at
variable prices that correlate to some extent with the operating costs of the
plants. FirstEnergy periodically requests from these eight entities the
information necessary to determine whether they are VIEs or whether JCP&L,
Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to
obtain the requested information, which in most cases was deemed by the
requested entity to be proprietary. As such, FirstEnergy applied the scope
exception that exempts enterprises unable to obtain the necessary information to
evaluate entities.
Since
FirstEnergy has no equity or debt interests in the NUG entities, its maximum
exposure to loss relates primarily to the above-market costs it incurs for
power. FirstEnergy expects any above-market costs it incurs to be recovered from
customers. Purchased power costs from these entities during 2009, 2008, and 2007
were $165 million, $178 million, and $176 million, respectively.
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
JCP&L
|
$ | 73 | $ | 84 | $ | 90 | ||||||
|
Met-Ed
|
57 | 61 | 56 | |||||||||
|
Penelec
|
35 | 33 | 30 | |||||||||
|
Total
|
$ | 165 | $ | 178 | $ | 176 | ||||||
9.
DIVESTITURES
On March
7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net
after-tax gain of $19.3 million. The sale of assets did not meet the criteria
for classification as discontinued operations as of December 31,
2008.
10.
TAXES
Income
Taxes
FirstEnergy
records income taxes in accordance with the liability method of accounting.
Deferred income taxes reflect the net tax effect of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts recognized for tax purposes. Investment tax credits,
which were deferred when utilized, are being amortized over the recovery period
of the related property. Deferred income tax liabilities related to temporary
tax and accounting basis differences and tax credit carryforward items are
recognized at the statutory income tax rates in effect when the liabilities are
expected to be paid. Deferred tax assets are recognized based on income tax
rates expected to be in effect when they are settled. Details of income taxes
for the three years ended December 31, 2009 are shown below:
211
|
PROVISION
FOR INCOME TAXES
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Currently
payable-
|
||||||||||||||||||||||||||||||||
|
Federal
|
$ | (183 | ) | $ | 87 | $ | 21 | $ | 40 | $ | 6 | $ | 40 | $ | (34 | ) | $ | (21 | ) | |||||||||||||
|
State
|
44 | 8 | 4 | 2 | - | 26 | (4 | ) | 4 | |||||||||||||||||||||||
| (139 | ) | 95 | 25 | 42 | 6 | 66 | (38 | ) | (17 | ) | ||||||||||||||||||||||
|
Deferred,
net-
|
||||||||||||||||||||||||||||||||
|
Federal
|
351 | 200 | 40 | (52 | ) | - | 41 | 60 | 60 | |||||||||||||||||||||||
|
State
|
42 | 24 | 3 | 1 | 2 | 2 | 7 | 4 | ||||||||||||||||||||||||
| 393 | 224 | 43 | (51 | ) | 2 | 43 | 67 | 64 | ||||||||||||||||||||||||
|
Investment
tax credit amortization
|
(9 | ) | (4 | ) | (2 | ) | (1 | ) | - | - | - | (1 | ) | |||||||||||||||||||
|
Total
provision for income taxes
|
$ | 245 | $ | 315 | $ | 66 | $ | (10 | ) | $ | 8 | $ | 109 | $ | 29 | $ | 46 | |||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Currently
payable-
|
||||||||||||||||||||||||||||||||
|
Federal
|
$ | 355 | $ | 156 | $ | 79 | $ | 119 | $ | 46 | $ | 101 | $ | 5 | $ | (34 | ) | |||||||||||||||
|
State
|
56 | 20 | 4 | 6 | - | 34 | 6 | (3 | ) | |||||||||||||||||||||||
| 411 | 176 | 83 | 125 | 46 | 135 | 11 | (37 | ) | ||||||||||||||||||||||||
|
Deferred,
net-
|
||||||||||||||||||||||||||||||||
|
Federal
|
343 | 109 | 22 | 16 | (12 | ) | 9 | 47 | 84 | |||||||||||||||||||||||
|
State
|
36 | 12 | (2 | ) | (2 | ) | (4 | ) | 4 | 4 | 12 | |||||||||||||||||||||
| 379 | 121 | 20 | 14 | (16 | ) | 13 | 51 | 96 | ||||||||||||||||||||||||
|
Investment
tax credit amortization
|
(13 | ) | (4 | ) | (4 | ) | (2 | ) | - | - | (1 | ) | (1 | ) | ||||||||||||||||||
|
Total
provision for income taxes
|
$ | 777 | $ | 293 | $ | 99 | $ | 137 | $ | 30 | $ | 148 | $ | 61 | $ | 58 | ||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Currently
payable-
|
||||||||||||||||||||||||||||||||
|
Federal
|
$ | 706 | $ | 528 | $ | 105 | $ | 166 | $ | 73 | $ | 138 | $ | 26 | $ | 41 | ||||||||||||||||
|
State
|
187 | 111 | (4 | ) | 20 | 7 | 42 | 7 | 12 | |||||||||||||||||||||||
| 893 | 639 | 101 | 186 | 80 | 180 | 33 | 53 | |||||||||||||||||||||||||
|
Deferred,
net-
|
||||||||||||||||||||||||||||||||
|
Federal
|
22 | (288 | ) | - | (23 | ) | (27 | ) | (25 | ) | 30 | 10 | ||||||||||||||||||||
|
State
|
(18 | ) | (42 | ) | 4 | 2 | 2 | (5 | ) | 6 | 1 | |||||||||||||||||||||
| 4 | (330 | ) | 4 | (21 | ) | (25 | ) | (30 | ) | 36 | 11 | |||||||||||||||||||||
|
Investment
tax credit amortization
|
(14 | ) | (4 | ) | (4 | ) | (2 | ) | (1 | ) | (1 | ) | (1 | ) | - | |||||||||||||||||
|
Total
provision for income taxes
|
$ | 883 | $ | 305 | $ | 101 | $ | 163 | $ | 54 | $ | 149 | $ | 68 | $ | 64 | ||||||||||||||||
FES and
the Utilities are party to an intercompany income tax allocation agreement with
FirstEnergy and its other subsidiaries that provides for the allocation of
consolidated tax liabilities. Net tax benefits attributable to FirstEnergy,
excluding any tax benefits derived from interest expense associated with
acquisition indebtedness from the merger with GPU, are reallocated to the
subsidiaries of FirstEnergy that have taxable income. That allocation is
accounted for as a capital contribution to the company receiving the tax
benefit.
212
The
following tables provide a reconciliation of federal income tax expense at the
federal statutory rate to the total provision for income taxes for the three
years ended December 31, 2009.
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Book
income before provision for income taxes
|
$ | 1,251 | $ | 892 | $ | 188 | $ | (23 | ) | $ | 32 | $ | 279 | $ | 84 | $ | 111 | |||||||||||||||
|
Federal
income tax expense at statutory rate
|
$ | 438 | $ | 312 | $ | 66 | $ | (8 | ) | $ | 11 | $ | 98 | $ | 29 | $ | 39 | |||||||||||||||
|
Increases
(reductions) in taxes resulting from-
|
||||||||||||||||||||||||||||||||
|
Amortization
of investment tax credits
|
(9 | ) | (4 | ) | (2 | ) | (1 | ) | - | - | - | (1 | ) | |||||||||||||||||||
|
State
income taxes, net of federal tax benefit
|
56 | 21 | 5 | 2 | 1 | 18 | 2 | 5 | ||||||||||||||||||||||||
|
Manufacturing
deduction
|
(13 | ) | (11 | ) | (2 | ) | 1 | (1 | ) | - | - | - | ||||||||||||||||||||
|
Effectively
settled tax items
|
(217 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Other,
net
|
(10 | ) | (3 | ) | (1 | ) | (4 | ) | (3 | ) | (7 | ) | (2 | ) | 3 | |||||||||||||||||
|
Total
provision for income taxes
|
$ | 245 | $ | 315 | $ | 66 | $ | (10 | ) | $ | 8 | $ | 109 | $ | 29 | $ | 46 | |||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Book
income before provision for income taxes
|
$ | 2,119 | $ | 800 | $ | 310 | $ | 421 | $ | 105 | $ | 335 | $ | 149 | $ | 146 | ||||||||||||||||
|
Federal
income tax expense at statutory rate
|
$ | 742 | $ | 280 | $ | 109 | $ | 147 | $ | 37 | $ | 117 | $ | 52 | $ | 51 | ||||||||||||||||
|
Increases
(reductions) in taxes resulting from-
|
||||||||||||||||||||||||||||||||
|
Amortization
of investment tax credits
|
(13 | ) | (4 | ) | (4 | ) | (2 | ) | - | - | (1 | ) | (1 | ) | ||||||||||||||||||
|
State
income taxes, net of federal tax benefit
|
60 | 21 | 1 | 2 | (2 | ) | 25 | 7 | 5 | |||||||||||||||||||||||
|
Manufacturing
deduction
|
(29 | ) | (16 | ) | (3 | ) | (8 | ) | (2 | ) | - | - | - | |||||||||||||||||||
|
Effectively
settled tax items
|
(14 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Other,
net
|
31 | 12 | (4 | ) | (2 | ) | (3 | ) | 6 | 3 | 3 | |||||||||||||||||||||
|
Total
provision for income taxes
|
$ | 777 | $ | 293 | $ | 99 | $ | 137 | $ | 30 | $ | 148 | $ | 61 | $ | 58 | ||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Book
income before provision for income taxes
|
$ | 2,192 | $ | 833 | $ | 298 | $ | 440 | $ | 145 | $ | 335 | $ | 164 | $ | 157 | ||||||||||||||||
|
Federal
income tax expense at statutory rate
|
$ | 767 | $ | 292 | $ | 104 | $ | 154 | $ | 51 | $ | 117 | $ | 57 | $ | 55 | ||||||||||||||||
|
Increases
(reductions) in taxes resulting from-
|
||||||||||||||||||||||||||||||||
|
Amortization
of investment tax credits
|
(14 | ) | (4 | ) | (4 | ) | (2 | ) | (1 | ) | (1 | ) | (1 | ) | - | |||||||||||||||||
|
State
income taxes, net of federal tax benefit
|
110 | 45 | - | 14 | 6 | 24 | 9 | 8 | ||||||||||||||||||||||||
|
Manufacturing
deduction
|
(9 | ) | (6 | ) | (2 | ) | (1 | ) | - | - | - | - | ||||||||||||||||||||
|
Other,
net
|
29 | (22 | ) | 3 | (2 | ) | (2 | ) | 9 | 3 | 1 | |||||||||||||||||||||
|
Total
provision for income taxes
|
$ | 883 | $ | 305 | $ | 101 | $ | 163 | $ | 54 | $ | 149 | $ | 68 | $ | 64 | ||||||||||||||||
213
Accumulated
deferred income taxes as of December 31, 2009 and 2008 are as
follows:
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
AS
OF DECEMBER 31, 2009
|
||||||||||||||||||||||||||||||||
|
Property
basis differences
|
$ | 3,049 | $ | 619 | $ | 508 | $ | 419 | $ | 177 | $ | 458 | $ | 275 | $ | 350 | ||||||||||||||||
|
Regulatory
transition charge
|
334 | - | 67 | 95 | 2 | 157 | 13 | - | ||||||||||||||||||||||||
|
Customer
receivables for future income taxes
|
111 | - | - | - | - | 13 | 49 | 49 | ||||||||||||||||||||||||
|
Deferred
customer shopping incentive
|
55 | - | - | 55 | - | - | - | - | ||||||||||||||||||||||||
|
Deferred
MISO/PJM transmission costs
|
89 | - | - | - | - | - | 90 | (1 | ) | |||||||||||||||||||||||
|
Other
regulatory assets - RCP
|
162 | - | 80 | 54 | 28 | - | ||||||||||||||||||||||||||
|
Deferred
sale and leaseback gain
|
(486 | ) | (426 | ) | (40 | ) | - | - | (9 | ) | (11 | ) | - | |||||||||||||||||||
|
Nonutility
generation costs
|
9 | - | - | - | - | - | 48 | (39 | ) | |||||||||||||||||||||||
|
Unamortized
investment tax credits
|
(48 | ) | (22 | ) | (4 | ) | (4 | ) | (2 | ) | (2 | ) | (5 | ) | (4 | ) | ||||||||||||||||
|
Unrealized
losses on derivative hedges
|
(44 | ) | (8 | ) | - | - | - | (1 | ) | (1 | ) | - | ||||||||||||||||||||
|
Pension
and other postretirement obligations
|
(611 | ) | (75 | ) | (57 | ) | (18 | ) | (34 | ) | (72 | ) | (20 | ) | (83 | ) | ||||||||||||||||
|
Lease
market valuation liability
|
(232 | ) | (101 | ) | - | - | (111 | ) | - | - | - | |||||||||||||||||||||
|
Oyster
Creek securitization (Note 12(C))
|
132 | - | - | - | - | 132 | - | - | ||||||||||||||||||||||||
|
Nuclear
decommissioning activities
|
(34 | ) | 23 | 5 | - | 12 | (19 | ) | (1 | ) | (52 | ) | ||||||||||||||||||||
|
Mark-to-market
adjustments
|
(76 | ) | (76 | ) | - | - | - | - | - | - | ||||||||||||||||||||||
|
Deferred
gain for asset sales -affiliated companies
|
- | - | 37 | 25 | 8 | - | - | - | ||||||||||||||||||||||||
|
Allowance
for equity funds used used during construction
|
15 | - | 15 | - | - | - | - | - | ||||||||||||||||||||||||
|
Loss
carryforwards
|
(33 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Loss
carryforward valuation reserve
|
21 | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
All
other
|
55 | (21 | ) | 49 | 19 | 1 | 31 | 16 | 22 | |||||||||||||||||||||||
|
Net
deferred income tax liability (asset)
|
$ | 2,468 | $ | (87 | ) | $ | 660 | $ | 645 | $ | 81 | $ | 688 | $ | 453 | $ | 242 | |||||||||||||||
|
AS
OF DECEMBER 31, 2008
|
||||||||||||||||||||||||||||||||
|
Property
basis differences
|
$ | 2,736 | $ | 434 | $ | 494 | $ | 428 | $ | 172 | $ | 436 | $ | 275 | $ | 329 | ||||||||||||||||
|
Regulatory
transition charge
|
292 | - | 40 | 29 | 4 | 190 | 29 | - | ||||||||||||||||||||||||
|
Customer
receivables for future income taxes
|
145 | - | 22 | 1 | - | 24 | 49 | 48 | ||||||||||||||||||||||||
|
Deferred
customer shopping incentive
|
151 | - | - | 151 | - | - | - | - | ||||||||||||||||||||||||
|
Deferred
MISO/PJM transmission costs
|
167 | - | 11 | 7 | 7 | - | 137 | 4 | ||||||||||||||||||||||||
|
Other
regulatory assets - RCP
|
253 | - | 121 | 100 | 32 | - | - | - | ||||||||||||||||||||||||
|
Deferred
sale and leaseback gain
|
(505 | ) | (438 | ) | (45 | ) | - | - | (10 | ) | (12 | ) | - | |||||||||||||||||||
|
Nonutility
generation costs
|
(52 | ) | - | - | - | - | - | 30 | (82 | ) | ||||||||||||||||||||||
|
Unamortized
investment tax credits
|
(51 | ) | (23 | ) | (5 | ) | (5 | ) | (2 | ) | (2 | ) | (6 | ) | (5 | ) | ||||||||||||||||
|
Unrealized
losses on derivative hedges
|
(68 | ) | (15 | ) | - | - | - | (1 | ) | (1 | ) | - | ||||||||||||||||||||
|
Pension
and other postretirement obligations
|
(715 | ) | (68 | ) | (94 | ) | (47 | ) | (25 | ) | (90 | ) | (72 | ) | (89 | ) | ||||||||||||||||
|
Lease
market valuation liability
|
(254 | ) | (124 | ) | - | - | (122 | ) | - | - | - | |||||||||||||||||||||
|
Oyster
Creek securitization (Note 12(C))
|
137 | - | - | - | - | 137 | - | - | ||||||||||||||||||||||||
|
Nuclear
decommissioning activities
|
(130 | ) | 14 | 2 | - | 13 | (34 | ) | (65 | ) | (55 | ) | ||||||||||||||||||||
|
Deferred
gain for asset sales -affiliated companies
|
- | - | 41 | 27 | 9 | - | - | - | ||||||||||||||||||||||||
|
Allowance
for equity funds used during construction
|
21 | - | 20 | 1 | - | - | - | - | ||||||||||||||||||||||||
|
Loss
carryforwards
|
(35 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Loss
carryforward valuation reserve
|
27 | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
All
other
|
44 | (48 | ) | 46 | 12 | (9 | ) | 39 | 24 | 20 | ||||||||||||||||||||||
|
Net
deferred income tax liability (asset)
|
$ | 2,163 | $ | (268 | ) | $ | 653 | $ | 704 | $ | 79 | $ | 689 | $ | 388 | $ | 170 | |||||||||||||||
214
Upon
reaching a settlement on several items under appeal for the tax years 2001-2003,
as well as other items that effectively settled in 2009, FirstEnergy recognized
approximately $100 million of net tax benefits, including $161 million that
favorably affected FirstEnergy’s effective tax rate. The offsetting $61 million
primarily related to tax items where the uncertainty was removed and the tax
refund will be received when the tax years are closed. Upon completion of the
federal tax examinations for tax years 2004-2006, as well as other tax
settlements reached in 2008, FirstEnergy recognized approximately $42 million of
net tax benefits, including $7 million that favorably affected FirstEnergy’s
effective tax rate. The remaining balance of the tax benefits recognized in 2008
adjusted goodwill as a purchase price adjustment ($20 million) and accumulated
deferred income taxes for temporary tax items ($15 million). During 2007, there
were no material changes to FirstEnergy’s unrecognized tax
benefits.
As of
December 31, 2009, it is reasonably possible that approximately $148 million of
the unrecognized benefits may be resolved within the next twelve months, of
which up to approximately $11 million, if recognized, would affect FirstEnergy’s
effective tax rate. The potential decrease in the amount of unrecognized tax
benefits is primarily associated with issues related to the capitalization of
certain costs and various state tax items.
In 2008,
FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method
related to the costs to repair and maintain electric generation stations. During
the second quarter of 2009, the IRS approved the change in accounting method and
$281 million of costs were included as a repair deduction on FirstEnergy’s 2008
consolidated tax return. Since the IRS did not complete its review over this
change in accounting method by the extended filing date of FirstEnergy’s federal
tax return, FirstEnergy increased the amount of unrecognized tax benefits by $34
million in the third quarter of 2009, with a corresponding adjustment to
accumulated deferred income taxes for this temporary tax item. There was no
impact on FirstEnergy’s effective tax rate for the year.
In 2009,
FirstEnergy, on behalf of OE, PP, CEI, TE, ATSI, JCP&L, Met-Ed and Penelec,
filed a change in accounting method related to the costs to repair and maintain
electric utility network (transmission and distribution) assets and is in the
process of computing the amount of costs that will qualify as a deduction to be
included on FirstEnergy’s 2009 consolidated tax return. This change in
accounting method is expected to have a material impact on taxable income for
2009 and could increase the amount of tax refunds to be recognized in 2010 with
a corresponding adjustment to accumulated deferred income taxes for this
temporary tax item. There would be no impact on FirstEnergy’s effective tax
rate.
The
changes in unrecognized tax benefits for the three years ended December 31, 2009
are as follows:
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
Balance
as of January 1, 2009
|
$ | 219 | $ | 5 | $ | (30 | ) | $ | (26 | ) | $ | (4 | ) | $ | 42 | $ | 28 | $ | 24 | |||||||||||||
|
Increase
for tax positions related to the current year
|
41 | 34 | 4 | 3 | - | - | - | - | ||||||||||||||||||||||||
|
Increase
for tax positions related to prior years
|
46 | 2 | 103 | 52 | 10 | - | - | - | ||||||||||||||||||||||||
|
Decrease
for tax positions related to prior years
|
(100 | ) | - | - | - | - | (28 | ) | (15 | ) | (13 | ) | ||||||||||||||||||||
|
Decrease
for settlement
|
(15 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Balance
as of December 31, 2009
|
$ | 191 | $ | 41 | $ | 77 | $ | 29 | $ | 6 | $ | 14 | $ | 13 | $ | 11 | ||||||||||||||||
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
Balance
as of January 1, 2008
|
$ | 272 | $ | 14 | $ | (12 | ) | $ | (17 | ) | $ | (1 | ) | $ | 38 | $ | 24 | $ | 16 | |||||||||||||
|
Increase
for tax positions related to the current year
|
14 | - | 1 | - | - | - | - | - | ||||||||||||||||||||||||
|
Increase
for tax positions related to prior years
|
- | 1 | 1 | - | - | 6 | 5 | 9 | ||||||||||||||||||||||||
|
Decrease
for tax positions related to prior years
|
(56 | ) | (10 | ) | (14 | ) | (8 | ) | (3 | ) | (2 | ) | (1 | ) | (1 | ) | ||||||||||||||||
|
Decrease
for settlement
|
(11 | ) | - | (6 | ) | (1 | ) | - | - | - | - | |||||||||||||||||||||
|
Balance
as of December 31, 2008
|
$ | 219 | $ | 5 | $ | (30 | ) | $ | (26 | ) | $ | (4 | ) | $ | 42 | $ | 28 | $ | 24 | |||||||||||||
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
Balance
as of January 1, 2007
|
$ | 268 | $ | 14 | $ | (19 | ) | $ | (15 | ) | $ | (3 | ) | $ | 44 | $ | 18 | $ | 20 | |||||||||||||
|
Increase
for tax positions related to the current year
|
1 | - | 1 | - | - | - | - | - | ||||||||||||||||||||||||
|
Increase
for tax positions related to prior years
|
3 | 4 | 10 | 2 | 2 | - | 6 | - | ||||||||||||||||||||||||
|
Decrease
for tax positions related to prior years
|
- | (4 | ) | (4 | ) | (4 | ) | - | (6 | ) | - | (4 | ) | |||||||||||||||||||
|
Balance
as of December 31, 2007
|
$ | 272 | $ | 14 | $ | (12 | ) | $ | (17 | ) | $ | (1 | ) | $ | 38 | $ | 24 | $ | 16 | |||||||||||||
215
FirstEnergy
recognizes interest expense or income related to uncertain tax positions. That
amount is computed by applying the applicable statutory interest rate to the
difference between the tax position recognized and the amount previously taken
or expected to be taken on the tax return. FirstEnergy includes net interest and
penalties in the provision for income taxes. The reversal of accrued interest
associated with the $161 million in recognized tax benefits favorably affected
FirstEnergy's effective tax rate in 2009 by $56 million and an interest
receivable of $11 million was removed from the accrued interest for uncertain
tax positions. The reversal of accrued interest associated with the $56 million
in recognized tax benefits favorably affected FirstEnergy’s effective tax rate
in 2008 by $12 million and an interest receivable of $4 million was removed from
the accrued interest for uncertain tax positions. During the years ended
December 31, 2009, 2008 and 2007, FirstEnergy recognized net interest expense
(income) of approximately $(49) million, $2 million and $19 million,
respectively. The net amount of interest accrued as of December 31, 2009 and
2008 was $21 million and $59 million, respectively.
The
following table summarizes the net interest expense (income) recognized by FES
and the Utilities for the three years ended December 31, 2009 and the cumulative
net interest payable (receivable) as of December 31, 2009 and 2008:
|
Net
Interest Expense (Income)
|
Net
Interest Payable
|
|||||||||||||||||||
|
For
the Years Ended
|
(Receivable)
|
|||||||||||||||||||
|
December
31,
|
As
of December 31,
|
|||||||||||||||||||
|
2009
|
2008
|
2007
|
2009
|
2008
|
||||||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||||||
|
FES
|
$ | (1 | ) | $ | - | $ | - | $ | 2 | $ | 1 | |||||||||
|
OE
|
4 | (4 | ) | 1 | 9 | (9 | ) | |||||||||||||
|
CEI
|
3 | (2 | ) | (1 | ) | 3 | (7 | ) | ||||||||||||
|
TE
|
- | - | - | 1 | (1 | ) | ||||||||||||||
|
JCP&L
|
(4 | ) | 1 | 1 | 1 | 11 | ||||||||||||||
|
Met-Ed
|
(2 | ) | 1 | 2 | 1 | 6 | ||||||||||||||
|
Penelec
|
(1 | ) | 2 | - | 1 | 6 | ||||||||||||||
FirstEnergy
has tax returns that are under review at the audit or appeals level by the IRS
and state tax authorities. All state jurisdictions are open from 2001-2008. The
IRS began reviewing returns for the years 2001-2003 in July 2004 and several
items were under appeal. In the fourth quarter of 2009, these items were settled
at appeals and sent to Joint Committee on Taxation for final review. The federal
audits for years 2004-2006 were completed in the third quarter of 2008 and
several items are under appeal. The IRS began auditing the year 2007 in February
2007 under its Compliance Assurance Process program and was completed in the
first quarter of 2009 with two items under appeal. The IRS began auditing the
year 2008 in February 2008 and the audit is expected to close before December
2010. The 2009 tax year audit began in February 2009 and is not expected to
close before December 2010. Management believes that adequate reserves have been
recognized and final settlement of these audits is not expected to have a
material adverse effect on FirstEnergy’s financial condition or results of
operations.
On July
13, 2007, FGCO completed a sale and leaseback transaction for its 93.825%
undivided interest in Bruce Mansfield Unit 1, representing 779 MW of net
demonstrated capacity (see Note 7). This transaction generated tax capital gains
of approximately $815 million, all of which were offset by existing tax capital
loss carryforwards. Accordingly, FirstEnergy reduced its tax loss carryforward
valuation allowance in the third quarter of 2007, with a corresponding reduction
to goodwill (see Note 2(E)).
FirstEnergy
has pre-tax net operating loss carryforwards for state and local income tax
purposes of approximately $1.044 billion, of which $194 million is expected to
be utilized. The associated deferred tax assets are $11 million. These losses
expire as follows:
|
Expiration
Period
|
FE
|
FES
|
Penelec
|
||||||||||
|
(In
millions)
|
|||||||||||||
| 2010-2014 | $ | 226 | $ | 16 | $ | - | |||||||
| 2015-2019 | 8 | - | - | ||||||||||
| 2020-2024 | 523 | 23 | 200 | ||||||||||
| 2025-2028 | 287 | 65 | - | ||||||||||
| $ | 1,044 | $ | 104 | $ | 200 | ||||||||
216
General
Taxes
Details
of general taxes for the three years ended December 31, 2009 are shown
below:
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||||||
|
Kilowatt-hour
excise
(1)
|
$ | 224 | $ | 1 | $ | 84 | $ | 66 | $ | 24 | $ | 49 | $ | - | $ | - | ||||||||||||||||
|
State
gross receipts
|
171 | 14 | 15 | - | - | - | 78 | 63 | ||||||||||||||||||||||||
|
Real
and personal property
|
253 | 53 | 64 | 74 | 21 | 5 | 2 | 2 | ||||||||||||||||||||||||
|
Social
security and unemployment
|
90 | 14 | 8 | 5 | 3 | 9 | 5 | 6 | ||||||||||||||||||||||||
|
Other
|
15 | 5 | - | - | - | - | 3 | 3 | ||||||||||||||||||||||||
|
Total
general taxes
|
$ | 753 | $ | 87 | $ | 171 | $ | 145 | $ | 48 | $ | 63 | $ | 88 | $ | 74 | ||||||||||||||||
|
2008
|
||||||||||||||||||||||||||||||||
|
Kilowatt-hour
excise
|
$ | 249 | $ | 1 | $ | 97 | $ | 70 | $ | 30 | $ | 51 | $ | - | $ | - | ||||||||||||||||
|
State
gross receipts
|
183 | 16 | 17 | - | - | - | 79 | 70 | ||||||||||||||||||||||||
|
Real
and personal property
|
240 | 53 | 61 | 67 | 19 | 5 | 3 | 2 | ||||||||||||||||||||||||
|
Social
security and unemployment
|
95 | 14 | 9 | 6 | 3 | 10 | 5 | 6 | ||||||||||||||||||||||||
|
Other
|
11 | 4 | 2 | - | - | 1 | (1 | ) | 2 | |||||||||||||||||||||||
|
Total
general taxes
|
$ | 778 | $ | 88 | $ | 186 | $ | 143 | $ | 52 | $ | 67 | $ | 86 | $ | 80 | ||||||||||||||||
|
2007
|
||||||||||||||||||||||||||||||||
|
Kilowatt-hour
excise
|
$ | 250 | $ | 1 | $ | 99 | $ | 69 | $ | 29 | $ | 52 | $ | - | $ | - | ||||||||||||||||
|
State
gross receipts
|
175 | 18 | 17 | - | - | - | 73 | 66 | ||||||||||||||||||||||||
|
Real
and personal property
|
237 | 53 | 59 | 65 | 19 | 5 | 2 | 2 | ||||||||||||||||||||||||
|
Social
security and unemployment
|
87 | 14 | 8 | 6 | 3 | 9 | 5 | 5 | ||||||||||||||||||||||||
|
Other
|
5 | 1 | (2 | ) | 2 | - | - | - | 3 | |||||||||||||||||||||||
|
Total
general taxes
|
$ | 754 | $ | 87 | $ | 181 | $ | 142 | $ | 51 | $ | 66 | $ | 80 | $ | 76 | ||||||||||||||||
|
(1)
|
Kilowatt-hour
excise tax for OE and TE includes a $7.1 million and $3.5 million
adjustment, respectively, recognized in 2009 related to prior
periods.
|
|
11.
|
REGULATORY
MATTERS
|
|
(A)
|
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 Reliability
First
later this
year.
217
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 Reliability
First
a potential violation
of NERC Standard PRC-005 resulting from its inability to validate maintenance
records for 20 protection system relays (out of approcimately 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. Reliability
First
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 Reliability
First
will propose for this
self-reported violation.
|
(B)
|
OHIO
|
On June
7, 2007, the Ohio Companies filed an application for an increase in electric
distribution rates with the PUCO and, on August 6, 2007, updated their filing.
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.
218
On
January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish
an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an
Amended ESP application, including an attached Stipulation and Recommendation
that was signed by the Ohio Companies, the Staff of the PUCO, and many of the
intervening parties. Specifically, the Amended ESP provided that generation
would be provided by FES at the average wholesale rate of the CBP process
described above for April and May 2009 to the Ohio Companies for their
non-shopping customers; for the period of June 1, 2009 through May 31, 2011,
retail generation prices would be based upon the outcome of a descending clock
CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio
Companies will not seek a base distribution rate increase, subject to certain
exceptions, with an effective date of such increase before January 1, 2012, that
CEI would agree to write-off approximately $216 million of its Extended RTC
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.
219
In
October 2009, the PUCO issued additional Entries on Rehearing, 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 rules 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 carbon dioxide
control planning requirements and changes to long term forecast reporting
requirements. The rules severely restrict the types of renewable energy
resources energy efficiency and peak reduction programs that may be included
toward meeting the statutory goals, which is expected to increase the cost of
compliance for the Ohio Companies' customers. As a result of the rules going
into effect in December 2009, and the PUCO’s failure to address certain energy
efficiency applications submitted by the Ohio Companies throughout the year and
the PUCO’s directive to postpone the launch of a PUCO-approved energy efficiency
program, 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.
|
(C)
|
PENNSYLVANIA
|
Met-Ed
and Penelec purchase a portion of their PLR and default service requirements
from FES through a fixed-price partial requirements wholesale power sales
agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG
energy to the market and requires FES to provide energy at fixed prices to
replace any NUG energy sold to the extent needed for Met-Ed and Penelec to
satisfy their PLR and default service obligations.
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 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 the 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.
220
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, as required in
connection with the PPUC’s January 2007 rate order. For Penelec’s customers the
new TSC resulted in an approximate 1% decrease in monthly bills, reflecting
projected PJM transmission costs as well as a reconciliation for costs already
incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM
charges paid by Met-Ed in the previous year and to reflect updated projected
costs. In order to gradually transition customers to the higher rate, the PPUC
approved Met-Ed’s proposal to continue to recover the prior period deferrals
allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs
to a future TSC to be fully recovered by December 31, 2010. Under this proposal,
monthly bills for Met-Ed’s customers 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 utilities 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 required 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 PPUC’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.
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Legislation
addressing rate mitigation and the expiration of rate caps has been introduced
in the legislative session that ended in 2008; several bills addressing these
issues were introduced in the 2009 legislative session. The final form and
impact of such legislation is 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.
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
Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the
PPUC issued Secretarial Letters approving 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 PPUC.
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 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. The PPUC is required to issue an order on the
plan no later than November 8, 2010.
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NEW
JERSEY
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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.
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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 which 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.
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(E)
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FERC
MATTERS
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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. This matter is pending in the Court and the outcome cannot be
predicted.
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PJM
Transmission Rate
On
January 31, 2005, certain PJM transmission owners made filings with the FERC
pursuant to a settlement agreement previously approved by the FERC. JCP&L,
Met-Ed and Penelec were parties to that proceeding and joined in two of the
filings. In the first filing, the settling transmission owners submitted a
filing justifying continuation of their existing rate design within the PJM RTO.
Hearings were held and numerous parties appeared and litigated various issues
concerning PJM rate design, notably AEP, which proposed to create a "postage
stamp," or average rate for all high voltage transmission facilities across PJM
and a zonal transmission rate for facilities below 345 kV. AEP's proposal would
have the effect of shifting recovery of the costs of high voltage transmission
lines to other transmission zones, including those where JCP&L, Met-Ed, and
Penelec serve load. On April 19, 2007, the FERC issued an order (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 have
been consolidated for argument in the Seventh Circuit. The Seventh Circuit Court
of Appeals issued a decision on August 6, 2009, that remanded the rate design to
FERC and denied the appeal. 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 PJM-wide 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 Regional Transmission Expansion
Planning 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, 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). Subject to satisfactory
outcomes in the FERC dockets, 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. To ensure a definitive
ruling at the same time FERC rules on its request to integrate ATSI into PJM, on
October 19, 2009, FirstEnergy filed a related complaint with 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.
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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 approved in the FERC Order.
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 proposed capacity 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 requests 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, and will participate in PJM’s next base residual auction for
capacity resources for the 2013-2014 delivery years. 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 Capacity Market Evolution Committee (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 FERC on April
1, 2010.
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.
225
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
Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES
signed an agreement to provide 75% of the Ohio Companies’ power requirements for
the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an
agreement to provide 100% of the Ohio Companies’ power requirements for the
period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an
order approving these two affiliate sales agreements. FERC authorization for
these affiliate sales was by means of a December 23, 2008 waiver of restrictions
on affiliate sales without prior approval of the FERC. Rehearing was denied on
July 31, 2009. On October 19, 2009, 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.
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12.
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CAPITALIZATION
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(A)
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COMMON
STOCK
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Retained
Earnings and Dividends
As of
December 31, 2009, FirstEnergy's unrestricted retained earnings were $4.5
billion. Dividends declared in 2009 were $2.20, which included four quarterly
dividends of $0.55 per share paid in the second, third and fourth quarters of
2009 and payable in the first quarter of 2010. Dividends declared in 2008 were
$2.20, which included four quarterly dividends of $0.55 per share paid in the
second, third and fourth quarters of 2008 and first quarter of 2009. The amount
and timing of all dividend declarations are subject to the discretion of the
Board of Directors and its consideration of business conditions, results of
operations, financial condition and other factors.
226
In
addition to paying dividends from retained earnings, each of FirstEnergy’s
electric utility subsidiaries has authorization from the FERC to pay cash
dividends to FirstEnergy from paid-in capital accounts, as long as its equity to
total capitalization ratio (without consideration of retained earnings) remains
above 35%. The articles of incorporation, indentures and various other
agreements relating to the long-term debt of certain FirstEnergy subsidiaries
contain provisions that could further restrict the payment of dividends on their
common stock. None of these provisions materially restricted FirstEnergy’s
subsidiaries’ ability to pay cash dividends to FirstEnergy as of December 31,
2009.
|
(B)
|
PREFERRED
AND PREFERENCE STOCK
|
FirstEnergy’s
and the Utilities’ preferred stock and preference stock authorizations are as
follows:
|
|
Preferred
Stock
|
Preference
Stock
|
||||||||||||||
|
Shares
|
Par
|
Shares
|
Par
|
|||||||||||||
|
Authorized
|
Value
|
Authorized
|
Value
|
|||||||||||||
|
FirstEnergy
|
5,000,000 | $ | 100 | |||||||||||||
|
OE
|
6,000,000 | $ | 100 | 8,000,000 |
no
par
|
|||||||||||
|
OE
|
8,000,000 | $ | 25 | |||||||||||||
|
Penn
|
1,200,000 | $ | 100 | |||||||||||||
|
CEI
|
4,000,000 |
no
par
|
3,000,000 |
no
par
|
||||||||||||
|
TE
|
3,000,000 | $ | 100 | 5,000,000 | $ | 25 | ||||||||||
|
TE
|
12,000,000 | $ | 25 | |||||||||||||
|
JCP&L
|
15,600,000 |
no
par
|
||||||||||||||
|
Met-Ed
|
10,000,000 |
no
par
|
||||||||||||||
|
Penelec
|
11,435,000 |
no
par
|
||||||||||||||
No
preferred shares or preference shares are currently outstanding.
|
(C)
|
LONG-TERM
DEBT AND OTHER LONG-TERM
OBLIGATIONS
|
The
following table presents the outstanding consolidated long-term debt and other
long-term obligations of FirstEnergy as of December 31, 2009 and
2008:
|
Weighted
Average
|
December
31,
|
||||||||||
|
Interest
Rate (%)
|
2009
|
2008
|
|||||||||
|
(In
millions)
|
|||||||||||
|
FMBs:
|
|||||||||||
|
Due
2009-2013
|
5.96 | $ | 28 | $ | 29 | ||||||
|
Due
2014-2018
|
8.84 | 330 | 330 | ||||||||
|
Due
2019-2023
|
6.22 | 107 | 7 | ||||||||
|
Due
2024-2028
|
8.75 | 314 | 14 | ||||||||
|
Due
2038
|
8.25 | 275 | 275 | ||||||||
|
Total
FMBs
|
1,054 | 655 | |||||||||
|
Secured
Notes:
|
|||||||||||
|
Due
2009-2013
|
7.68 | 356 | 607 | ||||||||
|
Due
2014-2018
|
7.35 | 557 | 613 | ||||||||
|
Due
2019-2023
|
7.05 | 341 | 70 | ||||||||
|
Total
Secured Notes
|
1,254 | 1,290 | |||||||||
|
Unsecured
Notes:
|
|||||||||||
|
Due
2009-2013
|
5.50 | 878 | 2,253 | ||||||||
|
Due
2014-2018
|
5.56 | 2,693 | 2,149 | ||||||||
|
Due
2019-2023
|
5.47 | 2,575 | 689 | ||||||||
|
Due
2024-2028
|
4.36 | 65 | 65 | ||||||||
|
Due
2029-2033
|
6.18 | 2,247 | 2,247 | ||||||||
|
Due
2034-2038
|
4.99 | 2,186 | 1,936 | ||||||||
|
Due
2039-2043
|
4.70 | 755 | 255 | ||||||||
|
Due
2047
|
3.00 | 46 | 46 | ||||||||
|
Total
Unsecured Notes
|
11,445 | 9,640 | |||||||||
|
Capital
lease obligations
|
13 | 8 | |||||||||
|
Net
unamortized discount on debt
|
(24 | ) | (17 | ) | |||||||
|
Long-term
debt due within one year
|
(1,834 | ) | (2,476 | ) | |||||||
|
Total
long-term debt and other long-term obligations
|
$ | 11,908 | $ | 9,100 | |||||||
227
Securitized
Transition Bonds
The
consolidated financial statements of FirstEnergy and JCP&L include the
accounts of JCP&L Transition Funding and JCP&L Transition Funding II,
wholly owned limited liability companies of JCP&L. In June 2002, JCP&L
Transition Funding sold $320 million of transition bonds to securitize the
recovery of JCP&L's bondable stranded costs associated with the previously
divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L
Transition Funding II sold $182 million of transition bonds to securitize the
recovery of deferred costs associated with JCP&L’s supply of
BGS.
JCP&L
did not purchase and does not own any of the transition bonds, which are
included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance
Sheets. As of December 31, 2009, $340 million of the transition bonds were
outstanding. The transition bonds are the sole obligations of JCP&L
Transition Funding and JCP&L Transition Funding II and are collateralized by
each company’s equity and assets, which consist primarily of bondable transition
property.
Bondable
transition property represents the irrevocable right under New Jersey law of a
utility company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on transition bonds and
other fees and expenses associated with their issuance. JCP&L sold its
bondable transition property to JCP&L Transition Funding and JCP&L
Transition Funding II and, as servicer, manages and administers the bondable
transition property, including the billing, collection and remittance of the
TBC, pursuant to separate servicing agreements with JCP&L Transition Funding
and JCP&L Transition Funding II. For the two series of transition bonds,
JCP&L is entitled to aggregate annual servicing fees of up to $628,000 that
are payable from TBC collections.
Other
Long-term Debt
FGCO,
NGC and each of the Utilities, except for JCP&L, have a first mortgage
indenture under which they can issue FMBs secured by a direct first mortgage
lien on substantially all of their property and franchises, other than
specifically excepted property.
FirstEnergy
and its subsidiaries have various debt covenants under their respective
financing arrangements. The most restrictive of the debt covenants relate to the
nonpayment of interest and/or principal on debt and the maintenance of certain
financial ratios. There also exist cross-default provisions in a number of the
respective financing arrangements of FirstEnergy, FES, FGCO, NGC and the
Utilities. These provisions generally trigger a default in the applicable
financing arrangement of an entity if it or any of its significant subsidiaries
defaults under another financing arrangement of a certain principal amount,
typically $50 million. Although such defaults by any of the Utilities will
generally cross-default FirstEnergy financing arrangements containing these
provisions, defaults by FirstEnergy will not generally cross-default applicable
financing arrangements of any of the Utilities. Defaults by any of FES, FGCO or
NGC will generally cross-default to applicable financing arrangements of
FirstEnergy and, due to the existence of guarantees by FirstEnergy of certain
financing arrangements of FES, FGCO and NGC, defaults by FirstEnergy will
generally cross-default FES, FGCO and NGC financing arrangements containing
these provisions. Cross-default provisions are not typically found in any of the
senior note or FMBs of FirstEnergy or the Utilities.
Based on
the amount of FMBs authenticated by the respective mortgage bond trustees
through December 31, 2009, the Utilities’ annual sinking fund requirement for
all FMB issued under the various mortgage indentures amounted to $35 million
(Penn - $6 million, Met-Ed - $8 million and Penelec - $21 million). Penn expects
to meet its 2010 annual sinking fund requirement with a replacement credit under
its mortgage indenture. Met-Ed and Penelec could fulfill their sinking fund
obligations by providing bondable property additions, previously retired FMBs or
cash to the respective mortgage bond trustees.
As of
December 31, 2009, FirstEnergy’s currently payable long-term debt includes
approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec
- $45 million) of variable interest rate PCRBs, the bondholders of which are
entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates
on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for
mandatory purchase prior to maturity with the purchase price payable from
remarketing proceeds, or if the PCRBs are not successfully remarketed, by
drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required
to reimburse the applicable LOC bank for any such drawings or, if the LOC bank
fails to honor its LOC for any reason, must itself pay the purchase price. Prior
to the third quarter of 2008, FirstEnergy subsidiaries had not experienced any
unsuccessful remarketings of these variable-rate PCRBs. Coincident with recent
disruptions in the variable-rate demand bond and capital markets generally,
certain of the PCRBs had been tendered by bondholders to the trustee. As of
January 31, 2009, all PCRBs that had been tendered were successfully
remarketed.
228
In 2009,
holders of approximately $434 million of LOC-supported PCRBs of OE and NGC were
notified that the applicable Wachovia Bank LOCs were set to expire. As a result,
these PCRBs were subject to mandatory purchase at a price equal to the principal
amount, plus accrued and unpaid interest, which OE and NGC funded through
short-term borrowings. FGCO remarketed $100 million of those PCRBs, which were
previously held by OE and NGC and remarketed the remaining $334 million of
PCRBs, of which $170 million was remarketed in fixed interest rate modes and
secured by FMBs, thereby eliminating the need for third-party credit support.
Also during 2009, FGCO and NGC remarketed approximately $329 million of other
PCRBs supported by LOCs set to expire in 2009. Those PCRBs were also remarketed
in fixed interest rate modes and secured by FMBs, thereby eliminating the need
for third-party credit support. FGCO and NGC delivered FMBs to certain LOC banks
listed above in connection with amendments to existing LOC and reimbursement
agreements supporting twelve other series of PCRBs as described below and
pledged FMBs to the applicable trustee under six separate series of PCRBs. On
August 14, 2009, $177 million of non-LOC supported fixed rate PCRBs were issued
and sold on behalf of FGCO to pay a portion of the cost of acquiring,
constructing and installing air quality facilities at its W.H. Sammis Generating
Station.
Sinking
fund requirements for FMBs and maturing long-term debt (excluding capital leases
and variable rate PCRBs) for the next five years are:
|
Year
|
FE
|
FES
|
OE
|
CEI
|
JCP&L
|
Met-Ed
|
Penelec
|
||||||||||||
|
(In
millions)
|
|||||||||||||||||||
|
2010
|
268
|
52
|
2
|
18
|
31
|
100
|
24
|
||||||||||||
|
2011
|
337
|
58
|
1
|
20
|
32
|
-
|
-
|
||||||||||||
|
2012
|
99
|
68
|
1
|
22
|
34
|
-
|
-
|
||||||||||||
|
2013
|
557
|
75
|
2
|
324
|
36
|
150
|
-
|
||||||||||||
|
2014
|
531
|
99
|
1
|
26
|
38
|
250
|
150
|
||||||||||||
The
following table classifies the outstanding PCRBs by year, for the next three
years, representing the next time the debt holders may exercise their right to
tender their PCRBs.
|
Year
|
FE
|
FES
|
Met-Ed
|
Penelec
|
||||||
|
(In
millions)
|
||||||||||
|
2010
|
1,568
|
1,494
|
29
|
45
|
||||||
|
2011
|
75
|
75
|
-
|
-
|
||||||
|
2012
|
244
|
244
|
-
|
-
|
||||||
Obligations
to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are
entitled to the benefit of irrevocable bank LOCs of $1.6 billion as of December
31, 2009, or noncancelable municipal bond insurance of $38 million as of
December 31, 2009, to pay principal of, or interest on, the applicable PCRBs. To
the extent that drawings are made under the LOCs or the insurance, FGCO, NGC and
the Utilities are entitled to a credit against their obligation to repay those
bonds. FGCO, NGC and the Utilities pay annual fees of 0.35% to 3.30% of the
amounts of the LOCs to the issuing banks and are obligated to reimburse the
banks or insurers, as the case may be, for any drawings thereunder. The insurers
hold FMBs as security for such reimbursement obligations. These amounts and
percentages for FirstEnergy, FES and the Utilities are as follows:
|
FE
|
FES
|
Met-Ed
|
Penelec
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Amounts
|
||||||||||||||||
|
LOCs
|
$ | 1,568 | $ | 1,494 | * | $ | 29 | $ | 45 | |||||||
|
Insurance
Policies
|
38 | - | 14 | 24 | ||||||||||||
|
Fees
|
||||||||||||||||
|
LOCs
|
0.35%
to 3.30%
|
0.35%
to 3.30%
|
1.5 | % | 1.5 | % | ||||||||||
| * | Includes LOC of $137 million issued for FirstEnergy on behalf of NGC. |
OE has
LOCs of $200 million and $134 million in connection with the sale and leaseback
of Beaver Valley Unit 2 and Perry Unit 1, respectively. In 2004, OE entered into
a Credit Agreement pursuant to which a standby LOC was issued in support of
approximately $236 million of the Beaver Valley Unit 2 LOCs and the issuer of
the standby LOC obtained the right to pledge or assign participations in OE's
reimbursement obligations under the credit agreement to a trust. The trust then
issued and sold trust certificates to institutional investors that were designed
to be the credit equivalent of an investment directly in OE. In 2009, these LOCs
were renewed in the amount of $145 million.
229
13. ASSET
RETIREMENT OBLIGATIONS
FirstEnergy
has recognized applicable legal obligations for AROs and their associated cost
for nuclear power plant decommissioning, reclamation of a sludge disposal pond
and closure of two coal ash disposal sites. In addition, FirstEnergy has
recognized conditional retirement obligations (primarily for asbestos
remediation).
The ARO
liabilities for FES, OE and TE primarily relate to the decommissioning of the
Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its
leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold
interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and
Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating
facility. FES and the Utilities use an expected cash flow approach to measure
the fair value of their nuclear decommissioning AROs.
FirstEnergy,
FES and the Utilities maintain nuclear decommissioning trust funds that are
legally restricted for purposes of settling the nuclear decommissioning ARO. The
fair values of the decommissioning trust assets as of December 31, 2009 and 2008
were as follows:
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
FE
|
$ | 1,859 | $ | 1,700 | ||||
|
FES
|
1,089 | 1,034 | ||||||
|
OE
|
121 | 117 | ||||||
|
TE
|
74 | 74 | ||||||
|
JCP&L
|
167 | 143 | ||||||
|
Met-Ed
|
266 | 226 | ||||||
|
Penelec
|
143 | 115 | ||||||
Accounting
standards for conditional retirement obligations associated with tangible
long-lived assets require recognition of the fair value of a liability for an
ARO in the period in which it is incurred if a reasonable estimate can made,
even though there may be uncertainty about timing or method of settlement. When
settlement is conditional on a future event occurring, it is reflected in the
measurement of the liability, not in the recognition of the
liability.
The
following table summarizes the changes to the ARO balances during 2009 and
2008.
|
ARO
Reconciliation
|
FE
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||||
|
(In
millions)
|
|||||||||||||||||||||||||||||||
|
Balance
as of January 1, 2008
|
$ | 1,279 | $ | 810 | $ | 105 | $ | 2 | $ | 28 | $ | 90 | $ | 161 | $ | 82 | |||||||||||||||
|
Liabilities
incurred
|
5 | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Liabilities
settled
|
(3 | ) | (2 | ) | - | - | - | - | - | - | |||||||||||||||||||||
|
Accretion
|
84 | 55 | 5 | - | 2 | 5 | 10 | 5 | |||||||||||||||||||||||
|
Revisions
in estimated cash flows
|
(18 | ) 1 | - | (18 | ) 1 | - | - | - | - | - | |||||||||||||||||||||
|
Balance
as of December 31, 2008
|
1,347 | 863 | 92 | 2 | 30 | 95 | 171 | 87 | |||||||||||||||||||||||
|
Liabilities
incurred
|
4 | 1 | - | - | - | - | - | - | |||||||||||||||||||||||
|
Accretion
|
90 | 58 | 6 | - | 2 | 7 | 11 | 6 | |||||||||||||||||||||||
|
Revisions
in estimated cash flows
|
(16 | ) | (1 | ) | (12 | ) | - | - | - | (2 | ) | (1 | ) | ||||||||||||||||||
|
Balance
as of December 31, 2009
|
$ | 1,425 | $ | 921 | $ | 86 | $ | 2 | $ | 32 | $ | 102 | $ | 180 | $ | 92 | |||||||||||||||
|
(1)
|
OE
revised the estimated cash flows associated with the retired Gorge and
Toronto plants based on an agreement to remediate asbestos at the sites
within one year.
|
14. SHORT-TERM
BORROWINGS AND BANK LINES OF CREDIT
FirstEnergy
had approximately $1.2 billion of short-term indebtedness as of December 31,
2009, comprised of $1.1 billion of borrowings under a $2.75 billion revolving
line of credit, $100 million of other bank borrowings and $31 million of
currently payable notes. Total short-term bank lines of committed credit to
FirstEnergy and the Utilities as of January 31, 2010 were approximately $3.4
billion of which $1.7
billion was unused and
available.
FirstEnergy,
along with certain of its subsidiaries, are parties 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%.
230
The
following table summarizes the borrowing sub-limits for each borrower under the
facility, as well as the limitations on short-term indebtedness applicable to
each borrower under current regulatory approvals and applicable statutory and/or
charter limitations as of December 31, 2009:
|
|
Revolving
|
Regulatory
and
|
|||||||
|
|
Credit
Facility
|
Other
Short-Term
|
|||||||
|
Borrower
|
Sub-Limit
|
Debt
Limitations
|
|||||||
|
(In
millions)
|
|||||||||
|
FirstEnergy
|
$ | 2,750 | $ | - | (1) | ||||
|
FES
|
1,000 | - | (1) | ||||||
|
OE
|
500 | 500 | |||||||
|
Penn
|
50 | 33 | (2) | ||||||
|
CEI
|
250 | (3) | 500 | ||||||
|
TE
|
250 | (3) | 500 | ||||||
|
JCP&L
|
425 | 411 | (2) | ||||||
|
Met-Ed
|
250 | 300 | (2) | ||||||
|
Penelec
|
250 | 300 | (2) | ||||||
|
ATSI
|
50 | (4) | 50 | ||||||
|
(1)
|
No
regulatory approvals, statutory or charter limitations
applicable.
|
|
(2)
|
Excluding
amounts which may be borrowed under the regulated companies' money
pool.
|
|
(3)
|
Borrowing
sub-limits for CEI and TE may be increased to up to $500 million by
delivering notice to the administrative agent that such borrower has
senior unsecured debt ratings of at least BBB by S&P and Baa2 by
Moody's.
|
|
(4)
|
The
borrowing sub-limit for ATSI may be increased up to $100 million by
delivering notice to the administrative agent that ATSI has received
regulatory approval to have short-term borrowings up to the same
amount.
|
The
regulated companies also have the ability to borrow from each other and
FirstEnergy to meet their short-term working capital requirements. A similar but
separate arrangement exists among the unregulated companies. FESC administers
these two money pools and tracks FirstEnergy’s surplus funds and those of the
respective regulated and unregulated subsidiaries, as well as proceeds available
from bank borrowings. Companies receiving a loan under the money pool agreements
must repay the principal amount of the loan, together with accrued interest,
within 364 days of borrowing the funds. The rate of interest is the same for
each company receiving a loan from their respective pool and is based on the
average cost of funds available through the pool. The average interest rate for
borrowings in 2009 was 0.72% for the regulated companies’ money pool and 0.90%
for the unregulated companies’ money pool.
The
weighted average interest rates on short-term borrowings outstanding as of
December 31, 2009 and 2008 were as follows:
|
2009
|
2008
|
|||||||
|
FE
|
0.74 | % | 1.19 | % | ||||
|
FES
|
1.84 | % | 1.08 | % | ||||
|
OE
(1)
|
0.72 | % | - | |||||
|
CEI
|
1.13 | % | 1.77 | % | ||||
|
TE
|
0.72 | % | 1.46 | % | ||||
|
JCP&L
(2)
|
- | 1.46 | % | |||||
|
Met-Ed
(2)
|
- | 0.92 | % | |||||
|
Penelec
|
0.72 | % | 0.95 | % | ||||
|
(1)
|
In,
2008, OE's short-term borrowings consisted of noninterest-bearing notes
related to its investment in certain low-income housing limited
partnerships.
|
|
(2)
|
JCP&L
and Met-Ed had no outstanding short-term borrowings as of December 31,
2009.
|
231
The
Utilities, with the exception of TE, JCP&L and Penn, each have a wholly
owned subsidiary whose borrowings are secured by customer accounts receivable
purchased from its respective parent company. The CEI subsidiary's borrowings
are also secured by customer accounts receivable purchased from TE. Each
subsidiary company has its own receivables financing arrangement and, as a
separate legal entity with separate creditors, would have to satisfy its
obligations to creditors before any of its remaining assets could be available
to its parent company. In December 2009, the Met-Ed and Penelec Funding LLC
receivables programs were renewed for a 364-day period. The Penn Power Funding
LLC program was not renewed in 2009 and was thereafter terminated effective
December 17, 2009. The receivables financing borrowing commitment by company are
shown in the following table. There were no outstanding borrowings as of
December 31, 2009.
|
Subsidiary
Company
|
Parent
Company
|
Commitment
|
Annual
Facility
Fee
|
Maturity
|
||||||
|
(In
millions)
|
||||||||||
|
OES
Capital, Incorporated
|
OE
|
$
|
170
|
0.20
|
%
|
February
22, 2010
|
||||
|
Centerior
Funding Corporation
|
CEI
|
200
|
0.20
|
February
22, 2010
|
||||||
|
Met-Ed
Funding LLC
|
Met-Ed
|
75
|
0.60
|
December
17, 2010
|
||||||
|
Penelec
Funding LLC
|
Penelec
|
70
|
0.60
|
December
17, 2010
|
||||||
|
$
|
515
|
|||||||||
|
15.
|
COMMITMENTS,
GUARANTEES AND CONTINGENCIES
|
|
(A)
|
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-$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.
|
(B)
|
GUARANTEES
AND OTHER ASSURANCES
|
As part
of normal business activities, FirstEnergy enters into various agreements on
behalf of its subsidiaries to provide financial or performance assurances to
third parties. These agreements include contract guarantees, surety bonds and
LOCs. As of December 31, 2009, outstanding guarantees and other assurances
aggregated approximately $4.2 billion, consisting of parental guarantees - $1.0
billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion
and LOCs - $0.5 billion.
232
FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity activities principally to facilitate or hedge normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of credit support for
the financing or refinancing by subsidiaries of costs related to the acquisition
of property, plant and equipment. These agreements legally obligate FirstEnergy
to fulfill the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financing where the law might otherwise limit the
counterparties' claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables
the counterparty's legal claim to be satisfied by other FirstEnergy assets. The
likelihood is remote that such parental guarantees of $0.4 billion (included in
the $1.0 billion discussed above) as of December 31, 2009 would increase amounts
otherwise payable by FirstEnergy to meet its obligations incurred in connection
with financings and ongoing energy and energy-related activities.
While
these types of guarantees are normally parental commitments for the future
payment of subsidiary obligations, subsequent to the occurrence of a credit
rating downgrade or “material adverse event,” the immediate posting of cash
collateral, provision of an LOC or accelerated payments may be required of the
subsidiary. 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. As of December 31, 2009,
FirstEnergy's maximum exposure under these collateral provisions was $648
million, consisting of $43 million due to “material adverse event” contractual
clauses, $98 million due to an acceleration of payment or funding obligation,
and $507 million due to a below investment grade credit rating including the $48
million related to the credit rating downgrade by S&P on February 11, 2010.
Additionally, stress case conditions of a credit rating downgrade or “material
adverse event” and hypothetical adverse price movements in the underlying
commodity markets would increase this amount to $807 million, consisting of $51
million due to “material adverse event” contractual clauses, $98 million related
to an acceleration of payment or funding obligation, and $658 million due to a
below investment grade credit rating.
Most of
FirstEnergy's surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related guarantees of $101 million provide
additional assurance to outside parties that contractual and statutory
obligations will be met in a number of areas including construction contracts,
environmental commitments and various retail transactions.
In
addition to guarantees and surety bonds, FES’ contracts, including power
contracts with affiliates awarded through competitive bidding processes,
typically contain margining provisions which require the posting of cash or LOCs
in amounts determined by future power price movements. Based on FES’ power
portfolio as of December 31, 2009, and forward prices as of that date, FES had
$179 million outstanding in margining accounts. Under a hypothetical adverse
change in forward prices (95% confidence level change in forward prices over a
one year time horizon), FES would be required to post an additional $129
million. Depending on the volume of forward contracts entered and future price
movements, FES could be required to post higher amounts for
margining.
In July
2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided
interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably
guaranteed all of FGCO’s obligations under each of the leases (see Note 7). The
related lessor notes and pass through certificates are not guaranteed by FES or
FGCO, but the notes are secured by, among other things, each lessor trust’s
undivided interest in Unit 1, rights and interests under the applicable lease
and rights and interests under other related agreements, including FES’ lease
guaranty.
FES’
debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC,
pursuant to guarantees entered into on March 26, 2007. Similar guarantees were
entered into on that date pursuant to which FES guaranteed the debt obligations
of each of FGCO and NGC. Accordingly, present and future holders of indebtedness
of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC
regardless of whether their primary obligor is FES, FGCO or NGC.
|
(C)
|
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.
233
Clean
Air Act Compliance
FirstEnergy
is required to meet federally-approved SO
2
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
SO
2
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 SO
2
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. NO
X
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 NO
X
reductions
at FirstEnergy's facilities. The EPA's NO
X
Transport
Rule imposes uniform reductions of NO
X
emissions
(an approximate 85% reduction in utility plant NO
X
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 NO
X
emissions
are contributing significantly to ozone levels in the eastern United States.
FirstEnergy believes its facilities are also complying with the NO
X
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
NO
X
and SO
2
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.
234
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 NO
X
and
SO
2
emissions in two phases (Phase I in 2009 for NO
X
, 2010 for
SO
2
and Phase II in 2015 for both NO
X
and
SO
2
),
ultimately capping SO
2
emissions
in affected states to 2.5 million tons annually and NO
X
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 “NO
X
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 SO
2
and
NO
X
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.
235
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 CO
2
, 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 CO
2
emissions
from automobiles as “air pollutants” under the CAA. Although this decision did
not address CO
2
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 CO
2
emissions,
or litigation alleging damages from GHG emissions, could require significant
capital and other expenditures or result in changes to its operations. The
CO
2
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-CO
2
emitting
gas-fired and nuclear generators.
236
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.
237
(D)
OTHER LEGAL PROCEEDINGS
Power
Outages and Related Litigation
In July
1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in
power outages throughout the service territories of many electric utilities,
including JCP&L's territory. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages due to the outages.
After
various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud,
common law fraud, negligent misrepresentation, strict product liability, and
punitive damages were dismissed, leaving only the negligence and breach of
contract causes of actions. The class was decertified twice by the trial court,
and appealed both times by the Plaintiffs, with the results being that: (1) the
Appellate Division limited the class only to those customers directly impacted
by the outages of JCP&L transformers in Red Bank, NJ, based on a common
incident involving the failure of the bushings of two large transformers in the
Red Bank substation which resulted in planned and unplanned outages in the area
during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded
this matter back to the Trial Court to allow plaintiffs sufficient time to
establish a damage model or individual proof of damages. On March 31, 2009, the
trial court again granted JCP&L’s motion to decertify the class. On April
20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory
appeal to the trial court's decision to decertify the class, which was granted
by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate
brief on August 25, 2009, and JCP&L filed an opposition brief on September
25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in
further support of their appeal of the trial court's decision decertifying the
class. The Appellate Division heard oral argument on January 5, 2010, before a
three-judge panel. JCP&L is awaiting the Court’s decision.
Nuclear
Plant Matters
In
August 2007, FENOC submitted an application to the NRC to renew the operating
licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional
20 years. 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.
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.
Other
Legal Matters
There
are various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to FirstEnergy's normal business operations pending against
FirstEnergy and its subsidiaries. The other potentially material items not
otherwise discussed above are described below.
JCP&L's
bargaining unit employees filed a grievance challenging JCP&L's 2002
call-out procedure that required bargaining unit employees to respond to
emergency power outages. On May 20, 2004, an arbitration panel concluded that
the call-out procedure violated the parties' collective bargaining agreement. On
September 9, 2005, the arbitration panel issued an opinion to award
approximately $16 million to the bargaining unit employees. A final order
identifying the individual damage amounts was issued on October 31, 2007 and the
award appeal process was initiated. The union filed a motion with the federal
Court to confirm the award and JCP&L filed its answer and counterclaim to
vacate the award on December 31, 2007. JCP&L and the union filed briefs in
June and July of 2008 and oral arguments were held in the fall. On February 25,
2009, the federal district court denied JCP&L’s motion to vacate the
arbitration decision and granted the union’s motion to confirm the award.
JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay
Enforcement of the Judgment on March 6, 2009. The appeal process could take as
long as 24 months. 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.
238
FirstEnergy
accrues legal liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably estimate the amount of such
costs. If it were ultimately determined that FirstEnergy or its subsidiaries
have legal liability or are otherwise made subject to liability based on the
above matters, it could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition, results of operations and cash
flows.
16. SEGMENT
INFORMATION
Financial
information for each of FirstEnergy’s reportable segments is presented in the
following table. FES and the Utilities do not have separate reportable operating
segments. With the completion of transition to a fully competitive generation
market in Ohio in 2009, the former Ohio Transitional Generation Services segment
was combined with the Energy Delivery Services segment, consistent with how
management views the business. Disclosures for FirstEnergy’s operating segments
for 2008 and 2007 have been reclassified to conform to the 2009
presentation.
The
energy delivery services segment transmits and distributes electricity through
our eight utility operating companies, serving 4.5 million customers within
36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for
its PLR and default service requirements in Ohio, Pennsylvania and New Jersey.
Its revenues are primarily derived from the delivery of electricity within our
service areas, cost recovery of regulatory assets and the sale of electric
generation service to retail customers who have not selected an alternative
supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise
areas. Its results reflect the commodity costs of securing electric generation
from FES and from non-affiliated power suppliers, the net PJM and MISO
transmission expenses related to the delivery of the respective generation
loads, and the deferral and amortization of certain fuel costs.
The
competitive energy services segment supplies electric power to end-use customers
through retail and wholesale arrangements, including associated company power
sales to meet all or a portion of the PLR and default service requirements of
FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail
sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This
business segment owns or leases and operates 19 generating facilities with a net
demonstrated capacity of 13,710 MWs and also purchases electricity to meet sales
obligations. The segment's net income is primarily derived from affiliated and
non-affiliated electric generation sales revenues less the related costs of
electricity generation, including purchased power and net transmission
(including congestion) and ancillary costs charged by PJM and MISO to deliver
energy to the segment’s customers.
239
The
other segment contains corporate items and other businesses that are below the
quantifiable threshold for separate disclosure as a reportable
segment.
|
Energy
|
Competitive
|
|||||||||||||||||||
|
Delivery
|
Energy
|
Reconciling
|
||||||||||||||||||
|
Segment
Financial Information
|
Services
|
Services
|
Other
|
Adjustments
|
Consolidated
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
External
revenues
|
$ | 11,144 | $ | 1,888 | $ | 37 | $ | (119 | ) | $ | 12,950 | |||||||||
|
Internal
revenues*
|
- | 2,843 | - | (2,826 | ) | 17 | ||||||||||||||
|
Total
revenues
|
11,144 | 4,731 | 37 | (2,945 | ) | 12,967 | ||||||||||||||
|
Depreciation
and amortization
|
1,464 | 270 | 10 | 11 | 1,755 | |||||||||||||||
|
Investment
income
|
139 | 121 | - | (56 | ) | 204 | ||||||||||||||
|
Net
interest charges
|
469 | 106 | 8 | 265 | 848 | |||||||||||||||
|
Income
taxes
|
290 | 345 | (265 | ) | (125 | ) | 245 | |||||||||||||
|
Net
income
|
435 | 517 | 257 | (219 | ) | 990 | ||||||||||||||
|
Total
assets
|
22,978 | 10,584 | 607 | 135 | 34,304 | |||||||||||||||
|
Total
goodwill
|
5,551 | 24 | - | - | 5,575 | |||||||||||||||
|
Property
additions
|
750 | 1,262 | 149 | 42 | 2,203 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
External
revenues
|
$ | 12,068 | $ | 1,571 | $ | 72 | $ | (84 | ) | $ | 13,627 | |||||||||
|
Internal
revenues
|
- | 2,968 | - | (2,968 | ) | - | ||||||||||||||
|
Total
revenues
|
12,068 | 4,539 | 72 | (3,052 | ) | 13,627 | ||||||||||||||
|
Depreciation
and amortization
|
1,154 | 243 | 4 | 13 | 1,414 | |||||||||||||||
|
Investment
income
|
171 | (34 | ) | 6 | (84 | ) | 59 | |||||||||||||
|
Net
interest charges
|
408 | 108 | 2 | 184 | 702 | |||||||||||||||
|
Income
taxes
|
611 | 314 | (53 | ) | (95 | ) | 777 | |||||||||||||
|
Net
income
|
916 | 472 | 116 | (165 | ) | 1,339 | ||||||||||||||
|
Total
assets
|
23,025 | 9,559 | 539 | 398 | 33,521 | |||||||||||||||
|
Total
goodwill
|
5,551 | 24 | - | - | 5,575 | |||||||||||||||
|
Property
additions
|
839 | 1,835 | 176 | 38 | 2,888 | |||||||||||||||
|
2007
|
||||||||||||||||||||
|
External
revenues
|
$ | 11,322 | $ | 1,468 | $ | 39 | $ | (27 | ) | $ | 12,802 | |||||||||
|
Internal
revenues
|
- | 2,901 | - | (2,901 | ) | - | ||||||||||||||
|
Total
revenues
|
11,322 | 4,369 | 39 | (2,928 | ) | 12,802 | ||||||||||||||
|
Depreciation
and amortization
|
899 | 204 | 4 | 26 | 1,133 | |||||||||||||||
|
Investment
income
|
241 | 16 | 1 | (138 | ) | 120 | ||||||||||||||
|
Net
interest charges
|
446 | 152 | 4 | 141 | 743 | |||||||||||||||
|
Income
taxes
|
643 | 330 | 4 | (94 | ) | 883 | ||||||||||||||
|
Net
income
|
965 | 495 | 12 | (160 | ) | 1,312 | ||||||||||||||
|
Total
assets
|
23,826 | 7,669 | 303 | 513 | 32,311 | |||||||||||||||
|
Total
goodwill
|
5,583 | 24 | - | - | 5,607 | |||||||||||||||
|
Property
additions
|
814 | 740 | 21 | 58 | 1,633 | |||||||||||||||
| * |
Under
the accounting standard for the effects of certain types of regulation,
internal revenues are not fully offset for sales of RECs by FES to the
Ohio Companies that are retained in
inventory.
|
240
Reconciling
adjustments to segment operating results from internal management reporting to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses and elimination of intersegment transactions.
Products
and Services
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
|
Year
|
|
Sales
|
|
|
|
(In
millions)
|
||||
|
2009
|
$
|
12,032
|
||
|
2008
|
|
12,693
|
||
|
2007
|
|
|
11,944
|
|
|
17.
|
NEW ACCOUNTING STANDARDS AND
INTERPRETATIONS
|
In 2009,
the FASB amended the derecognition guidance in the Transfers and Servicing Topic
of the FASB Accounting Standards Codification and eliminated the concept of a
QSPE. The amended guidance requires an evaluation of all existing QSPEs to
determine whether they must be consolidated. This standard is effective for
financial asset transfers that occur in fiscal years beginning after November
15, 2009. FirstEnergy does not expect this standard to have a material effect
upon its financial statements.
In 2009,
the FASB amended the consolidation guidance applied to VIEs. This standard
replaces the quantitative approach previously required to determine which entity
has a controlling financial interest in a VIE with a qualitative approach. Under
the new approach, the primary beneficiary of a VIE is the entity that has both
(a) the power to direct the activities of the VIE that most significantly impact
the entity’s economic performance, and (b) the obligation to absorb losses of
the entity, or the right to receive benefits from the entity, that could be
significant to the VIE. This standard also requires ongoing reassessments of
whether an entity is the primary beneficiary of a VIE and enhanced disclosures
about an entity’s involvement in VIEs. The standard is effective for fiscal
years beginning after November 15, 2009. FirstEnergy is currently evaluating the
impact of adopting this standard on its financial statements.
In 2010,
the FASB amended the Fair Value Measurements and Disclosures Topic of the FASB
Accounting Standards Codification to require additional disclosures about 1)
transfers of Level 1 and Level 2 fair value measurements, including the reason
for transfers, 2) purchases, sales, issuances and settlements in the roll
forward of activity in Level 3 fair value measurements, 3) additional
disaggregation to include fair value measurement disclosures for each class of
assets and liabilities and 4) disclosure of inputs and valuation techniques used
to measure fair value for both recurring and nonrecurring fair value
measurements. The amendment is effective for fiscal years beginning
after December 15, 2009, except for the disclosures about purchases, sales,
issuances and settlements in the roll forward of activity in Level 3 fair value
measurements, which is effective for fiscal years beginning after December 15,
2010. FirstEnergy does not expect this standard to have a material
effect upon its financial statements.
|
18.
|
TRANSACTIONS
WITH AFFILIATED COMPANIES
|
FES’ and
the Utilities’ operating revenues, operating expenses, investment income and
interest expense include transactions with affiliated companies. These
affiliated company transactions include PSAs between FES and the Utilities,
support service billings from FESC and FENOC, interest on associated company
notes and other transactions (see Note 7).
The Ohio
Companies had a PSA with FES through December 31, 2009 to meet their PLR and
default service obligations. Met-Ed and Penelec have a partial requirement PSA
with FES to meet a portion of their PLR and default service obligations (see
Note 9). FES is incurring interest expense through FGCO and NGC on associated
company notes payable to the Ohio Companies and Penn related to the 2005
intra-system generation asset transfers. The primary affiliated company
transactions for FES and the Utilities for the three years ended December 31,
2009 are as follows:
241
|
Affiliated
Company Transactions - 2009
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||||||
|
Electric
sales to affiliates
|
$ | 2,826 | $ | 187 | $ | - | $ | 35 | $ | - | $ | - | $ | - | ||||||||||||||
|
Ground
lease with ATSI
|
- | 12 | 7 | 2 | - | - | - | |||||||||||||||||||||
|
Other*
|
17 | - | - | - | - | - | - | |||||||||||||||||||||
|
Expenses:
|
||||||||||||||||||||||||||||
|
Purchased
power from affiliates
|
222 | 991 | 735 | 393 | - | 365 | 342 | |||||||||||||||||||||
|
Support
services
|
563 | 140 | 60 | 55 | 85 | 52 | 53 | |||||||||||||||||||||
|
Investment
Income:
|
||||||||||||||||||||||||||||
|
Interest
income from affiliates
|
- | 15 | - | 17 | - | - | - | |||||||||||||||||||||
|
Interest
income from FirstEnergy
|
4 | 1 | - | - | - | - | - | |||||||||||||||||||||
|
Interest
Expense:
|
||||||||||||||||||||||||||||
|
Interest
expense to affiliates
|
6 | 5 | 17 | - | 4 | 3 | 2 | |||||||||||||||||||||
|
Interest
expense to FirstEnergy
|
4 | - | 1 | 1 | - | - | 1 | |||||||||||||||||||||
|
|
* Under
the accounting standard for the effects of certain types of regulation,
internal revenues are not fully offset for sales of RECs by FES to the
Ohio Companies that are retained in
inventory.
|
|
Affiliated
Company Transactions - 2008
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||||||
|
Electric
sales to affiliates
|
$ | 2,968 | $ | 70 | $ | - | $ | 30 | $ | - | $ | - | $ | - | ||||||||||||||
|
Ground
lease with ATSI
|
- | 12 | 7 | 2 | - | - | - | |||||||||||||||||||||
|
Expenses:
|
||||||||||||||||||||||||||||
|
Purchased
power from affiliates
|
101 | 1,203 | 766 | 411 | - | 304 | 284 | |||||||||||||||||||||
|
Support
services
|
552 | 145 | 67 | 62 | 90 | 57 | 56 | |||||||||||||||||||||
|
Investment
Income:
|
||||||||||||||||||||||||||||
|
Interest
income from affiliates
|
- | 15 | 1 | 20 | 1 | - | 1 | |||||||||||||||||||||
|
Interest
income from FirstEnergy
|
13 | 13 | - | - | - | - | - | |||||||||||||||||||||
|
Interest
Expense:
|
||||||||||||||||||||||||||||
|
Interest
expense to affiliates
|
4 | 3 | 19 | 1 | 3 | 2 | 2 | |||||||||||||||||||||
|
Interest
expense to FirstEnergy
|
26 | - | 7 | 2 | 5 | 4 | 5 | |||||||||||||||||||||
|
Affiliated
Company Transactions - 2007
|
FES
|
OE
|
CEI
|
TE
|
JCP&L
|
Met-Ed
|
Penelec
|
|||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||||||
|
Electric
sales to affiliates
|
$ | 2,901 | $ | 73 | $ | 92 | $ | 167 | $ | - | $ | - | $ | - | ||||||||||||||
|
Ground
lease with ATSI
|
- | 12 | 7 | 2 | - | - | - | |||||||||||||||||||||
|
Expenses:
|
||||||||||||||||||||||||||||
|
Purchased
power from affiliates
|
234 | 1,261 | 770 | 392 | - | 290 | 285 | |||||||||||||||||||||
|
Support
services
|
560 | 146 | 70 | 55 | 100 | 54 | 58 | |||||||||||||||||||||
|
Investment
Income:
|
||||||||||||||||||||||||||||
|
Interest
income from affiliates
|
- | 30 | 17 | 18 | 1 | 1 | 1 | |||||||||||||||||||||
|
Interest
income from FirstEnergy
|
28 | 29 | 2 | - | - | - | - | |||||||||||||||||||||
|
Interest
Expense:
|
||||||||||||||||||||||||||||
|
Interest
expense to affiliates
|
31 | 1 | 1 | - | 1 | 1 | 1 | |||||||||||||||||||||
|
Interest
expense to FirstEnergy
|
34 | - | 1 | 10 | 11 | 10 | 11 | |||||||||||||||||||||
FirstEnergy does not
bill directly or allocate any of its costs to any subsidiary company. Costs are
allocated to FES and the Utilities from FESC and FENOC. The majority of costs
are directly billed or assigned at no more than cost. The remaining costs are
for services that are provided on behalf of more than one company, or costs that
cannot be precisely identified and are allocated using formulas developed by
FESC and FENOC. The current allocation or assignment formulas used and their
bases include multiple factor formulas: each company's proportionate amount of
FirstEnergy's aggregate direct payroll, number of employees, asset balances,
revenues, number of customers, other factors and specific departmental charge
ratios. Management believes that these allocation methods are reasonable.
Intercompany transactions with FirstEnergy and its other subsidiaries are
generally settled under commercial terms within thirty days.
242
|
19.
|
SUPPLEMENTAL
GUARANTOR INFORMATION
|
As
discussed, in Note 7, FES has fully and unconditionally guaranteed all of
FGCO's obligations under each of the leases associated with Bruce Mansfield Unit
1. The consolidating statements of income for the three years ended
December 31, 2009, consolidating balance sheets as of December 31,
2009, and December 31, 2008, and condensed consolidating statements of cash
flows for the three years ended December 31, 2009, for FES (parent and
guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in
wholly owned subsidiaries are accounted for by FES using the equity method.
Results of operations for FGCO and NGC are, therefore, reflected in FES’
investment accounts and earnings as if operating lease treatment was achieved
(see Note 7). The principal elimination entries eliminate investments in
subsidiaries and intercompany balances and transactions and the entries required
to reflect operating lease treatment associated with the 2007 Bruce Mansfield
Unit 1 sale and leaseback transaction.
243
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
||||||||||||||||||||
|
For the Year Ended December 31,
2009
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
REVENUES
|
$ | 4,390,111 | $ | 2,216,237 | $ | 1,360,522 | $ | (3,238,533 | ) | $ | 4,728,337 | |||||||||
|
EXPENSES:
|
||||||||||||||||||||
|
Fuel
|
18,416 | 971,021 | 138,026 | - | 1,127,463 | |||||||||||||||
|
Purchased
power from affiliates
|
3,220,197 | 18,336 | 222,406 | (3,238,533 | ) | 222,406 | ||||||||||||||
|
Purchased
power from non-affiliates
|
996,383 | - | - | - | 996,383 | |||||||||||||||
|
Other
operating expenses
|
220,660 | 395,330 | 518,473 | 48,762 | 1,183,225 | |||||||||||||||
|
Provision
for depreciation
|
4,147 | 121,007 | 139,488 | (5,249 | ) | 259,393 | ||||||||||||||
|
General
taxes
|
18,214 | 44,075 | 24,626 | - | 86,915 | |||||||||||||||
|
Total
expenses
|
4,478,017 | 1,549,769 | 1,043,019 | (3,195,020 | ) | 3,875,785 | ||||||||||||||
|
OPERATING
INCOME
|
(87,906 | ) | 666,468 | 317,503 | (43,513 | ) | 852,552 | |||||||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||||||||||
|
Investment
income
|
5,297 | 683 | 119,246 | - | 125,226 | |||||||||||||||
|
Miscellaneous
income (expense), including
|
||||||||||||||||||||
|
net
income from equity investees
|
656,451 | (3,931 | ) | 61 | (645,911 | ) | 6,670 | |||||||||||||
|
Interest
expense to affiliates
|
(135 | ) | (5,619 | ) | (4,352 | ) | - | (10,106 | ) | |||||||||||
|
Interest
expense - other
|
(44,837 | ) | (99,802 | ) | (62,034 | ) | 64,553 | (142,120 | ) | |||||||||||
|
Capitalized
interest
|
212 | 49,577 | 10,363 | - | 60,152 | |||||||||||||||
|
Total
other income (expense)
|
616,988 | (59,092 | ) | 63,284 | (581,358 | ) | 39,822 | |||||||||||||
|
INCOME
BEFORE INCOME TAXES
|
529,082 | 607,376 | 380,787 | (624,871 | ) | 892,374 | ||||||||||||||
|
INCOME
TAXES
|
(48,002 | ) | 207,171 | 135,785 | 20,336 | 315,290 | ||||||||||||||
|
NET
INCOME
|
$ | 577,084 | $ | 400,205 | $ | 245,002 | $ | (645,207 | ) | $ | 577,084 | |||||||||
244
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
||||||||||||||||||||
|
For the Year Ended December 31,
2008
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
REVENUES
|
$ | 4,470,112 | $ | 2,275,451 | $ | 1,204,534 | $ | (3,431,744 | ) | $ | 4,518,353 | |||||||||
|
EXPENSES:
|
||||||||||||||||||||
|
Fuel
|
16,322 | 1,171,993 | 126,978 | - | 1,315,293 | |||||||||||||||
|
Purchased
power from non-affiliates
|
778,882 | - | - | - | 778,882 | |||||||||||||||
|
Purchased
power from affiliates
|
3,417,126 | 14,618 | 101,409 | (3,431,744 | ) | 101,409 | ||||||||||||||
|
Other
operating expenses
|
116,972 | 416,723 | 502,096 | 48,757 | 1,084,548 | |||||||||||||||
|
Provision
for depreciation
|
5,986 | 119,763 | 111,529 | (5,379 | ) | 231,899 | ||||||||||||||
|
General
taxes
|
19,260 | 46,153 | 22,591 | - | 88,004 | |||||||||||||||
|
Total
expenses
|
4,354,548 | 1,769,250 | 864,603 | (3,388,366 | ) | 3,600,035 | ||||||||||||||
|
OPERATING
INCOME
|
115,564 | 506,201 | 339,931 | (43,378 | ) | 918,318 | ||||||||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||||||||||
|
Investment
income (loss)
|
10,953 | 2,034 | (35,665 | ) | - | (22,678 | ) | |||||||||||||
|
Miscellaneous
income (expense), including
|
||||||||||||||||||||
|
net
income from equity investees
|
438,214 | (5,400 | ) | - | (431,116 | ) | 1,698 | |||||||||||||
|
Interest
expense to affiliates
|
(314 | ) | (20,342 | ) | (9,173 | ) | - | (29,829 | ) | |||||||||||
|
Interest
expense - other
|
(24,674 | ) | (95,926 | ) | (56,486 | ) | 65,404 | (111,682 | ) | |||||||||||
|
Capitalized
interest
|
142 | 39,934 | 3,688 | - | 43,764 | |||||||||||||||
|
Total
other income (expense)
|
424,321 | (79,700 | ) | (97,636 | ) | (365,712 | ) | (118,727 | ) | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
539,885 | 426,501 | 242,295 | (409,090 | ) | 799,591 | ||||||||||||||
|
INCOME
TAXES
|
33,475 | 155,100 | 90,247 | 14,359 | 293,181 | |||||||||||||||
|
NET
INCOME
|
$ | 506,410 | $ | 271,401 | $ | 152,048 | $ | (423,449 | ) | $ | 506,410 | |||||||||
245
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING STATEMENTS OF INCOME
|
||||||||||||||||||||
|
For the Year Ended December 31,
2007
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
REVENUES
|
$ | 4,345,790 | $ | 1,982,166 | $ | 1,062,026 | $ | (3,064,955 | ) | $ | 4,325,027 | |||||||||
|
EXPENSES:
|
||||||||||||||||||||
|
Fuel
|
26,169 | 942,946 | 117,895 | - | 1,087,010 | |||||||||||||||
|
Purchased
power from non-affiliates
|
764,090 | - | - | - | 764,090 | |||||||||||||||
|
Purchased
power from affiliates
|
3,038,786 | 186,415 | 73,844 | (3,064,955 | ) | 234,090 | ||||||||||||||
|
Other
operating expenses
|
161,797 | 352,856 | 514,389 | 11,997 | 1,041,039 | |||||||||||||||
|
Provision
for depreciation
|
2,269 | 99,741 | 92,239 | (1,337 | ) | 192,912 | ||||||||||||||
|
General
taxes
|
20,953 | 41,456 | 24,689 | - | 87,098 | |||||||||||||||
|
Total
expenses
|
4,014,064 | 1,623,414 | 823,056 | (3,054,295 | ) | 3,406,239 | ||||||||||||||
|
OPERATING
INCOME
|
331,726 | 358,752 | 238,970 | (10,660 | ) | 918,788 | ||||||||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||||||||||
|
Investment
income
|
22,845 | 2,799 | 15,793 | - | 41,437 | |||||||||||||||
|
Miscellaneous
income (expense), including
|
||||||||||||||||||||
|
net
income from equity investees
|
319,133 | 1,411 | (913 | ) | (308,192 | ) | 11,439 | |||||||||||||
|
Interest
expense to affiliates
|
(1,320 | ) | (48,536 | ) | (15,645 | ) | - | (65,501 | ) | |||||||||||
|
Interest
expense - other
|
(9,503 | ) | (59,412 | ) | (39,458 | ) | 16,174 | (92,199 | ) | |||||||||||
|
Capitalized
interest
|
35 | 14,369 | 5,104 | - | 19,508 | |||||||||||||||
|
Total
other income (expense)
|
331,190 | (89,369 | ) | (35,119 | ) | (292,018 | ) | (85,316 | ) | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
662,916 | 269,383 | 203,851 | (302,678 | ) | 833,472 | ||||||||||||||
|
INCOME
TAXES
|
134,052 | 90,801 | 77,467 | 2,288 | 304,608 | |||||||||||||||
|
NET
INCOME
|
$ | 528,864 | $ | 178,582 | $ | 126,384 | $ | (304,966 | ) | $ | 528,864 | |||||||||
246
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
||||||||||||||||||||
|
As of December 31, 2009
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
CURRENT
ASSETS:
|
||||||||||||||||||||
|
Cash
and cash equivalents
|
$ | - | $ | 3 | $ | 9 | $ | - | $ | 12 | ||||||||||
|
Receivables-
|
||||||||||||||||||||
|
Customers
|
195,107 | - | - | - | 195,107 | |||||||||||||||
|
Associated
companies
|
305,298 | 175,730 | 134,841 | (297,308 | ) | 318,561 | ||||||||||||||
|
Other
|
28,394 | 10,960 | 12,518 | - | 51,872 | |||||||||||||||
|
Notes
receivable from associated companies
|
416,404 | 240,836 | 147,863 | - | 805,103 | |||||||||||||||
|
Materials
and supplies, at average cost
|
17,265 | 307,079 | 215,197 | - | 539,541 | |||||||||||||||
|
Prepayments
and other
|
80,025 | 18,356 | 9,401 | - | 107,782 | |||||||||||||||
| 1,042,493 | 752,964 | 519,829 | (297,308 | ) | 2,017,978 | |||||||||||||||
|
PROPERTY,
PLANT AND EQUIPMENT:
|
||||||||||||||||||||
|
In
service
|
90,474 | 5,478,346 | 5,174,835 | (386,023 | ) | 10,357,632 | ||||||||||||||
|
Less
- Accumulated provision for depreciation
|
13,649 | 2,778,320 | 1,910,701 | (171,512 | ) | 4,531,158 | ||||||||||||||
| 76,825 | 2,700,026 | 3,264,134 | (214,511 | ) | 5,826,474 | |||||||||||||||
|
Construction
work in progress
|
6,032 | 2,049,078 | 368,336 | - | 2,423,446 | |||||||||||||||
| 82,857 | 4,749,104 | 3,632,470 | (214,511 | ) | 8,249,920 | |||||||||||||||
|
INVESTMENTS:
|
||||||||||||||||||||
|
Nuclear
plant decommissioning trusts
|
- | - | 1,088,641 | - | 1,088,641 | |||||||||||||||
|
Investment
in associated companies
|
4,477,602 | - | - | (4,477,602 | ) | - | ||||||||||||||
|
Other
|
1,137 | 21,127 | 202 | - | 22,466 | |||||||||||||||
| 4,478,739 | 21,127 | 1,088,843 | (4,477,602 | ) | 1,111,107 | |||||||||||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||||||||||||||
|
Accumulated
deferred income taxes
|
93,379 | 381,849 | - | (388,602 | ) | 86,626 | ||||||||||||||
|
Goodwill
|
24,248 | - | - | - | 24,248 | |||||||||||||||
|
Property
taxes
|
- | 27,811 | 22,314 | - | 50,125 | |||||||||||||||
|
Unamortized
sale and leaseback costs
|
- | 16,454 | - | 56,099 | 72,553 | |||||||||||||||
|
Other
|
99,411 | 71,179 | 18,755 | (51,114 | ) | 138,231 | ||||||||||||||
| 217,038 | 497,293 | 41,069 | (383,617 | ) | 371,783 | |||||||||||||||
| $ | 5,821,127 | $ | 6,020,488 | $ | 5,282,211 | $ | (5,373,038 | ) | $ | 11,750,788 | ||||||||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||||||||||||||
|
CURRENT
LIABILITIES:
|
||||||||||||||||||||
|
Currently
payable long-term debt
|
$ | 736 | $ | 646,402 | $ | 922,429 | $ | (18,640 | ) | $ | 1,550,927 | |||||||||
|
Short-term
borrowings-
|
||||||||||||||||||||
|
Associated
companies
|
- | 9,237 | - | - | 9,237 | |||||||||||||||
|
Other
|
100,000 | - | - | - | 100,000 | |||||||||||||||
|
Accounts
payable-
|
||||||||||||||||||||
|
Associated
companies
|
261,788 | 170,446 | 295,045 | (261,201 | ) | 466,078 | ||||||||||||||
|
Other
|
51,722 | 193,641 | - | - | 245,363 | |||||||||||||||
|
Accrued
taxes
|
44,213 | 61,055 | 22,777 | (44,887 | ) | 83,158 | ||||||||||||||
|
Other
|
173,015 | 132,314 | 16,734 | 36,994 | 359,057 | |||||||||||||||
| 631,474 | 1,213,095 | 1,256,985 | (287,734 | ) | 2,813,820 | |||||||||||||||
|
CAPITALIZATION:
|
||||||||||||||||||||
|
Common
stockholder's equity
|
3,514,571 | 2,346,515 | 2,119,488 | (4,466,003 | ) | 3,514,571 | ||||||||||||||
|
Long-term
debt and other long-term obligations
|
1,519,339 | 1,906,818 | 554,825 | (1,269,330 | ) | 2,711,652 | ||||||||||||||
| 5,033,910 | 4,253,333 | 2,674,313 | (5,735,333 | ) | 6,226,223 | |||||||||||||||
|
NONCURRENT
LIABILITIES:
|
||||||||||||||||||||
|
Deferred
gain on sale and leaseback transaction
|
- | - | - | 992,869 | 992,869 | |||||||||||||||
|
Accumulated
deferred income taxes
|
- | - | 342,840 | (342,840 | ) | - | ||||||||||||||
|
Accumulated
deferred investment tax credits
|
- | 36,359 | 22,037 | - | 58,396 | |||||||||||||||
|
Asset
retirement obligations
|
- | 25,714 | 895,734 | - | 921,448 | |||||||||||||||
|
Retirement
benefits
|
33,144 | 170,891 | - | - | 204,035 | |||||||||||||||
|
Property
taxes
|
- | 27,811 | 22,314 | - | 50,125 | |||||||||||||||
|
Lease
market valuation liability
|
- | 262,200 | - | - | 262,200 | |||||||||||||||
|
Other
|
122,599 | 31,085 | 67,988 | - | 221,672 | |||||||||||||||
| 155,743 | 554,060 | 1,350,913 | 650,029 | 2,710,745 | ||||||||||||||||
| $ | 5,821,127 | $ | 6,020,488 | $ | 5,282,211 | $ | (5,373,038 | ) | $ | 11,750,788 | ||||||||||
247
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
||||||||||||||||||||
|
As of December 31, 2008
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
ASSETS
|
||||||||||||||||||||
|
CURRENT
ASSETS:
|
||||||||||||||||||||
|
Cash
and cash equivalents
|
$ | - | $ | 39 | $ | - | $ | - | $ | 39 | ||||||||||
|
Receivables-
|
||||||||||||||||||||
|
Customers
|
86,123 | - | - | - | 86,123 | |||||||||||||||
|
Associated
companies
|
363,226 | 225,622 | 113,067 | (323,815 | ) | 378,100 | ||||||||||||||
|
Other
|
991 | 11,379 | 12,256 | - | 24,626 | |||||||||||||||
|
Notes
receivable from associated companies
|
107,229 | 21,946 | - | - | 129,175 | |||||||||||||||
|
Materials
and supplies, at average cost
|
5,750 | 303,474 | 212,537 | - | 521,761 | |||||||||||||||
|
Prepayments
and other
|
76,773 | 35,102 | 660 | - | 112,535 | |||||||||||||||
| 640,092 | 597,562 | 338,520 | (323,815 | ) | 1,252,359 | |||||||||||||||
|
PROPERTY,
PLANT AND EQUIPMENT:
|
||||||||||||||||||||
|
In
service
|
134,905 | 5,420,789 | 4,705,735 | (389,525 | ) | 9,871,904 | ||||||||||||||
|
Less
- Accumulated provision for depreciation
|
13,090 | 2,702,110 | 1,709,286 | (169,765 | ) | 4,254,721 | ||||||||||||||
| 121,815 | 2,718,679 | 2,996,449 | (219,760 | ) | 5,617,183 | |||||||||||||||
|
Construction
work in progress
|
4,470 | 1,441,403 | 301,562 | - | 1,747,435 | |||||||||||||||
| 126,285 | 4,160,082 | 3,298,011 | (219,760 | ) | 7,364,618 | |||||||||||||||
|
INVESTMENTS:
|
||||||||||||||||||||
|
Nuclear
plant decommissioning trusts
|
- | - | 1,033,717 | - | 1,033,717 | |||||||||||||||
|
Long-term
notes receivable from associated companies
|
- | - | 62,900 | - | 62,900 | |||||||||||||||
|
Investment
in associated companies
|
3,596,152 | - | - | (3,596,152 | ) | - | ||||||||||||||
|
Other
|
1,913 | 59,476 | 202 | - | 61,591 | |||||||||||||||
| 3,598,065 | 59,476 | 1,096,819 | (3,596,152 | ) | 1,158,208 | |||||||||||||||
|
DEFERRED
CHARGES AND OTHER ASSETS:
|
||||||||||||||||||||
|
Accumulated
deferred income taxes
|
24,703 | 476,611 | - | (233,552 | ) | 267,762 | ||||||||||||||
|
Lease
assignment receivable from associated companies
|
- | 71,356 | - | - | 71,356 | |||||||||||||||
|
Goodwill
|
24,248 | - | - | - | 24,248 | |||||||||||||||
|
Property
taxes
|
- | 27,494 | 22,610 | - | 50,104 | |||||||||||||||
|
Unamortized
sale and leaseback costs
|
- | 20,286 | - | 49,646 | 69,932 | |||||||||||||||
|
Other
|
59,642 | 59,674 | 21,743 | (44,625 | ) | 96,434 | ||||||||||||||
| 108,593 | 655,421 | 44,353 | (228,531 | ) | 579,836 | |||||||||||||||
| $ | 4,473,035 | $ | 5,472,541 | $ | 4,777,703 | $ | (4,368,258 | ) | $ | 10,355,021 | ||||||||||
|
LIABILITIES
AND CAPITALIZATION
|
||||||||||||||||||||
|
CURRENT
LIABILITIES:
|
||||||||||||||||||||
|
Currently
payable long-term debt
|
$ | 5,377 | $ | 925,234 | $ | 1,111,183 | $ | (16,896 | ) | $ | 2,024,898 | |||||||||
|
Short-term
borrowings-
|
||||||||||||||||||||
|
Associated
companies
|
1,119 | 257,357 | 6,347 | - | 264,823 | |||||||||||||||
|
Other
|
1,000,000 | - | - | - | 1,000,000 | |||||||||||||||
|
Accounts
payable-
|
||||||||||||||||||||
|
Associated
companies
|
314,887 | 221,266 | 250,318 | (314,133 | ) | 472,338 | ||||||||||||||
|
Other
|
35,367 | 119,226 | - | - | 154,593 | |||||||||||||||
|
Accrued
taxes
|
8,272 | 60,385 | 30,790 | (19,681 | ) | 79,766 | ||||||||||||||
|
Other
|
61,034 | 136,867 | 13,685 | 36,853 | 248,439 | |||||||||||||||
| 1,426,056 | 1,720,335 | 1,412,323 | (313,857 | ) | 4,244,857 | |||||||||||||||
|
CAPITALIZATION:
|
||||||||||||||||||||
|
Common
stockholder's equity
|
2,944,423 | 1,832,678 | 1,752,580 | (3,585,258 | ) | 2,944,423 | ||||||||||||||
|
Long-term
debt and other long-term obligations
|
61,508 | 1,328,921 | 469,839 | (1,288,820 | ) | 571,448 | ||||||||||||||
| 3,005,931 | 3,161,599 | 2,222,419 | (4,874,078 | ) | 3,515,871 | |||||||||||||||
|
NONCURRENT
LIABILITIES:
|
||||||||||||||||||||
|
Deferred
gain on sale and leaseback transaction
|
- | - | - | 1,026,584 | 1,026,584 | |||||||||||||||
|
Accumulated
deferred income taxes
|
- | - | 206,907 | (206,907 | ) | - | ||||||||||||||
|
Accumulated
deferred investment tax credits
|
- | 39,439 | 23,289 | - | 62,728 | |||||||||||||||
|
Asset
retirement obligations
|
- | 24,134 | 838,951 | - | 863,085 | |||||||||||||||
|
Retirement
benefits
|
22,558 | 171,619 | - | - | 194,177 | |||||||||||||||
|
Property
taxes
|
- | 27,494 | 22,610 | - | 50,104 | |||||||||||||||
|
Lease
market valuation liability
|
- | 307,705 | - | - | 307,705 | |||||||||||||||
|
Other
|
18,490 | 20,216 | 51,204 | - | 89,910 | |||||||||||||||
| 41,048 | 590,607 | 1,142,961 | 819,677 | 2,594,293 | ||||||||||||||||
| $ | 4,473,035 | $ | 5,472,541 | $ | 4,777,703 | $ | (4,368,258 | ) | $ | 10,355,021 | ||||||||||
248
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
For the Year Ended December 31,
2009
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
NET
CASH PROVIDED FROM (USED FOR)
|
||||||||||||||||||||
|
OPERATING
ACTIVITIES
|
$ | (20,027 | ) | $ | 790,411 | $ | 621,649 | $ | (17,744 | ) | $ | 1,374,289 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||||||||||
|
New
financing-
|
||||||||||||||||||||
|
Long-term
debt
|
1,498,087 | 576,800 | 363,515 | - | 2,438,402 | |||||||||||||||
|
Equity
contributions from parent
|
- | 100,000 | 150,000 | (250,000 | ) | - | ||||||||||||||
|
Redemptions
and repayments-
|
||||||||||||||||||||
|
Long-term
debt
|
(1,766 | ) | (320,754 | ) | (404,383 | ) | 17,747 | (709,156 | ) | |||||||||||
|
Short-term
borrowings, net
|
(901,119 | ) | (248,120 | ) | (6,347 | ) | - | (1,155,586 | ) | |||||||||||
|
Other
|
(12,054 | ) | (6,157 | ) | (3,576 | ) | (3 | ) | (21,790 | ) | ||||||||||
|
Net
cash provided from financing activities
|
583,148 | 101,769 | 99,209 | (232,256 | ) | 551,870 | ||||||||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||||||||||
|
Property
additions
|
(4,372 | ) | (671,691 | ) | (546,869 | ) | - | (1,222,932 | ) | |||||||||||
|
Proceeds
from asset sales
|
- | 18,371 | - | - | 18,371 | |||||||||||||||
|
Sales
of investment securities held in trusts
|
- | - | 1,379,154 | - | 1,379,154 | |||||||||||||||
|
Purchases
of investment securities held in trusts
|
- | - | (1,405,996 | ) | - | (1,405,996 | ) | |||||||||||||
|
Loans
to associated companies, net
|
(309,175 | ) | (218,890 | ) | (147,863 | ) | - | (675,928 | ) | |||||||||||
|
Investment
in subsidiaries
|
(250,000 | ) | - | - | 250,000 | - | ||||||||||||||
|
Other
|
426 | (20,006 | ) | 725 | - | (18,855 | ) | |||||||||||||
|
Net
cash used for investing activities
|
(563,121 | ) | (892,216 | ) | (720,849 | ) | 250,000 | (1,926,186 | ) | |||||||||||
|
Net
change in cash and cash equivalents
|
- | (36 | ) | 9 | - | (27 | ) | |||||||||||||
|
Cash
and cash equivalents at beginning of year
|
- | 39 | - | - | 39 | |||||||||||||||
|
Cash
and cash equivalents at end of year
|
$ | - | $ | 3 | $ | 9 | $ | - | $ | 12 | ||||||||||
249
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
For the Year Ended December 31,
2008
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
NET
CASH PROVIDED FROM OPERATING ACTIVITIES
|
$ | 40,791 | $ | 350,986 | $ | 478,047 | $ | (16,896 | ) | $ | 852,928 | |||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||||||||||
|
New
financing-
|
||||||||||||||||||||
|
Long-term
debt
|
- | 353,325 | 265,050 | - | 618,375 | |||||||||||||||
|
Equity
contributions from parent
|
280,000 | 675,000 | 175,000 | (850,000 | ) | 280,000 | ||||||||||||||
|
Short-term
borrowings, net
|
701,119 | 18,571 | - | (18,931 | ) | 700,759 | ||||||||||||||
|
Redemptions
and repayments-
|
||||||||||||||||||||
|
Long-term
debt
|
(2,955 | ) | (293,349 | ) | (183,132 | ) | 16,896 | (462,540 | ) | |||||||||||
|
Short-term
borrowings, net
|
- | - | (18,931 | ) | 18,931 | - | ||||||||||||||
|
Common
stock dividend payment
|
(43,000 | ) | - | - | - | (43,000 | ) | |||||||||||||
|
Other
|
- | (3,107 | ) | (2,040 | ) | - | (5,147 | ) | ||||||||||||
|
Net
cash provided from financing activities
|
935,164 | 750,440 | 235,947 | (833,104 | ) | 1,088,447 | ||||||||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||||||||||
|
Property
additions
|
(43,244 | ) | (1,047,917 | ) | (744,468 | ) | - | (1,835,629 | ) | |||||||||||
|
Proceeds
from asset sales
|
- | 23,077 | - | - | 23,077 | |||||||||||||||
|
Sales
of investment securities held in trusts
|
- | - | 950,688 | - | 950,688 | |||||||||||||||
|
Purchases
of investment securities held in trusts
|
- | - | (987,304 | ) | - | (987,304 | ) | |||||||||||||
|
Loans
repayments from (loans to) associated companies
|
(83,457 | ) | (21,946 | ) | 69,012 | - | (36,391 | ) | ||||||||||||
|
Investment
in subsidiary
|
(850,000 | ) | - | - | 850,000 | - | ||||||||||||||
|
Other
|
744 | (54,601 | ) | (1,922 | ) | - | (55,779 | ) | ||||||||||||
|
Net
cash used for investing activities
|
(975,957 | ) | (1,101,387 | ) | (713,994 | ) | 850,000 | (1,941,338 | ) | |||||||||||
|
Net
change in cash and cash equivalents
|
(2 | ) | 39 | - | - | 37 | ||||||||||||||
|
Cash
and cash equivalents at beginning of year
|
2 | - | - | - | 2 | |||||||||||||||
|
Cash
and cash equivalents at end of year
|
$ | - | $ | 39 | $ | - | $ | - | $ | 39 | ||||||||||
250
FIRSTENERGY
SOLUTIONS CORP.
|
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
||||||||||||||||||||
|
|
||||||||||||||||||||
|
For the Year Ended December 31,
2007
|
FES
|
FGCO
|
NGC
|
Eliminations
|
Consolidated
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
NET
CASH PROVIDED FROM (USED FOR)
|
||||||||||||||||||||
|
OPERATING
ACTIVITIES
|
$ | (18,017 | ) | $ | 55,172 | $ | 263,468 | $ | (6,306 | ) | $ | 294,317 | ||||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||||||||||
|
New
financing-
|
||||||||||||||||||||
|
Long-term
debt
|
- | 1,576,629 | 179,500 | (1,328,919 | ) | 427,210 | ||||||||||||||
|
Equity
contributions from parent
|
700,000 | 700,000 | - | (700,000 | ) | 700,000 | ||||||||||||||
|
Short-term
borrowings, net
|
300,000 | - | 25,278 | (325,278 | ) | - | ||||||||||||||
|
Redemptions
and repayments-
|
||||||||||||||||||||
|
Common
stock
|
(600,000 | ) | - | - | - | (600,000 | ) | |||||||||||||
|
Long-term
debt
|
- | (1,048,647 | ) | (494,070 | ) | 6,306 | (1,536,411 | ) | ||||||||||||
|
Short-term
borrowings, net
|
- | (783,599 | ) | - | 325,278 | (458,321 | ) | |||||||||||||
|
Common
stock dividend payment
|
(117,000 | ) | - | - | - | (117,000 | ) | |||||||||||||
|
Other
|
- | (3,474 | ) | (1,725 | ) | - | (5,199 | ) | ||||||||||||
|
Net
cash provided from (used for) financing activities
|
283,000 | 440,909 | (291,017 | ) | (2,022,613 | ) | (1,589,721 | ) | ||||||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||||||||||
|
Property
additions
|
(10,603 | ) | (502,311 | ) | (225,795 | ) | - | (738,709 | ) | |||||||||||
|
Proceeds
from asset sales
|
- | 12,990 | - | - | 12,990 | |||||||||||||||
|
Proceeds
from sale and leaseback transaction
|
- | - | - | 1,328,919 | 1,328,919 | |||||||||||||||
|
Sales
of investment securities held in trusts
|
- | - | 655,541 | - | 655,541 | |||||||||||||||
|
Purchases
of investment securities held in trusts
|
- | - | (697,763 | ) | - | (697,763 | ) | |||||||||||||
|
Loans
repayments from associated companies
|
441,966 | - | 292,896 | - | 734,862 | |||||||||||||||
|
Investment
in subsidiary
|
(700,000 | ) | - | - | 700,000 | - | ||||||||||||||
|
Other
|
3,654 | (6,760 | ) | 2,670 | - | (436 | ) | |||||||||||||
|
Net
cash provided from (used for) investing activities
|
(264,983 | ) | (496,081 | ) | 27,549 | 2,028,919 | 1,295,404 | |||||||||||||
|
Net
change in cash and cash equivalents
|
- | - | - | - | - | |||||||||||||||
|
Cash
and cash equivalents at beginning of year
|
2 | - | - | - | 2 | |||||||||||||||
|
Cash
and cash equivalents at end of year
|
$ | 2 | $ | - | $ | - | $ | - | $ | 2 | ||||||||||
251
|
20.
|
SUMMARY
OF QUARTERLY FINANCIAL DATA
(UNAUDITED)
|
The
following summarizes certain consolidated operating results by quarter for 2009
and 2008.
|
Operating
|
Income
(Loss)
Before
|
Income
|
Earnings
|
|||||||||||||||||
|
Income
|
Income
|
Taxes
|
Available
To
|
|||||||||||||||||
|
Three Months Ended
|
Revenues
|
(Loss)
|
Taxes
|
(Benefit)
|
FirstEnergy
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
FE
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 3,334.0 | $ | 346.0 | $ | 169.0 | $ | 54.0 | $ | 119.0 | ||||||||||
|
March 31, 2008
|
3,277.0 | 618.0 | 464.0 | 187.0 | 276.0 | |||||||||||||||
|
June
30, 2009
|
3,271.0 | 802.0 | 656.0 | 248.0 | 414.0 | |||||||||||||||
|
June 30, 2008
|
3,245.0 | 582.0 | 423.0 | 160.0 | 263.0 | |||||||||||||||
|
September
30,2009
|
3,408.0 | 487.0 | 358.0 | 128.0 | 234.0 | |||||||||||||||
|
September 30,2008
|
3,904.0 | 846.0 | 709.0 | 238.0 | 471.0 | |||||||||||||||
|
December
31, 2009
|
2,954.0 | 244.0 | 52.0 | (185.0 | ) | 239.0 | ||||||||||||||
|
December 31, 2008
|
3,201.0 | 713.0 | 520.0 | 192.0 | 332.0 | |||||||||||||||
|
FES
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 1,226.1 | $ | 304.3 | $ | 262.5 | $ | 91.8 | $ | 170.7 | ||||||||||
|
March 31, 2008
|
1,099.1 | 175.7 | 147.8 | 57.8 | 90.0 | |||||||||||||||
|
June
30, 2009
|
1,341.2 | 468.9 | 466.6 | 169.2 | 297.4 | |||||||||||||||
|
June 30, 2008
|
1,071.3 | 142.2 | 115.4 | 47.3 | 68.1 | |||||||||||||||
|
September
30,2009
|
1,104.6 | 175.7 | 310.8 | 111.2 | 199.7 | |||||||||||||||
|
September 30,2008
|
1,241.6 | 288.8 | 278.9 | 93.2 | 185.7 | |||||||||||||||
|
December
31, 2009
|
1,056.4 | (96.3 | ) | (147.5 | ) | (56.9 | ) | (90.7 | ) | |||||||||||
|
December 31, 2008
|
1,106.4 | 311.6 | 257.5 | 94.9 | 162.6 | |||||||||||||||
|
OE
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 749.0 | $ | 30.2 | $ | 15.7 | $ | 4.0 | $ | 11.5 | ||||||||||
|
March 31, 2008
|
652.6 | 77.1 | 70.9 | 26.9 | 43.9 | |||||||||||||||
|
June
30, 2009
|
672.2 | 58.8 | 50.5 | 16.9 | 33.5 | |||||||||||||||
|
June 30, 2008
|
609.6 | 76.1 | 70.7 | 21.7 | 48.8 | |||||||||||||||
|
September
30,2009
|
602.5 | 52.8 | 50.6 | 15.9 | 34.6 | |||||||||||||||
|
September 30,2008
|
702.3 | 100.0 | 101.1 | 28.5 | 72.5 | |||||||||||||||
|
December
31, 2009 *
|
493.2 | 87.1 | 71.8 | 29.4 | 42.3 | |||||||||||||||
|
December 31, 2008
|
637.3 | 80.8 | 68.2 | 21.5 | 46.5 | |||||||||||||||
|
CEI
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 449.7 | $ | (144.1 | ) | $ | (166.9 | ) | $ | (61.5 | ) | $ | (105.9 | ) | ||||||
|
March 31, 2008
|
437.3 | 110.8 | 88.8 | 30.3 | 57.9 | |||||||||||||||
|
June
30, 2009
|
475.1 | 98.5 | 74.2 | 26.5 | 47.3 | |||||||||||||||
|
June 30, 2008
|
434.4 | 123.4 | 100.8 | 33.8 | 66.6 | |||||||||||||||
|
September
30,2009
|
435.5 | 61.6 | 35.1 | 9.8 | 25.0 | |||||||||||||||
|
September 30,2008
|
524.1 | 159.9 | 136.8 | 43.0 | 93.4 | |||||||||||||||
|
December
31, 2009
|
315.8 | 64.7 | 36.4 | 15.0 | 20.9 | |||||||||||||||
|
December 31, 2008
|
420.1 | 120.5 | 96.9 | 29.7 | 66.6 | |||||||||||||||
| * Includes a $4.8 million adjustment that increased net income in the fourth quarter of 2009 related to prior periods. | ||||||||||||||||||||
| (See Note 10 for description of adjustment). | ||||||||||||||||||||
252
|
Operating
|
Income
(Loss)
Before
|
Income
|
Earnings
|
|||||||||||||||||
|
Income
|
Income
|
Taxes
|
Available
To
|
|||||||||||||||||
|
Three Months Ended
|
Revenues
|
(Loss)
|
Taxes
|
(Benefit)
|
FirstEnergy
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
TE
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 244.8 | $ | 2.2 | $ | 0.9 | $ | (0.1 | ) | $ | 1.0 | |||||||||
|
March 31, 2008
|
211.7 | 26.1 | 25.1 | 8.1 | 17.0 | |||||||||||||||
|
June
30, 2009
|
226.2 | 10.1 | 9.8 | 3.4 | 6.4 | |||||||||||||||
|
June 30, 2008
|
221.5 | 30.9 | 28.7 | 7.4 | 21.3 | |||||||||||||||
|
September
30,2009
|
213.5 | 10.2 | 7.0 | (0.1 | ) | 7.1 | ||||||||||||||
|
September 30,2008
|
251.1 | 45.1 | 43.4 | 12.2 | 31.2 | |||||||||||||||
|
December
31, 2009 **
|
149.4 | 23.8 | 14.2 | 4.7 | 9.5 | |||||||||||||||
|
December 31, 2008
|
211.2 | 10.8 | 7.6 | 2.1 | 5.4 | |||||||||||||||
|
Met-Ed
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 429.7 | $ | 37.7 | $ | 28.4 | $ | 11.7 | $ | 16.6 | ||||||||||
|
March 31, 2008
|
400.3 | 45.6 | 38.9 | 16.7 | 22.2 | |||||||||||||||
|
June
30, 2009
|
377.6 | 27.8 | 17.0 | 7.0 | 10.0 | |||||||||||||||
|
June 30, 2008
|
392.0 | 37.8 | 32.7 | 12.9 | 19.8 | |||||||||||||||
|
September
30,2009
|
445.5 | 24.2 | 13.1 | 2.3 | 10.7 | |||||||||||||||
|
September 30,2008
|
455.5 | 45.1 | 38.3 | 16.3 | 22.0 | |||||||||||||||
|
December
31, 2009
|
436.2 | 37.2 | 25.6 | 7.6 | 18.2 | |||||||||||||||
|
December 31, 2008
|
405.2 | 46.1 | 39.0 | 15.0 | 24.0 | |||||||||||||||
|
Penelec
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 388.6 | $ | 44.2 | $ | 31.8 | $ | 13.1 | $ | 18.7 | ||||||||||
|
March 31, 2008
|
395.5 | 56.0 | 39.7 | 18.3 | 21.4 | |||||||||||||||
|
June
30, 2009
|
331.7 | 36.0 | 25.1 | 10.2 | 14.8 | |||||||||||||||
|
June 30, 2008
|
351.4 | 44.2 | 30.4 | 12.0 | 18.4 | |||||||||||||||
|
September
30,2009
|
355.5 | 32.3 | 21.8 | 6.0 | 15.8 | |||||||||||||||
|
September 30,2008
|
389.8 | 46.6 | 31.7 | 9.1 | 22.6 | |||||||||||||||
|
December
31, 2009
|
373.1 | 49.4 | 32.4 | 16.4 | 16.1 | |||||||||||||||
|
December 31, 2008
|
376.9 | 57.7 | 44.0 | 18.2 | 25.8 | |||||||||||||||
|
JCP&L
|
||||||||||||||||||||
|
March
31, 2009
|
$ | 773.7 | $ | 77.1 | $ | 50.1 | $ | 22.6 | $ | 27.6 | ||||||||||
|
March 31, 2008
|
794.2 | 86.9 | 62.4 | 28.4 | 34.0 | |||||||||||||||
|
June
30, 2009
|
708.1 | 95.4 | 67.9 | 29.8 | 38.1 | |||||||||||||||
|
June 30, 2008
|
834.7 | 97.4 | 74.4 | 31.5 | 42.9 | |||||||||||||||
|
September
30,2009
|
868.2 | 133.7 | 105.6 | 43.4 | 62.2 | |||||||||||||||
|
September 30,2008
|
1,102.6 | 157.7 | 131.7 | 55.8 | 75.9 | |||||||||||||||
|
December
31, 2009
|
642.7 | 84.1 | 55.7 | 13.0 | 42.6 | |||||||||||||||
|
December 31, 2008
|
740.8 | 92.5 | 66.7 | 32.5 | 34.2 | |||||||||||||||
| ** Includes a $2.5 million adjustment that increased net income in the fourth quarter of 2009 related to prior periods. | ||||||||||||||||||||
| (See Note 10 for description of adjustment). | ||||||||||||||||||||
253
|
21.
|
SUBSEQUENT
EVENTS
|
On
February 11, 2010, FirstEnergy and Allegheny Energy, Inc. (Allegheny) announced
that both companies' boards of directors unanimously approved a definitive
agreement in which the companies would combine in a stock-for-stock
transaction.
Under
the terms of the agreement, Allegheny shareholders would receive 0.667 of a
share of FirstEnergy common stock in exchange for each share of Allegheny they
own. Based on the closing stock prices for both companies on February 10, 2010,
Allegheny shareholders would receive a value of $27.65 per share, or $4.7
billion in the aggregate. FirstEnergy would also assume approximately $3.8
billion of Allegheny net debt.
The
merger is conditioned upon, among other things, the approval of the shareholders
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, the PPUC, the
Virginia State Corporation Commission and the West Virginia Public Service
Commission. The merger is also conditioned on effectiveness at the SEC of
FirstEnergy’s registration statement with respect to the shares to be issued in
the transaction. The companies anticipate that the necessary approvals may be
obtained within 12-14 months.
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
(see Note 15(B)). Moody's and Fitch affirmed the ratings and stable outlook of
FirstEnergy and its subsidiaries on February 11, 2010. These rating agency
actions were taken in response to the announcement of the proposed merger with
Allegheny.
254
None.
ITEM
9A. CONTROLS AND PROCEDURES -- FIRSTENERGY
Evaluation of Disclosure
Controls and Procedures
FirstEnergy's
Chief Executive Officer and Chief Financial Officer have reviewed and evaluated
such registrant’s disclosure controls and procedures, as defined in the
Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end
date covered by this report. Based upon this evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that FirstEnergy's disclosure
controls and procedures were effective as of December
31, 2009.
Management’s Report on
Internal Control over Financial Reporting
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act
of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control – Integrated
Framework, management conducted an evaluation of the effectiveness of
FirstEnergy's internal control over financial reporting under the supervision of
FirstEnergy's Chief Executive Officer and Chief Financial Officer. Based on that
evaluation, management concluded that FirstEnergy's internal control over
financial reporting was effective as of December 31, 2009. The
effectiveness of FirstEnergy's internal control over financial reporting, as of
December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report
included herein.
Changes in Internal Control
over Financial Reporting
There
were no changes in FirstEnergy's internal control over financial reporting
during the fourth quarter of 2009 that have materially affected, or are
reasonably likely to materially affect, FirstEnergy's internal control over
financial reporting.
ITEM
9A(T). CONTROLS AND PROCEDURES --FES, OE, CEI, TE, JCP&L, Met-Ed and
Penelec
Evaluation of Disclosure
Controls and Procedures
Each
registrant's Chief Executive Officer and Chief Financial Officer have reviewed
and evaluated such registrant's disclosure controls and procedures, as defined
in the Securities Exchange Act of 1934 rules 13a-15(e) and 15d-15(e), as of the
end date covered by this report. Based upon this evaluation, the respective
Chief Executive Officer and Chief Financial Officer concluded that such
registrant's disclosure controls and procedures were effective as of
December 31, 2009.
Management’s Report on
Internal Control over Financial Reporting
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act
of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control – Integrated
Framework, management conducted an evaluation of the effectiveness of each
registrant’s internal control over financial reporting under the supervision of
such registrant’s Chief Executive Officer and Chief Financial Officer. Based on
that evaluation, management concluded that each registrant’s internal control
over financial reporting was effective as of December 31, 2009. The
effectiveness of each registrant's internal control over financial reporting, as
of December 31, 2009, has not been audited by such registrant’s independent
registered public accounting firm.
Changes in Internal Control
over Financial Reporting
There
were no changes in internal control over financial reporting during the fourth
quarter of 2009 that have materially affected, or are reasonably likely to
materially affect, internal control over financial reporting for each
registrant.
ITEM
9B. OTHER INFORMATION
None.
255
PART
III
ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
The
information required by Item 10, with respect to identification of
FirstEnergy’s directors and with respect to reports required to be filed under
Section 16 of the Securities Exchange Act of 1934, is incorporated herein
by reference to FirstEnergy’s 2010 Proxy Statement filed with the SEC pursuant
to Regulation 14A under the Securities Exchange Act of 1934 and, with respect to
identification of executive officers, to “Part I, Item 1.
Business – Executive Officers” herein.
The
Board of Directors, upon recommendation of the Corporate Governance and Audit
Committees, has determined that Ernest J. Novak, Jr., an independent director,
is the audit committee financial expert.
FirstEnergy
makes available on its Web site at http://www.firstenergycorp.com/ir its
Corporate Governance Policies and the charters for each of the following
committees of the Board of Directors: Audit; Corporate Governance; Compensation;
Finance; and Nuclear.
FirstEnergy
has adopted a Code of Business Conduct, which applies to all employees,
including the Chief Executive Officer, the Chief Financial Officer and the Chief
Accounting Officer. In addition, the Board of Directors has its own Code of
Business Conduct. These Codes can be found on the Web site provided in the
previous paragraph.
|
ITEM
11.
|
EXECUTIVE
COMPENSATION
|
The
information required by Item 11 is incorporated herein by reference to
FirstEnergy’s 2010 Proxy Statement filed with the SEC pursuant to Regulation 14A
under the Securities Exchange Act of 1934.
|
ITEM
12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
|
The
information required by Item 12 is incorporated herein by reference to
FirstEnergy’s 2010 Proxy Statement filed with the SEC pursuant to Regulation 14A
under the Securities Exchange Act of 1934.
|
ITEM
13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
|
The
information required by Item 13 is incorporated herein by reference to
FirstEnergy’s 2010 Proxy Statement filed with the SEC pursuant to Regulation 14A
under the Securities Exchange Act of 1934.
ITEM
14. PRINCIPAL ACCOUNTING FEES AND SERVICES
A
summary of the audit and audit-related fees rendered by PricewaterhouseCoopers
LLP for the years ended December 31, 2009 and 2008 are as
follows:
|
Audit Fees
(1)
|
Audit-Related Fees
|
|||||||||||||||
|
Company
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
(In
thousands)
|
||||||||||||||||
|
FES
|
$ | 991 | $ | 835 | $ | - | $ | - | ||||||||
|
OE
|
1,019 | 1,155 | - | - | ||||||||||||
|
CEI
|
734 | 764 | - | - | ||||||||||||
|
TE
|
626 | 598 | - | - | ||||||||||||
|
JCP&L
|
715 | 682 | - | - | ||||||||||||
|
Met-Ed
|
607 | 583 | - | - | ||||||||||||
|
Penelec
|
613 | 595 | - | - | ||||||||||||
|
Other
subsidiaries
|
690 | 607 | - | - | ||||||||||||
|
Total
FirstEnergy
|
$ | 5,995 | $ | 5,819 | $ | - | $ | - | ||||||||
|
|
(1)
|
Professional
services rendered for the audits of FirstEnergy’s annual financial
statements and reviews of financial statements included in FirstEnergy’s
Quarterly Reports on Form 10-Q and for services in connection with
statutory and regulatory filings or engagements, including comfort letters
and consents for financings and filings made with the
SEC.
|
Tax
and Other Fees
There
were no other fees billed to FirstEnergy for tax or other services for the years
ended December 31, 2009 and 2008.
Additional
information required by this item is incorporated herein by reference to
FirstEnergy's 2010 Proxy Statement filed with the SEC pursuant to Regulation 14A
under the Securities Exchange Act of 1934.
256
PART
IV
ITEM
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The
following documents are filed as a part of this report on Form
10-K:
1. Financial
Statements:
Management's
Report on Internal Control Over Financial Reporting for FirstEnergy Corp., FES,
OE, CEI, TE, JCP&L, Met-Ed, and Penelec is listed under Item 8
herein.
Reports
of Independent Registered Public Accounting Firm for FirstEnergy Corp., FES, OE,
CEI, TE, JCP&L, Met-Ed, and Penelec are listed under Item 8
herein.
The
financial statements filed as a part of this report for FirstEnergy Corp., FES,
OE, CEI, TE, JCP&L, Met-Ed, and Penelec are listed under Item 8
herein.
2. Financial
Statement Schedules:
Reports
of Independent Registered Public Accounting Firm as to Schedules for FirstEnergy
Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are included herein on
pages 140, 141, 142, 143, 144, 145, 146 and 147.
Schedule
II – Consolidated Valuation and Qualifying Accounts for FirstEnergy Corp., FES,
OE, CEI, TE, JCP&L, Met-Ed, and Penelec are included herein on pages 302,
303, 304, 305, 306, 307, 308 and 309.
3. Exhibits
– FirstEnergy
Exhibit
Number
|
2-1
|
Agreement
and Plan of Merger, dated as of February 10, 2010, by and among
FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc.
(incorporated by reference to FE’s Form 8-K filed February 11, 2010,
Exhibit 2.1, File No. 333-21011)
|
|
(A)
3-1
|
Amended
Articles of Incorporation of FirstEnergy Corp.
|
|
3-2
|
FirstEnergy
Corp. Amended Code of Regulations. (incorporated by reference to FE’s Form
10-K filed February 25, 2009, Exhibit 3.1, File No.
333-21011)
|
|
4-1
|
Indenture,
dated November 15, 2001, between FirstEnergy Corp. and The Bank of New
York Mellon, as Trustee. (incorporated by reference to FE’s Form
S-3 filed September 21, 2001, Exhibit 4(a), File No.
333-69856)
|
|
(B)
10-1
|
FirstEnergy
Corp. 2007 Incentive Plan, effective May 15, 2007. (incorporated by
reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10.1, File
No. 333-21011)
|
|
(B)
10-2
|
Amended
FirstEnergy Corp. Deferred Compensation Plan for Outside Directors,
amended and restated as of January 1, 2005 and ratified as of September
18, 2007. (incorporated by reference to FE’s Form 10-K filed February 25,
2009, Exhibit 10.2, File No. 333-21011)
|
|
(B)
10-3
|
FirstEnergy
Corp. Supplemental Executive Retirement Plan, amended January 1,
1999. (incorporated by reference to FE’s Form 10-K filed March 20, 2000,
Exhibit 10-4, File No. 333-21011)
|
|
(B)
10-4
|
Stock
Option Agreement between FirstEnergy Corp. and officers dated
November 22, 2000. (incorporated by reference to FE’s Form 10-K filed
March 28, 2001, Exhibit 10-3, File No. 333-21011)
|
|
(B)
10-5
|
Stock
Option Agreement between FirstEnergy Corp. and officers dated
March 1, 2000. (incorporated by reference to FE’s Form 10-K filed
March 28, 2001, Exhibit 10-4, File No. 333-21011)
|
|
(B)
10-6
|
Stock
Option Agreement between FirstEnergy Corp. and director dated
January 1, 2000. (incorporated by reference to FE’s Form 10-K filed
March 28, 2001, Exhibit 10-5, File No.
333-21011)
|
257
|
(B)
10-7
|
Stock
Option Agreement between FirstEnergy Corp. and two directors dated
January 1, 2001. (incorporated by reference to FE’s Form 10-K filed
March 28, 2001, Exhibit 10-6, File No. 333-21011)
|
|
(B)
10-8
|
Stock
Option Agreements between FirstEnergy Corp. and One Director dated
January 1, 2002. (incorporated by reference to FE’s Form 10-K filed
April 1, 2002, Exhibit 10-5, File No. 333-21011)
|
|
(B)
10-9
|
FirstEnergy
Corp. Executive Deferred Compensation Plan, amended and restated as of
January 1, 2005 and ratified as of September 18, 2007. (incorporated by
reference to FE’s 10-Q filed October 31, 2007, Exhibit 10.2, File No.
333-21011)
|
|
(B)
10-10
|
Executive
Incentive Compensation Plan-Tier 2. (incorporated by reference to FE’s
Form 10-K filed April 1, 2002, Exhibit 10-7, File No.
333-21011)
|
|
(B)
10-11
|
Executive
Incentive Compensation Plan-Tier 3. (incorporated by reference to FE’s
Form 10-K filed April 1, 2002, Exhibit 10-8, File No.
333-21011)
|
|
(B)
10-12
|
Executive
Incentive Compensation Plan-Tier 4. (incorporated by reference to FE’s
Form 10-K filed April 1, 2002, Exhibit 10-9, File No.
333-21011)
|
|
(B)
10-13
|
Executive
Incentive Compensation Plan-Tier 5. (incorporated by reference to FE’s
Form 10-K filed April 1, 2002, Exhibit 10-10, File No.
333-21011)
|
|
(B)
10-14
|
Amendment
to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries,
effective April 5, 2001. (incorporated by reference to FE’s Form 10-K
filed April 1, 2002, Exhibit 10-11, File No. 333-21011)
|
|
(B)
10-15
|
Form
of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock
Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration
Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside
Directors of GPU, Inc. (incorporated by reference to FE’s Form 10-K filed
April 1, 2002, Exhibit 10-12, File No. 333-21011)
|
|
(B)
10-16
|
GPU,
Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees.
(incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit
10-13, File No. 333-21011, File No. 333-21011)
|
|
(B)
10-17
|
Executive
and Director Stock Option Agreement dated June 11, 2002. (incorporated by
reference to FE’s Form 10-K, Exhibit 10-1, File No.
333-21011)
|
|
(B)
10-18
|
Director
Stock Option Agreement. (incorporated by reference to FE’s Form 10-K filed
March 26, 2003, Exhibit 10-2, File No. 333-21011)
|
|
(B)
10-19
|
Executive
Incentive Compensation Plan 2002. (incorporated by reference to FE’s Form
10-K filed March 26, 2003, Exhibit 10-28, File No.
333-21011)
|
|
(B)
10-20
|
GPU,
Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as
amended and restated to reflect amendments through June 3, 1999.
(incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000,
Exhibit 10-V, File No. 001-06047)
|
|
(B)
10-21
|
Form
of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for
Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to
GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-Q, File No.
001-06047)
|
|
(B)
10-22
|
Form
of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for
Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to
GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-W, File No.
001-06047)
|
|
(B)
10-23
|
Form
of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for
Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to
GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-W, File No.
001-06047)
|
258
|
(B)
10-24
|
Deferred
Remuneration Plan for Outside Directors of GPU, Inc. as amended and
restated effective August 8, 2000. (incorporated by reference to GPU, Inc.
Form 10-K filed March 20, 2000, Exhibit 10-O, File No.
001-06047)
|
|
(B)
10-25
|
Retirement
Plan for Outside Directors of GPU, Inc. as amended and restated as of
August 8, 2000. (incorporated by reference to GPU, Inc. Form 10-K filed
March 20, 2000, Exhibit 10-N, File No. 001-06047)
|
|
(B)
10-26
|
Forms
of Estate Enhancement Program Agreements entered into by certain former
GPU directors. (incorporated by reference to GPU, Inc. Form 10-K filed
March 20, 2000, Exhibit 10-JJ, File No. 001-06047)
|
|
(A)(B)
10-27
|
Employment
Agreement for Richard R. Grigg dated February 26, 2008, (incorporated
by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10.5, File
No. 333-21011), as amended on January 29, 2010.
|
|
(B)
10-28
|
Stock
Option Agreement between FirstEnergy Corp. and an officer dated August 20,
2004. (incorporated by reference to FE’s Form 10-Q filed
November 4, 2004, Exhibit 10-42, File No. 333-21011)
|
|
(B)
10-29
|
Executive
Bonus Plan between FirstEnergy Corp. and Officers effective November 3,
2004. (incorporated by reference to FE’s Form 10-Q filed November 4, 2004,
Exhibit 10-44, File No. 333-21011)
|
|
10-30
|
Consent
Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K
filed March 18, 2005, Exhibit 10-1, File No. 333-21011)
|
|
(C)
10-31
|
Form
of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy
Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as
Administrative Agent for the Banks. (incorporated by reference to FE’s
Form 10-K filed March 3, 2006, Exhibit 10-1, File No.
333-21011)
|
|
(D)
10-32
|
Form
of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in
favor of the Participating Banks, Barclays Bank PLC, as administrative
agent and fronting bank, and KeyBank National Association, as syndication
agent, under the related Letter of Credit and Reimbursement Agreement.
(incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit
10-1, File No. 333-21011)
|
|
(B)
10-33
|
Form
of Restricted Stock Agreement between FirstEnergy Corp. and A. J.
Alexander, dated February 27, 2006. (incorporated by reference to FE’s
Form 10-Q filed May 9, 2006, Exhibit 10-6, File No.
333-21011)
|
|
(B)
10-34
|
Form
of Restricted Stock Unit Agreement (Performance Adjusted) between
FirstEnergy Corp. and A. J. Alexander, dated March 1, 2006. (incorporated
by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-7, File No.
333-21011)
|
|
(B)
10-35
|
Form
of Restricted Stock Unit Agreement (Performance Adjusted) between
FirstEnergy Corp. and named executive officers, dated March 1, 2006.
(incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit
10-8, File No. 333-21011)
|
|
(B)
10-36
|
Form
of Restricted Stock Unit Agreement (Performance Adjusted) between
FirstEnergy Corp. and R. H. Marsh, dated March 1, 2006. (incorporated by
reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-9, File No.
333-21011)
|
|
10-37
|
Confirmation
dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and
Co., International Limited. (incorporated by reference to FE’s Form 10-Q
filed May 9, 2007, Exhibit 10.1, File No. 333-21011)
|
|
(B)
10-38
|
FirstEnergy
Corp. Supplemental Executive Retirement Plan as amended September 18,
2007. (incorporated by reference to FE’s Form 10-Q filed October 31, 2007,
Exhibit 10.2, File No.
333-21011)
|
259
|
(A)(B)
10-39
|
Employment
Agreement between FirstEnergy Corp. and Gary R. Leidich, dated February
26, 2008 (incorporated by reference to FE’s Form 10-K filed February 29,
2008, Exhibit 10-88, File No. 333-21011), as amended on January 29,
2010.
|
|
(B)
10-40
|
Form of
Restricted Stock Unit Agreement for Gary R. Leidich (per Employment
Agreement dated February 26, 2008). (incorporated by reference to FE’s
Form 10-K filed February 29, 2008, Exhibit 10-90, File No.
333-21011)
|
|
(B)
10-41
|
Form of
Restricted Stock Agreement Amendment for Gary R. Leidich dated February
26, 2008. (incorporated by reference to FE’s Form 10-K filed
February 29, 2008, Exhibit 10-91, File No. 333-21011)
|
|
(B)
10-42
|
Form of
Restricted Stock Unit Agreement for Richard R. Grigg (per Employment
Agreement dated February 26, 2008). (incorporated by reference to FE’s
Form 10-K filed February 29, 2008, Exhibit 10-92, File No.
333-21011)
|
|
(B)
10-43
|
Form of
Performance-Adjusted Restricted Stock Unit Award Agreement as of March 3,
2008. (incorporated by reference to FE’s Form 10-K filed February 29,
2008, Exhibit 10-93, File No. 333-21011)
|
|
(B)
10-44
|
Form of
2008-2010 Performance Share Award Agreement effective January 1,
2008. (incorporated by reference to FE’s Form 10-K filed February 29,
2008, Exhibit 10-94, File No. 333-21011)
|
|
10-45
|
U.S.
$300,000,000 Credit Agreement, dated as of October 8, 2008, among
FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and
FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other
Banks parties thereto from time to time, as Banks and Credit Suisse, as
Administrative Agent. (incorporated by reference to FE’s Form 10-Q filed
November 7, 2008, Exhibit 10.1, File No. 333-21011)
|
|
(B)
10-46
|
Form of
2009-2011 Performance Share Award Agreement effective January 1, 2009
(incorporated by reference to FE's Form 10-K filed February 25, 2009,
Exhibit 10-48, File No. 333-21011)
|
|
(B)
10-47
|
Form of
Performance-Adjusted Restricted Stock Unit Award Agreement as of March 2,
2009 (incororaetd by reference to FE's Form 10-K filed February 25, 2009,
Exhibit 10-49, File No. 333-21011)
|
|
(A)(B)
10-48
|
Form of
2010-2012 Performance Share Award Agreement effective January 1,
2010
|
|
(A)(B)
10-49
|
Form of
Performance-Adjusted Restricted Stock Unit Award Agreement as of March 8,
2010
|
|
(B)
10-50
|
Form of
Director Indemnification Agreement (incorporated by reference to FE’s 10-Q
filed May 7, 2009, Exhibit 10.1, File No. 333-21011)
|
|
(B)
10-51
|
Form of
Management Director Indemnification Agreement (incorporated by reference
to FE’s 10-Q filed May 7, 2009, Exhibit 10.2, File No.
333-21011)
|
|
(A)
12-1
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
21
|
List of
Subsidiaries of the Registrant at December 31,
2009.
|
|
(A)
23-1
|
Consent of
Independent Registered Public Accounting Firm.
|
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
260
|
(A)
|
Provided
herein in electronic format as an exhibit.
|
|
(B)
|
Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K |
|
(C)
|
Four
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to four other series of pollution control revenue refunding bonds issued
by the Ohio Water Development Authority, the Ohio Air Quality Authority
and Beaver County Industrial Development Authority, Pennsylvania, relating
to pollution control notes of FirstEnergy Nuclear Generation
Corp.
|
|
(
D)
|
Three
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to three other series of pollution control revenue refunding bonds issued
by the Ohio Water Development Authority and the Beaver County Industrial
Development Authority relating to pollution control notes of FirstEnergy
Generation Corp. and FirstEnergy Nuclear Generation
Corp.
|
3.
Exhibits – FES
|
3-1
|
Articles
of Incorporation of FirstEnergy Solutions Corp., as amended
August 31, 2001. (i
ncorporated by reference to FES’
Form
S-4 filed August 6, 2007, Exhibit
3.1,
File No.
333-145140-01
)
|
|
3-2
|
Amended and Restated
Code of Regulations of FirstEnergy Solutions Corp. effective as of August
26, 2009 (i
ncorporated by reference to FES’
Form 8-K filed August
7, 2009, Exhibit 3.4, File N
o.
000-53742
)
|
|
4-1
|
Open-End
Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June
19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust
Company, N.A., as Trustee (
i
ncorporated by
reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1, File No.
333-145140-01)
|
|
4-1(a)
|
First
Supplemental Indenture dated as of June 25, 2008 (including Form of First
Mortgage Bonds, Guarantee Series A of 2008 due 2009 and Form First
Mortgage Bonds, Guarantee Series B of 2008 due 2009). (
i
ncorporated by
reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(a), File No.
333-145140-01)
|
|
4-1(b)
|
Second
Supplemental Indenture dated as of March 1, 2009 (including Form of First
Mortgage Bonds, Guarantee Series A of 2009 due 2014 and Form of First
Mortgage Bonds, Guarantee Series B of 2009 due 2023). (
i
ncorporated by
reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(b), File No.
333-145140-01)
|
|
4-1(c)
|
Third
Supplemental Indenture dated as of March 31, 2009 (including Form of First
Mortgage Bonds, Collateral Series A of 2009 due 2011). (
i
ncorporated by
reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(c), File No.
333-145140-01)
|
|
4-1(d)
|
Fourth
Supplemental Indenture, dated as of June 1, 2009 (including Form of First
Mortgage Bonds, Guarantee Series C of 2009 due 2018, Form of First
Mortgage Bonds, Guarantee Series D of 2009 due 2029, Form of First
Mortgage Bonds, Guarantee Series E of 2009 due 2029, Form of First
Mortgage Bonds, Collateral Series B of 2009 due 2011 and Form of First
Mortgage Bonds, Collateral Series C of 2009 due 2011). (incorporated by
reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.3, File No.
333-145140-01)
|
|
4-1(e)
|
Fifth
Supplemental Indenture, dated as of June 30, 2009 (including Form of First
Mortgage Bonds, Guarantee Series F of 2009 due 2047, Form of First
Mortgage Bonds, Guarantee Series G of 2009 due 2018 and Form of First
Mortgage Bonds, Guarantee Series H of 2009 due
2018). (incorporated by reference to FES’ Form 8-K filed July
6, 2009, Exhibit 4.2, File No. 333-145140-01)
|
|
4-1(f)
|
Sixth
Supplemental Indenture, dated as of December 1, 2009 (including Form of
First Mortgage Bonds, Collateral Series D of 2009 due 2012 (incorporated
by reference to FES’ Form 8-K filed December 4, 2009, Exhibit
4.2, File No. 000-53742)
|
261
|
4-2
|
Open-End
Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June
1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank
of New York Mellon Trust Company, N.A., as trustee (incorporated by
reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.1, File No.
333-145140-01)
|
|
4-2(a)
|
First
Supplemental Indenture, dated as of June 15, 2009 (including Form of First
Mortgage Bonds, Guarantee Series A of 2009 due 2033, Form of First
Mortgage Bonds, Guarantee Series B of 2009 due 2011, Form of First
Mortgage Bonds, Collateral Series A of 2009 due 2010, Form of First
Mortgage Bonds, Collateral Series B of 2009 due 2010, Form of First
Mortgage Bonds, Collateral Series C of 2009 due 2010, Form of First
Mortgage Bonds, Collateral Series D of 2009 due 2010, Form of First
Mortgage Bonds, Collateral Series E of 2009 due 2010, Form of First
Mortgage Bonds, Collateral Series F of 2009 due 2011 and Form of First
Mortgage Bonds, Collateral Series G of 2009 due 2011). (incorporated by
reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.2(i), File No.
333-145140-01)
|
|
4-2(b)
|
Second
Supplemental Indenture, dated as of June 30, 2009 (including Form of First
Mortgage Bonds, Guarantee Series C of 2009 due 2033, Form of First
Mortgage Bonds, Guarantee Series D of 2009 due 2033, Form of First
Mortgage Bonds, Guarantee Series E of 2009 due 2033, Form of First
Mortgage Bonds, Collateral Series H of 2009 due 2011, Form of First
Mortgage Bonds, Collateral Series I of 2009 due 2011 and Form of First
Mortgage Bonds, Collateral Series J of 2009 due 2010). (incorporated by
reference to FES’ Form 8-K filed July 6, 2009, Exhibit 4.1(f), File No.
333-145140-01)
|
|
4-2(c)
|
Third
Supplemental Indenture, dated as of December 1, 2009 (including Form of
First Mortgage Bonds, Collateral Series K of 2009 due 2012). (incorporated
by reference to FES’ Form 8-K filed December 4, 2009, Exhibit 4.1, File
No. 000-53742)
|
|
4-3
|
Indenture,
dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The
Bank of New York Mellon Trust Company, N.A. (incorporated by reference to
FES' Form 8-K filed August 7, 2009, Exhibit 4.1, File No.
000-53742)
|
|
4-3(a)
|
First
Supplemental Indenture, dated as of August 1, 2009 (including Form of
4.80% Senior Notes due 2015, Form of 6.05% Senior Notes due 2021 and Form
of 6.80% Senior Notes due 2039). (incorporated by reference to FES' Form
8-K filed August 7, 2009, Exhibit 4.2, File No.
000-53742)
|
|
10-1
|
Form of 6.85% Exchange
Certificate due 2034. (i
ncorporated by reference to FES’
Form S-4 filed August
6, 2007, Exhibit
4.1, File No.
333-145140-01)
|
|
10-2
|
Guaranty of FirstEnergy
Solutions Corp., dated as of July 1, 2007. (
incorporated by
reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-9, File No. 333-21011)
|
|
10-3
|
Indenture of Trust,
Open-End Mortgage and Security Agreement, dated as of July 1, 2007,
between the applicable Lessor and The Bank of New York Trust Company,
N.A., as Indenture Trustee. (
incorporated by reference to FE's
Form 8-K/A filed
August 2, 2007, Exhibit 10-3, File No.
333-21011)
|
|
10-4
|
6.85% Lessor Note due
2034. (
incorporated by reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-3, File No. 333-21011)
|
|
10-5
|
Registration
Rights Agreement, dated as of July 13, 2007, among FirstEnergy
Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust
Company, N.A., as Pass Through Trustee, Morgan Stanley & Co.
Incorporated, and Credit Suisse Securities (USA) LLC, as representatives
of the several initial purchasers named in the Purchase Agreement.
(
incorporated by reference to FE's
Form
8-K/A filed August 2, 2007, Exhibit 10-14, File No.
333-21011)
|
262
|
10-6
|
Participation
Agreement, dated as of June 26, 2007, among FirstEnergy Generation
Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor, the
applicable Lessor, U.S. Bank Trust National Association, as Trust Company,
the applicable Owner Participant, The Bank of New York Trust Company,
N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A.,
as Pass Through Trustee. (
incorporated by reference to FE's
Form
8-K/A filed August 2, 2007, Exhibit 10-1, File No.
333-21011)
|
|
10-7
|
Trust Agreement, dated
as of June 26, 2007, between the applicable Owner Participant and U.S.
Bank Trust National Association, as Owner
Trustee. (
incorporated by reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-2, File No. 333-21011)
|
|
10-8
|
Pass Through Trust
Agreement, dated as of June 26, 2007, among FirstEnergy
Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York
Trust Company, N.A., as Pass Through Trustee. (
incorporated by
reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-12, File No. 333-21011)
|
|
10-9
|
Bill of Sale and
Transfer, dated as of July 1, 2007, between FirstEnergy
Generation Corp. and the applicable Lessor. (
incorporated by
reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-5, File No. 333-21011)
|
|
10-10
|
Facility Lease
Agreement, dated as of July 1, 2007, between FirstEnergy
Generation Corp. and the applicable Lessor. (
incorporated by
reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-6, File No. 333-21011)
|
|
10-11
|
Site Lease, dated as of
July 1, 2007, between FirstEnergy Generation Corp. and the
applicable Lessor. (
incorporated by reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-7, File No. 333-21011)
|
|
10-12
|
Site Sublease, dated as
of July 1, 2007, between FirstEnergy Generation Corp. and the
applicable Lessor. (
incorporated by reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-8, File No. 333-21011)
|
|
10-13
|
Support Agreement,
dated as of July 1, 2007, between FirstEnergy Generation Corp.
and the applicable Lessor. (
incorporated by reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-10, File No. 333-21011)
|
|
10-14
|
Second Amendment to the
Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of
July 1, 2007, between FirstEnergy Generation Corp., The
Cleveland Electric Illuminating Company and The Toledo Edison Company.
(
incorporated by reference to FE's
Form 8-K/A filed August
2, 2007, Exhibit 10-11, File No. 333-21011)
|
|
10-15
|
OE Fossil Purchase and
Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy
Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q
filed August 1, 2005, Exhibit 10.2, File No.
333-21011)
|
|
10-16
|
CEI Fossil Purchase and
Sale Agreement by and between The Cleveland Electric Illuminating Company
(Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by
reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.6, File No.
333-21011)
|
|
10-17
|
TE Fossil Purchase and
Sale Agreement by and between The Toledo Edison Company (Seller) and
FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to
FE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No.
333-21011)
|
|
10-18
|
Agreement, dated
August 26, 2005, by and between FirstEnergy Generation Corp. and
Bechtel Power Corporation. (incorporated by reference to FE’s Form 10-Q
filed November 2, 2005, Exhibit 10-2, File No.
333-21011)
|
|
10-19
|
CEI Fossil Note, dated
October 24, 2005, of FirstEnergy Generation Corp. (incorporated by
reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.15, File
N
o.
333-145140-01
)
|
|
10-20
|
CEI Fossil Security
Agreement, dated October 24, 2005, by and between FirstEnergy
Generation Corp. and The Cleveland Electric Illuminating Company.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.16, File N
o.
333-145140-01
)
|
263
|
10-21
|
OE
Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.17, File N
o.
333-145140-01
)
|
|
10-22
|
OE Fossil
Security Agreement, dated October 24, 2005, by and between
FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated
by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.18, File
N
o.
333-145140-01
)
|
|
10-23
|
Amendment No. 1 to OE
Fossil Security Agreement, dated as of June 30, 2007, between
FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated
by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.19, File
N
o.
333-145140-01
)
|
|
10-24
|
PP Fossil Note, dated
October 24, 2005, of FirstEnergy Generation Corp. (incorporated by
reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.20, File
N
o.
333-145140-01
)
|
|
10-25
|
PP Fossil
Security Agreement, dated October 24, 2005, by and between
FirstEnergy Generation Corp. and Pennsylvania Power Company.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.21, File N
o.
333-145140-01
)
|
|
10-26
|
Amendment No. 1 to PP
Fossil Security Agreement, dated as of June 30, 2007, between
FirstEnergy Generation Corp. and Pennsylvania Power Company.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.22, File N
o.
333-145140-01
)
|
|
10-27
|
TE Fossil Note,
dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated
by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.23, File
N
o.
333-145140-01
)
|
|
10-28
|
TE Fossil
Security Agreement, dated October 24, 2005, by and between
FirstEnergy Generation Corp. and The Toledo Edison Company.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.24, File N
o.
333-145140-01
)
|
|
10-29
|
CEI Nuclear
Note, dated December 16, 2005, of FirstEnergy Nuclear Generation
Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.25, File N
o.
333-145140-01
)
|
|
10-30
|
CEI Nuclear
Security Agreement, dated December 16, 2005, by and between
FirstEnergy Nuclear Generation Corp. and The Cleveland Electric
Illuminating Company. (incorporated by reference to FES’ Form S-4/A filed
August 20, 2007, Exhibit 10.26, File N
o.
333-145140-01
)
|
|
10-31
|
OE Nuclear Note, dated
December 16, 2005, of FirstEnergy Nuclear Generation Corp.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit
10.27
, File N
o.
333-145140-01
)
|
|
10-32
|
PP Nuclear Note,
dated December 16, 2005, of FirstEnergy Nuclear Generation Corp.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.28, File N
o.
333-145140-01
)
|
|
10-33
|
TE Nuclear Note, dated
December 16, 2005, of FirstEnergy Nuclear Generation Corp.
(incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.29, File N
o.
333-145140-01
)
|
|
10-34
|
TE Nuclear Security
Agreement, dated December 16, 2005, by and between FirstEnergy
Nuclear Generation Corp. and The Toledo Edison Company. (incorporated by
reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.30, File
N
o.
333-145140-01
)
|
|
10-35
|
Mansfield Power Supply
Agreement, dated August 10, 2006, among The Cleveland Electric
Illuminating Company, The Toledo Edison Company and FirstEnergy Generation
Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007,
Exhibit 10.31, File N
o.
333-145140-01
)
|
|
10-36
|
Nuclear Power Supply
Agreement, dated August 10, 2006, between FirstEnergy Nuclear Generation
Corp. and FirstEnergy Solutions Corp. (incorporated by reference to
FES’ Form S-4/A filed August 20, 2007, Exhibit 10.32, File N
o.
333-145140-01
)
|
264
|
10-37
|
Revised
Power Supply Agreement, dated December 8, 2006, among FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company and The Toledo Edison Company. (incorporated by reference to FES’
Form S-4/A filed August 20, 2007, Exhibit 10.34, File N
o.
333-145140-01
)
|
|
10-38
|
GENCO Power Supply
Agreement, dated January 1, 2007, between FirstEnergy Generation Corp. and
FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A
filed August 20, 2007, Exhibit 10.36, File N
o.
333-145140-01
)
|
|
10-39
|
Form of Guaranty dated
as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and
Morgan Stanley Senior Funding, Inc., as Lender under the U.S. $250,000,000
Credit Agreement, dated as of March 2, 2007, with FirstEnergy
Solutions Corp., as Borrower. (incorporated by reference to FE’s Form
10-Q filed May 9, 2007, Exhibit 10-23, File N
o.
333-145140-01
)
|
|
10-40
|
Guaranty, dated as of
March 26, 2007, by FirstEnergy Generation Corp. on behalf of
FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A
filed August 20, 2007, Exhibit 10.39, File N
o.
333-145140-01
)
|
|
10-41
|
Guaranty, dated as of
March 26, 2007, by FirstEnergy Solutions Corp. on behalf of
FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A
filed August 20, 2007, Exhibit 10.40, File N
o.
333-145140-01
)
|
|
10-42
|
Guaranty, dated as of
March 26, 2007, by FirstEnergy Solutions Corp. on behalf of
FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’
Form S-4/A filed August 20, 2007, Exhibit 10.41, File N
o.
333-145140-01
)
|
|
10-43
|
Guaranty, dated as of
March 26, 2007, by FirstEnergy Nuclear Generation Corp. on
behalf of FirstEnergy Solutions Corp. (incorporated by reference to FES’
Form S-4/A filed August 20, 2007, Exhibit 10.42, File N
o.
333-145140-01
)
|
|
(B)
10-44
|
Form
of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy
Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as
Administrative Agent for the Banks. (incorporated by reference to FE’s
Form 10-K filed March 3, 2006, Exhibit 10-58
, File No.
333-21011
)
|
|
(B)
10-45
|
Form
of Trust Indenture dated as of December 1, 2005 between Ohio Water
Development Authority and JP Morgan Trust Company related to issuance of
FirstEnergy Nuclear Generation Corp. pollution control revenue refunding
bonds. (incorporated by reference to FE’s Form 10-K filed March 3, 2006,
Exhibit 10-59
,
File No. 333-21011
)
|
|
10-46
|
GENCO Power Supply
Agreement dated as of October 14, 2005 between FirstEnergy Generation
Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer).
(
incorporated by reference to FE’s Form 10-K filed March 3,
2006
, Exhibit
10-60, File No. 333-21011)
|
|
10-47
|
Nuclear
Power Supply Agreement dated as of October 14, 2005 between FirstEnergy
Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer).
(incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit
10-61
, File No.
333-21011
)
|
|
(B)
10-48
|
Form
of Letter of Credit and Reimbursement Agreement Dated as of December 16,
2005 among FirstEnergy Nuclear Generation Corp., and the Participating
Banks and Barclays Bank PLC. (incorporated by reference to FE’s Form 10-K
filed March 3, 2006, Exhibit 10-62
, File No.
333-21011
)
|
|
(B)
10-49
|
Form
of Waste Water Facilities and Solid Waste Facilities Loan Agreement
between Ohio Water Development Authority and FirstEnergy Nuclear
Generation Corp., dated as of December 1, 2005. (incorporated by reference
to FE’s Form 10-K filed March 3, 2006, Exhibit 10-63
, File No.
333-21011
)
|
265
|
10-50
|
Nuclear
Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between
Ohio Edison Company and the Toledo Edison Company (Sellers) and
FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference
to FE’s Form 10-K filed March 3, 2006, Exhibit 10-64
, File No.
333-21011
)
|
|
10-51
|
Mansfield
Power Supply Agreement dated as of October 14, 2005 between Cleveland
Electric Illuminating Company and The Toledo Edison Company (Sellers) and
FirstEnergy Generation Corp. (Buyer). (incorporated by reference to FE’s
Form 10-K filed March 3, 2006, Exhibit 10-65
, File No.
333-21011
)
|
|
10-52
|
Power
Supply Agreement dated as of October 31, 2005 between FirstEnergy
Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio
Edison Company, The Cleveland Electric Illuminating Company, and The
Toledo Edison Company (Buyers). (incorporated by reference to FE’s Form
10-K filed March 3, 2006, Exhibit 10-66
, File No.
333-21011
)
|
|
10-53
|
Electric
Power Supply Agreement dated as of October 3, 2005 between FirstEnergy
Solutions Corp. (Seller) and Pennsylvania Power Company
(Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006,
Exhibit 10-67
,
File No. 333-21011
)
|
|
(C)
10-54
|
Form
of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006
among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank
PLC, as administrative agent and fronting bank, and KeyBank National
Association, as syndication agent. (incorporated by reference to FE’s Form
10-Q filed May 9, 2006, Exhibit 10-2
, File No.
333-21011
)
|
|
(C)
10-54(a)
|
Form
of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated
as of June 12, 2009, by and among FirstEnergy Generation Corp.,
FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the
banks party thereto, Barclays Bank PLC, as fronting Bank and
administrative agent and KeyBank National Association, as syndication
agent, to Letter of Credit and Reimbursement Agreement dated as of April
3, 2006 (incorporated by reference to FES’ Form 8-K filed June 19, 2009,
Exhibit 10.2, File No. 333-145140-01)
|
|
(C)
10-55
|
Form
of Trust Indenture dated as of April 1, 2006 between the Ohio Water
Development Authority and The Bank of New York Trust Company, N.A. as
Trustee securing pollution control revenue refunding bonds issued on
behalf of FirstEnergy Generation Corp. (incorporated by reference to FE’s
Form 10-Q filed May 9, 2006, Exhibit 10-3
, File No.
333-21011
)
|
|
(C)
10-56
|
Form
of Waste Water Facilities Loan Agreement between the Ohio Water
Development Authority and FirstEnergy Generation Corp. dated as of April
1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006,
Exhibit 10-4
,
File No. 333-21011
)
|
|
(D)
10-57
|
Form
of Trust Indenture dated as of December 1, 2006 between the Ohio Water
Development Authority and The Bank of New York Trust Company, N.A. as
Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds
(FirstEnergy Nuclear Generation Corp. Project). (incorporated by reference
to FE’s Form 10-K filed February 28, 2007, Exhibit 10-77
, File No.
333-21011
)
|
|
(D)
10-58
|
Form
of Waste Water Facilities and Solid Waste Facilities Loan Agreement
between the Ohio Water Development Authority and FirstEnergy Nuclear
Generation Corp. dated as of December 1, 2006. (incorporated by
reference to FE’s Form 10-K filed February 28, 2007, Exhibit 10-80
, File No.
333-21011
)
|
|
10-59
|
Consent Decree dated
March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March
18, 2005, Exhibit 10.1, File No. 333-21011)
|
|
10-61
|
Amendment
to Agreement for Engineering, Procurement and Construction of Air Quality
Control Systems by and between FirstEnergy Generation Corp. and Bechtel
Power Corporation dated September 14, 2007. (
incorporated by
reference to FE’s
Form 10-Q filed October 31, 2007, Exhibit
10.1
, File No.
333-21011
)
|
|
10-61
|
Asset
Purchase Agreement by and between Calpine Corporation, as Seller, and
FirstEnergy Generation Corp., as Buyer, dated as of January 28, 2008.
(
incorporated by
reference to FE’s
Form 10-K filed February 29, 2008, Exhibit
10-48
, File No.
333-21011
)
|
266
|
10-62
|
U.S.
$300,000,000 Credit Agreement, dated as of October 8, 2008, among
FirstEnergy Generation Corp., as Borrower, FirstEnergy Corp. and
FirstEnergy Solutions Corp., as Guarantors, Credit Suisse and the other
Banks parties thereto from time to time, as Banks and Credit Suisse, as
Administrative Agent. (
incorporated by
reference to FE’s
Form 10-Q filed November 7, 2008, Exhibit
10.1
, File No.
333-21011
)
|
|
10-63
|
Master
SSO Supply Agreement, entered into May 18, 2009, by and between The
Cleveland Electric Illuminating Company, the Toledo Edison Company and
Ohio Edison Company and FirstEnergy Solutions Corp. (
incorporated by
reference to FE’s
Form 10-Q filed August 3, 2009, Exhibit 10.2
, File No.
333-21011
)
|
|
10-64
|
Surplus
Margin Guaranty, dated as of June 16, 2009, made by FirstEnergy Nuclear
Generation Corp. in favor of The Cleveland Electric Illuminating Company,
The Toledo Edison Company and Ohio Edison Company (incorporated by
reference to FES’ Form 8-K filed June 19, 2009, Exhibit 10.3, File No.
333-145140-01)
|
|
10-65
|
Registration
Rights Agreement, dated August 7, 2009, among FirstEnergy Solutions Corp.,
and Morgan Stanley & Co. Incorporated, Barclays Capital Inc., Credit
Suisse Securities (USA) LLC and RBS Securities Inc., as representatives of
the initial purchasers (incorporated by reference to FES' Form 8-K filed
August 7, 2009, Exhibit 10.1, File No. 000-53742)
|
|
(A)
12-2
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
herein in electronic format as an exhibit.
|
|
(B)
|
Four
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to four other series of pollution control revenue refunding bonds issued
by the Ohio Water Development Authority, the Ohio Air Quality Authority
and Beaver County Industrial Development Authority, Pennsylvania, relating
to pollution control notes of FirstEnergy Nuclear Generation
Corp.
|
|
(C)
|
Three
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to three other series of pollution control revenue refunding bonds issued
by the Ohio Water Development Authority and the Beaver County Industrial
Development Authority relating to pollution control notes of FirstEnergy
Generation Corp. and FirstEnergy Nuclear Generation
Corp.
|
|
(D)
|
Seven
substantially similar agreements, each dated as of the same date, were
executed and delivered by the registrant and its affiliates with respect
to one other series of pollution control revenue refunding bonds issued by
the Ohio Water Development Authority, three other series of pollution
control bonds issued by the Ohio Air Quality Development Authority and the
three other series of pollution control bonds issued by the Beaver County
Industrial Development Authority, relating to pollution control notes of
FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation
Corp.
|
3.
Exhibits – OE
|
2-1
|
Agreement
and Plan of Merger, dated as of September 13, 1996, between Ohio
Edison Company and Centerior Energy Corporation. (incorporated by
reference to OE’s Form 8–K filed September 17, 1996,
Exhibit 2–1, File No.
001-02578)
|
267
|
3-1
|
Amended
and Restated Articles of Incorporation of Ohio Edison Company, Effective
December 18, 2007. (
incorporated by
reference to
OE’s Form 10-K filed February 29, 2008, Exhibit
3-4
,
File
No. 001-02578)
|
|
3-2
|
Amended
and Restated Code of Regulations of Ohio Edison Company, dated
December 14, 2007. (
incorporated by
reference to
OE’s Form 10-K filed February 29, 2008, Exhibit
3-5
,
File
No. 001-02578)
|
|
4-1
|
General
Mortgage Indenture and Deed of Trust dated as of January 1, 1998
between Ohio Edison Company and the Bank of New York, as Trustee, as
amended and supplemented by Supplemental Indentures: (incorporated by
reference to OE’s Form S-3 filed June 5, 1996, Exhibit 4(b), File
No. 333-05277)
|
|
4-1(a)
|
February
1, 2003 (incorporated by reference to OE’s Form10-K filed March 15, 2004,
Exhibit 4-4, File No. 001-02578)
|
|
4-1(b)
|
March
1, 2003 (incorporated by reference to OE’s Form10-K filed March 15, 2004,
Exhibit 4-5
,
File No.
001-02578)
|
|
4-1(c)
|
August
1, 2003 (incorporated by reference to OE’s Form10-K filed March 15, 2004,
Exhibit 4-6, File No. 001-02578)
|
|
4-1(d)
|
June 1, 2004 (
incorporated
by reference to OE’s Form10-K filed March 10, 2005, Exhibit 4-4, File No.
001-02578)
|
|
4-1(e)
|
December
1, 2004 (incorporated by reference to OE’s Form10-K filed March 10, 2005,
Exhibit 4-4, File No. 001-02578)
|
|
4-1(f)
|
April
1, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005,
Exhibit 4-4
,
File No.
001-02578)
|
|
4-1(g)
|
April
15, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1,
2005, Exhibit 4-5
,
File No.
001-02578)
|
|
4-1(h)
|
June
1, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005,
Exhibit 4-6
,
File No.
001-02578)
|
|
4-1(i)
|
October
1, 2008 (incorporated by reference to OE’s Form 8-K filed October 22,
2008, Exhibit 4.1
, File No.
001-02578)
|
|
4-2
|
Indenture
dated as of April 1, 2003 between Ohio Edison Company and The Bank of New
York, as Trustee. (incorporated by reference to OE’s Form10-K filed March
15, 2004, Exhibit 4-3
,
File No.
001-02578)
|
|
4-2(a)
|
Officer’s
Certificate (including the forms of the 6.40% Senior Notes due 2016 and
the 6.875% Senior Notes due 2036), dated June 21, 2006. (incorporated
by reference to OE’s Form 8-K filed June 27, 2006, Exhibit 4, File No.
001-02578)
|
|
10-1
|
Amendment
No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as of
October 1, 1973, as amended, by the CAPCO Companies to National City
Bank as Bond Trustee. (incorporated by reference to 1985 Form 10-K,
Exhibit 10-30)
|
|
10-2
|
Amendment
No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO
Companies to National City Bank as Bond Trustee. (incorporated by
reference to 1986 Form 10-K, Exhibit 10-33)
|
|
10-3
|
Amendment
No. 6A dated as of December 1, 1991, to the Bond Guaranty dated
as of October 1, 1973, by The Cleveland Electric Illuminating
Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power
Company, The Toledo Edison Company to National City Bank, as Bond Trustee.
(incorporated by reference to 1991 Form 10-K,
Exhibit 10-33)
|
|
10-4
|
Amendment
No. 6B dated as of December 30, 1991, to the Bond Guaranty dated
as of October 1, 1973 by The Cleveland Electric Illuminating Company,
Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company,
The Toledo Edison Company to National City Bank, as Bond Trustee.
(incorporated by reference to 1991 Form 10-K,
Exhibit 10-34)
|
|
(B)
10-5
|
Ohio
Edison System Executive Supplemental Life Insurance Plan. (incorporated by
reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-44,
File No. 001-02578)
|
268
|
(B)
10-6
|
Ohio
Edison System Executive Incentive Compensation
Plan. (incorporated by reference to OE’s Form 10-K filed
March 19, 1996, Exhibit 10-45, File No. 001-02578)
|
|
(B)
10-7
|
Ohio
Edison System Restated and Amended Supplemental Executive Retirement Plan.
(incorporated by reference to OE’s Form 10-K filed March 19, 1996,
Exhibit 10-47, File No. 001-02578)
|
|
(B)
10-8
|
Form
of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for
Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for
Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors
of GPU, Inc. (incorporated by reference to OE’s Form 10-K filed April 1,
2002, Exhibit 10-26, File No. 001-02578)
|
|
(B)
10-9
|
GPU,
Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees.
(incorporated by reference to OE’s Form 10-K filed April 1, 2002, Exhibit
10-27, File No. 001-02578))
|
|
(B)
10-10
|
Severance
pay agreement between Ohio Edison Company and A. J. Alexander.
(incorporated by reference to OE’s Form 10-K filed March 19, 1996,
Exhibit 10-50, File No. 001-02578)
|
|
(C)
10-11
|
Participation
Agreement dated as of March 16, 1987 among Perry One Alpha Limited
Partnership, as Owner Participant, the Original Loan Participants listed
in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding
Corporation, as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-1)
|
|
(C)
10-12
|
Amendment
No. 1 dated as of September 1, 1987 to Participation Agreement
dated as of March 16, 1987 among Perry One Alpha Limited Partnership,
as Owner Participant, the Original Loan Participants listed in
Schedule 1 thereto, as Original Loan Participants, PNPP Funding
Corporation, as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company (now The Bank of New York), as
Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-46)
|
|
(C)
10-13
|
Amendment
No. 3 dated as of May 16, 1988 to Participation Agreement dated
as of March 16, 1987, as amended among Perry One Alpha Limited
Partnership, as Owner Participant, PNPP Funding Corporation, The First
National Bank of Boston, as Owner Trustee, Irving Trust Company, as
Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-47)
|
|
(C)
10-14
|
Amendment
No. 4 dated as of November 1, 1991 to Participation Agreement
dated as of March 16, 1987 among Perry One Alpha Limited Partnership,
as Owner Participant, PNPP Funding Corporation, as Funding Corporation,
PNPP II Funding Corporation, as New Funding Corporation, The First
National Bank of Boston, as Owner Trustee, The Bank of New York, as
Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-47)
|
|
(C)
10-15
|
Amendment
No. 5 dated as of November 24, 1992 to Participation Agreement
dated as of March 16, 1987, as amended, among Perry One Alpha Limited
Partnership, as Owner Participant, PNPP Funding Corporation, as Funding
Corporation, PNPP II Funding Corporation, as New Funding Corporation,
The First National Bank of Boston, as Owner Trustee, The Bank of New York,
as Indenture Trustee and Ohio Edison Company as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-49)
|
|
(C)
10-16
|
Amendment
No. 6 dated as of January 12, 1993 to Participation Agreement
dated as of March 16, 1987 among Perry One Alpha Limited Partnership,
as Owner Participant, PNPP Funding Corporation, as Funding Corporation,
PNPP II Funding Corporation, as New Funding Corporation, The First
National Bank of Boston, as Owner Trustee, The Bank of New York, as
Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit
10-50)
|
269
|
(C)
10-17
|
Amendment
No. 7 dated as of October 12, 1994 to Participation Agreement
dated as of March 16, 1987 as amended, among Perry One Alpha Limited
Partnership, as Owner Participant, PNPP Funding Corporation, as Funding
Corporation, PNPP II Funding Corporation, as New Funding Corporation,
The First National Bank of Boston, as Owner Trustee, The Bank of New York,
as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-54, File No. 001-02578))
|
|
(C)
10-18
|
Facility
Lease dated as of March 16, 1987 between The First National Bank of
Boston, as Owner Trustee, with Perry One Alpha Limited Partnership,
Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to
1986 Form 10-K, Exhibit 28-2)
|
|
(C)
10-19
|
Amendment
No. 1 dated as of September 1, 1987 to Facility Lease dated as
of March 16, 1997 between The First National Bank of Boston, as Owner
Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-49)
|
|
(C)
10-20
|
Amendment
No. 2 dated as of November 1, 1991, to Facility Lease dated as
of March 16, 1987, between The First National Bank of Boston, as
Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-50)
|
|
(C)
10-21
|
Amendment
No. 3 dated as of November 24, 1992 to Facility Lease dated as
March 16, 1987 as amended, between The First National Bank of Boston,
as Owner Trustee, with Perry One Alpha Limited partnership, as Owner
Participant and Ohio Edison Company, as Lessee. (incorporated by reference
to 1992 Form 10-K, Exhibit 10-54)
|
|
(C)
10-22
|
Amendment
No. 4 dated as of January 12, 1993 to Facility Lease dated as of
March 16, 1987 as amended, between, The First National Bank of
Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as
Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-59, File No. 001-02578))
|
|
(C)
10-23
|
Amendment
No. 5 dated as of October 12, 1994 to Facility Lease dated as of
March 16, 1987 as amended, between, The First National Bank of
Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as
Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995, Exhibit
10-60, File No. 001-02578)
|
|
(C)
10-24
|
Letter
Agreement dated as of March 19, 1987 between Ohio Edison Company,
Lessee, and The First National Bank of Boston, Owner Trustee under a Trust
dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation,
required by Section 3(d) of the Facility Lease. (incorporated by reference
to 1986 Form 10-K, Exhibit 28-3)
|
|
(C)
10-25
|
Ground
Lease dated as of March 16, 1987 between Ohio Edison Company, Ground
Lessor, and The First National Bank of Boston, as Owner Trustee under a
Trust Agreement, dated as of March 16, 1987, with the Owner
Participant, Tenant. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-4)
|
|
(C)
10-26
|
Trust
Agreement dated as of March 16, 1987 between Perry One Alpha Limited
Partnership, as Owner Participant, and The First National Bank of Boston.
(incorporated by reference to 1986 Form 10-K,
Exhibit 28-5)
|
|
(C)
10-27
|
Trust
Indenture, Mortgage, Security Agreement and Assignment of Facility Lease
dated as of March 16, 1987 between The First National Bank of Boston,
as Owner Trustee under a Trust Agreement dated as of March 16, 1987
with Perry One Alpha Limited Partnership, and Irving Trust Company, as
Indenture Trustee. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-6)
|
|
(C)
10-28
|
Supplemental
Indenture No. 1 dated as of September 1, 1987 to Trust
Indenture, Mortgage, Security Agreement and Assignment of Facility Lease
dated as of March 16, 1987 between The First National Bank of Boston
as Owner Trustee and Irving Trust Company (now The Bank of New York), as
Indenture Trustee. (incorporated by reference to 1991 Form 10-K,
Exhibit 10-55)
|
|
(C)
10-29
|
Supplemental
Indenture No. 2 dated as of November 1, 1991 to Trust Indenture,
Mortgage, Security Agreement and Assignment of Facility Lease dated as of
March 16, 1987 between The First National Bank of Boston, as Owner
Trustee and The Bank of New York, as Indenture Trustee. (incorporated by
reference to 1991 Form 10-K, Exhibit
10-56)
|
270
|
(C)
10-30
|
Tax
Indemnification Agreement dated as of March 16, 1987 between Perry
One, Inc. and PARock Limited Partnership as General Partners and Ohio
Edison Company, as Lessee. (incorporated by reference to 1986
Form 10-K, Exhibit 28-7)
|
|
(C)
10-31
|
Amendment
No. 1 dated as of November 1, 1991 to Tax Indemnification
Agreement dated as of March 16, 1987 between Perry One, Inc. and
PARock Limited Partnership and Ohio Edison Company. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-58)
|
|
(C)
10-32
|
Amendment
No. 2 dated as of January 12, 1993 to Tax Indemnification
Agreement dated as of March 16, 1987 between Perry One, Inc. and
PARock Limited Partnership and Ohio Edison Company. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-69, File No. 001-02578)
|
|
(C)
10-33
|
Amendment
No. 3 dated as of October 12, 1994 to Tax Indemnification
Agreement dated as of March 16, 1987 between Perry One, Inc. and
PARock Limited Partnership and Ohio Edison Company. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-70, File No. 001-02578)
|
|
(C)
10-34
|
Partial
Mortgage Release dated as of March 19, 1987 under the Indenture
between Ohio Edison Company and Bankers Trust Company, as Trustee, dated
as of the 1st day of August 1930. (incorporated by reference to 1986
Form 10-K, Exhibit 28-8)
|
|
(C)
10-35
|
Assignment,
Assumption and Further Agreement dated as of March 16, 1987 among The
First National Bank of Boston, as Owner Trustee under a Trust Agreement,
dated as of March 16, 1987, with Perry One Alpha Limited Partnership,
The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio
Edison Company, Pennsylvania Power Company and Toledo Edison Company.
(incorporated by reference to 1986 Form 10-K,
Exhibit 28-9)
|
|
(C)
10-36
|
Additional
Support Agreement dated as of March 16, 1987 between The First
National Bank of Boston, as Owner Trustee under a Trust Agreement, dated
as of March 16, 1987, with Perry One Alpha Limited Partnership, and
Ohio Edison Company. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-10)
|
|
(C)
10-37
|
Bill
of Sale, Instrument of Transfer and Severance Agreement dated as of
March 19, 1987 between Ohio Edison Company, Seller, and The First
National Bank of Boston, as Owner Trustee under a Trust Agreement, dated
as of March 16, 1987, with Perry One Alpha Limited Partnership.
(incorporated by reference to 1986 Form 10-K,
Exhibit 28-11)
|
|
(C)
10-38
|
Easement
dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The
First National Bank of Boston, as Owner Trustee under a Trust Agreement,
dated as of March 16, 1987, with Perry One Alpha Limited Partnership,
Grantee. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-12)
|
|
10-39
|
Participation
Agreement dated as of March 16, 1987 among Security Pacific Capital
Leasing Corporation, as Owner Participant, the Original Loan Participants
listed in Schedule 1 Hereto, as Original Loan Participants, PNPP
Funding Corporation, as Funding Corporation, The First National Bank of
Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and
Ohio Edison Company, as Lessee. (incorporated by reference to 1986
Form 10-K, Exhibit 28-13)
|
|
10-40
|
Amendment
No. 1 dated as of September 1, 1987 to Participation Agreement
dated as of March 16, 1987 among Security Pacific Capital Leasing
Corporation, as Owner Participant, The Original Loan Participants Listed
in Schedule 1 thereto, as Original Loan Participants, PNPP Funding
Corporation, as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1991 Form 10-K,
Exhibit 10-65)
|
271
|
10-41
|
Amendment
No. 4 dated as of November 1, 1991, to Participation Agreement
dated as of March 16, 1987 among Security Pacific Capital Leasing
Corporation, as Owner Participant, PNPP Funding Corporation, as Funding
Corporation, PNPP II Funding Corporation, as New Funding Corporation,
The First National Bank of Boston, as Owner Trustee, The Bank of New York,
as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-66)
|
|
10-42
|
Amendment
No. 5 dated as of November 24, 1992 to Participation Agreement
dated as of March 16, 1987 as amended among Security Pacific Capital
Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as
Funding Corporation, PNPP II Funding Corporation, as New Funding
Corporation, The First National Bank of Boston, as Owner Trustee, The Bank
of New York, as Indenture Trustee and Ohio Edison Company, as Lessee.
(incorporated by reference to 1992 Form 10-K,
Exhibit 10-71)
|
|
10-43
|
Amendment
No. 6 dated as of January 12, 1993 to Participation Agreement
dated as of March 16, 1987 as amended among Security Pacific Capital
Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as
Funding Corporation, PNPP II Funding Corporation, as New Funding
Corporation, The First National Bank of Boston, as Owner Trustee, The Bank
of New York, as Indenture Trustee and Ohio Edison Company, as Lessee.
(incorporated by reference to OE’s Form 10-K filed March 21,
1995, Exhibit 10-80, File No. 001-02578)
|
|
10-44
|
Amendment
No. 7 dated as of October 12, 1994 to Participation Agreement
dated as of March 16, 1987 as amended among Security Pacific Capital
Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as
Funding Corporation, PNPP II Funding Corporation, as New Funding
Corporation, The First National Bank of Boston, as Owner Trustee, The Bank
of New York, as Indenture Trustee and Ohio Edison Company, as Lessee.
(incorporated by reference to OE’s Form 10-K filed March 21,
1995, File No. 001-02578)
|
|
10-45
|
Facility
Lease dated as of March 16, 1987 between The First National Bank of
Boston, as Owner Trustee, with Security Pacific Capital Leasing
Corporation, Lessor, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1986 Form 10-K, Exhibit 28-14)
|
|
10-46
|
Amendment
No. 1 dated as of September 1, 1987 to Facility Lease dated as
of March 16, 1987 between The First National Bank of Boston as Owner
Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-68)
|
|
10-47
|
Amendment
No. 2 dated as of November 1, 1991 to Facility Lease dated as of
March 16, 1987 between The First National Bank of Boston as Owner
Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-69)
|
|
10-48
|
Amendment
No. 3 dated as of November 24, 1992 to Facility Lease dated as
of March 16, 1987, as amended, between, The First National Bank of
Boston, as Owner Trustee, with Security Pacific Capital Leasing
Corporation, as Owner Participant and Ohio Edison Company, as Lessee.
(incorporated by reference to 1992 Form 10-K,
Exhibit 10-75)
|
|
10-49
|
Amendment
No. 4 dated as of January 12, 1993 to Facility Lease dated as of
March 16, 1987 as amended between, The First National Bank of Boston,
as Owner Trustee, with Security Pacific Capital Leasing Corporation, as
Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-76)
|
|
10-50
|
Amendment
No. 5 dated as of October 12, 1994 to Facility Lease dated as of
March 16, 1987 as amended between, The First National Bank of Boston,
as Owner Trustee, with Security Pacific Capital Leasing Corporation, as
Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-87, File No. 001-02578)
|
|
10-51
|
Letter
Agreement dated as of March 19, 1987 between Ohio Edison Company, as
Lessee, and The First National Bank of Boston, as Owner Trustee under a
Trust, dated as of March 16, 1987, with Security Pacific Capital
Leasing Corporation, required by Section 3(d) of the Facility Lease.
(incorporated by reference to 1986 Form 10-K,
Exhibit 28-15)
|
272
|
10-52
|
Ground
Lease dated as of March 16, 1987 between Ohio Edison Company, Ground
Lessor, and The First National Bank of Boston, as Owner Trustee under a
Trust Agreement, dated as of March 16, 1987, with Perry One Alpha
Limited Partnership, Tenant. (incorporated by reference to 1986
Form 10-K, Exhibit 28-16)
|
|
10-53
|
Trust
Agreement dated as of March 16, 1987 between Security Pacific Capital
Leasing Corporation, as Owner Participant, and The First National Bank of
Boston. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-17)
|
|
10-54
|
Trust
Indenture, Mortgage, Security Agreement and Assignment of Facility Lease
dated as of March 16, 1987 between The First National Bank of Boston,
as Owner Trustee under a Trust Agreement, dated as of March 16, 1987,
with Security Pacific Capital Leasing Corporation, and Irving Trust
Company, as Indenture Trustee. (incorporated by reference to 1986
Form 10-K, Exhibit 28-18)
|
|
10-55
|
Supplemental
Indenture No. 1 dated as of September 1, 1987 to Trust
Indenture, Mortgage, Security Agreement and Assignment of Facility Lease
dated as of March 16, 1987 between The First National Bank of Boston,
as Owner Trustee and Irving Trust Company (now The Bank of New York), as
Indenture Trustee. (incorporated by reference to 1991 Form 10-K,
Exhibit 10-74)
|
|
10-56
|
Supplemental
Indenture No. 2 dated as of November 1, 1991 to Trust Indenture,
Mortgage, Security Agreement and Assignment of Facility Lease dated as of
March 16, 1987 between The First National Bank of Boston, as Owner
Trustee and The Bank of New York, as Indenture Trustee. (incorporated by
reference to 1991 Form 10-K, Exhibit 10-75)
|
|
10-57
|
Tax
Indemnification Agreement dated as of March 16, 1987 between Security
Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison
Company, as Lessee. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-19)
|
|
10-58
|
Amendment
No. 1 dated as of November 1, 1991 to Tax Indemnification
Agreement dated as of March 16, 1987 between Security Pacific Capital
Leasing Corporation and Ohio Edison Company. (incorporated by reference to
1991 Form 10-K, Exhibit 10-77)
|
|
10-59
|
Amendment
No. 2 dated as of January 12, 1993 to Tax Indemnification
Agreement dated as of March 16, 1987 between Security Pacific Capital
Leasing Corporation and Ohio Edison Company. (incorporated by reference to
OE’s Form 10-K filed March 21, 1995, Exhibit 10-96, File
No. 001-02578)
|
|
10-60
|
Amendment
No. 3 dated as of October 12, 1994 to Tax Indemnification
Agreement dated as of March 16, 1987 between Security Pacific Capital
Leasing Corporation and Ohio Edison Company. (incorporated by reference to
OE’s Form 10-K filed March 21, 1995, Exhibit 10-97, File
No. 001-02578)
|
|
10-61
|
Assignment,
Assumption and Further Agreement dated as of March 16, 1987 among The
First National Bank of Boston, as Owner Trustee under a Trust Agreement,
dated as of March 16, 1987, with Security Pacific Capital Leasing
Corporation, The Cleveland Electric Illuminating Company, Duquesne Light
Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison
Company. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-20)
|
|
10-62
|
Additional
Support Agreement dated as of March 16, 1987 between The First
National Bank of Boston, as Owner Trustee under a Trust Agreement, dated
as of March 16, 1987, with Security Pacific Capital Leasing
Corporation, and Ohio Edison Company. (incorporated by reference to 1986
Form 10-K, Exhibit 28-21)
|
|
10-63
|
Bill
of Sale, Instrument of Transfer and Severance Agreement dated as of
March 19, 1987 between Ohio Edison Company, Seller, and The First
National Bank of Boston, as Owner Trustee under a Trust Agreement, dated
as of March 16, 1987, with Security Pacific Capital Leasing
Corporation, Buyer. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-22)
|
|
10-64
|
Easement
dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The
First National Bank of Boston, as Owner Trustee under a Trust Agreement,
dated as of March 16, 1987, with Security Pacific Capital Leasing
Corporation, Grantee. (incorporated by reference to 1986 Form 10-K,
Exhibit 28-23)
|
273
|
10-65
|
Refinancing
Agreement dated as of November 1, 1991 among Perry One Alpha Limited
Partnership, as Owner Participant, PNPP Funding Corporation, as Funding
Corporation, PNPP II Funding Corporation, as New Funding Corporation,
The First National Bank of Boston, as Owner Trustee, The Bank of New York,
as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee,
The Bank of New York, as New Collateral Trust Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1991 Form 10-K,
Exhibit 10-82)
|
|
10-66
|
Refinancing
Agreement dated as of November 1, 1991 among Security Pacific Leasing
Corporation, as Owner Participant, PNPP Funding Corporation, as Funding
Corporation, PNPP II Funding Corporation, as New Funding Corporation,
The First National Bank of Boston, as Owner Trustee, The Bank of New York,
as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee,
The Bank of New York as New Collateral Trust Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1991 Form 10-K,
Exhibit 10-83)
|
|
10-67
|
Ohio
Edison Company Master Decommissioning Trust Agreement for Perry Nuclear
Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley
Power Station Unit One and Beaver Valley Power Station Unit Two dated
July 1, 1993. (1993 Form 10-K,
Exhibit 10-94)
|
|
(D)
10-68
|
Participation
Agreement dated as of September 15, 1987, among Beaver Valley Two Pi
Limited Partnership, as Owner Participant, the Original Loan Participants
listed in Schedule 1 Thereto, as Original Loan Participants, BVPS
Funding Corporation, as Funding Corporation, The First National Bank of
Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and
Ohio Edison Company as Lessee. (incorporated by reference to 1987
Form 10-K, Exhibit 28-1)
|
|
(D)
10-69
|
Amendment
No. 1 dated as of February 1, 1988, to Participation Agreement
dated as of September 15, 1987, among Beaver Valley Two Pi Limited
Partnership, as Owner Participant, the Original Loan Participants listed
in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding
Corporation, as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-2)
|
|
(D)
10-70
|
Amendment
No. 3 dated as of March 16, 1988 to Participation Agreement
dated as of September 15, 1987, as amended, among Beaver Valley Two
Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation,
The First National Bank of Boston, as Owner Trustee, Irving Trust Company,
as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-99)
|
|
(D)
10-71
|
Amendment
No. 4 dated as of November 5, 1992 to Participation Agreement
dated as of September 15, 1987, as amended, among Beaver Valley Two
Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation,
BVPS II Funding Corporation, The First National Bank of Boston, as
Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1992 Form 10-K,
Exhibit 10-100)
|
|
(D)
10-72
|
Amendment
No. 5 dated as of September 30, 1994 to Participation Agreement
dated as of September 15, 1987, as amended, among Beaver Valley Two
Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation,
BVPS II Funding Corporation, The First National Bank of Boston, as
Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to OE’s Form 10-K
filed March 21, 1995, Exhibit 10-118, File No.
001-02578)
|
|
(D)
10-73
|
Facility
Lease dated as of September 15, 1987, between The First National Bank
of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited
Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by
reference to 1987 Form 10-K, Exhibit 28-3)
|
|
(D)
10-74
|
Amendment
No. 1 dated as of February 1, 1988, to Facility Lease dated as
of September 15, 1987, between The First National Bank of Boston, as
Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and
Ohio Edison Company, Lessee. (incorporated by reference to 1987
Form 10-K,
Exhibit 28-4)
|
274
|
(D)
10-75
|
Amendment
No. 2 dated as of November 5, 1992, to Facility Lease dated as
of September 15, 1987, as amended, between The First National Bank of
Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership,
as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-103)
|
|
(D)
10-76
|
Amendment
No. 3 dated as of September 30, 1994 to Facility Lease dated as
of September 15, 1987, as amended, between The First National Bank of
Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership,
as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-122, File No. 001-02578)
|
|
(D)
10-77
|
Ground
Lease and Easement Agreement dated as of September 15, 1987, between
Ohio Edison Company, Ground Lessor, and The First National Bank of Boston,
as Owner Trustee under a Trust Agreement, dated as of September 15,
1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (incorporated
by reference to 1987 Form 10-K, Exhibit 28-5)
|
|
(D)
10-78
|
Trust
Agreement dated as of September 15, 1987, between Beaver Valley Two
Pi Limited Partnership, as Owner Participant, and The First National Bank
of Boston. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-6)
|
|
(D)
10-79
|
Trust
Indenture, Mortgage, Security Agreement and Assignment of Facility Lease
dated as of September 15, 1987, between The First National Bank of
Boston, as Owner Trustee under a Trust Agreement dated as of
September 15, 1987, with Beaver Valley Two Pi Limited Partnership,
and Irving Trust Company, as Indenture Trustee. (incorporated by reference
to 1987 Form 10-K, Exhibit 28-7)
|
|
(D)
10-80
|
Supplemental
Indenture No. 1 dated as of February 1, 1988 to Trust Indenture,
Mortgage, Security Agreement and Assignment of Facility Lease dated as of
September 15, 1987 between The First National Bank of Boston, as
Owner Trustee under a Trust Agreement dated as of September 15, 1987
with Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as
Indenture Trustee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-8)
|
|
(D)
10-81
|
Tax
Indemnification Agreement dated as of September 15, 1987, between
Beaver Valley Two Pi Inc. and PARock Limited Partnership as General
Partners and Ohio Edison Company, as Lessee. (incorporated by reference to
1987 Form 10-K, Exhibit 28-9)
|
|
(D)
10-82
|
Amendment
No. 1 dated as of November 5, 1992 to Tax Indemnification
Agreement dated as of September 15, 1987, between Beaver Valley Two
Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison
Company, as Lessee. (incorporated by reference to OE’s Form 10-K
filed March 21, 1995, Exhibit 10-128, File No.
001-02578)
|
|
(D)
10-83
|
Amendment
No. 2 dated as of September 30, 1994 to Tax Indemnification
Agreement dated as of September 15, 1987, between Beaver Valley Two
Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison
Company, as Lessee. (incorporated by reference to OE’s Form 10-K
filed March 21, 1995, Exhibit 10-129, File No.
001-02578)
|
|
(D)
10-84
|
Tax
Indemnification Agreement dated as of September 15, 1987, between HG
Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee.
(1987 Form 10-K, Exhibit 28-10)
|
|
(D)
10-85
|
Amendment
No. 1 dated as of November 5, 1992 to Tax Indemnification
Agreement dated as of September 15, 1987, between HG Power Plant,
Inc., as Limited Partner and Ohio Edison Company, as Lessee. (incorporated
by reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-131, File No. 001-02578)
|
|
(D)
10-86
|
Amendment
No. 2 dated as of September 30, 1994 to Tax Indemnification
Agreement dated as of September 15, 1987, between HG Power Plant,
Inc., as Limited Partner and Ohio Edison Company, as Lessee. (incorporated
by reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-132, File No.
001-02578)
|
275
|
(D)
10-87
|
Assignment,
Assumption and Further Agreement dated as of September 15, 1987,
among The First National Bank of Boston, as Owner Trustee under a Trust
Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi
Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne
Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo
Edison Company. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-11)
|
|
(D)
10-88
|
Additional
Support Agreement dated as of September 15, 1987, between The First
National Bank of Boston, as Owner Trustee under a Trust Agreement, dated
as of September 15, 1987, with Beaver Valley Two Pi Limited
Partnership, and Ohio Edison Company. (incorporated by reference to 1987
Form 10-K, Exhibit 28-12)
|
|
(E)
10-89
|
Participation
Agreement dated as of September 15, 1987, among Chrysler Consortium
Corporation, as Owner Participant, the Original Loan Participants listed
in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding
Corporation as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison
Company, as Lessee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-13)
|
|
(E)
10-90
|
Amendment
No. 1 dated as of February 1, 1988, to Participation Agreement
dated as of September 15, 1987, among Chrysler Consortium
Corporation, as Owner Participant, the Original Loan Participants listed
in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding
Corporation, as Funding Corporation, The First National Bank of Boston, as
Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison
Company, as Lessee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-14)
|
|
(E)
10-91
|
Amendment
No. 3 dated as of March 16, 1988 to Participation Agreement
dated as of September 15, 1987, as amended, among Chrysler Consortium
Corporation, as Owner Participant, BVPS Funding Corporation, The First
National Bank of Boston, as Owner Trustee, Irving Trust Company, as
Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-114)
|
|
(E)
10-92
|
Amendment
No. 4 dated as of November 5, 1992 to Participation Agreement
dated as of September 15, 1987, as amended, among Chrysler Consortium
Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II
Funding Corporation, The First National Bank of Boston, as Owner Trustee,
The Bank of New York, as Indenture Trustee and Ohio Edison Company, as
Lessee. (incorporated by reference to 1992 Form 10-K,
Exhibit 10-115)
|
|
(E)
10-93
|
Amendment
No. 5 dated as of January 12, 1993 to Participation Agreement
dated as of September 15, 1987, as amended, among Chrysler Consortium
Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II
Funding Corporation, The First National Bank of Boston, as Owner Trustee,
The Bank of New York, as Indenture Trustee and Ohio Edison Company, as
Lessee. (incorporated by reference to OE’s Form 10-K filed March
21, 1995, Exhibit 10-139, File No. 001-02578)
|
|
(E)
10
-94
|
Amendment
No. 6 dated as of September 30, 1994 to Participation Agreement
dated as of September 15, 1987, as amended, among Chrysler Consortium
Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II
Funding Corporation, The First National Bank of Boston, as Owner Trustee,
The Bank of New York, as Indenture Trustee and Ohio Edison Company, as
Lessee. (incorporated by reference to OE’s Form 10-K filed March
21, 1995, Exhibit 10-140, File No. 001-02578)
|
|
(E)
10-95
|
Facility
Lease dated as of September 15, 1987, between The First National Bank
of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor,
and Ohio Edison Company, as Lessee. (incorporated by reference to 1987
Form 10-K, Exhibit 28-15)
|
|
(E)
10-96
|
Amendment
No. 1 dated as of February 1, 1988, to Facility Lease dated as
of September 15, 1987, between The First National Bank of Boston, as
Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio
Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-16)
|
276
|
(E)
10-97
|
Amendment
No. 2 dated as of November 5, 1992 to Facility Lease dated as of
September 15, 1987, as amended, between The First National Bank of
Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner
Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-118)
|
|
(E)
10-98
|
Amendment
No. 3 dated as of January 12, 1993 to Facility Lease dated as of
September 15, 1987, as amended, between The First National Bank of
Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner
Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to 1992 Form 10-K, Exhibit 10-119)
|
|
(E)
10-99
|
Amendment
No. 4 dated as of September 30, 1994 to Facility Lease dated as
of September 15, 1987, as amended, between The First National Bank of
Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner
Participant, and Ohio Edison Company, as Lessee. (incorporated by
reference to OE’s Form 10-K filed March 21, 1995,
Exhibit 10-145, File No. 001-02578)
|
|
(E)
10-100
|
Ground
Lease and Easement Agreement dated as of September 15, 1987, between
Ohio Edison Company, Ground Lessor, and The First National Bank of Boston,
as Owner Trustee under a Trust Agreement, dated as of September 15,
1987, with Chrysler Consortium Corporation, Tenant. (incorporated by
reference to 1987 Form 10-K, Exhibit 28-17)
|
|
(E)
10-101
|
Trust
Agreement dated as of September 15, 1987, between Chrysler Consortium
Corporation, as Owner Participant, and The First National Bank of Boston.
(incorporated by reference to 1987 Form 10-K,
Exhibit 28-18)
|
|
(E)
10-102
|
Trust
Indenture, Mortgage, Security Agreement and Assignment of Facility Lease
dated as of September 15, 1987, between The First National Bank of
Boston, as Owner Trustee under a Trust Agreement, dated as of
September 15, 1987, with Chrysler Consortium Corporation and Irving
Trust Company, as Indenture Trustee. (incorporated by reference to 1987
Form 10-K, Exhibit 28-19)
|
|
(E)
10-103
|
Supplemental
Indenture No. 1 dated as of February 1, 1988 to Trust Indenture,
Mortgage, Security Agreement and Assignment of Facility Lease dated as of
September 15, 1987 between The First National Bank of Boston, as
Owner Trustee under a Trust Agreement dated as of September 15, 1987
with Chrysler Consortium Corporation and Irving Trust Company, as
Indenture Trustee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-20)
|
|
(E)
10-104
|
Tax
Indemnification Agreement dated as of September 15, 1987, between
Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison
Company, Lessee. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-21)
|
|
(E)
10-105
|
Amendment
No. 1 dated as of November 5, 1992 to Tax Indemnification
Agreement dated as of September 15, 1987, between Chrysler Consortium
Corporation, as Owner Participant, and Ohio Edison Company, as Lessee.
(incorporated by reference to OE’s Form 10-K filed March 21,
1995, Exhibit 10-151, File No. 001-02578)
|
|
(E)
10-106
|
Amendment
No. 2 dated as of January 12, 1993 to Tax Indemnification
Agreement dated as of September 15, 1987, between Chrysler Consortium
Corporation, as Owner Participant, and Ohio Edison Company, as Lessee.
(incorporated by reference to OE’s Form 10-K filed March 21,
1995, Exhibit 10-152, File No. 001-02578)
|
|
(E)
10-107
|
Amendment
No. 3 dated as of September 30, 1994 to Tax Indemnification
Agreement dated as of September 15, 1987, between Chrysler Consortium
Corporation, as Owner Participant, and Ohio Edison Company, as Lessee.
(incorporated by reference to OE’s Form 10-K filed March 21,
1995, Exhibit 10-153, File No. 001-02578)
|
|
(E)
10-108
|
Assignment,
Assumption and Further Agreement dated as of September 15, 1987,
among The First National Bank of Boston, as Owner Trustee under a Trust
Agreement, dated as of September 15, 1987, with Chrysler Consortium
Corporation, The Cleveland Electric Illuminating Company, Duquesne Light
Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo
Edison Company. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-22)
|
277
|
(E)
10-109
|
Additional
Support Agreement dated as of September 15, 1987, between The First
National Bank of Boston, as Owner Trustee under a Trust Agreement, dated
as of September 15, 1987, with Chrysler Consortium Corporation, and
Ohio Edison Company. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-23)
|
|
10-110
|
Operating
Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of
June 1, 1976, and executed on September 15, 1987, by and between
the CAPCO Companies. (incorporated by reference to 1987 Form 10-K,
Exhibit 28-25)
|
|
10-111
|
OE
Nuclear Capital Contribution Agreement by and between Ohio Edison Company
and FirstEnergy Nuclear Generation Corp. (incorporated by reference
to OE’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No.
001-02578)
|
|
10-112
|
OE
Fossil Purchase and Sale Agreement by and between Ohio Edison Company
(Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by
reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 10.2,
File No. 001-02578)
|
|
10-113
|
OE Fossil
Security Agreement, dated October 24, 2005, by and between
FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated
by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.18, File
No.
333-145140-01
)
|
|
10-114
|
Consent
Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K
filed March 18, 2005, Exhibit 10.1, File No. 333-21011)
|
|
10-115
|
Nuclear
Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between
Ohio Edison Company and The Toledo Edison Company (Sellers) and
FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference
to OE’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No.
001-02578)
|
|
10-116
|
Power
Supply Agreement dated as of October 31, 2005 between FirstEnergy
Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio
Edison Company, The Cleveland Electric Illuminating Company and The Toledo
Edison Company (Buyers). (incorporated by reference to OE’s
Form 10-K filed March 2, 2006, Exhibit 10-65, File No.
001-02578)
|
|
10-117
|
Revised
Power Supply Agreement, dated December 8, 2006, among FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company and The Toledo Edison Company. (
incorporated by
reference to FES’ Form S-4/A filed August 20, 2007
, Exhibit
10.34
, File
No.
333-145140-01)
|
|
10-118
|
Master
SSO Supply Agreement, entered into May 18, 2009, by and between The
Cleveland Electric Illuminating Company, the Toledo Edison Company and
Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by
reference to OE’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No.
001-02578)
|
|
(A)
12-3
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
23-2
|
Consent
of Independent Registered Public Accounting Firm.
|
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
herein in electronic format as an exhibit.
|
|
(B)
|
Management
contract or compensatory plan contract or arrangement filed pursuant to
Item 601 of Regulation S-K.
|
278
|
(C)
|
Substantially
similar documents have been entered into relating to three additional
Owner Participants.
|
|
(D)
|
Substantially
similar documents have been entered into relating to five additional Owner
Participants.
|
|
(E)
|
Substantially
similar documents have been entered into relating to two additional Owner
Participants.
|
3. Exhibits
– Common Exhibits for CEI and TE
Exhibit
Number
|
2-1
|
Agreement
and Plan of Merger between Ohio Edison Company and Centerior Energy dated
as of September 13, 1996. (incorporated by reference to FE’s
Form S-4 filed February 3, 1997, Exhibit (2)-1,
File No. 333-21011)
|
|
2-2
|
Merger
Agreement by and among Centerior Acquisition Corp., FirstEnergy Corp and
Centerior Energy Corp
.
(incorporated by reference to FE’s Form S-4 filed February 3, 1997,
Exhibit (2)-3, File No. 333-21011)
|
|
10-1
|
CAPCO
Administration Agreement dated November 1, 1971, as of
September 14, 1967, among the CAPCO Group members regarding the
organization and procedures for implementing the objectives of the CAPCO
Group. (incorporated by reference to Amendment No. 1,
Exhibit 5(p), File No. 2-42230)
|
|
10-2
|
Amendment
No. 1, dated January 4, 1974, to CAPCO Administration Agreement
among the CAPCO Group members. (incorporated by reference to OE’s
File No. 2-68906, Exhibit 5(c)(3))
|
|
10-3
|
Agreement
for the Termination or Construction of Certain Agreement By and Among the
CAPCO Group members, dated December 23, 1993 and effective as of
September 1, 1980. (incorporated by reference to CEI’s Form 10-K
filed on March 31, 1994, Exhibit 10b(4), File No.
001-02323)
|
|
10-4
|
Second Amendment to the
Bruce Ma
nsfield Units 1, 2, and
3 Operating Agreement, dated as of July 1, 2007, between
FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company
and The Toledo Edison Company. (incorporated by reference to FE’s Form
8-K/A filed August 2, 2007, Exhibit 10-11, File. No.
333-21011
)
|
|
10-5
|
Amendment
No. 6A dated as of December 1, 1991, to the Bond Guaranty dated
as of October 1, 1973, by The Cleveland Electric Illuminating
Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power
Company, The Toledo Edison Company to National City Bank, as Bond Trustee.
(incorporated by reference to OE’s 1991 Form 10-K ,
Exhibit 10-33)
|
|
10-6
|
Amendment
No. 6B dated as of December 30, 1991, to the Bond Guaranty dated
as of October 1, 1973 by The Cleveland Electric Illuminating Company,
Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company,
The Toledo Edison Company to National City Bank, as Bond Trustee.
(incorporated by reference to OE’s 1991 Form 10-K,
Exhibit 10-34)
|
|
10-7
|
Form
of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation,
The Cleveland Electric Illuminating Company, The Toledo Edison Company and
Irving Trust Company, as Trustee. (incorporated by reference to
File No. 33-18755, Exhibit 4(a))
|
|
10-8
|
Form
of Supplemental Indenture to Collateral Trust Indenture constituting
Exhibit 10-10 above, including form of Secured Lease Obligation bond.
(incorporated by reference to File No. 33-18755,
Exhibit 4(b))
|
|
10-9
|
Form
of Collateral Trust Indenture among Beaver Valley II Funding Corporation,
The Cleveland Electric Illuminating Company and The Toledo Edison Company
and The Bank of New York, as Trustee. (incorporated by reference to
File No. 33-46665,
Exhibit (4)(a))
|
279
|
10-10
|
Form
of Supplemental Indenture to Collateral Trust Indenture constituting
Exhibit 10-12 above, including form of Secured Lease Obligation Bond.
(incorporated by reference to File No. 33-46665,
Exhibit (4)(b))
|
|
10-11
|
Form
of Collateral Trust Indenture among CTC Mansfield Funding Corporation,
Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust
Company, as Trustee. (incorporated by reference to
File No. 33-20128, Exhibit 4(a))
|
|
10-12
|
Form
of Supplemental Indenture to Collateral Trust Indenture constituting
Exhibit 10-14 above, including forms of Secured Lease Obligation
bonds. (incorporated by reference to File No. 33-20128,
Exhibit 4(b))
|
|
10-13
|
Form
of Facility Lease dated as of September 15, 1987 between The First
National Bank of Boston, as Owner Trustee under a Trust Agreement dated as
of September 15, 1987 with the limited partnership Owner Participant
named therein, Lessor, and The Cleveland Electric Illuminating Company and
The Toledo Edison Company, Lessee. (incorporated by reference to
File No. 33-18755, Exhibit 4(c))
|
|
10-14
|
Form
of Amendment No. 1 to Facility Lease constituting Exhibit 10-16
above. (incorporated by reference to File No. 33-18755,
Exhibit 4(e))
|
|
10-15
|
Form
of Facility Lease dated as of September 15, 1987 between The First
National Bank of Boston, as Owner Trustee under a Trust Agreement dated as
of September 15, 1987 with the corporate Owner Participant named
therein, Lessor, and The Cleveland Electric Illuminating Company and The
Toledo Edison Company, Lessees. (incorporated by reference to
File No. 33-18755, Exhibit 4(d))
|
|
10-16
|
Form
of Amendment No. 1 to Facility Lease constituting Exhibit 10-18
above. (incorporated by reference to File No. 33-18755,
Exhibit 4(f))
|
|
10-17
|
Form
of Facility Lease dated as of September 30, 1987 between Meridian
Trust Company, as Owner Trustee under a Trust Agreement dated as of
September 30, 1987 with the Owner Participant named therein, Lessor,
and The Cleveland Electric Illuminating Company and The Toledo Edison
Company, Lessees. (incorporated by reference to
File No. 33-20128, Exhibit 4(c))
|
|
10-18
|
Form
of Amendment No. 1 to the Facility Lease constituting
Exhibit 10-20 above. (incorporated by reference to
File No. 33-20128, Exhibit 4(f))
|
|
10-19
|
Form
of Participation Agreement dated as of September 15, 1987 among the
limited partnership Owner Participant named therein, the Original Loan
Participants listed in Schedule 1 thereto, as Original Loan
Participants, CTC Beaver Valley Fund Corporation, as Funding Corporation,
The First National Bank of Boston, as Owner Trustee, Irving Trust Company,
as Indenture Trustee, and The Cleveland Electric Illuminating Company and
The Toledo Edison Company, as Lessees. (incorporated by reference to
File No. 33-18755, Exhibit 28(a))
|
|
10-20
|
Form
of Amendment No. 1 to Participation Agreement constituting
Exhibit 10-22 above (incorporated by reference to
File No. 33-18755, Exhibit 28(c))
|
|
10-21
|
Form
of Participation Agreement dated as of September 15, 1987 among the
corporate Owner Participant named therein, the Original Loan Participants
listed in Schedule 1 thereto, as Owner Loan Participants, CTC Beaver
Valley Funding Corporation, as Funding Corporation, The First National
Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture
Trustee, and The Cleveland Electric Illuminating Company and The Toledo
Edison Company, as Lessees. (incorporated by reference to
File No. 33-18755, Exhibit 28(b))
|
|
10-22
|
Form
of Amendment No. 1 to Participation Agreement constituting
Exhibit 10-24 above (incorporated by reference to
File No. 33-18755,
Exhibit 28(d))
|
280
|
10-23
|
Form
of Participation Agreement dated as of September 30, 1987 among the
Owner Participant named therein, the Original Loan Participants listed in
Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding
Corporation, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank
& Trust Company, as Indenture Trustee, and The Cleveland Electric
Illuminating Company and The Toledo Edison Company, as Lessees.
(incorporated by reference to File No. 33-0128,
Exhibit 28(a))
|
|
10-24
|
Form
of Amendment No. 1 to the Participation Agreement constituting
Exhibit 10-26 above (incorporated by reference to
File No. 33-20128, Exhibit 28(b))
|
|
10-25
|
Form
of Ground Lease dated as of September 15, 1987 between Toledo Edison,
Ground Lessor, and The First National Bank of Boston, as Owner Trustee
under a Trust Agreement dated as of September 15, 1987 with the Owner
Participant named therein, Tenant. (incorporated by reference to
File No. 33-18755, Exhibit 28(e))
|
|
10-26
|
Form
of Site Lease dated as of September 30, 1987 between Toledo Edison,
Lessor, and Meridian Trust Company, as Owner Trustee under a Trust
Agreement dated as of September 30, 1987 with the Owner Participant
named therein, Tenant. (incorporated by reference to
File No. 33-20128, Exhibit 28(c))
|
|
10-27
|
Form
of Site Lease dated as of September 30, 1987 between The Cleveland
Electric Illuminating Company, Lessor, and Meridian Trust Company, as
Owner Trustee under a Trust Agreement dated as of September 30, 1987
with the Owner Participant named therein, Tenant. (incorporated by
reference to File No. 33-20128,
Exhibit 28(d))
|
|
10-28
|
Form
of Amendment No. 1 to the Site Leases constituting
Exhibits 10-29 and 10-30 above (incorporated by reference to
File No. 33-20128, Exhibit 4(f))
|
|
10-29
|
Form
of Assignment, Assumption and Further Agreement dated as of
September 15, 1987 among The First National Bank of Boston, as Owner
Trustee under a Trust Agreement dated as of September 15, 1987 with
the Owner Participant named therein, The Cleveland Electric Illuminating
Company, Duquesne, Ohio Edison Company, Pennsylvania Power Company and The
Toledo Edison Company. (incorporated by reference to
File No. 33-18755, Exhibit 28(f))
|
|
10-30
|
Form
of Additional Support Agreement dated as of September 15, 1987
between The First National Bank of Boston, as Owner Trustee under a Trust
Agreement dated as of September 15, 1987 with the Owner Participant
named therein and The Toledo Edison Company. (incorporated by reference to
File No. 33-18755, Exhibit 28(g))
|
|
10-31
|
Form
of Support Agreement dated as of September 30, 1987 between Meridian
Trust Company, as Owner Trustee under a Trust Agreement dated as of
September 30, 1987 with the Owner Participant named therein, The
Toledo Edison Company, The Cleveland Electric Illuminating Company,
Duquesne, Ohio Edison Company and Pennsylvania Power Company.
(incorporated by reference to File No. 33-20128,
Exhibit 28(e))
|
|
10-32
|
Form
of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement
dated as of September 30, 1987 between The Toledo Edison Company,
Seller, and The First National Bank of Boston, as Owner Trustee under a
Trust Agreement dated as of September 15, 1987 with the Owner
Participant named therein, Buyer. (incorporated by reference to
File No. 33-18755, Exhibit 28(h))
|
|
10-33
|
Form
of Bill of Sale, Instrument of Transfer and Severance Agreement dated as
of September 30, 1987 between The Toledo Edison Company, Seller, and
Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as
of September 30, 1987 with the Owner Participant named therein,
Buyer. (incorporated by reference to File No. 33-20128,
Exhibit 28(f))
|
|
10-34
|
Form
of Bill of Sale, Instrument of Transfer and Severance Agreement dated as
of September 30, 1987 between The Cleveland Electric Illuminating
Company, Seller, and Meridian Trust Company, as Owner Trustee under a
Trust Agreement dated as of September 30, 1987 with the Owner
Participant named therein, Buyer. (incorporated by reference to
File No. 33-20128,
Exhibit 28(g))
|
281
|
10-35
|
Forms
of Refinancing Agreement, including exhibits thereto, among the Owner
Participant named therein, as Owner Participant, CTC Beaver Valley Funding
Corporation, as Funding Corporation, Beaver Valley II Funding Corporation,
as New Funding Corporation, The Bank of New York, as Indenture Trustee,
The Bank of New York, as New Collateral Trust Trustee, and The Cleveland
Electric Illuminating Company and The Toledo Edison Company, as Lessees.
(incorporated by reference to File No. 33-46665,
Exhibit (28)(e)(i))
|
|
10-36
|
Form
of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc.,
The Cleveland Electric Illuminating Company and The Toledo Edison Company.
(incorporated by reference to CEI’s Form S-4 filed March 10, 1998,
Exhibit 10(a), File No. 333-47651)
|
|
10-37
|
Form
of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc.,
The Cleveland Electric Illuminating Company and The Toledo Edison Company.
(incorporated by reference to CEI’s Form S-4 filed March 10, 1998,
Exhibit 10(b), File No. 333-47651)
|
|
10-38
|
Form
of Amendment No. 2 to Facility Lease among US West Financial
Services, Inc., The Cleveland Electric Illuminating Company and The Toledo
Edison Company. (incorporated by reference to CEI’s Form S-4 filed
March 10, 1998, Exhibit 10(c),
File No. 333-47651)
|
|
10-39
|
Form
of Amendment No. 3 to Facility Lease among US West Financial
Services, Inc., The Cleveland Electric Illuminating Company and The Toledo
Edison Company. (incorporated by reference to CEI’s Form S-4 filed
March 10, 1998, Exhibit 10(d),
File No. 333-47651)
|
|
10-40
|
Form
of Amendment No. 2 to Facility Lease among Midwest Power Company, The
Cleveland Electric Illuminating Company and The Toledo Edison Company.
(incorporated by reference to CEI’s Form S-4 filed March 10, 1998 ,
Exhibit 10(e), File No. 333-47651)
|
|
10-41
|
Centerior
Energy Corporation Equity Compensation Plan. (incorporated by reference to
Centerior Energy Corporation’s Form S-8 filed May 26, 1995,
Exhibit 99, File No. 33-59635)
|
|
10-42
|
Revised
Power Supply Agreement, dated December 8, 2006, among FirstEnergy
Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating
Company and The Toledo Edison Company. (incorporated by reference to FES’
Form S-4/A filed August 20, 2007, Exhibit 10.34, File No.
333-145140-01)
|
3. Exhibits
– CEI
| 3-1 |
Amended
and Restated Articles of Incorporation of The Cleveland Electric
Illuminating Company, Effective December 21, 2007. (
incorporated by
reference to CEI’s
Form 10-K filed February 29, 2008, Exhibit 3.3,
File No. 001-02323)
|
| 3-2 |
Amended
and Restated Code of Regulations of The Cleveland Electric Illuminating
Company, dated December 14, 2007. (
incorporated by
reference to CEI’s
Form 10-K filed February 29, 2008, Exhibit 3.4,
File No. 001-02323)
|
| (B) 4-1 |
Mortgage
and Deed of Trust between The Cleveland Electric Illuminating Company and
Guaranty Trust Company of New York (now The Chase Manhattan Bank (National
Association)), as Trustee, dated July 1, 1940. (
incorporated by
reference to
File No. 2-4450,
Exhibit 7(a))
|
|
Supplemental
Indentures between The Cleveland Electric Illuminating Company and the
Trustee, supplemental to Exhibit 4-1, dated as
follows:
|
|
|
4-1(a)
|
July 1,
1940 (
incorporated by
reference to
File No. 2-4450,
Exhibit 7(b))
|
|
4-1(b)
|
August 18,
1944 (
incorporated by
reference to
File No. 2-9887,
Exhibit 4(c))
|
|
4-1(c)
|
December 1,
1947 (
incorporated by
reference to
File No. 2-7306,
Exhibit 7(d))
|
|
4-1(d)
|
September 1,
1950 (
incorporated by
reference to
File No. 2-8587,
Exhibit 7(c))
|
|
4-1(e)
|
June 1,
1951 (
incorporated by
reference to
File No. 2-8994,
Exhibit 7(f))
|
|
4-1(f)
|
May 1,
1954 (
incorporated by
reference to
File No. 2-10830,
Exhibit 4(d))
|
|
4-1(g)
|
March 1,
1958 (
incorporated by
reference to
File No. 2-13839,
Exhibit 2(a)(4))
|
|
4-1(h)
|
April 1,
1959 (
incorporated by
reference to
File No. 2-14753,
Exhibit 2(a)(4))
|
|
4-1(i)
|
December 20,
1967 (
incorporated by
reference to
File No. 2-30759,
Exhibit 2(a)(4))
|
|
4-1(j)
|
January 15,
1969 (
incorporated by
reference to
File No. 2-30759,
Exhibit 2(a)(5))
|
|
4-1(k)
|
November 1,
1969 (
incorporated by
reference to
File No. 2-35008,
Exhibit 2(a)(4))
|
|
4-1(l)
|
June 1,
1970 (
incorporated by
reference to
File No. 2-37235,
Exhibit 2(a)(4))
|
282
|
4-1(m)
|
November 15,
1970 (
incorporated by
reference to
File No. 2-38460,
Exhibit 2(a)(4))
|
|
4-1(n)
|
May 1,
1974 (
incorporated by
reference to
File No. 2-50537,
Exhibit 2(a)(4))
|
|
4-1(o)
|
April 15,
1975 (
incorporated by
reference to
File No. 2-52995,
Exhibit 2(a)(4))
|
|
4-1(p)
|
April 16,
1975 (
incorporated by
reference to
File No. 2-53309,
Exhibit 2(a)(4))
|
|
4-1(q)
|
May 28,
1975 (
incorporated by
reference to
Form 8-A filed June 5, 1975,
Exhibit 2(c), File No. 1-2323)
|
|
4-1(r)
|
February 1,
1976 (
incorporated by
reference to
1975 Form 10-K, Exhibit 3(d)(6),
File No. 1-2323)
|
|
4-1(s)
|
November 23,
1976 (
incorporated by
reference to
File No. 2-57375,
Exhibit 2(a)(4))
|
|
4-1(t)
|
July 26,
1977 (
incorporated by
reference to
File No. 2-59401,
Exhibit 2(a)(4))
|
|
4-1(u)
|
September 7,
1977 (
incorporated by
reference to
File No. 2-67221,
Exhibit 2(a)(5))
|
|
4-1(v)
|
May 1,
1978 (
incorporated by
reference to
June 1978 Form 10-Q, Exhibit 2(b),
File No. 1-2323)
|
|
4-1(w)
|
September 1,
1979 (
incorporated by
reference to
September 1979 Form 10-Q, Exhibit 2(a),
File No. 1-2323)
|
|
4-1(x)
|
April 1,
1980 (
incorporated by
reference to
September 1980 Form 10-Q,
Exhibit 4(a)(2), File No. 1-2323)
|
|
4-1(y)
|
April 15,
1980 (
incorporated by
reference to
September 1980 Form 10-Q, Exhibit 4(b),
File No. 1-2323)
|
|
4-1(z)
|
May 28,
1980 (
incorporated by
reference to
Amendment No. 1, Exhibit 2(a)(4),
File No. 2-67221)
|
|
4-1(aa)
|
June 9,
1980 (
incorporated by
reference to
September 1980 Form 10-Q, Exhibit 4(d),
File No. 1-2323)
|
|
4-1(bb)
|
December 1,
1980 (
incorporated by
reference to
1980 Form 10-K, Exhibit 4(b)(29),
File No. 1-2323)
|
|
4-1(cc)
|
July 28,
1981 (
incorporated by
reference to
September 1981
Form 10-Q, Exhibit 4(a),
File No. 1-2323)
|
|
4-1(dd)
|
August 1, 1981 (
incorporated by
reference to
September 1981
Form 10-Q, Exhibit 4(b),
File No. 1-2323)
|
|
4-1(ee)
|
March 1,
1982 (
incorporated by
reference to
Amendment No. 1, Exhibit 4(b)(3),
File No. 2-76029)
|
|
4-1(ff)
|
July 15,
1982 (
incorporated by
reference to
September 1982 Form 10-Q, Exhibit 4(a),
File No. 1-2323)
|
|
4-1(gg)
|
September 1,
1982 (
incorporated by
reference to
September 1982 Form 10-Q,
Exhibit 4(a)(1), File No. 1-2323)
|
|
4-1(hh)
|
November 1,
1982 (
incorporated by
reference to
September 1982 Form 10-Q,
Exhibit (a)(2), File No. 1-2323)
|
|
4-1(ii)
|
November 15,
1982 (
incorporated by
reference to
1982 Form 10-K, Exhibit 4(b)(36),
File No. 1-2323)
|
|
4-1(jj)
|
May 24,
1983 (
incorporated by
reference to
June 1983 Form 10-Q, Exhibit 4(a), File
No. 1-2323)
|
|
4-1(kk)
|
May 1,
1984 (
incorporated by
reference to
June 1984 Form 10-Q, Exhibit 4,
File No. 1-2323)
|
|
4-1(ll)
|
May 23,
1984 (
incorporated by
reference to
Form 8-K dated May 22, 1984, Exhibit 4,
File No. 1-2323)
|
|
4-1(mm)
|
June 27,
1984 (
incorporated by
reference to
Form 8-K dated June 11, 1984,
Exhibit 4, File No. 1-2323)
|
|
4-1(nn)
|
September 4,
1984 (
incorporated by
reference to
1984 Form 10-K, Exhibit 4b(41),
File No. 1-2323)
|
|
4-1(oo)
|
November 14,
1984 (
incorporated by
reference to
1984 Form 10 K, Exhibit 4b(42),
File No. 1-2323)
|
|
4-1(pp)
|
November 15,
1984 (
incorporated by
reference to
1984 Form 10-K, Exhibit 4b(43),
File No. 1-2323)
|
|
4-1(qq)
|
April 15,
1985
incorporated
by reference to
(Form 8-K dated May 8, 1985,
Exhibit 4(a), File No. 1-2323)
|
|
4-1(rr)
|
May 28,
1985 (
incorporated by
reference to
Form 8-K dated May 8, 1985,
Exhibit 4(b), File No. 1-2323)
|
|
4-1(ss)
|
August 1,
1985 (
incorporated by
reference to
September 1985 Form 10-Q, Exhibit 4,
File No. 1-2323)
|
|
4-1(tt)
|
September 1,
1985 (
incorporated by
reference to
Form 8-K dated September 30, 1985,
Exhibit 4, File No. 1-2323)
|
|
4-1(uu)
|
November 1,
1985 (
incorporated by
reference to
Form 8-K dated January 31, 1986,
Exhibit 4, File No. 1-2323)
|
|
4-1(vv)
|
April 15,
1986 (
incorporated by
reference to
March 1986 Form 10-Q, Exhibit 4,
File No. 1-2323)
|
|
4-1(ww)
|
May 14,
1986 (
incorporated by
reference to
June 1986 Form 10-Q, Exhibit 4(a),
File No. 1-2323)
|
|
4-1(xx)
|
May 15,
1986 (
incorporated by
reference to
June 1986 Form 10-Q, Exhibit 4(b),
File No. 1-2323)
|
|
4-1(yy)
|
February 25,
1987 (
incorporated by
reference to
1986 Form 10-K, Exhibit 4b(52),
File No. 1-2323)
|
283
|
4-1(zz)
|
October 15,
1987 (
incorporated by
reference to
September 1987 Form 10-Q, Exhibit 4, File
No. 1-2323)
|
|
4-1(aaa)
|
February 24,
1988 (
incorporated by
reference to
1987 Form 10-K, Exhibit 4b(54),
File No. 1-2323)
|
|
4-1(bbb)
|
September 15,
1988 (
incorporated by
reference to
1988 Form 10-K, Exhibit 4b(55),
File No. 1-2323)
|
|
4-1(ccc)
|
May 15,
1989 (
incorporated by
reference to
File No. 33-32724,
Exhibit 4(a)(2)(i))
|
|
4-1(ddd)
|
June 13,
1989 (
incorporated by
reference to
File No. 33-32724,
Exhibit 4(a)(2)(ii))
|
|
4-1(eee)
|
October 15,
1989 (
incorporated by
reference to
File No. 33-32724,
Exhibit 4(a)(2)(iii))
|
|
4-1(fff)
|
January 1,
1990 (
incorporated by
reference to
1989 Form 10-K, Exhibit 4b(59),
File No. 1-2323)
|
|
4-1(ggg)
|
June 1,
1990 (
incorporated by
reference to
September 1990 Form 10-Q, Exhibit 4(a),
File No. 1-2323)
|
|
4-1(hhh)
|
August 1,
1990 (
incorporated by
reference to
September 1990 Form 10-Q, Exhibit 4(b),
File No. 1-2323)
|
|
4-1(iii)
|
May 1,
1991 (
incorporated by
reference to
June 1991 Form 10-Q, Exhibit 4(a),
File No. 1-2323)
|
|
4-1(jjj)
|
May 1,
1992 (
incorporated by
reference to
File No. 33-48845,
Exhibit 4(a)(3))
|
|
4-1(kkk)
|
July 31,
1992 (
incorporated by
reference to
File No. 33-57292,
Exhibit 4(a)(3))
|
|
4-1(lll)
|
January 1,
1993 (
incorporated by
reference to
1992 Form 10-K, Exhibit 4b(65),
File No. 1-2323)
|
|
4-1(mmm)
|
February 1,
1993 (
incorporated by
reference to
1992 Form 10-K, Exhibit 4b(66),
File No. 1-2323)
|
|
4-1(nnn)
|
May 20,
1993 (
incorporated by
reference to
Form 8-K dated July 14, 1993,
Exhibit 4(a), File No. 1-2323)
|
|
4-1(ooo)
|
June 1,
1993 (
incorporated by
reference to
Form 8-K dated July 14, 1993,
Exhibit 4(b), File No. 1-2323)
|
|
4-1(ppp)
|
September 15,
1994 (
incorporated by
reference to
CEI’s Form 10-Q filed November 14, 1994,
Exhibit 4(a), File No. 001-02323)
|
|
4-1(qqq)
|
May 1,
1995 (
incorporated by
reference to
CEI’s Form 10-Q filed November 13, 1995,
Exhibit 4(a), File No. 001-02323)
|
|
4-1(rrr)
|
May 2,
1995 (
incorporated by
reference to
CEI’s Form 10-Q filed November 13, 1995,
Exhibit 4(b) , File No. 001-02323)
|
|
4-1(sss)
|
June 1,
1995 (
incorporated by
reference to
CEI’s Form 10-Q filed November 13, 1995,
Exhibit 4(c) , File No. 001-02323)
|
|
4-1(ttt)
|
July 15,
1995 (i
ncorporated by
reference to
CEI’s Form 10-K filed March 29, 1996,
Exhibit 4b(73) , File No. 001-02323)
|
|
4-1(uuu)
|
August 1,
1995 (i
ncorporated by
reference to
CEI’s Form 10-K filed March 29, 1996,
Exhibit 4b(74) , File No. 001-02323)
|
|
4-1(vvv)
|
June 15,
1997 (incorporated by reference to CEI’s Form S-4 filed September 18,
2007, Exhibit 4(a), File No. 333-35931)
|
|
4-1(www)
|
October 15,
1997 (incorporated by reference to CEI’s Form S-4 filed March 10,
1998, Exhibit 4(a), File No. 333-47651)
|
|
4-1(xxx)
|
June 1,
1998 (incorporated by reference to CEI’s Form S-4,
Exhibit 4b(77), File No. 333-72891)
|
|
4-1(yyy)
|
October 1,
1998 (incorporated by reference to CEI’s Form S-4 filed February 24,
1999, Exhibit 4b(78),
File No. 333-72891)
|
|
4-1(zzz)
|
October 1,
1998 (incorporated by reference to CEI’s Form S-4 filed February 24,
1999, Exhibit 4b(79),
File No. 333-72891)
|
|
4-1(aaaa)
|
February 24,
1999 (incorporated by reference to CEI’s Form S-4 filed February 24,
1999, Exhibit 4b(80),
File No. 333-72891)
|
|
4-1(bbbb)
|
September 29,
1999 (i
ncorporated by
reference to
CEI’s Form 10-K filed March 29, 2000, Exhibit 4b(81) ,
File No. 001-02323)
|
|
4-1(cccc)
|
January 15,
2000 (i
ncorporated by
reference to
CEI’s Form 10-K filed March 29, 2000, Exhibit 4b(82) ,
File No. 001-02323)
|
|
4-1(dddd)
|
May
15, 2002 (i
ncorporated by
reference to
CEI’s Form 10-K filed March 26, 2003, Exhibit 4b(83) ,
File No. 001-02323)
|
|
4-1(eeee)
|
October
1, 2002 (i
ncorporated by
reference to
CEI’s Form 10-K filed March 26, 2003, Exhibit 4b(84) ,
File No. 001-02323)
|
|
4-1(ffff)
|
Supplemental
Indenture dated as of September 1, 2004 (i
ncorporated by
reference to
CEI’s Form 10-Q filed November 4, 2004, Exhibit
4-1(85) , File No. 001-02323)
|
|
4-1(gggg)
|
Supplemental
Indenture dated as of October 1, 2004 (i
ncorporated by
reference to
CEI’s Form 10-Q filed November 4, 2004, Exhibit
4-1(86) , File No. 001-02323)
|
|
4-1(hhhh)
|
Supplemental
Indenture dated as of April 1, 2005 (i
ncorporated by
reference to
CEI’s Form 10-Q filed August 1, 2005, Exhibit 4.1,
File No. 001-02323)
|
|
4-1(iiii)
|
Supplemental
Indenture dated as of July 1, 2005 (i
ncorporated by
reference to
CEI’s Form 10-Q filed August 1, 2005, Exhibit 4.2,
File No. 001-02323)
|
284
|
4-1(jjjj)
|
Eighty-Ninth
Supplemental Indenture, dated as of November 1, 2008 (relating to First
Mortgage Bonds, 8.875% Series due 2018). (i
ncorporated by
reference to
CEI’s Form 8-K filed November 19, 2008, Exhibit 4.1,
File No. 001-02323)
|
|
4-1(kkk)
|
Ninetieth
Supplemental Indenture, dated as of August 1, 2009 (including Form of
First Mortgage Bonds, 5.50% Series due 2024). (incorporated by reference
to CEI's Form 8-K filed on August 18, 2009, Exhibit 4.1,
File No. 001-02323)
|
|
4-2
|
Form
of Note Indenture between The Cleveland Electric Illuminating Company and
The Chase Manhattan Bank, as Trustee dated as of October 24, 1997.
(incorporated by reference to CEI's Form S-4 filed March 10, 1998,
Exhibit 4(b) , File No. 333-47651)
|
|
4-2(a)
|
Form
of Supplemental Note Indenture between The Cleveland Electric Illuminating
Company and The Chase Manhattan Bank, as Trustee dated as of
October 24, 1997. (incorporated by reference to CEI's Form S-4
filed March 10, 1998, Exhibit 4(c), File
No. 333-47651)
|
|
4-3
|
Indenture
dated as of December 1, 2003 between The Cleveland Electric Illuminating
Company and JPMorgan Chase Bank, as Trustee. (incorporated by reference to
CEI's Form 10-K filed March 15, 2004, Exhibit 4-1,
File No. 001-02323)
|
|
4-3(a)
|
Officer’s
Certificate (including the form of 5.95% Senior Notes due 2036), dated as
of December 11, 2006. (incorporated by reference to CEI's Form 8-K filed
December 12, 2006, Exhibit 4,
File No. 001-02323)
|
|
4-3(b)
|
Officer’s
Certificate (including the form of 5.70% Senior Notes due 2017), dated as
of March 27, 2007. (incorporated by reference to CEI's Form 8-K filed
March 28, 2007, Exhibit 4,
File No. 001-02323)
|
|
10-1
|
CEI
Nuclear Purchase and Sale Agreement by and between The Cleveland Electric
Illuminating Company and FirstEnergy Nuclear Generation Corp.
(incorporated by reference to CEI's Form 10-Q filed August 1, 2005,
Exhibit 10.1, File No. 001-02323)
|
|
10-2
|
CEI
Fossil Purchase and Sale Agreement by and between The Cleveland Electric
Illuminating Company (Seller) and FirstEnergy Generation Corp.
(Purchaser). (incorporated by reference to CEI's Form 10-Q filed August 1,
2005, Exhibit 10.2, File No. 001-02323)
|
|
10-3
|
CEI Fossil Security
Agreement, dated October 24, 2005, by and between FirstEnergy
Generation Corp. and The Cleveland Electric Illuminating Company.
(Form S-4/A filed August 20, 2007, Exhibit 10.16, File No.
333-145140-01
)
|
|
10-4
|
CEI Nuclear
Security Agreement, dated December 16, 2005, by and between
FirstEnergy Nuclear Generation Corp. and The Cleveland Electric
Illuminating Company. (
incorporated by reference to FE's
Form S-4/A filed August
20, 2007, Exhibit 10.26
, File No.
333-145140-01
)
|
|
10-5
|
Nuclear
Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between
Ohio Edison Company and The Toledo Edison Company (Sellers) and
FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference
to CEI's Form 10-K filed March 2, 2006, Exhibit 10-64,
File No. 001-02323)
|
|
10-6
|
Power
Supply Agreement dated as of October 31, 2005 between FirstEnergy
Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio
Edison Company, The Cleveland Electric Illuminating Company and The Toledo
Edison Company (Buyers). (incorporated by reference to CEI's Form 10-K
filed March 2, 2006, Exhibit 10-66,
File No. 001-02323)
|
|
10-7
|
Mansfield
Power Supply Agreement dated as of October 14, 2005 between The Cleveland
Electric Illuminating Company and The Toledo Edison Company (Sellers) and
FirstEnergy Generation Corp. (Buyer). (incorporated by reference to CEI's
Form 10-K filed March 2, 2006, Exhibit 10-65,
File No. 001-02323)
|
|
10-8
|
Master
SSO Supply Agreement, entered into May 18, 2009, by and between The
Cleveland Electric Illuminating Company, the Toledo Edison Company and
Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by
reference to CEI's Form 10-Q filed August 3, 2009, Exhibit 10.2,
File No. 001-02323)
|
285
|
(A)
12-4
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
23-3
|
Consent of Independent Registered Public Accounting Firm |
|
(A)
31-2
|
Certification
of chief financial officer, as adopted
pursuant
to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
herein in electronic format as an exhibit.
|
|
(B)
|
Pursuant
to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, CEI has
not filed as an exhibit to this Form 10-K any instrument with respect to
long-term debt if the total amount of securities authorized thereunder
does not exceed 10% of the total assets of CEI, but hereby agrees to
furnish to the Commission on request any such
instruments.
|
3. Exhibits
– TE
|
3-1
|
Amended
and Restated Articles of Incorporation of The Toledo Edison Company,
effective December 18, 2007. (
incorporated by
reference to TE’s
Form 10-K filed February 29, 2008, Exhibit 3c,
File No. 001-03583)
|
|
3-2
|
Amended
and Restated Code of Regulations of The Toledo Edison Company, dated
December 14, 2007. (
incorporated by
reference to TE’s
Form 10-K filed February 29, 2008, Exhibit 3d,
File No. 001-03583)
|
|
(B)
4-1
|
Indenture,
dated as of April 1, 1947, between The Toledo Edison Company and The Chase
National Bank of the City of New York (now The Chase Manhattan Bank
(National Association)), as Trustee. (
incorporated by
reference to
File No. 2-26908, Exhibit 2(b))
|
|
Supplemental
Indentures between The Toledo Edison Company and the Trustee, supplemental
to Exhibit 4-1, dated as follows:
|
|
|
4-1(a)
|
September 1,
1948 (
incorporated by
reference to
File No. 2-26908,
Exhibit 2(d))
|
|
4-1(b)
|
April 1,
1949 (
incorporated by
reference to
File No. 2-26908,
Exhibit 2(e))
|
|
4-1(c)
|
December 1,
1950 (
incorporated by
reference to
File No. 2-26908,
Exhibit 2(f))
|
|
4-1(d)
|
March 1,
1954 (
incorporated by
reference to
File No. 2-26908,
Exhibit 2(g))
|
|
4-1(e)
|
February 1,
1956 (
incorporated by
reference to
File No. 2-26908,
Exhibit 2(h))
|
|
4-1(f)
|
May 1,
1958 (
incorporated by
reference to
File No. 2-59794,
Exhibit 5(g))
|
|
4-1(g)
|
August 1,
1967 (
incorporated by
reference to
File No. 2-26908,
Exhibit 2(c))
|
|
4-1(h)
|
November 1,
1970 (
incorporated by
reference to
File No. 2-38569,
Exhibit 2(c))
|
|
4-1(i)
|
August 1,
1972 (
incorporated by
reference to
File No. 2-44873,
Exhibit 2(c))
|
|
4-1(j)
|
November 1,
1973 (
incorporated by
reference to
File No. 2-49428,
Exhibit 2(c))
|
|
4-1(k)
|
July 1,
1974 (
incorporated by
reference to
File No. 2-51429,
Exhibit 2(c))
|
|
4-1(l)
|
October 1,
1975 (
incorporated by
reference to
File No. 2-54627,
Exhibit 2(c))
|
|
4-1(m)
|
June 1,
1976 (
incorporated by
reference to
File No. 2-56396,
Exhibit 2(c))
|
|
4-1(n)
|
October 1,
1978 (
incorporated by
reference to
File No. 2-62568,
Exhibit 2(c))
|
|
4-1(o)
|
September 1,
1979 (
incorporated by
reference to
File No. 2-65350,
Exhibit 2(c))
|
|
4-1(p)
|
September 1,
1980 (
incorporated by
reference to
File No. 2-69190,
Exhibit 4(s))
|
|
4-1(q)
|
October 1,
1980 (
incorporated by
reference to
File No. 2-69190,
Exhibit 4(c))
|
|
4-1(r)
|
April 1,
1981 (
incorporated by
reference to
File No. 2-71580,
Exhibit 4(c))
|
|
4-1(s)
|
November 1,
1981 (
incorporated by
reference to
File No. 2-74485,
Exhibit 4(c))
|
|
4-1(t)
|
June 1,
1982 (
incorporated by
reference to
File No. 2-77763,
Exhibit 4(c))
|
|
4-1(u)
|
September 1,
1982 (
incorporated by
reference to
File No. 2-87323,
Exhibit 4(x))
|
|
4-1(v)
|
April 1,
1983 (
incorporated by
reference to
March 1983 Form 10-Q, Exhibit 4(c),
File No. 1-3583)
|
|
4-1(w)
|
December 1,
1983 (
incorporated by
reference to
1983 Form 10-K, Exhibit 4(x),
File No. 1-3583)
|
|
4-1(x)
|
April 1,
1984 (
incorporated by
reference to
File No. 2-90059,
Exhibit 4(c))
|
|
4-1(y)
|
October 15,
1984 (
incorporated by
reference to
1984 Form 10-K, Exhibit 4(z),
File No. 1-3583)
|
|
4-1(z)
|
October 15,
1984 (
incorporated by
reference to
1984 Form 10-K, Exhibit 4(aa),
File No. 1-3583)
|
|
4-1(aa)
|
August 1,
1985 (
incorporated by
reference to
File No. 33-1689,
Exhibit 4(dd))
|
|
4-1(bb)
|
August 1,
1985 (
incorporated by
reference to
File No. 33-1689,
Exhibit 4(ee))
|
286
|
4-1(cc)
|
December 1,
1985 (
incorporated by
reference to
File No. 33-1689,
Exhibit 4(c)
)
|
|
4-1(dd)
|
March 1,
1986 (
incorporated by
reference to
1
986
Form 10-K,
Exhibit 4b(31),
File No. 1-3583)
|
|
4-1(ee)
|
October 15,
1987 (
incorporated by
reference to
September 30, 1
987 Form 10-Q,
Exhibit 4,
File No. 1-3583)
|
|
4-1(ff)
|
September 15,
1988 (
incorporated by
reference to
1
988
Form 10-K,
Exhibit 4b(33),
File No. 1-3583)
|
|
4-1(gg)
|
June 15,
1989 (
incorporated by
reference to
1
989
Form 10-K,
Exhibit 4b(34),
File No. 1-3583)
|
|
4-1(hh)
|
October 15,
1989 (
incorporated by
reference to
1
989
Form 10-K,
Exhibit 4b(35),
File No. 1-3583)
|
|
4-1(ii)
|
May 15,
1990 (
incorporated by
reference to
June 30, 1
990 Form 10-Q,
Exhibit 4,
File No. 1-3583)
|
|
4-1(jj)
|
March 1,
1991 (
incorporated by
reference to
June 30, 1
991 Form 10-Q,
Exhibit 4(b),
File No. 1-3583)
|
|
4-1(kk)
|
May 1,
1992 (
incorporated by
reference to
File No.
33-48844,
Exhibit 4(a)(3)
)
|
|
4-1(ll)
|
August 1,
1992 (
incorporated by
reference to
1
992
Form 10-K,
Exhibit 4b(39),
File No. 1-3583)
|
|
4-1(mm)
|
October 1,
1992 (
incorporated by
reference to
1
992
Form 10-K,
Exhibit 4b(40),
File No. 1-3583)
|
|
4-1(nn)
|
January 1,
1993 (
incorporated by
reference to
1
992
Form 10-K,
Exhibit 4b(41),
File No. 1-3583)
|
|
4-1(oo)
|
September 15,
1994 (
incorporated by
reference to
TE’s Form 10-Q filed November 14, 1994,
Exhibit 4(b), File No. 001-03583)
|
|
4-1(pp)
|
May 1,
1995 (
incorporated by
reference to
TE’s Form 10-Q filed November 14, 1994,
Exhibit 4(d), File No. 001-03583)
|
|
4-1(qq)
|
June 1,
1995 (
incorporated by
reference to
TE’s Form 10-Q filed November 14, 1994,
Exhibit 4(e), File No. 001-03583)
|
|
4-1(rr)
|
July 14,
1995 (
incorporated by
reference to
TE’s Form 10-Q filed November 14, 1994,
Exhibit 4(f), File No. 001-03583)
|
|
4-1(ss)
|
July 15,
1995 (
incorporated by
reference to
TE’s Form 10-Q filed November 14, 1994,
Exhibit 4(g), File No. 1-3583)
|
|
4-1(tt)
|
August 1,
1997 (
incorporated by
reference to
TE’s Form 10-K filed March 29, 1999,
Exhibit 4b(47), File No. 001-03583)
|
|
4-1(uu)
|
June 1,
1998 (
incorporated by
reference to
TE’s Form 10-K filed March 29, 1999,
Exhibit 4b(48), File No. 001-03583)
|
|
4-1(vv)
|
January 15,
2000 (
incorporated by
reference to
TE’s Form 10-K filed March 29, 1999, Exhibit
4b(49), File No. 001-03583)
|
|
4-1(ww)
|
May 1,
2000 (
incorporated by
reference to
TE’s Form 10-K filed April 16, 2000, Exhibit
4b(50), File No. 001-03583)
|
|
4-1(xx)
|
September
1, 2000 (
incorporated by
reference to
TE’s Form 10-K filed April 16, 2001, Exhibit 4b(51),
File No. 001-03583)
|
|
4-1(yy)
|
October
1, 2002 (
incorporated by
reference to
TE’s Form 10-K filed March 26, 2003, Exhibit 4b(52),
File No. 001-03583)
|
|
4-1(zz)
|
April
1, 2003 (
incorporated by
reference to
TE’s Form 10-K filed March 15, 2004, Exhibit 4b(53),
File No. 001-03583)
|
|
4-1(aaa)
|
September
1, 2004 (
incorporated by
reference to
TE’s 10-Q filed November 4, 2004, Exhibit 4.2.56,
File No. 001-03583)
|
|
4-1(bbb)
|
April
1, 2005 (
incorporated by
reference to
TE’s June 2005 10-Q, Exhibit 4.1,
File No. 001-03583)
|
|
4-1(ccc)
|
April
23, 2009 (
incorporated by
reference to
TE’s Form 8-K filed April 24, 2009, Exhibit 4.3,
File No. 001-03583)
|
|
4-1(ddd)
|
April
24, 2009 (
incorporated by
reference to
TE’s Form 8-K filed April 24, 2009, Exhibit 4.4,
File No. 001-03583)
|
|
4-2
|
Indenture
dated as of November 1, 2006, between The Toledo Edison Company and The
Bank of New York Trust Company, N.A. (incorporated by reference to TE’s
Form 10-K filed February 28, 2007, Exhibit 4-2,
File No. 001-03583)
|
|
4-2(a)
|
Officer’s
Certificate (including the form of 6.15% Senior Notes due 2037), dated
November 16, 2006. (incorporated by reference to TE’s Form 8-K filed
November 17, 2006, Exhibit 4,
File No. 001-03583)
|
|
4-2(b)
|
First
Supplemental Indenture, dated as of April 24, 2009, between the Toledo
Edison Company and The Bank of New York Mellon Trust Company, N.A., as
trustee to the Indenture dated as of November 1, 2006 (incorporated by
reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.1,
File No. 001-03583)
|
287
|
4-2(c)
|
Officer’s
Certificate (including the Form of the 7.25% Senior Secured Notes due
2020), dated April 24, 2009 (incorporated by reference to TE’s Form 8-K
filed April 24, 2009, Exhibit 4.2,
File No. 001-03583)
|
|
10-1
|
TE
Nuclear Purchase and Sale Agreement by and between The Toledo Edison
Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser).
(incorporated by reference to TE’s Form 10-Q filed August 1, 2005, Exhibit
10.1, File No. 001-03583)
|
|
10-2
|
TE
Fossil Purchase and Sale Agreement by and between The Toledo Edison
Company (Seller) and FirstEnergy Generation Corp. (Purchaser).
(incorporated by reference to TE’s Form 10-Q filed August 1, 2005, Exhibit
10.2, File No. 001-03583)
|
|
10-3
|
TE Fossil
Security Agreement, dated October 24, 2005, by and between
FirstEnergy Generation Corp. and The Toledo Edison Company.
(
incorporated by reference to FES’
Form S-4/A filed
August 20, 2007, Exhibit 10.24, File No.
333-145140-01
)
|
|
10-4
|
Nuclear
Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between
Ohio Edison Company and The Toledo Edison Company (Sellers) and
FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference
to TE’s Form 10-K filed March 2, 2006, Exhibit 10-64,
File No. 001-03583)
|
|
10-5
|
Power
Supply Agreement dated as of October 31, 2005 between FirstEnergy
Solutions Corp. (Seller) and the FirstEnergy Operating Companies – Ohio
Edison Company, The Cleveland Electric Illuminating Company and The Toledo
Edison Company (Buyers). (incorporated by reference to TE’s Form 10-K,
Exhibit 10-6, File No. 001-03583)
|
|
10-6
|
Mansfield
Power Supply Agreement dated as of October 14, 2005 between The Cleveland
Electric Illuminating Company and The Toledo Edison Company (Sellers) and
FirstEnergy Generation Corp. (Buyer). (incorporated by reference to TE’s
Form 10-K, Exhibit 10-65, File No. 001-03583)
|
|
10-7
|
Master
SSO Supply Agreement, entered into May 18, 2009, by and between The
Cleveland Electric Illuminating Company, the Toledo Edison Company and
Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by
reference to TE’s Form 10-Q filed August 3, 2009, Exhibit 10.2,
File No. 001-03583
|
|
(A)
12-5
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
23-4
|
Consent of Independent Registered Public Accounting Firm |
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
herein in electronic format as an exhibit.
|
|
(B)
|
Pursuant
to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not
filed as an exhibit to this Form 10-K any instrument with respect to
long-term debt if the total amount of securities authorized thereunder
does not exceed 10% of the total assets of TE, but hereby agrees to
furnish to the Commission on request any such
instruments.
|
3. Exhibits
– JCP&L
|
3-1
|
Amended
and Restated Certificate of Incorporation of Jersey Central Power &
Light Company, filed February 14, 2008. (
incorporated by
reference to JCP&L’s
Form 10-K filed February 29, 2008, Exhibit
3-D, File No. 001-03141)
|
288
|
3-2
|
Amended
and Restated Bylaws of Jersey Central Power & Light Company, dated
January 9, 2008. (
incorporated by
reference to
JCP&L’s
Form
10-K filed February 29, 2008, Exhibit 3-E, File No.
001-03141)
|
|
4-1
|
Senior
Note Indenture, dated as of July 1, 1999, between Jersey Central Power
& Light Company and The Bank of New York Mellon Trust Company, N.A.,
as successor trustee to United States Trust Company of New York. (
incorporated by
reference to
JCP&L’s
Form
S-3 filed May 18, 1999, Exhibit 4-A, File No.
333-78717)
|
|
4-1(a)
|
First
Supplemental Indenture, dated October 31, 2007, between Jersey Central
Power & Light Company, The Bank of New York, as resigning trustee, and
The Bank of New York Trust Company, N.A., as successor trustee. (
incorporated by
reference to
JCP&L’s
Form
S-4/A filed November 11, 2007, Exhibit 4-2, File No.
333-146968)
|
|
4-1(b)
|
Form
of Jersey Central Power & Light Company 6.40% Senior Note due 2036.
(
incorporated by
reference to
JCP&L’s
Form
8-K filed May 12, 2006, Exhibit 10-1, File No.
001-03141)
|
|
4-1(c)
|
Form
of 7.35% Senior Notes due 2019. (
incorporated by
reference to
JCP&L’s
Form
8-K filed January 27, 2009, Exhibit 4.1, File No.
001-03141)
|
|
10-1
|
Indenture
dated as of August 10, 2006 between JCP&L Transition Funding II LLC as
Issuer and The Bank of New York as Trustee.
(
incorporated by
reference to
JCP&L’s
Form 8-K
filed August 10, 2006, Exhibit 4-1
, File No. 001-03141
)
|
|
10-2
|
2006-A
Series Supplement dated as of August 10, 2006 between JCP&L Transition
Funding II LLC as Issuer and The Bank of New York as Trustee.
(
incorporated by
reference to
JCP&L’s
Form 8-K
filed August 10, 2006, Exhibit 4-2)
|
|
10-3
|
Bondable
Transition Property Sale Agreement dated as of August 10, 2006 between
JCP&L Transition Funding II LLC as Issuer and Jersey Central Power
& Light Company as Seller. (
incorporated by
reference to
JCP&L’s
Form
8-K filed August 10, 2006, Exhibit 10-1, File No.
001-03141)
|
|
10-4
|
Bondable
Transition Property Service Agreement dated as of August 10, 2006 between
JCP&L Transition Funding II LLC as Issuer and Jersey Central Power
& Light Company as Servicer. (
incorporated by
reference to
JCP&L’s
Form
8-K filed August 10, 2006, Exhibit 10-2, File No.
001-03141)
|
|
10-5
|
Administration
Agreement dated as of August 10, 2006 between JCP&L Transition Funding
II LLC as Issuer and FirstEnergy Service Company as Administrator. (
incorporated by
reference to
JCP&L’s
Form
8-K filed August 10, 2006, Exhibit 10-3, File No.
001-03141)
|
|
(A)
12-6
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
23-5
|
Consent of Independent Registered Public Accounting Firm |
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
herein electronic format as an
exhibit.
|
3.
Exhibits – Met-Ed
|
3-1
|
Amended
and Restated Articles of Incorporation of Metropolitan Edison Company,
effective December 19, 2007. (
incorporated by
reference to Met-Ed’s
Form 10-K filed February 29, 2008, Exhibit
3.9, File No. 001-00446)
|
|
3-2
|
Amended
and Restated Bylaws of Metropolitan Edison Company, dated
December 14, 2007. (
incorporated by
reference to Met-Ed’s
Form 10-K filed February 29, 2008, Exhibit
3.10, File No. 001-00446)
|
289
|
4-1
|
Indenture
of Metropolitan Edison Company, dated November 1, 1944, between
Metropolitan Edison Company and United States Trust Company of New York,
Successor Trustee, as amended and supplemented by fourteen supplemental
indentures dated February 1, 1947 through May 1, 1960. (Metropolitan
Edison Company’s Instruments of Indebtedness Nos. 1 to 14 inclusive, and
16, incorporated by reference to Amendment No. 1 to 1959 Annual Report of
GPU, Inc. on Form U5S, File Nos. 30-126 and 1-3292)
|
|
4-1(a)
|
Supplemental
Indenture of Metropolitan Edison Company, dated December 1,
1962. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(1))
|
|
4-1(b)
|
Supplemental
Indenture of Metropolitan Edison Company, dated March 20, 1964. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(2))
|
|
4-1(c)
|
Supplemental
Indenture of Metropolitan Edison Company, dated July 1, 1965. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(3))
|
|
4-1(d)
|
Supplemental
Indenture of Metropolitan Edison Company, dated June 1, 1966. (
incorporated by
reference to
Registration No. 2-24883, Exhibit
2-B-4))
|
|
4-1(e)
|
Supplemental
Indenture of Metropolitan Edison Company, dated March 22, 1968. (
incorporated by
reference to
Registration No. 2-29644, Exhibit
4-C-5)
|
|
4-1(f)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1, 1968. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(6))
|
|
4-1(g)
|
Supplemental
Indenture of Metropolitan Edison Company, dated August 1, 1969. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(7))
|
|
4-1(h)
|
Supplemental
Indenture of Metropolitan Edison Company, dated November 1, 1971. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(8))
|
|
4-1(i)
|
Supplemental
Indenture of Metropolitan Edison Company, dated May 1, 1972. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(9))
|
|
4-1(j)
|
Supplemental
Indenture of Metropolitan Edison Company, dated December 1, 1973. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(10))
|
|
4-1(k)
|
Supplemental
Indenture of Metropolitan Edison Company, dated October 30, 1974. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(11))
|
|
4-1(l)
|
Supplemental
Indenture of Metropolitan Edison Company, dated October 31, 1974. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(12))
|
|
4-1(m)
|
Supplemental
Indenture of Metropolitan Edison Company, dated March 20, 1975. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(13))
|
|
4-1(n)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 25, 1975. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(15))
|
|
4-1(o)
|
Supplemental
Indenture of Metropolitan Edison Company, dated January 12, 1976. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(16))
|
|
4-1(p)
|
Supplemental
Indenture of Metropolitan Edison Company, dated March 1, 1976. (
incorporated by
reference to
Registration No. 2-59678, Exhibit
2-E(17))
|
|
4-1(q)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 28, 1977. (
incorporated by
reference to
Registration No. 2-62212, Exhibit
2-E(18))
|
|
4-1(r)
|
Supplemental
Indenture of Metropolitan Edison Company, dated January 1, 1978. (
incorporated by
reference to
Registration No. 2-62212, Exhibit
2-E(19))
|
|
4-1(s)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1, 1978. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(19))
|
|
4-1(t)
|
Supplemental
Indenture of Metropolitan Edison Company, dated June 1, 1979. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(20))
|
|
4-1(u)
|
Supplemental
Indenture of Metropolitan Edison Company, dated January 1, 1980. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(21))
|
|
4-1(v)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1, 1981. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(22))
|
|
4-1(w)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 10, 1981. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(23))
|
|
4-1(x)
|
Supplemental
Indenture of Metropolitan Edison Company, dated December 1, 1982. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(24))
|
|
4-1(y)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1, 1983. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(25))
|
|
4-1(z)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1, 1984. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(26))
|
|
4-1(aa)
|
Supplemental
Indenture of Metropolitan Edison Company, dated March 1, 1985. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(27))
|
|
4-1(bb)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1,
1985. (Registration No. 33-48937, Exhibit
4-A(28))
|
290
|
4-1(cc)
|
Supplemental
Indenture of Metropolitan Edison Company, dated June 1, 1988. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(29))
|
|
4-1(dd)
|
Supplemental
Indenture of Metropolitan Edison Company, dated April 1, 1990. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(30))
|
|
4-1(ee)
|
Amendment
dated May 22, 1990 to Supplemental Indenture of Metropolitan Edison
Company, dated April 1, 1990. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(31))
|
|
4-1(ff)
|
Supplemental
Indenture of Metropolitan Edison Company, dated September 1,
1992. (
incorporated by
reference to
Registration No. 33-48937, Exhibit
4-A(32)(a))
|
|
4-1(gg)
|
Supplemental
Indenture of Metropolitan Edison Company, dated December 1, 1993. (
incorporated by
reference to
GPU, Inc.’s Form U5S filed May 2, 1994, Exhibit C-58,
File No. 30-126)
|
|
4-1(hh)
|
Supplemental
Indenture of Metropolitan Edison Company, dated July 15, 1995. (
incorporated by
reference to
1995 Form 10-K, Exhibit 4-B-35, File No.
1-446)
|
|
4-1(ii)
|
Supplemental
Indenture of Metropolitan Edison Company, dated August 15, 1996. (
incorporated by
reference to
Met-Ed’s Form 10-K filed March 10, 1997, Exhibit
4-B-35, File No. 033-51001)
|
|
4-1(jj)
|
Supplemental
Indenture of Metropolitan Edison Company, dated May 1, 1997. (
incorporated by
reference to
Met-Ed’s Form 10-K filed March 13, 1998, Exhibit
4-B-36, File No. 033-51001)
|
|
4-1(kk)
|
Supplemental
Indenture of Metropolitan Edison Company, dated July 1, 1999. (
incorporated by
reference to
Met-Ed’s Form 10-K filed March 20, 2000, Exhibit
4-B-38, File No. 033-51001)
|
|
4-1(ll)
|
Supplemental
Indenture of Metropolitan Edison Company, dated May 1, 2001. (
incorporated by
reference to
Met-Ed’s Form 10-K filed April 1,
2002, Exhibit 4-5, File No. 033-51001)
|
|
4-1(mm)
|
Supplemental
Indenture of Metropolitan Edison Company, dated March 1, 2003. (
incorporated by
reference to
Met-Ed’s Form 10-K filed March 15, 2004, Exhibit 4-10,
File No. 033-51001)
|
|
4-2
|
Senior
Note Indenture between Metropolitan Edison Company and United States Trust
Company of New York, dated July 1, 1999. (incorporated by reference to
GPU, Inc.’s Form U5S filed May 2, 2002, Exhibit C-154, File No.
001-06047)
|
|
4-2(a)
|
Form
of Metropolitan Edison Company 7.70% Senior Notes due 2019. (
incorporated by
reference to
Met-Ed’s Form 8-K filed January 21, 2009, Exhibit 4.1,
File No. 001-00446)
|
|
(A)
12-7
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
23-6
|
Consent of Independent Registered Public Accounting Firm |
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
herein electronic format as an
exhibit.
|
3.
Exhibits – Penelec
|
3-1
|
Amended
and Restated Articles of Incorporation of Pennsylvania Electric Company,
effective December 19, 2007. (
incorporated by
reference to Penelec’s
Form 10-K filed February 29, 2008, Exhibit
3.11, File No. 001-03522)
|
|
3-2
|
Amended
and Restated Bylaws of Pennsylvania Electric Company, dated
December 14, 2007. (
incorporated by
reference to Penelec’s
Form 10-K filed February 29, 2008, Exhibit
3.12, File No. 001-03522)
|
|
4-1
|
Mortgage
and Deed of Trust of Pennsylvania Electric Company, dated
January 1, 1942, between Pennsylvania Electric Company and
United States Trust Company of New York, Successor Trustee, and indentures
supplemental thereto dated March 7, 1942 through May 1, 1960 –
(Pennsylvania Electric Company’s Instruments of Indebtedness Nos. 1-20,
inclusive, incorporated by reference to Amendment No. 1 to 1959 Annual
Report of GPU on Form U5S, File Nos. 30-126 and
1-3292)
|
291
|
4-1(a)
|
Supplemental
Indentures to Mortgage and Deed of Trust of Pennsylvania Electric Company,
dated May 1, 1961 through December 1, 1977. (incorporated by reference to
Registration No. 2-61502, Exhibit 2-D(1) to 2-D(19))
|
|
4-1(b)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated June 1, 1978.
(incorporated by reference to Registration No. 33-49669, Exhibit
4-A(2))
|
|
4-1(c)
|
Supplemental
Indenture of Pennsylvania Electric Company dated June 1, 1979.
(incorporated by reference to Registration No. 33-49669, Exhibit
4-A(3))
|
|
4-1(d)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated September 1, 1984.
(incorporated by reference to Registration No. 33-49669, Exhibit
4-A(4))
|
|
4-1(e)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated December 1, 1985.
(incorporated by reference to Registration No. 33-49669, Exhibit
4-A(5))
|
|
4-1(f)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated December 1, 1986.
(incorporated by reference to Registration No. 33-49669, Exhibit
4-A(6))
|
|
4-1(g)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated May 1, 1989.
(incorporated by reference to Registration No. 33-49669, Exhibit
4-A(7))
|
|
4-1(h)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated December 1, 1990.
(incorporated by reference to Registration No. 33-45312, Exhibit
4-A(8))
|
|
4-1(i)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated March 1, 1992.
(incorporated by reference to Registration No. 33-45312, Exhibit
4-A(9))
|
|
4-1(j)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated June 1, 1993.
(incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 1994,
Exhibit C-73, File No. 001-06047)
|
|
4-1(k)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated November 1, 1995.
(incorporated by reference to 1995 Form 10-K, Exhibit 4-C-11, File No.
1-3522)
|
|
4-1(l)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated August 15, 1996.
(incorporated by reference to Penelec’s Form 10-K filed March 10, 1997,
Exhibit 4-C-12, File No. 001-03522)
|
|
4-1(m)
|
Supplemental
Indenture of Pennsylvania Electric Company, dated May 1, 2001.
(incorporated by reference to Penelec’s Form 10-K filed April 1, 2002,
Exhibit 4-C-16, File No. 001-03522)
|
|
4-2
|
Senior
Note Indenture between Pennsylvania Electric Company and United States
Trust Company of New York, dated April 1, 1999. (incorporated by reference
to Penelec’s Form 10-K filed March 20, 2000, Exhibit 4-C-13, File No.
001-03522)
|
|
4-2(a)
|
Form
of Pennsylvania Electric Company 6.05% Senior Notes due 2017.
(incorporated by reference to Penelec’s Form 8-K filed August 31, 2007,
Exhibit 4.1, File No. 001-03522)
|
|
4-2(b)
|
Company
Order, dated as of September 30, 2009 establishing the terms of the 5.20%
Senior Notes due 2020 and 6.15% Senior Notes due
2038 (incorporated by reference to Penelec's Form 8-K filed
October 6, 2009, Exhibit 4.1, File No. 001-03522)
|
|
4-2(c)
|
Supplemental
Indenture No. 2, dated as of October 1, 2009, to the Indenture dated as of
April 1, 2009, as amended, between Pennsylvania Electric Company and The
Bank of New York Mellon, as successor trustee (incorporated by reference
to Penelec's Form 8-K filed October 6, 2009, Exhibit 4.4, File No.
001-03522)
|
|
4-2(d)
|
Agreement
of Resignation, Appointment and Acceptance among The Bank of New York
Mellon, as Resigning Trustee, The Bank of New York Mellon Trust Company,
N.A., as Successor Trustee and Pennsylvania Electric Company, dated
October 1, 2009 (incorporated by reference to Penelec's Form 8-K filed on
October 6, 2009, Exhibit 4.5, File No. 001-03522)
|
|
(A)
12-8
|
Consolidated
ratios of earnings to fixed charges.
|
|
(A)
23-7
|
Consent
of Independent Registered Public Accounting Firm.
|
|
(A)
31-1
|
Certification
of chief executive officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
|
(A)
31-2
|
Certification
of chief financial officer, as adopted pursuant to Rule
13a-15(e)/15d-15(e).
|
292
|
(A)
32
|
Certification
of chief executive officer and chief financial officer, pursuant to 18
U.S.C. §1350.
|
|
(A)
|
Provided
here in electronic format as an
exhibit.
|
3.
Exhibits - Common Exhibits for FES, Met-Ed and Penelec
|
10-1
|
Notice
of Termination Tolling Agreement dated as of April 7, 2006; Restated
Partial Requirements Agreement, dated January 1, 2003, by and among,
Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly
Electric Power and Light Company and FirstEnergy Solutions Corp., as
amended by a First Amendment to Restated Requirements Agreement, dated
August 29, 2003 and by a Second Amendment to Restated Requirements
Agreement, dated June 8, 2004 (“Partial Requirements Agreement”).
(incorporated by reference to Met-Ed’s Form 10-Q filed May 9, 2006,
Exhibit 10-5, File No. 001-00446)
|
|
10-2
|
Third
Restated Partial Requirements Agreement, among Metropolitan Edison
Company, Pennsylvania Electric Company, a Pennsylvania corporation, The
Waverly Electric Power and Light Company and FirstEnergy Solutions Corp.,
dated November 1, 2008. (incorporated by reference to Met-Ed’s Form 10-Q
filed November 7, 2008, Exhibit 10-2, File No.
001-00446)
|
|
10-3
|
Fourth
Restated Partial Requirements Agreement, among Metropolitan Edison
Company, Pennsylvania Electric Company, a Pennsylvania corporation, The
Waverly Electric Power and Light Company and FirstEnergy Solutions Corp.,
dated November 1, 2008. (incorporated by reference to Met-Ed’s Form 10-Q
filed November 9, 2009, Exhibit 10.2, File No.
001-00446)
|
3.
Exhibits - Common Exhibits for FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed
and Penelec
|
10-1
|
$2,750,000,000 Credit Agreement dated as of August
24, 2006 among FirstEnergy Corp., FirstEnergy Solutions Corp., American
Transmission Systems, Inc., Ohio Edison Company, Pennsylvania Power
Company, The Cleveland Electric Illuminating Company, The Toledo Edison
Company Jersey Central Power & Light Company, Metropolitan Edison
Company and Pennsylvania Electric Company, as Borrowers, the banks party
thereto, the fronting banks party thereto and the swing line lenders party
thereto. (incorporated by reference to FE’s Form 8-K filed August 24,
2006, Exhibit 10-1, File N
o. 333-21011)
|
|
10-2
|
Consent
and Amendment to $2,750,000,000 Credit Agreement dated November 2,
2007. (
incorporated by
reference to FE’s
Form 10-K filed February 29, 2008, Exhibit
10-2
, File N
o.
333-21011)
|
293
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholders and Board of Directors of
FirstEnergy
Corp.:
Our audits of the
consolidated
financial statements and of the effectiveness of
internal control over financial reporting referred to in our report
dated
February 18, 2010 also included an audit of the financial statement schedule
listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial
statement schedule presents fairly, in all material respects, the information
set forth therein when read in conjunction with the related consolidated
financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
294
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
FirstEnergy
Solutions Corp.:
Our audits of the
consolidated
financial statements referred to in our report dated
February 18, 2010
also included an audit of the financial statement
schedule listed in Item 15(a)(2) of this Form 10-K.
In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
295
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
Ohio
Edison Company:
Our audits of the
consolidated financial
statements referred to in
our report
dated
February 18, 2010 also included an audit of the financial statement schedule
listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial
statement schedule presents fairly, in all material respects, the information
set forth therein when read in conjunction with the related consolidated
financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
296
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
The
Cleveland Electric Illuminating Company:
Our audits of the
consolidated financial
statements referred to in
our report dated
February 18, 2010
also included an audit of the financial statement
schedule listed in Item 15(a)(2) of this Form 10-K.
In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
297
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
The
Toledo Edison Company:
Our audits of the
consolidated financial
statements referred to in
our report dated
February 18, 2010
also included an audit of the financial statement
schedule listed in Item 15(a)(2) of this Form 10-K.
In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
298
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
Jersey
Central Power & Light Company:
Our audits of the
consolidated financial
statements referred to in
our report dated
February 18, 2010
also included an audit of the financial statement
schedule listed in Item 15(a)(2) of this Form 10-K.
In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
299
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
Metropolitan
Edison Company:
Our audits of the
consolidated financial
statements referred to in
our report dated
February 18, 2010
also included an audit of the financial statement
schedule listed in Item 15(a)(2) of this Form 10-K.
In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
300
Report of Independent
Registered Public
Accounting Firm
on
Financial
Statement Schedule
To the
Stockholder and Board of Directors of
Pennsylvania
Electric Company:
Our audits of the
consolidated financial
statements referred to in
our report dated
February 18, 2010
also included an audit of the financial statement
schedule listed in Item 15(a)(2) of this Form 10-K.
In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
PricewaterhouseCoopers
LLP
Cleveland,
Ohio
February
18, 2010
301
SCHEDULE
II
|
FIRSTENERGY
CORP.
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to
Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 27,847 | $ | 67,503 | $ | 32,975 | (a) | $ | 94,894 | (b) | $ | 33,431 | ||||||||
|
–
other
|
$ | 9,167 | $ | (405 | ) | $ | 10,457 | (a) | $ | 12,250 | (b) | $ | 6,969 | |||||||
|
Loss
carryforward
|
||||||||||||||||||||
|
tax
valuation reserve
|
$ | 27,294 | $ | (1,091 | ) | $ | (4,921 | ) | $ | - | $ | 21,282 | ||||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 35,567 | $ | 48,297 | $ | 31,308 | (a) | $ | 87,325 | (b) | $ | 27,847 | ||||||||
|
–
other
|
$ | 21,924 | $ | 11,339 | $ | 3,189 | (a) | $ | 27,285 | (b) | $ | 9,167 | ||||||||
|
Loss
carryforward
|
||||||||||||||||||||
|
tax
valuation reserve
|
$ | 30,616 | $ | 1,435 | $ | (4,757 | ) | $ | - | $ | 27,294 | |||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 43,214 | $ | 53,522 | $ | 50,165 | (a) | $ | 111,334 | (b) | $ | 35,567 | ||||||||
|
–
other
|
$ | 23,964 | $ | 4,933 | $ | 406 | (a) | $ | 7,379 | (b) | $ | 21,924 | ||||||||
|
Loss
carryforward
|
||||||||||||||||||||
|
tax
valuation reserve
|
$ | 415,531 | $ | 8,819 | $ | (393,734 | ) | $ | - | $ | 30,616 | |||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
302
SCHEDULE
II
|
FIRSTENERGY
SOLUTIONS CORP.
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 5,899 | $ | 6,142 | $ | - | (a) | $ | - | (b) | $ | 12,041 | ||||||||
|
–
other
|
$ | 6,815 | $ | (161 | ) | $ | 57 | (a) | $ | 9 | (b) | $ | 6,702 | |||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 8,072 | $ | (2,174 | ) | $ | 110 | (a) | $ | 109 | (b) | $ | 5,899 | |||||||
|
–
other
|
$ | 9 | $ | 4,374 | $ | 2,541 | (a) | $ | 109 | (b) | $ | 6,815 | ||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 7,938 | $ | 94 | $ | 532 | (a) | $ | 492 | (b) | $ | 8,072 | ||||||||
|
–
other
|
$ | 5,593 | $ | 9 | $ | - | (a) | $ | 5,593 | (b) | $ | 9 | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
303
SCHEDULE
II
|
OHIO
EDISON COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to
Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 6,065 | $ | 16,230 | $ | 11,252 | (a) | $ | 28,428 | (b) | $ | 5,119 | ||||||||
|
–
other
|
$ | 7 | $ | 17 | $ | 326 | (a) | $ | 332 | (b) | $ | 18 | ||||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 8,032 | $ | 12,179 | $ | 10,027 | (a) | $ | 24,173 | (b) | $ | 6,065 | ||||||||
|
–
other
|
$ | 5,639 | $ | 16,618 | $ | 394 | (a) | $ | 22,644 | (b) | $ | 7 | ||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 15,033 | $ | 10,513 | $ | 30,234 | (a) | $ | 47,748 | (b) | $ | 8,032 | ||||||||
|
–
other
|
$ | 1,985 | $ | 4,117 | $ | (240 | )(a) | $ | 223 | (b) | $ | 5,639 | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
304
SCHEDULE
II
|
THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to
Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 5,916 | $ | 16,764 | $ | 8,942 | (a) | $ | 26,383 | (b) | $ | 5,239 | ||||||||
|
–
other
|
$ | 11 | $ | 50 | $ | 51 | (a) | $ | 91 | (b) | $ | 21 | ||||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 7,540 | $ | 11,323 | $ | 9,179 | (a) | $ | 22,126 | (b) | $ | 5,916 | ||||||||
|
–
other
|
$ | 433 | $ | (183 | ) | $ | 30 | (a) | $ | 269 | (b) | $ | 11 | |||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 6,783 | $ | 17,998 | $ | 7,842 | (a) | $ | 25,083 | (b) | $ | 7,540 | ||||||||
|
–
other
|
$ | - | $ | 431 | $ | 124 | (a) | $ | 122 | (b) | $ | 433 | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
305
SCHEDULE
II
|
THE
TOLEDO EDISON COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 203 | $ | (115 | ) | $ | 165 | (a) | $ | 45 | (b) | $ | 208 | |||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 615 | $ | (247 | ) | $ | 121 | (a) | $ | 286 | (b) | $ | 203 | |||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts
|
$ | 430 | $ | 361 | $ | 13 | (a) | $ | 189 | (b) | $ | 615 | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
306
SCHEDULE
II
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,230 | $ | 11,519 | $ | 5,424 | (a) | $ | 16,667 | (b) | $ | 3,506 | ||||||||
|
–
other
|
$ | 45 | $ | (37 | ) | $ | 380 | (a) | $ | 388 | (b) | $ | - | |||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,691 | $ | 10,377 | $ | 3,504 | (a) | $ | 14,342 | (b) | $ | 3,230 | ||||||||
|
–
other
|
$ | - | $ | 44 | $ | 24 | (a) | $ | 23 | (b) | $ | 45 | ||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,524 | $ | 8,563 | $ | 4,049 | (a) | $ | 12,445 | (b) | $ | 3,691 | ||||||||
|
–
other
|
$ | - | $ | - | $ | - | (a) | $ | - | (b) | $ | - | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
307
SCHEDULE
II
|
METROPOLITAN
EDISON COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to
Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,616 | $ | 9,583 | $ | 3,926 | (a) | $ | 13,081 | (b) | $ | 4,044 | ||||||||
|
–
other
|
$ | - | $ | 8 | $ | 26 | (a) | $ | 34 | (b) | $ | - | ||||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 4,327 | $ | 9,004 | $ | 3,729 | (a) | $ | 13,444 | (b) | $ | 3,616 | ||||||||
|
–
other
|
$ | 1 | $ | 19 | $ | 21 | (a) | $ | 41 | (b) | $ | - | ||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 4,153 | $ | 9,971 | $ | 3,548 | (a) | $ | 13,345 | (b) | $ | 4,327 | ||||||||
|
–
other
|
$ | 2 | $ | 245 | $ | 18 | (a) | $ | 264 | (b) | $ | 1 | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
308
SCHEDULE
II
|
PENNSYLVANIA
ELECTRIC COMPANY
|
||||||||||||||||||||
|
CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS
|
||||||||||||||||||||
|
FOR
THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
|
||||||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
Beginning
|
Charged
|
to
Other
|
Ending
|
|||||||||||||||||
|
Description
|
Balance
|
to Income
|
Accounts
|
Deductions
|
Balance
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Year
Ended December 31, 2009:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,121 | $ | 7,264 | $ | 3,431 | (a) | $ | 10,333 | (b) | $ | 3,483 | ||||||||
|
–
other
|
$ | 65 | $ | (57 | ) | $ | 7,557 | (a) | $ | 7,562 | (b) | $ | 3 | |||||||
|
Year
Ended December 31, 2008:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,905 | $ | 7,589 | $ | 4,758 | (a) | $ | 13,131 | (b) | $ | 3,121 | ||||||||
|
–
other
|
$ | 105 | $ | 57 | $ | 36 | (a) | $ | 133 | (b) | $ | 65 | ||||||||
|
Year
Ended December 31, 2007:
|
||||||||||||||||||||
|
Accumulated
provision for
|
||||||||||||||||||||
|
uncollectible
accounts – customers
|
$ | 3,814 | $ | 8,351 | $ | 3,958 | (a) | $ | 12,218 | (b) | $ | 3,905 | ||||||||
|
–
other
|
$ | 3 | $ | 181 | $ | 3 | (a) | $ | 82 | (b) | $ | 105 | ||||||||
|
(a) Represents
recoveries and reinstatements of accounts previously written
off.
|
||||||||||||||||||||
|
(b) Represents
the write-off of accounts considered to be uncollectible.
|
||||||||||||||||||||
309
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
|
FIRSTENERGY
CORP.
|
|
|
BY:
/s/ Anthony J. Alexander
|
|
|
Anthony
J. Alexander
|
|
|
President
and Chief Executive Officer
|
Date: February
18, 2010
310
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ George
M. Smart
|
/s/ Anthony
J. Alexander
|
|
|
George
M. Smart
|
Anthony
J. Alexander
|
|
|
Chairman
of the Board
|
President
and Chief Executive Officer
|
|
|
and
Director (Principal Executive Officer)
|
||
|
/s/ Mark
T. Clark
|
/s/ Harvey
L. Wagner
|
|
|
Mark
T. Clark
|
Harvey
L. Wagner
|
|
|
Executive
Vice President and Chief Financial
|
Vice
President, Controller and Chief Accounting
|
|
|
Officer
(Principal Financial Officer)
|
Officer
(Principal Accounting Officer)
|
|
|
/s/ Paul
T. Addison
|
/s/
Ernest J. Novak,
Jr.
|
|
|
Paul
T. Addison
|
Ernest
J. Novak, Jr.
|
|
|
Director
|
Director
|
|
|
/s/ Michael
J. Anderson
|
/s/ Catherine
A. Rein
|
|
|
Michael
J. Anderson
|
Catherine
A. Rein
|
|
|
Director
|
Director
|
|
|
/s/ Carol
A. Cartwright
|
/s/ Wes
M. Taylor
|
|
|
Carol
A. Cartwright
|
Wes
M. Taylor
|
|
|
Director
|
Director
|
|
|
/s/ William
T. Cottle
|
/s/
Jesse T. Williams,
Sr.
|
|
|
William
T. Cottle
|
Jesse
T. Williams, Sr.
|
|
|
Director
|
Director
|
|
|
/s/ Robert
B. Heisler, Jr.
|
||
|
Robert
B. Heisler, Jr.
|
||
|
Director
|
||
Date: February
18,
2010
311
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
FIRSTENERGY
SOLUTIONS CORP.
|
|
|
BY: /s/
Donald R. Schneider
|
|
|
Donald
R. Schneider
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ Donald
R. Schneider
|
/s/
Mark T. Clark
|
|
|
Donald
R. Schneider
|
Mark
T. Clark
|
|
|
President
|
Executive
Vice President and Chief
|
|
|
(Principal
Executive Officer)
|
Financial
Officer and Director
|
|
|
(Principal
Financial Officer)
|
||
|
/s/ Anthony
J. Alexander
|
/s/ Harvey
L. Wagner
|
|
|
Anthony
J. Alexander
|
Harvey
L. Wagner
|
|
|
Director
|
Vice
President and Controller
|
|
|
(Principal
Accounting Officer)
|
||
|
/s/ Gary
R. Leidich
|
||
|
Gary
R. Leidich
|
||
|
Director
|
||
Date: February
18, 2010
312
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
OHIO
EDISON COMPANY
|
|
|
BY: /s/
Richard R. Grigg
|
|
|
Richard
R. Grigg
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ Anthony
J. Alexander
|
/s/ Richard
R. Grigg
|
|
|
Anthony
J. Alexander
|
Richard
R. Grigg
|
|
|
Director
|
President
and Director
|
|
|
(Principal
Executive Officer)
|
||
|
/s/
Mark T. Clark
|
/s/ Harvey
L. Wagner
|
|
|
Mark
T. Clark
|
Harvey
L. Wagner
|
|
|
Executive
Vice President and Chief
|
Vice
President and Controller
|
|
|
Financial
Officer and Director
|
(Principal
Accounting Officer)
|
|
|
(Principal
Financial Officer)
|
Date: February
18, 2010
313
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
THE
CLEVELAND ELECTRIC
ILLUMINATING
COMPANY
|
|
|
BY: /s/
Richard R. Grigg
|
|
|
Richard
R. Grigg
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ Anthony
J. Alexander
|
/s/ Richard
R. Grigg
|
|
|
Anthony
J. Alexander
|
Richard
R. Grigg
|
|
|
Director
|
President
and Director
|
|
|
(Principal
Executive Officer)
|
||
|
/s/ Mark
T. Clark
|
/s/ Harvey
L. Wagner
|
|
|
Mark
T. Clark
|
Harvey
L. Wagner
|
|
|
Executive
Vice President and Chief
|
Vice
President and Controller
|
|
|
Financial
Officer and Director
|
(Principal
Accounting Officer)
|
|
|
(Principal
Financial Officer)
|
Date: February
18, 2010
314
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
THE
TOLEDO EDISON COMPANY
|
|
|
BY: /s/
Richard R. Grigg
|
|
|
Richard
R. Grigg
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/
Anthony J. Alexander
|
/s/ Richard
R. Grigg
|
|
|
Anthony
J. Alexander
|
Richard
R. Grigg
|
|
|
Director
|
President
and Director
|
|
|
(Principal
Executive Officer)
|
||
|
/s/
Mark T. Clark
|
/s/ Harvey
L. Wagner
|
|
|
Mark
T. Clark
|
Harvey
L. Wagner
|
|
|
Executive
Vice President and Chief
|
Vice
President and Controller
|
|
|
Financial
Officer and Director
|
(Principal
Accounting Officer)
|
|
|
(Principal
Financial Officer)
|
Date: February
18, 2010
315
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
JERSEY
CENTRAL POWER & LIGHT COMPANY
|
|
|
BY:
/s/ Donald M. Lynch
|
|
|
Donald
M. Lynch
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ Donald
M. Lynch
|
/s/ Kevin
R. Burgess
|
|
|
Donald
M. Lynch
|
Kevin
R. Burgess
|
|
|
President
and Director
(Principal
Executive Officer)
|
Controller
(Principal
Financial and Accounting Officer)
|
|
|
/s/ Richard
R. Grigg
|
/s/ Gelorma
E. Persson
|
|
|
Richard
R. Grigg
|
Gelorma
E. Persson
|
|
|
Director
|
Director
|
|
|
/s/ Charles
E. Jones
|
/s/ Jesse
T. Williams, Sr.
|
|
|
Charles
E. Jones
|
Jesse
T. Williams, Sr.
|
|
|
Director
|
Director
|
|
|
/s/
Mark A. Julian
|
||
|
Mark
A. Julian
|
||
|
Director
|
Date: February
18, 2010
316
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
METROPOLITAN
EDISON COMPANY
|
|
|
BY: /s/
Richard R. Grigg
|
|
|
Richard
R. Grigg
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ Richard
R. Grigg
|
/s/ Mark
T. Clark
|
|
|
Richard
R. Grigg
|
Mark
T. Clark
|
|
|
President
and Director
|
Executive
Vice President and Chief
|
|
|
(Principal
Executive Officer)
|
Financial
Officer
|
|
|
(Principal
Financial Officer)
|
||
|
/s/ Donald
A. Brennan
|
/s/ Harvey
L. Wagner
|
|
|
Donald
A. Brennan
|
Harvey
L. Wagner
|
|
|
Regional
President and Director
|
Vice
President and Controller
|
|
|
(Principal
Accounting Officer)
|
||
|
/s/ Randy
Scilla
|
||
|
Randy
Scilla
|
||
|
Assistant
Treasurer and Director
|
Date: February
18, 2010
317
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
PENNSYLVANIA
ELECTRIC COMPANY
|
|
|
BY: /s/
Richard R. Grigg
|
|
|
Richard
R. Grigg
|
|
|
President
|
Date: February
18, 2010
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the date indicated:
|
/s/ Richard
R. Grigg
|
/s/ Mark
T. Clark
|
|
|
Richard
R. Grigg
|
Mark
T. Clark
|
|
|
President
and Director
|
Executive
Vice President and Chief
|
|
|
(Principal
Executive Officer)
|
Financial
Officer
|
|
|
(Principal
Financial Officer)
|
||
|
/s/ James
R. Napier, Jr.
|
/s/ Harvey
L. Wagner
|
|
|
James
R. Napier, Jr.
|
Harvey
L. Wagner
|
|
|
Regional
President and Director
|
Vice
President and Controller
|
|
|
(Principal
Accounting Officer)
|
||
|
/s/ Randy
Scilla
|
||
|
Randy
Scilla
|
||
|
Assistant
Treasurer and Director
|
Date: February
18, 2010
318
TABLE OF CONTENTS
Part IprintItem 1. BusinessprintItem 1A. Risk FactorsprintItem 1B. Unresolved Staff CommentsprintItem 2. PropertiesprintItem 3. Legal ProceedingsprintItem 4. Submission Of Matters To A Vote Of Security HoldersprintPart IIprintItem 5. Market For Registrant S Common Equity, Related StockholderprintItem 6. Selected Financial DataprintItem 7. Management S Discussion and Analysis Of Registrant and SubsidiariesprintItem 7A. Quantitative and Qualitative Disclosures About Market RiskprintItem 8. Financial Statements and Supplementary DataprintItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureprintItem 9. Changes in and Disagreements with Accountants on AccountingprintItem 9A. Controls and Procedures -- FirstenergyprintItem 9a(t). Controls and Procedures --fes, Oe, Cei, Te, Jcp&l, Met-ed and PenelecprintItem 9B. Other InformationprintPart IIIprintItem 10. Directors, Executive Officers and Corporate GovernanceprintItem 11. Executive CompensationprintItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersprintItem 13. Certain Relationships and Related Transactions, and Director IndependenceprintItem 14. Principal Accounting Fees and ServicesprintPart IVprintItem 15. Exhibits, Financial Statement Schedulesprint