Unassociated Document
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
|
o
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
|
For
the transition period from __________
to_________
|
Commission
File Number
|
|
Registrants;
States of Incorporation;
Address and Telephone
Number
|
|
I.R.S.
Employer
Identification Nos.
|
|
1-3525
|
|
American Electric Power
Company, Inc. (A New York Corporation)
|
|
13-4922640
|
|
1-3457
|
|
Appalachian Power
Company (A Virginia Corporation)
|
|
54-0124790
|
|
1-2680
|
|
Columbus Southern Power
Company (An Ohio Corporation)
|
|
31-4154203
|
|
1-3570
|
|
Indiana Michigan Power
Company (An Indiana Corporation)
|
|
35-0410455
|
|
1-6543
|
|
Ohio Power
Company (An Ohio Corporation)
|
|
31-4271000
|
|
0-343
|
|
Public Service Company
of Oklahoma (An Oklahoma Corporation)
|
|
73-0410895
|
|
1-3146
|
|
Southwestern Electric
Power Company (A Delaware Corporation)
1
Riverside Plaza, Columbus, Ohio 43215
Telephone
(614) 716-1000
|
|
72-0323455
|
Indicate
by check mark if the registrants American Electric Power Company, Inc.,
Appalachian Power Company and Ohio Power Company, is each a well-known
seasoned issuer, as defined in Rule 405 on the Securities
Act.
|
Yes x
|
No. o
|
|
|
|
Indicate
by check mark if the registrants Columbus Southern Power Company, Indiana
Michigan Power Company, Public Service Company of Oklahoma and
Southwestern Electric Power Company, are well-known seasoned issuers, as
defined in Rule 405 on the Securities Act.
|
Yes o
|
No. x
|
|
|
|
Indicate
by check mark if the registrants are not required to file reports pursuant
to Section 13 or Section 15(d) of the Exchange Act.
|
Yes o
|
No. x
|
|
|
|
Indicate
by check mark whether the registrants (1) have 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
registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past 90 days.
|
Yes x
|
No. o
|
|
|
|
Indicate
by check mark whether American Electric Power Company, Inc. has submitted
electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule
405 of Regulation S-T (232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to
submit and post such files).
|
Yes x
|
No. o
|
Indicate
by check mark whether Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company have
submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (232.405 of this chapter) during the
preceding 12 months (or for such shorter period that the registrants were
required to submit and post such files).
|
Yes o
|
No. o
|
Indicate
by check mark if disclosure of delinquent filers with respect to
Appalachian Power Company, Ohio Power Company, Public Service Company of
Oklahoma or Southwestern Electric Power Company pursuant to Item 405 of
Regulation S-K (229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive
proxy or information statements of Appalachian Power Company, Ohio Power
Company, Public Service Company of Oklahoma or Southwestern Electric Power
Company incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
|
x
|
|
|
|
|
Indicate
by check mark whether American Electric Power Company, Inc. 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. (Check One)
|
|
|
Large accelerated
filer x
|
Accelerated
filer o
|
Non-accelerated
filer
o (Do not check if
a smaller reporting company)
|
Smaller
reporting
company o
|
|
|
|
Indicate
by check mark whether Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company are
large accelerated filers, accelerated filers, non-accelerated filers or
smaller reporting companies. See definitions of ‘large
accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in
Rule 12b-2 of the Exchange Act. (Check One)
|
|
|
Large
accelerated
filer o
|
Accelerated
filer o
|
Non-accelerated
filer
x (Do not check if
a smaller reporting company)
|
Smaller
reporting
company o
|
|
|
|
Indicate
by check mark if the registrants are shell companies, as defined in Rule
12b-2 of the Exchange Act.
|
Yes o
|
No. x
|
Columbus
Southern Power Company and Indiana Michigan Power 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 such Form 10-K.
Securities
registered pursuant to Section 12(b) of the Act:
Registrant
|
|
Title of each class
|
|
Name
of each exchange
on
which registered
|
American
Electric Power Company, Inc.
|
|
Common
Stock, $6.50 par value
|
|
New
York Stock Exchange
|
Appalachian
Power Company
|
|
None
|
|
|
Columbus
Southern Power Company
|
|
None
|
|
|
Indiana
Michigan Power Company
|
|
6%
Senior Notes, Series D, Due 2032
|
|
New
York Stock Exchange
|
Ohio
Power Company
|
|
None
|
|
|
Public
Service Company of Oklahoma
|
|
6%
Senior Notes, Series B, Due 2032
|
|
New
York Stock Exchange
|
Southwestern
Electric Power Company
|
|
None
|
|
|
Securities
registered pursuant to Section 12(g) of the Act:
Registrant
|
|
Title of each class
|
American
Electric Power Company, Inc.
|
|
None
|
Appalachian
Power Company
|
|
4.50%
Cumulative Preferred Stock, Voting, no par value
|
Columbus
Southern Power Company
|
|
None
|
Indiana
Michigan Power Company
|
|
None
|
Ohio
Power Company
|
|
4.50%
Cumulative Preferred Stock, Voting, $100 par value
|
Public
Service Company of Oklahoma
|
|
None
|
Southwestern
Electric Power Company
|
|
4.28%
Cumulative Preferred Stock, Voting, $100 par value
|
|
|
4.65%
Cumulative Preferred Stock, Voting, $100 par value
|
|
|
5.00%
Cumulative Preferred Stock, Voting, $100 par
value
|
|
|
Aggregate market value of
voting and non-voting common equity held by non-affiliates of the
registrants as of
June 30, 2009, the last trading date of the registrants’ most recently
completed second fiscal quarter
|
|
Number
of shares of common stock outstanding of the registrants at
December
31, 2009
|
American
Electric Power Company, Inc.
|
|
$13,810,991,818
|
|
478,054,407
|
|
|
|
|
($6.50
par value)
|
Appalachian
Power Company
|
|
None
|
|
13,499,500
|
|
|
|
|
(no
par value)
|
Columbus
Southern Power Company
|
|
None
|
|
16,410,426
|
|
|
|
|
(no
par value)
|
Indiana
Michigan Power Company
|
|
None
|
|
1,400,000
|
|
|
|
|
(no
par value)
|
Ohio
Power Company
|
|
None
|
|
27,952,473
|
|
|
|
|
(no
par value)
|
Public
Service Company of Oklahoma
|
|
None
|
|
9,013,000
|
|
|
|
|
($15
par value)
|
Southwestern
Electric Power Company
|
|
None
|
|
7,536,640
|
|
|
|
|
($18
par value)
|
Note
On Market Value Of Common Equity Held By Non-Affiliates
American
Electric Power Company, Inc. owns all of the common stock of Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio
Power Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company (see Item 12 herein).
Documents
Incorporated By Reference
Description
|
Part
of Form 10-K
Into
Which Document Is Incorporated
|
|
|
Portions
of Annual Reports of the following companies for
the
fiscal year ended December 31, 2009:
|
Part
II
|
American Electric Power Company,
Inc.
|
|
Appalachian Power
Company
|
|
Columbus Southern Power
Company
|
|
Indiana Michigan Power
Company
|
|
Ohio Power
Company
|
|
Public Service Company of
Oklahoma
|
|
Southwestern Electric Power
Company
|
|
|
|
Portions
of Proxy Statement of American Electric Power Company, Inc. for 2009
Annual Meeting of Shareholders.
|
Part
III
|
|
|
Portions
of Information Statements of the following companies for 2009 Annual
Meeting of Shareholders:
|
Part
III
|
Appalachian Power
Company
|
|
Ohio Power
Company
|
|
Public Service Company of
Oklahoma
|
|
Southwestern Electric Power
Company
|
|
This
combined Form 10-K is separately filed by American Electric Power Company, Inc.,
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Ohio Power Company, Public Service Company of Oklahoma and
Southwestern Electric Power Company. Information contained herein
relating to any individual registrant is filed by such registrant on its own
behalf. Except for American Electric Power Company, Inc., each registrant makes
no representation as to information relating to the other
registrants.
You
can access financial and other information at AEP’s website, including AEP’s
Principles of Business Conduct (which also serves as a code of ethics applicable
to Item 10 of this Form 10-K), certain committee charters and Principles of
Corporate Governance. The address is www.AEP.com. AEP makes
available, free of charge on its website, copies of its annual report on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments
to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934 as soon as reasonably practicable after filing
such material electronically or otherwise furnishing it to the SEC.
TABLE
OF CONTENTS
Item
Number
|
|
|
|
Glossary
of Terms
|
|
|
Forward-Looking
Information
|
|
PART
I
|
1
|
|
Business
|
|
|
|
General
|
|
|
|
Utility
Operations
|
|
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AEP
River
Operations
|
|
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|
Generation
and
Marketing
|
|
1
|
A
|
Risk
Factors
|
|
1
|
B
|
Unresolved
Staff
Comments
|
|
2
|
|
Properties
|
|
|
|
Generation
Facilities
|
|
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Transmission
and Distribution
Facilities
|
|
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|
Titles
|
|
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|
System
Transmission Lines and Facility
Siting
|
|
|
|
Construction
Program
|
|
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|
Potential
Uninsured
Losses
|
|
3
|
|
Legal
Proceedings
|
|
4
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Submission
Of Matters To A Vote Of Security
Holders
|
|
|
|
Executive
Officers of the
Registrant
|
|
PART
II
|
5
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|
Market
For Registrants’ Common Equity, Related Stockholder Matters And
Issuer Purchases Of Equity Securities
|
|
6
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|
Selected
Financial
Data
|
|
7
|
|
Management’s
Discussion And Analysis Of Financial Condition And Results
Of
Operations
|
|
7
|
A
|
Quantitative
And Qualitative Disclosures About Market
Risk
|
|
8
|
|
Financial
Statements And Supplementary
Data
|
|
9
|
|
Changes
In And Disagreements With Accountants On Accounting And
Financial Disclosure
|
|
9
|
A
|
Controls
And
Procedures
|
|
9
|
B
|
Other
Information
|
|
PART
III
|
10
|
|
Directors,
Executive Officers and Corporate
Governance
|
|
11
|
|
Executive
Compensation
|
|
12
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|
Security
Ownership Of Certain Beneficial Owners and Management And Related
Stockholder Matters
|
|
13
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|
Certain
Relationships and Related Transactions, And Director Independence
|
|
14
|
|
Principal
Accounting Fees And
Services
|
|
PART
IV
|
15
|
|
Exhibits
and Financial Statement
Schedules
|
|
|
|
Financial
Statements
|
|
|
|
Signatures
|
|
|
|
Exhibit
Index
|
|
GLOSSARY
OF TERMS
The
following abbreviations or acronyms used in this Form 10-K are defined
below:
Abbreviation or Acronym
|
Definition
|
AECC
|
Arkansas
Electric Cooperative Corporation, an unaffiliated
corporation
|
AEGCo
|
AEP
Generating Company, an electric utility subsidiary of
AEP
|
AEP
or parent
|
American
Electric Power Company, Inc.
|
AEP
East companies
|
APCo,
CSPCo, I&M, KPCo and OPCo
|
AEP
Power Pool
|
APCo,
CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection
Agreement
|
AEP
River Operations
|
AEP’s
inland river transportation subsidiary, AEP River Operations LLC (formerly
AEP MEMCO LLC), operating primarily on the Ohio, Illinois, and lower
Mississippi rivers
|
AEPSC
|
American
Electric Power Service Corporation, a service company subsidiary of
AEP
|
AEP
System or the System
|
The
American Electric Power System, an integrated electric utility system,
owned and operated by AEP’s electric utility
subsidiaries
|
AEP
West companies
|
PSO,
SWEPCo, TCC and TNC
|
AEP
Utilities
|
AEP
Utilities, Inc., a subsidiary of AEP, formerly, Central and South West
Corporation
|
AFUDC
|
Allowance
for funds used during construction (the net cost of borrowed funds, and a
reasonable rate of return on other funds, used for construction under
regulatory accounting)
|
ALJ
|
Administrative
law judge
|
APCo
|
Appalachian
Power Company, a public utility subsidiary of AEP
|
APSC
|
Arkansas
Public Service Commission
|
Buckeye
|
Buckeye
Power, Inc., an unaffiliated corporation
|
CAA
|
Clean
Air Act
|
CAAA
|
Clean
Air Act Amendments of 1990
|
CCS
|
Carbon
capture and storage technology
|
CERCLA
|
Comprehensive
Environmental Response, Compensation and Liability Act of
1980
|
CO2
|
Carbon
dioxide and other greenhouse gases
|
Cook
Plant
|
The
Donald C. Cook Nuclear Plant, owned by I&M, and located near Bridgman,
Michigan
|
CSPCo
|
Columbus
Southern Power Company, a public utility subsidiary of
AEP
|
CSW
|
Central
and South West Corporation, a public utility holding company that merged
with AEP in June 2000.
|
CSW
Operating Agreement
|
Agreement,
dated January 1, 1997, as amended, originally by and among PSO, SWEPCo,
TCC and TNC, currently by and between PSO and SWEPCO governing generating
capacity allocation. AEPSC acts as the agent for the
parties.
|
DOE
|
United
States Department of Energy
|
DP&L
|
The
Dayton Power and Light Company, an unaffiliated utility
company
|
Duke
Ohio
|
Duke
Energy Ohio, Inc.
|
EMF
|
Electric
and Magnetic Fields
|
EPA
|
United
States Environmental Protection Agency
|
EPACT
|
The
Energy Policy Act of 2005
|
ERCOT
|
Electric
Reliability Council of Texas
|
ESP
|
Electric
Security Plans, filed with the PUCO, pursuant to the Ohio
Amendments
|
ETEC
|
East
Texas Electric Cooperative
|
FERC
|
Federal
Energy Regulatory Commission
|
Fitch
|
Fitch
Ratings, Inc.
|
FPA
|
Federal
Power Act
|
I&M
|
Indiana
Michigan Power Company, a public utility subsidiary of
AEP
|
IGCC
|
Integrated
Gasification Combined Cycle
|
Interconnection
Agreement
|
Agreement,
dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo
and OPCo, defining the sharing of costs and benefits associated with their
respective generating plants
|
IURC
|
Indiana
Utility Regulatory Commission
|
KgPCo
|
Kingsport
Power Company, a public utility subsidiary of AEP
|
KPCo
|
Kentucky
Power Company, a public utility subsidiary of AEP
|
KPSC
|
Kentucky
Public Service Commission
|
Lawrenceburg
Plant
|
A
1,146 MW gas-fired unit owned by AEGCo and located near Lawrenceburg,
Indiana
|
LLWPA
|
Low-Level
Waste Policy Act of 1980
|
LPSC
|
Louisiana
Public Service Commission
|
MISO
|
Midwest
Independent Transmission System Operator
|
Moody’s
|
Moody’s
Investors Service, Inc.
|
MW
|
Megawatt
|
NOx
|
Nitrogen
oxide
|
NPC
|
National
Power Cooperatives, Inc., an unaffiliated corporation
|
NRC
|
Nuclear
Regulatory Commission
|
NSR
Consent Decree
|
The
2007 settlement with the Federal EPA, the United States Department of
Justice, certain states and special interest groups that ended the
litigation which had alleged that APCo, CSPCo, I&M and OPCo violated
the new source review requirements of the CAA.
|
OASIS
|
Open
Access Same-time Information System
|
OATT
|
Open
Access Transmission Tariff, filed with FERC
|
OCC
|
Corporation
Commission of the State of Oklahoma
|
Ohio
Act
|
Ohio
electric restructuring legislation
|
Ohio
Amendments
|
Amendments
to the Ohio Act adopted in April 2008 which required electric utilities to
adjust their rates by filing an ESP with the PUCO
|
OPCo
|
Ohio
Power Company, a public utility subsidiary of AEP
|
OSS
|
Off-system
sales
|
OVEC
|
Ohio
Valley Electric Corporation, an electric utility company in which AEP and
CSPCo together own a 43.47% equity interest
|
PJM
|
PJM
Interconnection, L.L.C., a regional transmission
organization
|
PM
|
Particulate
Matter
|
PSO
|
Public
Service Company of Oklahoma, a public utility subsidiary of
AEP
|
PUCO
|
Public
Utilities Commission of Ohio
|
PUCT
|
Public
Utility Commission of Texas
|
RCRA
|
Resource
Conservation and Recovery Act of 1976, as amended
|
REP
|
Texas
retail electricity provider
|
Rockport
Plant
|
A
generating plant owned and partly leased by AEGCo and I&M (two 1,300
MW, coal-fired) located near Rockport, Indiana
|
ROE
|
Return
on Equity
|
RTO
|
Regional
Transmission Organization
|
SEC
|
Securities
and Exchange Commission
|
S&P
|
Standard
& Poor’s Ratings Service
|
SO2
|
Sulfur
dioxide
|
SPP
|
Southwest
Power Pool
|
SWEPCo
|
Southwestern
Electric Power Company, a public utility subsidiary of
AEP
|
TA
|
Transmission
Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo and
OPCo, which allocates costs and benefits in connection with the operation
of transmission assets
|
TCA
|
Transmission
Coordination Agreement dated January 1, 1997, restated and amended, as
approved by FERC in 2002, by and among, PSO, SWEPCo, TNC and AEPSC, in
connection with the operation of the transmission assets of the three
public utility subsidiaries
|
TCC
|
AEP
Texas Central Company, formerly Central Power and Light Company, a public
utility subsidiary of AEP
|
Texas
Act
|
Texas
electric restructuring legislation
|
TNC
|
AEP
Texas North Company, formerly West Texas Utilities Company, a public
utility subsidiary of AEP
|
TVA
|
Tennessee
Valley Authority
|
VSCC
|
Virginia
State Corporation Commission
|
WPCo
|
Wheeling
Power Company, a public utility subsidiary of AEP
|
WVPSC
|
West
Virginia Public Service Commission
|
FORWARD-LOOKING
INFORMATION
This
report made by the registrants contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of
1934. Although the registrants believe that their expectations are
based on reasonable assumptions, any such statements may be influenced by
factors that could cause actual outcomes and results to be materially different
from those projected. Among the factors that could cause actual
results to differ materially from those in the forward-looking statements
are:
·
|
The
economic climate and growth in, or contraction within, our service
territory and changes in market demand and demographic
patterns.
|
·
|
Inflationary
or deflationary interest rate trends.
|
·
|
Volatility
in the financial markets, particularly developments affecting the
availability of capital on reasonable terms and developments impairing our
ability to finance new capital projects and refinance existing debt at
attractive rates.
|
·
|
The
availability and cost of funds to finance working capital and capital
needs, particularly during periods when the time lag between incurring
costs and recovery is long and the costs are material.
|
·
|
Electric
load and customer growth.
|
·
|
Weather
conditions, including storms, and our ability to recover significant storm
restoration costs through applicable rate mechanisms.
|
·
|
Available
sources and costs of, and transportation for, fuels and the
creditworthiness and performance of fuel suppliers and
transporters.
|
·
|
Availability
of necessary generating capacity and the performance of our generating
plants.
|
·
|
Our
ability to recover I&M’s Donald C. Cook Nuclear Plant Unit 1
restoration costs through warranty, insurance and the regulatory
process.
|
·
|
Our
ability to recover regulatory assets and stranded costs in connection with
deregulation.
|
·
|
Our
ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.
|
·
|
Our
ability to build or acquire generating capacity, including the Turk Plant,
and transmission line facilities (including our ability to obtain any
necessary regulatory approvals and permits) when needed at acceptable
prices and terms and to recover those costs (including the costs of
projects that are cancelled) through applicable rate cases or competitive
rates.
|
·
|
New
legislation, litigation and government regulation, including requirements
for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or
particulate matter and other substances or additional regulation of flyash
and similar combustion products that could impact the continued operation
and cost recovery of our plants.
|
·
|
Timing
and resolution of pending and future rate cases, negotiations and other
regulatory decisions (including rate or other recovery of new investments
in generation, distribution and transmission service and environmental
compliance).
|
·
|
Resolution
of litigation (including our dispute with Bank of
America).
|
·
|
Our
ability to constrain operation and maintenance costs.
|
·
|
Our
ability to develop and execute a strategy based on a view regarding prices
of electricity, natural gas and other energy-related
commodities.
|
·
|
Changes
in the creditworthiness of the counterparties with whom we have
contractual arrangements, including participants in the energy trading
market.
|
·
|
Actions
of rating agencies, including changes in the ratings of
debt.
|
·
|
Volatility
and changes in markets for electricity, natural gas, coal, nuclear fuel
and other energy-related commodities.
|
·
|
Changes
in utility regulation, including the implementation of ESPs and related
regulation in Ohio and the allocation of costs within regional
transmission organizations, including PJM and SPP.
|
·
|
Accounting
pronouncements periodically issued by accounting standard-setting
bodies.
|
·
|
The
impact of volatility in the capital markets on the value of the
investments held by our pension, other postretirement benefit plans and
nuclear decommissioning trust and the impact on future funding
requirements.
|
·
|
Prices
and demand for power that we generate and sell at
wholesale.
|
·
|
Changes
in technology, particularly with respect to new, developing or alternative
sources of generation.
|
·
|
Other
risks and unforeseen events, including wars, the effects of terrorism
(including increased security costs), embargoes and other catastrophic
events.
|
The
registrants expressly disclaim any obligation to update any forward-looking
information.
PART
I
ITEM
1. BUSINESS
GENERAL
OVERVIEW
AND DESCRIPTION OF SUBSIDIARIES
AEP was
incorporated under the laws of the State of New York in 1906 and reorganized in
1925. It is a public utility holding company that owns, directly or indirectly,
all of the outstanding common stock of its public utility subsidiaries and
varying percentages of other subsidiaries.
The
service areas of AEP’s public utility subsidiaries cover portions of the states
of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee,
Texas, Virginia and West Virginia. The generating and transmission facilities of
AEP’s public utility subsidiaries are interconnected and their operations are
coordinated. Transmission networks are interconnected with extensive
distribution facilities in the territories served. The public utility
subsidiaries of AEP have traditionally provided electric service, consisting of
generation, transmission and distribution, on an integrated basis to their
retail customers. Restructuring legislation in Michigan, Ohio, and the ERCOT
area of Texas has caused AEP public utility subsidiaries in those states to
unbundle previously integrated regulated rates for their retail
customers.
The AEP
System is an integrated electric utility system. As a result, the member
companies of the AEP System have contractual, financial and other business
relationships with the other member companies, such as participation in the AEP
System savings and retirement plans and tax returns, sales of electricity and
transportation and handling of fuel. The companies of the AEP System also obtain
certain accounting, administrative, information systems, engineering, financial,
legal, maintenance and other services at cost from a common provider,
AEPSC.
At
December 31, 2009, the subsidiaries of AEP had a total of 21,673 employees.
Because it is a holding company rather than an operating company, AEP has no
employees. The public utility subsidiaries of AEP are:
APCo (organized in Virginia
in 1926) is engaged in the generation, transmission and distribution of electric
power to approximately 959,000 retail customers in the southwestern portion of
Virginia and southern West Virginia, and in supplying and marketing electric
power at wholesale to other electric utility companies, municipalities and other
market participants. At December 31, 2009, APCo and its wholly owned
subsidiaries had 2,577 employees. Among the principal industries
served by APCo are paper, rubber, coal mining, textile mill products and stone,
clay and glass products. In addition to its AEP System interconnections, APCo is
interconnected with the following unaffiliated utility companies: Carolina Power
& Light Company, Duke Carolina and Virginia Electric and Power Company. APCo
has several points of interconnection with TVA and has entered into agreements
with TVA under which APCo and TVA interchange and transfer electric power over
portions of their respective systems. APCo is a member of
PJM.
CSPCo (organized in Ohio in
1937, the earliest direct predecessor company having been organized in 1883) is
engaged in the generation, transmission and distribution of electric power to
approximately 749,000 retail customers in Ohio, and in supplying and marketing
electric power at wholesale to other electric utilities, municipalities and
other market participants. At December 31, 2009, CSPCo had 1,283 employees.
CSPCo’s service area is comprised of two areas in Ohio, which include portions
of twenty-five counties. One area includes the City of Columbus and the other is
a predominantly rural area in south central Ohio. Among the principal industries
served are primary metals, chemicals and allied products, health services and
electronic machinery. In addition to its AEP System interconnections, CSPCo is
interconnected with the following unaffiliated utility companies: Duke Ohio,
DP&L and Ohio Edison Company. CSPCo is a member of
PJM.
I&M (organized in Indiana
in 1925) is engaged in the generation, transmission and distribution of electric
power to approximately 583,000 retail customers in northern and eastern Indiana
and southwestern Michigan, and in supplying and marketing electric power at
wholesale to other electric utility companies, rural electric cooperatives,
municipalities and other market participants. At December 31, 2009,
I&M had 3,008 employees. Among the principal industries served are primary
metals, transportation equipment, electrical and electronic machinery,
fabricated metal products, rubber and chemicals and allied products, rubber
products and transportation equipment. Since 1975, I&M has leased and
operated the assets of the municipal system of the City of Fort Wayne, Indiana.
This lease extends through February 2010 and its termination is currently being
litigated. In addition to its AEP System interconnections, I&M is
interconnected with the following unaffiliated utility companies: Central
Illinois Public Service Company, Duke Ohio, Commonwealth Edison Company,
Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light
Company, Louisville Gas and Electric Company, Northern Indiana Public Service
Company, Duke Indiana and Richmond Power & Light Company. I&M
is a member of PJM.
KPCo (organized in Kentucky
in 1919) is engaged in the generation, transmission and distribution of electric
power to approximately 175,000 retail customers in an area in eastern Kentucky,
and in supplying and marketing electric power at wholesale to other electric
utility companies, municipalities and other market participants. At
December 31, 2009, KPCo had 478 employees. Among the principal industries served
are petroleum refining, coal mining and chemical production. In addition to its
AEP System interconnections, KPCo is interconnected with the following
unaffiliated utility companies: Kentucky Utilities Company and East Kentucky
Power Cooperative Inc. KPCo is also interconnected with TVA. KPCo is
a member of PJM.
KgPCo
(organized in Virginia in 1917) provides electric service to
approximately 47,000 retail customers in Kingsport and eight neighboring
communities in northeastern Tennessee. Kingsport Power Company does not own any
generating facilities and is a member of PJM. It purchases electric power from
APCo for distribution to its customers. At December 31, 2009, Kingsport Power
Company had 57 employees.
OPCo (organized in Ohio in
1907 and re-incorporated in 1924) is engaged in the generation, transmission and
distribution of electric power to approximately 710,000 retail customers in the
northwestern, east central, eastern and southern sections of Ohio, and in
supplying and marketing electric power at wholesale to other electric utility
companies, municipalities and other market participants. At December 31, 2009,
OPCo had 2,391 employees. Among the principal industries served by OPCo are
primary metals, chemical manufacturing, petroleum refining, and rubber and
plastic products. In addition to its AEP System interconnections, OPCo is
interconnected with the following unaffiliated utility companies: Duke Ohio, The
Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company,
Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The
Toledo Edison Company and West Penn Power Company. OPCo is a member
of PJM.
PSO (organized in Oklahoma
in 1913) is engaged in the generation, transmission and distribution of electric
power to approximately 531,000 retail customers in eastern and southwestern
Oklahoma, and in supplying and marketing electric power at wholesale to other
electric utility companies, municipalities, rural electric cooperatives and
other market participants. At December 31, 2009, PSO had 1,281 employees. Among
the principal industries served by PSO are paper manufacturing and timber
products, natural gas and oil extraction, transportation, non-metallic mineral
production, oil refining and steel processing, In addition to its AEP System
interconnections, PSO is interconnected with Empire District Electric Company,
Oklahoma Gas and Electric Company, Southwestern Public Service Company and
Westar Energy, Inc. PSO is a member of SPP.
SWEPCo (organized in Delaware
in 1912) is engaged in the generation, transmission and distribution of electric
power to approximately 474,000 retail customers in northeastern Texas,
northwestern Louisiana and western Arkansas, and in supplying and marketing
electric power at wholesale to other electric utility companies, municipalities,
rural electric cooperatives and other market participants. At December 31, 2009,
SWEPCo had 1,671 employees. Among the principal industries served by SWEPCo are
natural gas and oil production, petroleum refining, manufacturing of pulp and
paper, chemicals, food processing, and metal refining. The territory served by
SWEPCo also includes several military installations, colleges and universities.
SWEPCO also owns and operates a lignite coal mining operation. In
addition to its AEP System interconnections, SWEPCo is interconnected with Cleco
Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas &
Electric Co. SWEPCo is a member of SPP.
In
November 2009, SWEPCo signed a letter of intent to purchase the transmission and
distribution assets and to assume certain liabilities of Valley Electric
Membership Corporation (VEMCO) for approximately $96 million, subject to
regulatory approval by the LPSC and the APSC. VEMCO services
approximately 30,000 member customers in eight parishes south of Shreveport,
Louisiana. SWEPCo expects to complete the transaction in the second
quarter of 2010.
TCC
(organized in Texas in 1945) is engaged in the transmission and
distribution of electric power to approximately 766,000 retail customers through
REPs in southern Texas. Under the Texas Act, TCC has completed the final stage
of exiting the generation business and has sold all of its generation
assets. At December 31, 2009, TCC had 1,174 employees. Among the
principal industries served by TCC are chemical and petroleum refining,
chemicals and allied products, oil and gas extraction, food processing, metal
refining, plastics, and machinery equipment. In addition to its AEP System
interconnections, TCC is a member of ERCOT.
TNC (organized in Texas in
1927) is engaged in the transmission and distribution of electric power to
approximately 185,000 retail customers through REPs in west and central Texas.
TNC’s remaining generating capacity that is not deactivated has been transferred
to an affiliate at TNC’s cost pursuant to an agreement effective through
2027. At December 31, 2009, TNC had 368 employees. Among the
principal industries served by TNC are petroleum refining, agriculture and the
manufacturing or processing of cotton seed products, oil products, precision and
consumer metal products, meat products and gypsum products. The territory served
by TNC also includes several military installations and correctional facilities.
In addition to its AEP System interconnections, TNC is a member of
ERCOT.
WPCo
(organized in West Virginia in 1883 and reincorporated in 1911) provides
electric service to approximately 41,000 retail customers in northern West
Virginia. WPCo does not own any generating facilities. WPCo is a
member of PJM. It purchases electric power from OPCo for distribution to its
customers. At December 31, 2009, WPCo had 60 employees.
AEGCo (organized in Ohio in
1982) is an electric generating company. AEGCo sells power at wholesale to
I&M, CSPCo and KPCo. AEGCo has no employees.
SERVICE COMPANY
SUBSIDIARY
AEP also
owns a service company subsidiary, AEPSC. AEPSC provides accounting,
administrative, information systems, engineering, financial, legal, maintenance
and other services at cost to the AEP affiliated companies. The
executive officers of AEP and certain of its public utility subsidiaries are
employees of AEPSC. At December 31, 2009, AEPSC had 6,180
employees.
CLASSES
OF SERVICE
The
principal classes of service from which the public utility subsidiaries of AEP
derive revenues and the amount of such revenues during the year ended December
31, 2009 are as follows:
Description
|
|
AEP System(a)
|
|
|
APCo
|
|
|
CSPCo
|
|
|
I&M
|
|
|
|
(in
thousands)
|
|
UTILITY
OPERATIONS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Sales
|
|
$ |
4,405,000 |
|
|
$ |
1,022,942 |
|
|
$ |
749,623 |
|
|
$ |
265,428 |
|
Commercial
Sales
|
|
|
3,171,000 |
|
|
|
493,297 |
|
|
|
715,727 |
|
|
|
352,821 |
|
Industrial
Sales
|
|
|
2,630,000 |
|
|
|
598,631 |
|
|
|
265,403 |
|
|
|
368,109 |
|
PJM
Net Charges
|
|
|
(7,000 |
) |
|
|
(777 |
) |
|
|
(1,893 |
) |
|
|
(1,918 |
) |
Provision
for Rate Refund
|
|
|
1,000 |
|
|
|
197 |
|
|
|
- |
|
|
|
- |
|
Other
Retail Sales
|
|
|
191,000 |
|
|
|
68,123 |
|
|
|
6,341 |
|
|
|
6,572 |
|
Total
Retail
|
|
|
10,391,000 |
|
|
|
2,182,413 |
|
|
|
1,735,201 |
|
|
|
991,012 |
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System
Sales
|
|
|
1,617,000 |
|
|
|
386,534 |
|
|
|
186,759 |
|
|
|
485,440 |
|
Transmission
|
|
|
232,000 |
|
|
|
(47 |
) |
|
|
(1,520 |
) |
|
|
11,698 |
|
Total
Wholesale
|
|
|
1,849,000 |
|
|
|
386,487 |
|
|
|
185,239 |
|
|
|
497,138 |
|
Other
Electric Revenues
|
|
|
385,000 |
|
|
|
35,594 |
|
|
|
13,898 |
|
|
|
197,158 |
|
Other
Operating Revenues
|
|
|
108,000 |
|
|
|
8,772 |
|
|
|
3,022 |
|
|
|
193,422 |
|
Sales
to Affiliates
|
|
|
- |
|
|
|
263,389 |
|
|
|
67,213 |
|
|
|
306,294 |
|
Total
Utility Operating Revenues
|
|
|
12,733,000 |
|
|
|
2,876,655 |
|
|
|
2,004,573 |
|
|
|
2,185,024 |
|
OTHER
|
|
|
756,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
TOTAL
REVENUES
|
|
$ |
13,489,000 |
|
|
$ |
2,876,655 |
|
|
$ |
2,004,573 |
|
|
$ |
2,185,024 |
|
(a)
|
Includes
revenues of other subsidiaries not shown. Intercompany
transactions have been eliminated for the year ended December 31,
2009.
|
Description
|
|
OPCo
|
|
|
PSO
|
|
|
SWEPCo
|
|
|
|
(in
thousands)
|
|
UTILITY
OPERATIONS:
|
|
|
|
|
|
|
|
|
|
Retail
Sales
|
|
|
|
|
|
|
|
|
|
Residential
Sales
|
|
$ |
637,838 |
|
|
$ |
441,743 |
|
|
$ |
423,987 |
|
Commercial
Sales
|
|
|
424,982 |
|
|
|
295,817 |
|
|
|
366,616 |
|
Industrial
Sales
|
|
|
608,614 |
|
|
|
197,605 |
|
|
|
238,224 |
|
PJM
Net Charges
|
|
|
(2,180 |
) |
|
|
- |
|
|
|
- |
|
Provision
for Rate Refund
|
|
|
- |
|
|
|
(1,599 |
) |
|
|
2,591 |
|
Other
Retail Sales
|
|
|
10,140 |
|
|
|
64,695 |
|
|
|
7,658 |
|
Total
Retail
|
|
|
1,679,394 |
|
|
|
998,261 |
|
|
|
1,039,076 |
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System
Sales
|
|
|
235,321 |
|
|
|
32,809 |
|
|
|
215,640 |
|
Transmission
|
|
|
(3,847 |
) |
|
|
28,571 |
|
|
|
42,740 |
|
Total
Wholesale
|
|
|
231,474 |
|
|
|
61,380 |
|
|
|
258,380 |
|
Other
Electric Revenues
|
|
|
30,389 |
|
|
|
15,373 |
|
|
|
17,600 |
|
Other
Operating Revenues
|
|
|
12,570 |
|
|
|
3,980 |
|
|
|
44,928 |
|
Sales
to Affiliates
|
|
|
1,057,747 |
|
|
|
45,756 |
|
|
|
29,318 |
|
Total
Utility Operating Revenues
|
|
|
3,011,574 |
|
|
|
1,124,750 |
|
|
|
1,389,302 |
|
OTHER
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
TOTAL
REVENUES
|
|
$ |
3,011,574 |
|
|
$ |
1,124,750 |
|
|
$ |
1,389,302 |
|
FINANCING
General
Companies
within the AEP System generally use short-term debt to finance working capital
needs. Short-term debt is also used to finance acquisitions,
construction and redemption or repurchase of outstanding securities until such
needs can be financed with long-term debt. In recent history, short-term funding
needs have been provided for by cash on hand, borrowing under AEP's revolving
credit agreements and AEP’s commercial paper program. Funds are
made available to subsidiaries under the AEP corporate borrowing program.
Certain public utility subsidiaries of AEP also sell accounts receivable to
provide liquidity. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2009 Annual
Reports, under the heading entitled Financial Condition for
additional information concerning short-term funding and our access to bank
lines of credit, commercial paper and capital markets.
AEP’s
revolving credit agreements (which backstop the commercial paper program)
include covenants and events of default typical for this type of facility,
including a maximum debt/capital test and a $50 million cross-acceleration
provision. At December 31, 2009, AEP was in compliance with its debt covenants.
With the exception of a voluntary bankruptcy or insolvency, any event of default
has either or both a cure period or notice requirement before termination of the
agreements. A voluntary bankruptcy or insolvency of AEP would be considered an
immediate termination event. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2009 Annual
Reports, under the heading entitled Financial Condition for
additional information with respect to AEP’s credit agreements.
AEP’s
subsidiaries have also utilized, and expect to continue to utilize, additional
financing arrangements, such as leasing arrangements, including the leasing of
coal transportation equipment and facilities.
Credit
Ratings
The
credit ratings of AEP and its registrant subsidiaries as of February 23, 2010
are set forth below. In 2009, Moody’s Investors Service placed the
credit ratings of AEP (the parent) on negative outlook. In 2009,
Fitch Ratings placed the credit ratings of TCC and SWEPCO on negative
outlook. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2009 Annual
Reports, under the heading entitled Financial Condition for
additional information with respect to the credit ratings of the
registrants.
|
Moody’s
|
S&P
|
Fitch
|
Company
|
Senior
Unsecured
|
Outlook*
|
Senior
Unsecured
|
Outlook*
|
Senior
Unsecured
|
Outlook*
|
AEP
|
Baa2
|
N
|
BBB
|
S
|
BBB
|
S
|
AEP
Short Term Rating
|
P-2
|
N
|
A-2
|
S
|
F-2
|
S
|
APCo
|
Baa2
|
S
|
BBB
|
S
|
BBB
|
S
|
CSPCo
|
A3
|
S
|
BBB
|
S
|
A-
|
S
|
I&M
|
Baa2
|
S
|
BBB
|
S
|
BBB
|
S
|
OPCo
|
Baa1
|
S
|
BBB
|
S
|
BBB+
|
S
|
PSO
|
Baa1
|
S
|
BBB
|
S
|
BBB+
|
S
|
SWEPCo
|
Baa3
|
S
|
BBB
|
S
|
BBB+
|
N
|
* S=Stable Outlook; N=Negative
Outlook
ENVIRONMENTAL
AND OTHER MATTERS
General
AEP’s
subsidiaries are currently subject to regulation by federal, state and local
authorities with regard to air and water-quality control and other environmental
matters, and are subject to zoning and other regulation by local authorities.
The environmental issues that we believe are potentially material to the AEP
system are outlined below.
Clean
Air Act Requirements
The CAA
establishes a comprehensive program to protect and improve the nation’s air
quality and control mobile and stationary sources of air
emissions. The major CAA programs affecting our power plants are
described below. The states implement and administer many of these
programs and could impose additional or more stringent
requirements.
National Ambient Air Quality
Standards: The CAA requires the Federal EPA to review
periodically the available scientific data for six criteria pollutants and
establish a concentration level in the ambient air for those substances that is
adequate to protect the public health and welfare with an extra safety
margin. These concentration levels are known as national ambient air
quality standards (NAAQS).
Each
state identifies the areas within its boundaries that meet the NAAQS (attainment
areas) and those that do not (nonattainment areas). Each state must
develop a state implementation plan (SIP) to bring nonattainment areas into
compliance with the NAAQS and maintain good air quality in attainment
areas. All SIPs are submitted to the Federal EPA for
approval. If a state fails to develop adequate plans, the Federal EPA
develops and implements a plan. As the Federal EPA reviews the NAAQS,
the attainment status of areas can change and states may be required to develop
new SIPs. In 2008, the Federal EPA issued revised NAAQS for both
ozone and fine particulate matter (PM 2.5). The PM
2.5
standard was remanded by the D.C. Circuit Court of Appeals, but a new standard
has not yet been proposed. In 2009 the Obama Administration
reconsidered the ozone standard and proposed a more stringent
standard. Federal EPA has also proposed a new short-term standard for
SO2
and a new, lower standard for NO2. The
Federal EPA also established a lower standard for lead. These new
standards could result in additional emission reductions being required from our
facilities.
In 2005,
the Federal EPA issued the Clean Air Interstate Rule (CAIR). It
requires specific reductions in SO2 and
NOx
emissions from power plants and assists states developing new SIPs to meet the
NAAQS. CAIR reduces regional emissions of SO2 and
NOx
(which can be transformed into PM and ozone) from power plants in the Eastern
U.S. (28 states and the District of Columbia). CAIR requires power
plants within these states to reduce emissions of SO2 by 45% by
2010, and by 57% by 2015 from 2003 levels. NOx emissions
were subject to additional limits beginning in 2009, and would be reduced by a
total of 61% by 2015 from 2003 levels. Reduction of both SO2 and
NOx
emissions under CAIR is to be achieved through a cap-and-trade
program. In July 2008, the D.C. Circuit Court of Appeals remanded
CAIR to the Federal EPA. CAIR remains in effect while Federal EPA
conducts further rulemaking, and we are complying with our obligations under
CAIR. We are unable to predict how the Federal EPA will respond
to the remand, but we expect a proposal from Federal EPA in the spring of
2010. A SIP that complied with CAIR also established compliance with
other CAA requirements, including certain visibility goals. It is
uncertain how Federal EPA will deal with these requirements on
remand. The Federal EPA or states may elect to seek further
reductions of SO2 and
NOx in
response to more stringent PM and ozone NAAQS or restrict or eliminate the
trading programs in the replacement developed for CAIR.
Hazardous Air
Pollutants: As a result of the 1990 Amendments to the CAA, the
Federal EPA investigated hazardous air pollutant (HAP) emissions from the
electric utility sector and submitted a report to Congress, identifying mercury
emissions from coal-fired power plants as warranting further
study. In 2005, the Federal EPA issued a Clean Air Mercury Rule
(CAMR) setting New Source Performance Standards (NSPS) for mercury emissions
from new and modified coal-fired power plants and requiring all states to issue
new SIPs including mercury requirements for existing coal-fired power
plants. The Federal EPA issued a model federal rule based on a
cap-and-trade program for mercury emissions from existing coal-fired power
plants that would reduce mercury emissions to 38 tons per year from all existing
plants in 2010, and to 15 tons per year in 2018.
In 2008,
the D.C. Circuit Court of Appeals vacated and remanded CAMR to the Federal
EPA. The Federal EPA has issued an information collection request to
coal-fired power plants for emission information on mercury and several
additional HAPs, and has announced its intention to issue a proposed rule in
2011. We are unable to predict at this time how the Federal EPA
response to the remand will affect our facilities or their costs of operation,
but it could be material.
To comply
with the remand of CAIR, Federal EPA may impose NOx and/or
SO2
budgets on a state-by-state basis rather than across a multi-state
region. If Federal EPA takes this approach, we would have
significantly less flexibility planning for compliance and may have to install
additional environmental control equipment on some of our units. In
addition, with the remand of CAMR, Federal EPA will likely establish Maximum
Achievable Control Technology (MACT) standards for mercury and other hazardous
air pollutants that could require installation of scrubbers on all coal units,
regardless of age or size. It would be costly and inefficient to
retrofit all of our units with such controls, and we will urge Federal EPA to
carefully consider all of the options available to it to avoid such a
result. However, we have a number of our older units, including some
that are already subject to control requirements under the NSR Consent Decree,
for which it may be economically inefficient to install scrubbers or other
environmental controls, including CCS. The timing and ultimate
disposition of those units will be dictated by environmental regulations, the
economics of maintaining or retrofitting the units, transmission requirements,
demand for electricity, availability and cost of replacement power, legislative
mandates and capital requirements, and regulatory decisions about cost recovery
of the remaining investment in retired units. In addition, if some
coal units are prematurely forced to retire, we may need to make investments in
new transmission lines and substations to create stronger interconnections with
neighboring systems.
The Acid Rain
Program: The 1990 Amendments to the CAA include a
cap-and-trade emission reduction program for SO2 emissions
from power plants. By 2000, the program established a nationwide cap
on power plant SO2 emissions
of 8.9 million tons per year. The 1990 Amendments also contain
requirements for power plants to reduce NOx emissions
through the use of available combustion controls.
The
success of the SO2
cap-and-trade program encouraged the Federal EPA and the states to use it as a
model for other emission reduction programs, including CAIR and
CAMR. We continue to meet our obligations under the Acid Rain Program
through the installation of controls, use of alternate fuels and participation
in the emissions allowance markets. CAIR currently uses the SO2 allowances
originally allocated through the Acid Rain Program as the basis for its SO2
cap-and-trade system. We are unable to predict if or how any
replacement for CAIR will utilize the SO2 allowances
from the Acid Rain Program.
Regional
Haze: The CAA establishes visibility goals for certain
federally designated areas, including national parks, and requires states to
submit SIPs that will demonstrate reasonable progress toward preventing
impairment of visibility in these areas (Regional Haze program). In
2005, the Federal EPA issued its Clean Air Visibility Rule (CAVR), detailing how
the CAA’s best available retrofit technology (BART) requirements will be applied
to facilities built between 1962 and 1977 that emit more than 250 tons per year
of certain pollutants in specific industrial categories, including power
plants. The final rule contains a demonstration that CAIR will result
in more visibility improvements than BART for power plants subject to
it. Thus, states are allowed to substitute CAIR requirements in their
Regional Haze program SIPs for controls that would otherwise be required by
BART. For BART-eligible facilities located in states not subject to
CAIR requirements for SO2 and
NOx
(Oklahoma, Texas and Arkansas of the AEP System), some additional
controls will be required. The courts upheld the final
rule.
In
January 2009, the Federal EPA issued a determination that 37 states (including
Indiana, Ohio, Oklahoma, Texas and Virginia) failed to submit SIPs fulfilling
the Regional Haze program requirements by the deadline, and commencing a 2-year
period for the development of a Federal Implementation Plan (FIP) in these
states. We are unable to predict if or how the remand of CAIR or the
development of a FIP to satisfy CAVR in certain states may affect our compliance
obligations for the Regional Haze programs.
Clean
Water Act Requirements
|
Our
operations are also subject to the Federal Clean Water Act, which prohibits the
discharge of pollutants into waters of the United States except pursuant to
appropriate permits, and regulates systems that withdraw surface water for
use in our power plants. In 2004, the Federal EPA issued a final rule
requiring all large existing power plants with once-through cooling water
systems to meet certain standards to reduce mortality of aquatic organisms
pinned against the plant’s cooling water intake screen or entrained in the
cooling water. The standards vary based on the water bodies from
which the plants draw their cooling water. We expected additional
capital and operating expenses, which the Federal EPA estimated could be $193
million for our plants. We undertook site-specific studies and have
been evaluating site-specific compliance or mitigation measures that could
significantly change these cost estimates.
In July
2007, the Federal EPA suspended the 2004 rule, except for the requirement that
permitting agencies develop best professional judgment (BPJ) controls for
existing facility cooling water intake structures that reflect the best
technology available for minimizing adverse environmental impact. The
result is that the BPJ control standard for cooling water intake structures in
effect prior to the 2004 rule is used as the applicable standard by permitting
agencies pending finalization of revised rules by the Federal EPA.
In April
2009, the U.S. Supreme Court issued a decision that allows the Federal EPA the
discretion to rely on cost-benefit analysis in setting national performance
standards and in providing for cost-benefit variances from those standards as
part of the regulations. We cannot predict if or how the Federal EPA
will apply this decision to any revision of the regulations or what effect it
may have on similar requirements adopted by the states. We expect
Federal EPA to issue revised rules in 2010.
Federal
EPA is also engaged in rulemaking to update the technology-based standards that
govern discharges from new and existing power plants under the Clean Water Act’s
NPDES program. These standards were last updated over 20 years ago,
and EPA has issued two rounds of information collection requests to inform its
rulemaking. In October 2009, Federal EPA issued a final report for
the power plant sector and determined that revisions to its existing standards
are necessary, but EPA has not yet proposed any specific
requirements. Until new standards are proposed, we cannot predict the
outcome or impact of these rules on our operations.
Our operations produce a number of
different coal combustion products, including flyash, bottom ash, gypsum, and
other materials. In December 2008, the breach of a dike at the
Tennessee Valley Authority’s Kingston Station resulted in a spill of several
million cubic yards of ash into a nearby river and onto private properties,
prompting federal and state reviews of ash storage and disposal practices at
many coal-fired electric generating facilities, including ours. AEP
operates 37 ash ponds and we manage these ponds in a manner that complies with
state and local requirements, including dam safety rules designed to assure the
structural integrity of these facilities. We also operate a number of
dry disposal facilities in accordance with state standards, including ground
water monitoring and other applicable standards. Approximately 40% of
AEP’s coal combustion products are recycled. Federal EPA completed an
extensive study of the characteristics of coal ash in 2000 and concluded that
combustion wastes do not warrant regulation as hazardous
waste. However, Federal EPA issued a Notice of Data Availability and
request for public comment in 2007, and is expected to propose new management
standards for coal ash and related wastes in early 2010, which could require
conversion of ash impoundments to dry disposal facilities or impose hazardous
waste regulations upon these wastes. Until these standards are
proposed, we cannot predict the outcome or impact of these rules on our
operations, but the costs could be material and could reduce our ability to
market combustion wastes for beneficial uses.
Position and
strategy: The topics of whether the earth is warming, how much
and how fast, what role human activity plays, and what to do about it are very
controversial and actively debated. The public policy makers and
influencers in Washington and in the 11 states we serve have conflicting views.
We are focused on taking, in the short term, actions that we see as prudent,
such as improving energy efficiency, investing in developing cost-effective and
less carbon-intensive technologies, and evaluating our assets across a range of
plausible scenarios and outcomes. We are also active participants in
a variety of public policy discussions at state and federal levels, to assure
that proposed new requirements are feasible and the economies of the states we
serve are not placed at a competitive disadvantage.
We
support a reasonable approach to reduce emissions of CO2 and other
greenhouse gases (generally referred to throughout as CO2) that
recognizes that a reliable and affordable electric supply is vital to economic
stability. We have taken measurable, voluntary actions to reduce and
offset our own CO2
emissions. We participate in a number of voluntary programs to
monitor, mitigate, and reduce CO2 emissions,
including the Federal EPA’s Climate Leaders program, the DOE’s CO2 reporting
program, and the Chicago Climate Exchange. We are considering several
options that protect the reliability of the electric system while reducing our
carbon emissions. Our strategy is to pursue multiple options including renewable
energy, energy efficiency, new technologies, offsets and nuclear generation. At
the same time we will continue to improve the efficiency of our plants, retire
or mothball some older, inefficient coal units when factors warrant, and
complete our environmental retrofit program. For additional information on
legislative and regulatory responses to global warming, including limitations on
CO2
emissions, see Management’s
Financial Discussion and Analysis of Results of Operations under the
headings entitled Environmental Matters – Global
Warming. Specific steps taken to reduce CO2 emissions
include the following:
Carbon Capture and Storage
We
successfully captured, transported and stored CO2 emissions
from a coal-fired power plant in deep geologic formations for the first time in
October 2009, for 20 MW of our 1,300 MW Mountaineer Plant in West
Virginia. The next phase of this project – to install the nation’s
first commercial-scale coal-derived CO2 capture
and storage system at the Mountaineer Plant—will be partially funded through the
U.S. Department of Energy’s (DOE) Clean Coal Power Initiative. AEP has been
awarded federal grant funding of $334 million, which represents approximately
half the cost of this phase of the project, exclusive of asset retirement
obligations. The commercial-scale phase of AEP’s CO2 program
will capture approximately 90% of the CO2 from 235
MW of the plant’s 1,300 MW of capacity.
Renewable
Sources of Energy
Some of
our states have passed legislation establishing renewable energy, alternative
energy, and/or energy efficiency requirements or goals (including Ohio, Texas,
Michigan, Virginia and West Virginia) and we are taking steps to comply with
these requirements in a timely fashion. In order to meet these requirements and
as a key part of its corporate sustainability effort, AEP pledged to increase
its renewable power by an additional 2000 MW from its 2007 levels by 2011,
subject to regulatory approval. By the end of 2009, AEP has already
secured, through power purchase agreements, an additional 1,013.5 MW of
renewable power. AEP’s integrated resource plan contains a 10%
renewable energy target by 2020, which, together with other qualifying
alternative energy and energy efficiency measures, will exceed the clean energy
requirements currently in effect in our states.
Limiting
Emissions through Energy Efficiency
Energy
efficiency is a high priority for us because it is a cost-effective way to
reduce CO2
emissions and can delay the need to build new power plants. We work
closely with regulators, environmental groups, technical experts and others to
develop and implement efficiency and demand response programs. We
have a 2012 goal to reduce 1,000 MW of demand and 2,250,000 MWh of energy
consumption. Through 2009, we have achieved 152 MW and 471,000 MWh of
demand and energy reduction, respectively.
With
regulatory support from the PUCO and partial funding from the DOE, AEP Ohio’s
gridSMARTSM
Demonstration Project will install 110,000 advanced electricity meters, smart
appliances, secure integrated smart grid technology, and enable plug-in hybrid
electric vehicles and other consumer systems that will help customers manage
electricity use and costs. The $150 million project, $75 million of which will
come from federal stimulus funds, is designed to reduce energy consumption by
18,000 MWh and peak demand by 15 MW over a three year period – eliminating the
equivalent of the energy needed to power 1,800 homes. To pay for this project,
the PUCO approved project trackers in customer rates that allow us to recover
costs specific to these programs in a timely manner.
Current and Projected
CO2
Emissions: Our total CO2 emissions
in 2008 (including our ownership in the Kyger Creek and Clifty Creek plants)
were approximately 155 million metric tons. We estimate that our 2009
emissions were approximately 140 million metric tons. Since 2004 our cumulative
CO2
emission reductions were 51 million metric tons by the end of 2008 from adjusted
baseline levels in 1998 through 2001, and will be in excess of 70 million tons
at the end of 2009. Emissions in 2010 and beyond will be affected by
continued changes in our generation portfolio, market prices, the pace and scale
of the economic recovery in our jurisdictions, available capital, weather, and
other factors. We expect overall increases in CO2 emissions
during the 2010-2012 timeframe as our sales and generation rebound somewhat from
recession lows in 2009. However, over much of the remainder of the decade we
expect emissions growth to be relatively flat as increased fossil generation
needed to meet modest sales growth is largely offset by retirements of some
older coal-fired units and increased use of renewable energy, particularly from
wind.
Corporate
governance: Several years ago in response to a shareholder
proposal, our Board of Directors created an ad hoc committee to evaluate
our actions to mitigate the economic impact from future policies to reduce
CO2
and other emissions. Our Board of Directors continues to review
environmental issues on a regular basis and in connection with its review of our
strategic plan. The Board of Directors is also frequently informed of
any new material environmental issues, including updates on any proposed
legislation. The Board of Directors’ Committee on Directors and
Corporate Governance oversees our Sustainability Report, including the portion
of the report that relates to environmental issues. Environmental
planning and policy leadership are criteria incorporated into our executive
incentive compensation plan.
Other
environmental issues and matters
·
|
Litigation
with the federal and/or certain state governments and certain special
interest groups regarding regulated air emissions and/or whether emissions
from coal-fired generating plants cause or contribute to global warming.
See Management’s
Financial Discussion and Analysis of Results of Operations under
the heading entitled Litigation - Environmental Litigation
and Note 6 to the consolidated financial statements entitled Commitments, Guarantees and
Contingencies, included in the 2009 Annual Reports, for further
information.
|
·
|
CERCLA,
which imposes costs for environmental remediation upon owners and previous
owners of sites, as well as transporters and generators of hazardous
material disposed of at such sites. See Note 6 to the
consolidated financial statements entitled Commitments, Guarantees and
Contingencies, included in the 2009 Annual Reports, under the
heading entitled The
Comprehensive Environmental Response Compensation and Liability Act
(Superfund) and State
Remediation for further information.
|
Environmental
Investments
Investments
related to improving AEP System plants’ environmental performance and compliance
with air and water quality standards during 2007, 2008 and 2009 and the current
estimates for 2010, 2011 and 2012 are shown below, in each case excluding AFUDC
or capitalized interest. AEP expects to make substantial investments in addition
to the amounts set forth below in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls. Such future investments are needed in order to
comply with air and water quality standards that have been adopted and have
deadlines for compliance after 2012 or have been proposed and may be
adopted. Future investments could be significantly greater if
emissions reduction requirements are accelerated or otherwise become more
onerous or if CO2 becomes
regulated. While we expect to recover our expenditures for pollution control
technologies, replacement generation and associated operating costs from
customers through regulated rates (in regulated jurisdictions) or market prices,
without such recovery those costs could adversely affect future results of
operations and cash flows, and possibly financial condition. The cost
of complying with applicable environmental laws, regulations and rules is
expected to be material to the AEP System. See Management’s Financial Discussion
and Analysis of Results of Operations under the heading entitled Environmental Matters
and Note 6 to the
consolidated financial statements, entitled Commitments, Guarantees and
Contingencies, included in the 2009 Annual Reports, for more information
regarding environmental expenditures in general.
Historical
and Projected Environmental Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
Actual
|
|
|
Actual
|
|
|
Actual
|
|
|
Estimate
|
|
|
Estimate
|
|
|
Estimate
|
|
(in
thousands)
|
|
Total
AEP System*
|
|
$ |
994,100 |
|
|
$ |
886,800 |
|
|
$ |
457,200 |
|
|
$ |
321,700 |
|
|
$ |
233,900 |
|
|
$ |
405,600 |
|
APCo
|
|
|
351,900 |
|
|
|
361,200 |
|
|
|
191,900 |
|
|
|
127,000 |
|
|
|
57,600 |
|
|
|
16,200 |
|
CSPCo
|
|
|
130,000 |
|
|
|
162,800 |
|
|
|
73,800 |
|
|
|
76,600 |
|
|
|
20,600 |
|
|
|
39,000 |
|
I&M
|
|
|
9,300 |
|
|
|
22,400 |
|
|
|
19,600 |
|
|
|
10,100 |
|
|
|
800 |
|
|
|
1,600 |
|
OPCo
|
|
|
481,700 |
|
|
|
311,800 |
|
|
|
151,000 |
|
|
|
67,500 |
|
|
|
49,400 |
|
|
|
39,300 |
|
PSO
|
|
|
1,500 |
|
|
|
5,000 |
|
|
|
1,000 |
|
|
|
1,700 |
|
|
|
15,200 |
|
|
|
59,800 |
|
SWEPCo
|
|
|
14,300 |
|
|
|
12,000 |
|
|
|
10,700 |
|
|
|
30,400 |
|
|
|
64,800 |
|
|
|
143,900 |
|
*
|
Includes
expenditures of the subsidiaries shown and other subsidiaries not shown.
The figures reflect construction expenditures, not investments in
subsidiary companies. Excludes discontinued
operations.
|
Electric
and Magnetic Fields
EMF are
found everywhere there is electricity. Electric fields are created by the
presence of electric charges. Magnetic fields are produced by the flow of those
charges. This means that EMF are created by electricity flowing in transmission
and distribution lines, electrical equipment, household wiring, and
appliances. A number of studies in the past have examined the
possibility of adverse health effects from EMF. While some of the
epidemiological studies have indicated some association between exposure to EMF
and health effects, none has produced any conclusive evidence that EMF does or
does not cause adverse health effects.
Management cannot predict the ultimate
impact of the question of EMF exposure and adverse health effects. If further
research shows that EMF exposure contributes to increased risk of cancer or
other health problems, or if the courts conclude that EMF exposure harms
individuals and that utilities are liable for damages, or if states limit the
strength of magnetic fields to such a level that the current electricity
delivery system must be significantly changed, then the results of operations
and financial condition of AEP and its operating subsidiaries could be
materially adversely affected unless these costs can be recovered from
customers.
UTILITY
OPERATIONS
GENERAL
Utility
operations constitute most of AEP’s business operations. Utility
operations include (i) the generation, transmission and distribution of electric
power to retail customers and (ii) the supplying and marketing of electric power
at wholesale (through the electric generation function) to other electric
utility companies, municipalities and other market
participants. AEPSC, as agent for AEP’s public utility subsidiaries,
performs marketing, generation dispatch, fuel procurement and power-related risk
management and trading activities.
ELECTRIC
GENERATION
Facilities
AEP’s
public utility subsidiaries own or lease approximately 37,000 MW of domestic
generation. See Item 2 —
Properties for more information regarding AEP’s generation
capacity.
AEP
Power Pool and CSW Operating Agreement
APCo,
CSPCo, I&M, KPCo, OPCo, and AEPSC are parties to the AEP Interconnection
Agreement, which has been approved by the FERC. This agreement
defines how the member companies share the costs and benefits associated with
their generating plants. This sharing is based upon each company’s “member load
ratio.” The member load ratio is calculated monthly by dividing each company’s
highest monthly peak demand for the last twelve months by the aggregate of the
highest monthly peak demand for the last twelve months for all member companies.
The member load ratio multiplied by the aggregate generation capacity of all the
member companies determines each member company's capacity
obligation. The difference between each member company's obligation
and its own generation capacity determines the capacity surplus or deficit of
each member company. The agreement requires the deficit companies to
make monthly capacity equalization payments to the surplus companies based on
the surplus companies' average fixed cost of generation. Member
companies that deliver energy to other member companies to meet their internal
load requirements are reimbursed at average variable costs. In
addition, all member companies share off-system sales margins based upon each
member company's member load ratio. Consequently, the agreement
provides a strong risk sharing and mitigation arrangement among the member
companies. As of December 31, 2009, the member-load-ratios were as
follows:
|
Peak
Demand
(MW)
|
Member-Load
Ratio
(%)
|
APCo
|
8,308
|
35.6
|
CSPCo
|
4,209
|
18.0
|
I&M
|
4,245
|
18.2
|
KPCo
|
1,674
|
7.2
|
OPCo
|
4,901
|
21.0
|
APCo,
CSPCo, I&M, KPCo and OPCo are parties to the AEP System Interim Allowance
Agreement (Allowance Agreement), which has been approved by the FERC and
provides, among other things, for the transfer of SO2 emission
allowances associated with transactions under the Interconnection
Agreement. The following table shows the net (credits) or charges
allocated among the parties under the Interconnection Agreement during the years
ended December 31, 2007, 2008 and 2009:
|
2007
|
2008
|
2009
|
|
(in
thousands)
|
APCo
|
$454,800
|
$575,300
|
$668,700
|
CSPCo
|
173,000
|
233,200
|
257,600
|
I&M
|
(93,200)
|
(153,000)
|
(100,900)
|
KPCo
|
41,200
|
65,000
|
31,600
|
OPCo
|
(575,800)
|
(720,500)
|
(857,000)
|
PSO,
SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement (CSW
Operating Agreement), which has been approved by the FERC. The CSW Operating
Agreement requires these public utility subsidiaries to maintain adequate annual
planning reserve margins and requires the subsidiaries that have capacity in
excess of the required margins to make such capacity available for sale to other
public utility subsidiary parties as capacity commitments. Parties are
compensated for energy delivered to the recipients based upon the deliverer’s
incremental cost plus a portion of the recipient’s savings realized by the
purchaser that avoids the use of more costly alternatives. Revenues
and costs arising from third party sales in their region are generally shared
based on the amount of energy each west zone public utility subsidiary
contributes that is sold to third parties. The separation of the
generation business undertaken by TCC and TNC to comply with the Texas Act has
made their business operations incompatible with the CSW Operating
Agreement. As a result, with FERC approval, these companies as of May
1, 2006, are no longer parties to, and no longer supply generating capacity
under, the CSW Operating Agreement.
The
following table shows the net (credits) or charges allocated among the parties
under the CSW Operating Agreement during the years ended December 31, 2007, 2008
and 2009:
|
2007
|
2008
|
2009
|
|
(in
thousands)
|
PSO
|
$(17,500)
|
$(57,000)
|
$(22,762)
|
SWEPCo
|
16,800
|
59,900
|
22,762
|
Power
generated by or allocated or provided under the Interconnection Agreement or CSW
Operating Agreement to any public utility subsidiary is primarily sold to
customers by such public utility subsidiary at rates approved by the public
utility commission in the jurisdiction of sale. See Regulation — Rates under
Item 1, Utility
Operations.
Under
both the Interconnection Agreement and CSW Operating Agreement, power that is
not needed to serve the native load of our public utility subsidiaries is sold
in the wholesale market by AEPSC on behalf of those subsidiaries. See
Risk Management and
Trading, below,
for a discussion of the trading and marketing of such power.
AEP’s
System Integration Agreement provides for the integration and coordination of
AEP’s East companies, PSO and SWEPCO. This includes joint dispatch of generation
within the AEP System and the distribution, between the two zones, of costs and
benefits associated with the transfers of power between the two zones (including
sales to third parties and risk management and trading activities). It is
designed to function as an umbrella agreement in addition to the Interconnection
Agreement and the CSW Operating Agreement, each of which controls the
distribution of costs and benefits for activities within each
zone. Because TCC and TNC have exited the generation business, these
two companies are no longer parties to the System Integration
Agreement.
Risk
Management and Trading
As agent
for AEP’s public utility subsidiaries, AEPSC sells excess power into the market
and engages in power, natural gas, coal and emissions allowances risk management
and trading activities focused in regions in which AEP traditionally operates
and in adjacent regions. These activities primarily involve the purchase and
sale of electricity (and to a lesser extent, natural gas, coal and emissions
allowances) under physical forward contracts at fixed and variable prices. These
contracts include physical transactions, over-the-counter swaps and
exchange-traded futures and options. The majority of physical forward contracts
are typically settled by netting into offsetting contracts. These transactions are
executed with numerous counterparties or on exchanges. Counterparties and
exchanges may require cash or cash related instruments to be deposited on these
transactions as margin against open positions. As of December 31, 2009,
counterparties have posted approximately $52 million in cash, cash equivalents
or letters of credit with AEPSC for the benefit of AEP’s public utility
subsidiaries (while, as of that date, AEP’s public utility subsidiaries had
posted approximately $203 million with counterparties and
exchanges). Since open trading contracts are valued based on market
prices of various commodities, exposures change daily. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2009 Annual
Reports, under the heading entitled Quantitative and Qualitative
Disclosures About Risk Management Activities for additional
information.
Fuel
Supply
The
following table shows the sources of fuel used by the AEP System:
|
2007
|
2008
|
2009
|
Coal
and Lignite
|
85%
|
86%
|
88%
|
Natural
Gas
|
6%
|
6%
|
6%
|
Nuclear
|
9%
|
8%
|
5%
|
Hydroelectric
and other
|
<1%
|
<1%
|
1%
|
Price
increases in one or more fuel sources relative to other fuels may result in
increased use of other fuels. Variations in the generation of nuclear power are
primarily related to a 2008 forced outage caused by a low pressure turbine blade
failure event, refueling and maintenance outages.
Coal and
Lignite: AEP’s
public utility subsidiaries procure coal and lignite under a combination of
purchasing arrangements including long-term contracts, affiliate operations and
spot agreements with various producers and coal trading firms. The
economic climate in 2009 exerted downward pressure on electric demand, resulting
in lower market prices for fuel. This lower demand led to a
significant decrease in AEP’s coal consumption in 2009. As a result of decreased
coal consumption and corresponding increases in fuel inventory, AEP initiated
discussions with its coal suppliers in an effort to better match deliveries with
consumption and to minimize the impact on fuel inventory costs, carrying costs
and cash.
Most of
the coal purchased by AEP is procured through term
contracts. Generally, the prices paid under these term contracts are
often lower than spot coal market prices. As term contracts expire
they are replaced with new agreements, often at higher prices. The
price we paid for coal delivered in 2009 rose from the prior year primarily as a
result of this contract replacement process.
The
following table shows the amount of coal and lignite delivered to the AEP System
plants during the past three years and the average delivered price of coal
purchased by AEP System companies:
|
2007
|
2008
|
2009
|
Total
coal delivered to AEP System plants (thousands of tons)
|
72,644
|
77,054
|
75,909
|
Average
price per ton of purchased coal
|
$36.65
|
$47.14
|
$49.54
|
Management
believes that AEP’s public utility subsidiaries will be able to secure and
transport coal and lignite of adequate quality and in adequate quantities to
operate their coal and lignite-fired units. Through subsidiaries, AEP
owns, leases or controls more than 9,000 railcars, 697 barges, 18 towboats and a
coal handling terminal with 18 million tons of annual capacity to move and store
coal for use in our generating facilities. See AEP River Operations
for a discussion of AEP’s for-profit coal and other dry-bulk commodity
transportation operations that are not part of AEP’s Utility Operations
segment.
The coal
supplies at AEP System plants vary from time to time depending on various
factors, including, but not limited to, demand for electric power, unit outages,
transportation infrastructure limitations, space limitations, plant coal
consumption rates, availability of acceptable coals, labor issues and weather
conditions which may interrupt production or deliveries. At December 31, 2009,
the System’s coal inventory was approximately 61 days.
In cases
of emergency or shortage, AEP has developed programs to conserve coal supplies
at its plants. Such programs have been filed and reviewed with federally
approved electric reliability organizations. In some cases, the
relevant state regulatory agency has prescribed actions to be taken under
specified circumstances by System companies, subject to the jurisdiction of such
agency.
The FERC
has adopted regulations relating, among other things, to the circumstances under
which, in the event of fuel emergencies or shortages, it might order electric
utilities to generate and transmit electric power to other regions or systems
experiencing fuel shortages, and to ratemaking principles by which such electric
utilities would be compensated. In addition, the federal government is
authorized, under prescribed conditions, to reallocate coal and to require the
transportation thereof, for the use at power plants or major fuel-burning
installations experiencing fuel shortages.
Natural
Gas: Through its
public utility subsidiaries, AEP consumed nearly 96 billion cubic feet of
natural gas during 2009 for generating power. This represents a slight decrease
from 2008 due to reduced demand in AEP’s western jurisdictions. Many
of the natural gas-fired power plants are connected to at least two pipelines,
which allows greater access to competitive supplies and improves delivery
reliability. A portfolio of long-term, monthly, seasonal firm and daily peaking
purchase and transportation agreements (that are entered into on a competitive
basis and based on market prices) supplies natural gas requirements for each
plant, as needed.
Nuclear:
I&M has made commitments to meet the current nuclear fuel requirements of
the Cook Plant. I&M has made and will make purchases of uranium in various
forms in the spot, short-term, and mid-term markets. I&M also continues to
lease a portion of its nuclear fuel requirements.
For
purposes of the storage of high-level radioactive waste in the form of spent
nuclear fuel, I&M completed modifications to its spent nuclear fuel storage
pool more than 10 years ago. I&M anticipates that the Cook Plant has
sufficient storage capacity for its spent nuclear fuel to permit normal
operations through 2013. I&M has entered into an agreement to
provide for onsite dry cask storage. Initial loading of spent nuclear
fuel into the dry casks is tentatively scheduled to begin in 2012.
Nuclear
Waste and Decommissioning
As the
owner of the Cook Plant, I&M has a significant future financial commitment
to dispose of spent nuclear fuel and decommission and decontaminate the plant
safely. The cost to decommission a nuclear plant is affected by NRC regulations
and the spent nuclear fuel disposal program. In 2009, when the most
recent study was done, the estimated cost of decommissioning and disposal of
low-level radioactive waste for the Cook Plant ranged from $831 million to $1.5
billion in 2009 non-discounted dollars. At December 31, 2009, the
total decommissioning trust fund balance for the Cook Plant was approximately
$1.1 billion. The balance of funds available to decommission Cook
Plant will differ based on contributions and investment returns. The
ultimate cost of retiring the Cook Plant may be materially different from
estimates and funding targets as a result of the:
·
|
Type
of decommissioning plan selected;
|
·
|
Escalation
of various cost elements (including, but not limited to, general inflation
and the cost of energy);
|
·
|
Further
development of regulatory requirements governing
decommissioning;
|
·
|
Technology
available at the time of decommissioning differing significantly from that
assumed in studies;
|
·
|
Availability
of nuclear waste disposal facilities;
and
|
·
|
Availability
of a DOE facility for permanent storage of spent nuclear
fuel.
|
Accordingly,
management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant will not be significantly different than current
projections. We will seek recovery from customers through our
regulated rates if actual decommissioning costs exceed our
projections. See Note 6 to the consolidated financial statements,
entitled Commitments,
Guarantees and Contingencies under
the heading Nuclear
Contingencies, included in the 2009 Annual Reports, for information with
respect to nuclear waste and decommissioning.
Low-Level
Radioactive Waste: The LLWPA mandates that the
responsibility for the disposal of low-level radioactive waste rests with the
individual states. Low-level radioactive waste consists largely of ordinary
refuse and other items that have come in contact with radioactive materials.
Michigan does not currently have a disposal site for such waste available.
I&M cannot predict when such a site may be available, but Utah licenses a
low-level radioactive waste disposal site which currently accepts low-level
radioactive waste from Michigan. I&M ships some of its low level
waste to a facility in Utah. There is currently no set date limiting I&M’s
access to the Utah facility. I&M stores the remaining type
of low-level waste onsite. In order to have capacity for the duration
of its licensed operation of Cook Plant for onsite storage of waste not shipped
to Utah, I&M will have to modify its existing facilities sometime in the
next ten to fifteen years.
Structured
Arrangements Involving Capacity, Energy, and Ancillary Services
In
January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement
relating to the construction and operation of a 510 MW gas-fired electric
generating peaking facility to be owned by NPC, called the Mone
Plant. OPCo is entitled to 100% of the power generated by the Mone
Plant, and is responsible for the fuel and other costs of the facility through
May 2012, as extended. Following that, NPC and OPCo will be entitled to 80% and
20%, respectively, of the power of the Mone Plant, and both parties will
generally be responsible for their allocable portion of the fuel and other costs
of the facility.
Certain
Power Agreements
I&M: The Unit Power Agreement
between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo
to I&M of all the capacity (and the energy associated therewith) available
to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo,
I&M is obligated to pay a demand charge for the right to receive such power
(and an energy charge for any associated energy taken by
I&M). The agreement will continue in effect until the last of the
lease terms of Unit 2 of the Rockport Plant has expired (currently December
2022) unless extended in specified circumstances.
Pursuant
to an assignment between I&M and KPCo, and a unit power agreement between
KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated
therewith) available to AEGCo from both units of the Rockport Plant. KPCo has
agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the
terms of the Unit Power Agreement between AEGCo and I&M for such
entitlement. The KPCo unit power agreement expires in December
2022.
CSPCo: The Unit Power Agreement
between AEGCo and CSPCo, dated March 15, 2007, provides for the sale by AEGCo to
CSPCo of all the capacity and associated unit contingent energy and ancillary
services available to AEGCo at the Lawrenceburg Plant that are scheduled and
dispatched by CSPCo. CSPCo is obligated to pay a capacity charge
(whether or not power is available from the Lawrenceburg Plant), and the fuel,
operating and maintenance charges associated with the energy dispatched by
CSPCo, and to reimburse AEGCo for other costs associated with the operation and
ownership of the Lawrenceburg Plant. The agreement will continue in
effect until December 31, 2017 unless extended as set forth in the
agreement.
OVEC: AEP and several
unaffiliated utility companies jointly own OVEC. The aggregate equity
participation of AEP in OVEC is 43.47%. Until 2001, OVEC supplied
from its generating capacity the power requirements of a uranium enrichment
plant near Portsmouth, Ohio owned by the DOE. The sponsoring
companies are now entitled to receive and obligated to pay for all OVEC capacity
(approximately 2,200 MW) in proportion to their respective power participation
ratios. The aggregate power participation ratio of APCo, CSPCo,
I&M and OPCo is 43.47%. The proceeds from the sale of power by OVEC are
designed to be sufficient for OVEC to meet its operating expenses and fixed
costs and to provide a return on its equity capital. The Amended and
Restated Inter-Company Power Agreement, which defines the rights of the owners
and sets the power participation ratio of each, will expire by its terms in
March 2026. AEP and the other owners have authorized environmental
investments related to their ownership interests. As of December
2009, OVEC’s Board of Directors has authorized capital expenditures totaling
approximately $1 billion in connection with the engineering and construction of
flue gas desulfurization projects and the associated scrubber waste disposal
landfills at its two generating plants. OVEC’s Board of Directors has
delayed for an indeterminate period final completion of construction at both of
the plants. If approved and fully funded, the estimated total cost to
complete the scrubber and landfill projects would be in excess of $1.3 billion,
which OVEC would expect to finance through issuing debt.
ELECTRIC
TRANSMISSION AND DISTRIBUTION
General
AEP’s
public utility subsidiaries (other than AEGCo) own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item 2—Properties for more
information regarding the transmission and distribution lines. Most of the
transmission and distribution services are sold, in combination with electric
power, to retail customers of AEP’s public utility subsidiaries in their service
territories. These sales are made at rates approved by the state
utility commissions of the states in which they operate, and in some instances,
approved by the FERC. See Item 1 –Utility Operations -
Regulation—Rates. The FERC regulates and approves the rates for wholesale
transmission transactions. See Item 1 –Utility Operations -
Regulation—FERC. As discussed below, some transmission
services also are separately sold to non-affiliated companies.
AEP’s
public utility subsidiaries (other than AEGCo) hold franchises or other rights
to provide electric service in various municipalities and regions in their
service areas. In some cases, these franchises provide the utility
with the exclusive right to provide electric service. These
franchises have varying provisions and expiration dates. In general,
the operating companies consider their franchises to be adequate for the conduct
of their business. For a discussion of competition in the sale of
power, see Item 1 –Utility
Operations - Competition.
AEP
Transmission Pool
Transmission
Agreement: APCo, CSPCo, I&M,
KPCo and OPCo operate their transmission lines as a single interconnected and
coordinated system in the AEP East transmission zone and are parties to the
Transmission Agreement (TA), defining how they share the costs and benefits
associated with their relative ownership of the bulk transmission system (lines
operated at 138kV and above and stations containing extra high voltage
equipment). The TA has been approved by the FERC. Sharing under the TA is based
upon each company’s “member-load-ratio.” The member-load-ratio is
calculated monthly by dividing such company’s highest monthly peak demand for
the last twelve months by the aggregate of the highest monthly peak demand for
the last twelve months for all east zone operating companies. The
respective peak demands and member-load-ratios as of December 31, 2009 are set
forth above in the section titled ELECTRIC GENERATION – AEP
Power Pool and CSW Operating Agreement.
In June
2009, AEP filed with FERC to amend the TA in order to add WPCo and KgPCo and to
reallocate PJM costs on an individual basis instead of on a Member-Load-Ratio
basis. In August 2009, FERC accepted the proposed amendment to the TA
for filing, suspended it for a nominal period, to become effective on the first
day of the month after a final FERC order in the proceeding, as requested,
subject to refund. FERC established a hearing and settlement
procedure. Settlement discussions in the case are currently
underway.
The
following table shows the net (credits) or charges allocated among the parties
to the TA during the years ended December 31, 2007, 2008 and 2009:
|
2007
|
2008
|
2009
|
|
(in
thousands)
|
APCo
|
$(25,000)
|
$(29,000)
|
$(12,500)
|
CSPCo
|
51,900
|
55,000
|
51,300
|
I&M
|
(34,600)
|
(37,000)
|
(38,400)
|
KPCo
|
(800)
|
(2,000)
|
(8,800)
|
OPCo
|
8,500
|
13,000
|
8,400
|
Transmission
Coordination Agreement, OATT, and ERCOT Protocols: PSO, SWEPCo, TNC and
AEPSC are parties to the TCA. Under the TCA, a coordinating committee
is charged with the responsibility of (i) overseeing the coordinated planning of
the transmission facilities of the parties to the agreement, including the
performance of transmission planning studies, (ii) the interaction of such
subsidiaries with independent system operators and other regional bodies
interested in transmission planning and (iii) compliance with the terms of the
OATT filed with the FERC and the rules of the FERC relating to such
tariff. Pursuant to the TCA, AEPSC has responsibility for monitoring
the reliability of their transmission systems and administering
the OATT on behalf of the other parties to the agreement. The TCA
also provides for the allocation among the parties of revenues collected for
transmission and ancillary services provided under the OATT. These
allocations have been determined by the FERC-approved OATT for the SPP (with
respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect
to TCC and TNC).
The
following table shows the net (credits) or charges allocated pursuant to the
TCA, SPP OATT and ERCOT protocols as described above during the years ended
December 31, 2007, 2008 and 2009:
|
2007
|
2008
|
2009
|
|
(in
thousands)
|
PSO
|
$500
|
$8,200
|
$11,000
|
SWEPCo
|
(500)
|
(8,200)
|
(11,000)
|
TCC
|
1,100
|
1,500
|
1,700
|
TNC
|
(1,100)
|
(1,500)
|
(1,700)
|
Transmission
Services for Non-Affiliates: In addition to
providing transmission services in connection with their own power sales, AEP’s
public utility subsidiaries through RTOs also provide transmission services for
non-affiliated companies. See Item 1 –Utility Operations –
Electric Transmission and Distribution - Regional Transmission Organizations,
below.
Transmission of electric power by AEP’s public utility subsidiaries is
regulated by the FERC.
Coordination of
East and West Zone Transmission: AEP’s System
Transmission Integration Agreement provides for the integration and coordination
of the planning, operation and maintenance of the transmission facilities of AEP
East and AEP West companies. The System Transmission Integration Agreement
functions as an umbrella agreement in addition to the TA and the TCA. The System
Transmission Integration Agreement contains two service schedules that
govern:
·
|
The
allocation of transmission costs and revenues
and
|
·
|
The
allocation of third-party transmission costs and revenues and System
dispatch costs.
|
The
System Transmission Integration Agreement contemplates that additional service
schedules may be added as circumstances warrant.
Regional
Transmission Organizations
The AEP
East Companies are members of PJM (a FERC-approved RTO). SWEPCo and
PSO are members of the SPP (another FERC-approved RTO). RTOs operate,
plan and control utility transmission assets in a manner designed to provide
open access to such assets in a way that prevents discrimination between
participants owning transmission assets and those that do not. The remaining AEP
West companies (TCC and TNC) are members of ERCOT. See Note 4 to the
consolidated financial statements, entitled Rate Matters, included in the
2009 Annual Reports under the heading entitled Regional Transmission Rate
Proceedings at the FERC for additional information regarding
RTOs.
REGULATION
General
Except
for transmission and/or retail generation sales in certain of its jurisdictions,
AEP’s public utility subsidiaries’ retail rates and certain other matters are
subject to traditional cost-based regulation by the state utility
commissions. AEP’s subsidiaries are also subject to regulation by the
FERC under the FPA with respect to wholesale power and transmission service
transactions as well as certain unbundled retail transmission rates mainly in
Ohio. I&M is subject to regulation by the NRC under the Atomic
Energy Act of 1954, as amended, with respect to the operation of the Cook
Plant. AEP and its public utility subsidiaries are also subject to
the regulatory provisions of EPACT, much of which is administered by the
FERC. EPACT provides the FERC limited “backstop” transmission siting
authority as well as increased utility merger oversight. The law also
provides incentives and funding for clean coal technologies and initiatives to
voluntarily reduce CO2
emissions.
Rates
Historically,
state utility commissions have established electric service rates on a
cost-of-service basis, which is designed to allow a utility an opportunity to
recover its cost of providing service and to earn a reasonable return on its
investment used in providing that service. A utility’s cost of service generally
reflects its operating expenses, including operation and maintenance expense,
depreciation expense and taxes. State utility commissions periodically adjust
rates pursuant to a review of (i) a utility’s adjusted revenues and expenses
during a defined test period and (ii) such utility’s level of investment. Absent
a legal limitation, such as a law limiting the frequency of rate changes or
capping rates for a period of time, a state utility commission can review and
change rates on its own initiative. Some states may initiate reviews at the
request of a utility, customer, governmental or other representative of a group
of customers. Such parties may, however, agree with one another not to request
reviews of or changes to rates for a specified period of time.
Public
utilities have traditionally financed capital investments until the new asset
was placed in service. Provided the asset was found to be a prudent
investment, it was then added to rate base and entitled to a return through rate
recovery. Given long lead times in construction, the high costs of
plant and equipment and difficult capital markets, we are actively pursuing
strategies to accelerate rate recognition of investments and cash
flow. AEP representatives continue to engage our state commissioners
and legislators on alternative ratemaking options to reduce regulatory lag and
enhance certainty in the process. These options include
pre-approvals, a return on construction work in progress, rider/trackers,
securitization, formula rates and the inclusion of future test-year projections
into rates.
In many
jurisdictions, the rates of AEP’s public utility subsidiaries are generally
based on the cost of providing traditional bundled electric service (i.e.,
generation, transmission and distribution service). In the ERCOT area of Texas,
our utilities have exited the generation business and they currently charge
unbundled cost-based rates for transmission and distribution service
only. In Ohio, rates for electric service are unbundled for
generation, transmission and distribution service. Historically, the
state regulatory frameworks in the service area of the AEP System reflected
specified fuel costs as part of bundled (or, more recently, unbundled) rates or
incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel
adjustment clauses permit periodic adjustments to fuel cost recovery from
customers and therefore provide protection against exposure to fuel cost
changes.
The
following state-by-state analysis summarizes the regulatory environment of
certain major jurisdictions in which AEP operates. Several public utility
subsidiaries operate in more than one jurisdiction. See Note 4 to the
consolidated financial statements, entitled Rate Matters, included in the
2009 Annual Reports, for more information regarding pending rate
matters.
Indiana:
I&M provides retail electric service in Indiana at bundled rates approved by
the IURC, with rates set on a cost-of-service basis. Indiana provides
for timely fuel and purchased power cost recovery through a fuel cost recovery
mechanism.
Ohio: CSPCo and OPCo each operate
as a functionally separated utility and provide “default” retail electric
service to customers at unbundled rates pursuant to the Ohio
Act. CSPCo and OPCo provide distribution services to retail customers
at cost based rates approved by the PUCO. Transmission services are
provided at OATT rates based on rates established by the FERC. CSPCo
and OPCo’s generation/supply rates are subject to their Electric Security Plans
that the PUCO modified and approved in a March 2009 order. The
order established standard service offer rates in effect through
2011. The order also provides a fuel adjustment clause for the
three-year period of the ESP. The order has been appealed by various
parties to the Supreme Court of Ohio. Although the Supreme Court of
Ohio has rejected or dismissed a number of procedural and other challenges to
the order, the order remains on appeal with that Court.
Oklahoma: PSO provides retail
electric service in Oklahoma at bundled rates approved by the
OCC. PSO’s rates are set on a cost-of-service basis. Fuel and
purchased energy costs above or below the amount included in base rates are
recovered or refunded by applying a fuel adjustment factor to retail
kilowatt-hour sales. The factor is generally adjusted annually and is based upon
forecasted fuel and purchased energy costs. Over or under collections of fuel
costs for prior periods are returned to or recovered from customers in the year
following when new annual factors are established.
Texas: TCC has sold all of its
generation assets. TNC has one active generation
unit. However, all of the output from that unit is sold to a
non-utility affiliate pursuant to an agreement effective through
2027. Retail customers in TCC’s and TNC’s ERCOT service area of Texas
are served through non-affiliated Retail Electric Providers
(“REPs”). TCC and TNC provide transmission and distribution service
on a cost-of-service basis at rates approved by the PUCT and wholesale
transmission service under tariffs approved by the FERC consistent with PUCT
rules. Effective September 2009, competition in the SPP area of Texas
has been delayed until certain steps defined by statute and by PUCT rule have
been accomplished. As such, the PUCT continues to approve base and fuel rates
for SWEPCo’s Texas operations on a cost of service basis.
Virginia: APCo currently provides
retail electric service in Virginia at unbundled rates approved by the
VSCC. Virginia generally allows for timely recovery of fuel costs
through a fuel adjustment clause. Transmission services are provided
at OATT rates based on rates established by the FERC. APCo is
permitted to retain a minimum of 25% of the margins from its off-system sales
with the remaining margins from such sales credited against its fuel adjustment
clause factor with a true-up to actual. In addition to base rates and
fuel cost recovery, APCo is permitted to recover a variety of costs through rate
adjustment clauses.
West
Virginia: APCo
and WPCo provide retail electric service at bundled rates approved by the WVPSC,
with rates set on a cost-of-service basis. West Virginia generally allows for
timely recovery of fuel costs through an expanded net energy clause which trues
up to actual expenses.
Other
Jurisdictions:
The public utility subsidiaries of AEP also provide service at cost based
regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and
regulated unbundled rates in Michigan. These jurisdictions provide
for the timely recovery of fuel costs through fuel adjustment clauses that
true-up to actual expenses.
The
following table illustrates certain regulatory information with respect to the
states in which the public utility subsidiaries of AEP operate:
Jurisdiction
|
Percentage of AEP System
Retail
Revenues
(1)
|
Percentage
of OSS Profits Shared with Ratepayers
|
AEP
Utility
Subsidiaries
Operating in that Jurisdiction
|
Authorized
Return on Equity
(2)
|
|
|
|
|
|
Ohio
|
33%
|
No
sharing included in ESPs
|
OPCo
|
(3)
|
|
|
|
CSPCo
|
(3)
|
|
|
|
|
|
Texas
|
12%
|
Not
Applicable in ERCOT
|
TCC
(4)
|
9.96%
|
|
|
|
TNC
(4)
|
9.96%
|
|
|
90%
in SPP
|
SWEPCo
|
15.70%
|
|
|
|
|
|
Virginia
|
12%
|
75%
|
APCo
|
10.20%
|
|
|
|
|
|
West
Virginia
|
10%
|
100%
|
APCo
|
10.50%
|
|
|
|
WPCo
|
10.50%
|
|
|
|
|
|
Oklahoma
|
10%
|
75%
|
PSO
|
10.50%
|
|
|
|
|
|
Indiana
|
10%
|
50%
after certain level (5)
|
I&M
|
10.50%
|
|
|
|
|
|
Kentucky
|
5%
|
60%
to 70% after certain levels (6)
|
KPCo
|
10.50%
|
|
|
|
|
|
Louisiana
|
3%
|
50%
to 100% after certain levels (7)
|
SWEPCo
|
10.57%
|
|
|
|
|
|
Arkansas
|
2%
|
50%
to 100% after certain levels (8)
|
SWEPCo
|
10.25%
|
|
|
|
|
|
Michigan
|
2%
|
100%
in one area, 0% in the other area
|
I&M
|
13.00%
|
|
|
|
|
|
Tennessee
|
1%
|
Not
Applicable
|
Kingsport
|
12.00%
|
|
|
|
|
|
(1)
|
Represents
the percentage of revenues from sales to retail customers from AEP utility
companies operating in each state to the total AEP System revenues from
sales to retail customers for the year ended December 31,
2009.
|
(2)
|
Identifies
the predominant authorized return on equity and may not include other,
less significant, permitted recovery. Actual return on equity
varies from authorized return on
equity.
|
(3)
|
CSPCo’s
and OPCo’s generation revenues are governed by its Electric Security Plans
(ESP) filed and approved by the PUCO. Starting in April 2009,
the ESP became effective which authorized rate increases during the ESP
period, subject to caps that limit the rate increases for CSPCo to 7% in
2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and
8% in 2011. Some rate components and increases are exempt from
the cap limitations. The ESP also provided for a fuel
adjustment clause for the three-year period of the ESP. CSPCo
and OPCo provide distribution services at cost based rates approved by the
PUCO. Transmission services are provided at OATT rates based on
rates established by the FERC.
|
(4)
|
Operating
in the ERCOT region of Texas and consists of distribution and transmission
functions. Generation operations were divested in compliance
with the Texas electric
restructuring.
|
(5)
|
There
is an annual $37.5 million credit established for off-system sales in base
rates. If the off-system sales profits exceed the amount built
into base rates, I&M reimburses ratepayers 50% of the
excess.
|
(6)
|
There
is an annual $24.9 million credit established for off-system sales in base
rates. If the monthly off-system sales profits do not meet the
monthly level built into base rates, ratepayers reimburse KPCo 70% of the
shortfall. If the monthly off-system sales profits exceed the
monthly base amount built into base rates, KPCo reimburses ratepayers 70%
of the excess up to and including $30 million annually. After
$30 million, the percentage drops to
60%.
|
(7)
|
Below
$0.874 million, 100% is shared with customers; from $0.874 million to $1.3
million, 85% is shared with customers; above $1.3 million, 50% is shared
with customers.
|
(8)
|
Below
$0.759 million, 100% is shared with customers; from $0.759 million to $1.2
million, 85% is shared with customers; above $1.2 million, 50% is shared
with customers.
|
FERC
Under the
FPA, the FERC regulates rates for interstate power sales at wholesale,
transmission of electric power, accounting and other matters, including
construction and operation of hydroelectric projects. The FERC regulations
require AEP to provide open access transmission service at FERC-approved rates.
The FERC also regulates unbundled transmission service to retail
customers. The FERC also regulates the sale of power for resale in
interstate commerce by (i) approving contracts for wholesale sales to municipal
and cooperative utilities and (ii) granting authority to public utilities to
sell power at wholesale at market-based rates upon a showing that the seller
lacks the ability to improperly influence market prices. Except for
wholesale power that AEP delivers within its control area of the SPP, AEP has
market-rate authority from the FERC, under which much of its wholesale marketing
activity takes place. The FERC requires each public utility that owns
or controls interstate transmission facilities to, directly or through an RTO,
file an open access network and point-to-point transmission tariff that offers
services comparable to the utility’s own uses of its transmission system. The
FERC also requires all transmitting utilities, directly or through an RTO, to
establish an OASIS, which electronically posts transmission information such as
available capacity and prices, and requires utilities to comply with Standards
of Conduct that prohibit utilities’ transmission employees from providing
non-public transmission information to the utility’s marketing
employees.
The FERC
oversees RTOs, entities created to operate, plan and control utility
transmission assets. Order 2000 also prescribes certain characteristics and
functions of acceptable RTO proposals. The AEP East Companies are
members of PJM. SWEPCo and PSO are members of SPP.
The FERC
has jurisdiction over the issuances of securities of our public utility
subsidiaries, the acquisition of securities of utilities, the acquisition or
sale of certain utility assets, and mergers with another electric utility or
holding company. In addition, both the FERC and state regulators are
permitted to review the books and records of any company within a holding
company system. EPACT gives the FERC limited “backstop” transmission
siting authority as well as increased utility merger oversight.
COMPETITION
The
public utility subsidiaries of AEP, like the electric industry generally, face
competition in the sale of available power on a wholesale basis, primarily to
other public utilities and power marketers. The Energy Policy Act of 1992 was
designed, among other things, to foster competition in the wholesale market by
creating a generation market with fewer barriers to entry and mandating that all
generators have equal access to transmission services. As a result, there are
more generators able to participate in this market. The principal factors in
competing for wholesale sales are price (including fuel costs), availability of
capacity and power and reliability of service.
AEP’s
public utility subsidiaries also compete with self-generation and with
distributors of other energy sources, such as natural gas, fuel oil and coal,
within their service areas. The primary factors in such competition are price,
reliability of service and the capability of customers to utilize sources of
energy other than electric power. With respect to competing generators and
self-generation, the public utility subsidiaries of AEP believe that they
generally maintain a favorable competitive position. With respect to alternative
sources of energy, the public utility subsidiaries of AEP believe that the
reliability of their service and the limited ability of customers to substitute
other cost-effective sources for electric power place them in a favorable
competitive position, even though their prices may be higher than the costs of
some other sources of energy.
Significant
changes in the global economy have led to increased price competition for
industrial customers in the United States, including those served by the AEP
System. Some of these industrial customers have requested price reductions from
their suppliers of electric power. In addition, industrial customers that are
downsizing or reorganizing often close a facility based upon its costs, which
may include, among other things, the cost of electric power. The public utility
subsidiaries of AEP cooperate with such customers to meet their business needs
through, for example, providing various off-peak or interruptible supply options
pursuant to tariffs filed with, and approved by, the various state commissions.
Occasionally, these rates are negotiated with the customer, and then filed with
the state commissions for approval. While competition for retail electric
service is required by law in the states of Michigan and Ohio, the public
utility subsidiaries of AEP believe that they are unlikely to be materially
affected by this competition in an adverse manner.
In Ohio,
CSPCo has seen an increase in the number of customers, and their associated
loads, switching from CSPCo to generation service from other providers (although
as of December 31, 2009, the amount switching was less than 1% of CSPCo’s entire
load.) In February 2010 the PUCO granted a retail supply subsidiary
of AEP a certificate to operate as a competitive retail electric service
provider in Ohio.
SEASONALITY
The sale
of electric power is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change due to the nature and location of
AEP’s facilities and the terms of power sale contracts into which AEP enters. In
addition, AEP has historically sold less power, and consequently earned less
income, when weather conditions are milder. Unusually mild weather in the future
could diminish AEP’s results of operations and may impact its financial
condition. Conversely, unusually extreme weather conditions could
increase AEP’s results of operations.
AEP RIVER
OPERATIONS
Our AEP
River Operations Segment transports coal and dry bulk commodities primarily on
the Ohio, Illinois, and lower Mississippi rivers. Almost all of our
customers are nonaffiliated third parties who obtain the transport of coal and
dry bulk commodities for various uses. We charge these customers
market rates for the purpose of making a profit. Depending on market
conditions and other factors, including barge availability, we permit AEP
utility subsidiary affiliates to use certain of our equipment at rates that
reflect our cost. Our affiliated utility customers procure the
transport of coal for use as fuel in their respective generating
plants. We charge affiliated customers rates that reflect our
costs. AEP River Operations includes approximately 2,287 barges, 46
towboats and 26 harbor boats that we own or lease. These assets are separate
from the barges and towboats dedicated exclusively to transporting coal for use
as fuel in our own generating facilities discussed under the prior
segment. See Item 1
– Utility Operations - Electric Generation —Fuel Supply—Coal and
Lignite.
Competition
within the barging industry for major commodity contracts is intense, with a
number of companies offering transportation services in the waterways we serve.
We compete with other carriers primarily on the basis of commodity shipping
rates, but also with respect to customer service,
available routes, value-added services (including scheduling convenience and
flexibility), information timeliness and equipment. The industry continues
to experience consolidation. The resulting companies
increasingly offer the widespread geographic reach necessary to support major
national customers. Demand for barging services can be seasonal,
particularly with respect to the movement of harvested agricultural commodities
(beginning in the late summer and extending through the fall). Cold
winter weather may also limit our operations when certain of the waterways we
serve are closed.
Our
transportation operations are subject to regulation by the U.S. Coast
Guard, federal laws, state laws and certain international
conventions. Legislation has been proposed that could make our
towboats subject to inspection by the U.S. Coast Guard.
GENERATION AND
MARKETING
Our
Generation and Marketing Segment consists of non-utility generating assets and a
competitive power supply and energy trading and marketing
business. We enter into short and long-term transactions to buy or
sell capacity, energy and ancillary services primarily in the ERCOT
market. As of December 31, 2009, the assets utilized in this segment
included approximately 310 MW of company-owned domestic wind power
facilities, 177 MW of
domestic wind power from long-term purchase power agreements and 377 MW of
coal-fired capacity which was obtained through an agreement effective through
2027 that transfers TNC’s interest in the Oklaunion power
station to AEP Energy Partners, Inc. TNC transfered its coal-fired
generation capacity to comply with the separation requirements of the Texas
Act. The power obtained from the Oklaunion power station is marketed
and sold in ERCOT. We are regulated by the PUCT for transactions
inside ERCOT and by the FERC for transactions outside of ERCOT. While
peak load in ERCOT typically occurs in the summer, we do not necessarily expect
seasonal variation in our operations.
ITEM
1A. RISK FACTORS
General
Risks of Our Regulated Operations
We may not be able to recover the
costs of our substantial planned investment in capital improvements and
additions.
(Applies to each registrant.)
Our
business plan calls for extensive investment in capital improvements and
additions, including the installation of environmental upgrades and retrofits,
construction and/or acquisition of additional generation units and transmission
facilities, modernizing existing infrastructure as well as other initiatives.
Our public utility subsidiaries currently provide service at rates approved by
one or more regulatory commissions. If these regulatory commissions
do not approve adjustments to the rates we charge, we would not be able to
recover the costs associated with our planned extensive
investment. This would cause our financial results to be
diminished. While we may seek to limit the impact of any denied
recovery by attempting to reduce the scope of our capital investment, there can
be no assurance as to the effectiveness of any such mitigation efforts,
particularly with respect to previously incurred costs and
commitments.
Our
planned capital investment program coincides with a material increase in the
price of the fuels used to generate electricity. Most of our jurisdictions have
fuel clauses that permit us to recover these increased fuel costs through rates
without a general rate case. While prudent capital investment and
variable fuel costs each generally warrant recovery, in practical terms our
regulators could limit the amount or timing of increased costs that we would
recover through higher rates. Any such limitation could cause
our financial results to be diminished.
Turk Plant construction and operation
permits could be reversed on appeal. (Applies to
SWEPCo)
In
November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in
Arkansas by issuing a Certificate of Environmental Compatibility and Public
Need. In June 2009, the Arkansas Court of Appeals issued a unanimous
decision that would reverse the APSC’s grant of its permission for construction
of the Turk Plant to serve Arkansas retail customers. In October
2009, the Arkansas Supreme Court granted the petitions filed by SWEPCo and the
APSC to review the Arkansas Court of Appeals decision. While the appeal is
pending, SWEPCo is continuing construction on the plant.
In
November 2008, SWEPCo received the required air permit approval for the Turk
Plant from the Arkansas Department of Environmental Quality. In
December 2008, certain opponents filed an appeal of the air permit with the
Arkansas Pollution Control and Ecology Commission. The commission
upheld the air permit in a January 2010 ruling. These same opponents
filed a petition with the Federal EPA to review the air permit. In
December 2009, the Federal EPA rejected their petition on every issue except
one, where the Federal EPA asked the ADEQ to supplement the air permit record on
one aspect of its Best Available Control Technology analysis. The
Turk Plant cannot be placed into service without an air permit. If
SWEPCo is unable to complete the Turk Plant construction and place the Turk
Plant in service, it would reduce net income, cash flow and possibly harm our
financial condition unless the resultant losses can be fully recovered, with a
return on unrecovered balances, through rates in all of its
jurisdictions.
Rate recovery approved in Ohio may be
overturned on appeal, may not provide full recovery of fuel costs and/or may
have to be returned. (Applies to AEP, OPCo and
CSPCo)
The PUCO
issued an order in March 2009 that modified and approved the Electric Security
Plans (“ESPs”) of CSPCo and OPCo. The ESPs established rates in
effect through 2011. The ESP order generally authorized rate
increases during the ESP period, subject to caps that limit the rate increases
for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009,
7% in 2010 and 8% in 2011. The order also provides a fuel adjustment
clause (“FAC”) for the three-year period of the ESP. The FAC increase
will be phased in to avoid having the resultant rate increases exceed the
ordered annual caps. The order allows CSPCo and OPCo to defer
unrecovered FAC costs and to accrue carrying charges on such deferrals at
CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC
balance at the end of the three-year ESP period will be recovered through a
non-bypassable surcharge over the period 2012 through 2018. Although
the Supreme Court of Ohio has rejected or dismissed a number of procedural and
other challenges to the order, the order remains on appeal with that
Court.
Under our
ESP orders, CSPCo and OPCo may be required to return recovery awarded if their
earnings meet a certain threshold identified by the Significantly Excessive
Earnings Test (SEET). The PUCO must determine if rate adjustments
included in the ESP result in significantly excessive earnings. If
so, the excess amount must be returned to customers. The PUCO’s
decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected
to be finalized until a SEET filing is made by CSPCo and OPCo in 2010 and the
PUCO issues an order. The PUCO staff recommended that the SEET be calculated on
an individual company basis and not on a combined CSPCo/OPCo basis.
If the
PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery,
if deferred fuel costs are not fully recovered for other reasons, or if the PUCO
determines CSPCo’s or OPCo’s earnings are significantly excessive, it could
reduce future net income and cash flows and harm our financial
condition.
Rate recovery approved in Texas may
be overturned on appeal. (Applies to AEP)
In March
2008, the PUCT issued an order that increased TCC’s annual pretax income by
approximately $50 million. Various parties appealed the PUCT
decision. In February 2009, the Texas District Court affirmed the
PUCT in most respects. In March 2009, various intervenors appealed
the Texas District Court decision to the Texas Court of
Appeals. Management is unable to predict the outcome of these
proceedings. If the appeals are successful, it could reduce future
net income and cash flows.
Our request for rate recovery in
Texas may not be approved in its entirety. (Applies to AEP and
SWEPCo)
In August
2009, SWEPCo filed a base rate case with the PUCT to increase non-fuel base
rates by approximately $75 million annually based on a requested return on
common equity of 11.5%. If the PUCT denies all or part of the
requested rate recovery, it could reduce future net income and cash
flows.
Our request for rate recovery in
Virginia may not be approved in its entirety. (Applies to AEP and
APCo)
In July
2009, APCo filed a base rate case with the Virginia SCC requesting an increase
in the generation and distribution portions of its base rates of $169 million
(later adjusted to $154 million) annually and a 13.35% return on
equity. If the Virginia SCC denies all or part of the requested rate
recovery, it could reduce future net income and cash flows and harm our
financial condition.
Our request for rate recovery in
Kentucky may not be approved in its entirety. (Applies to AEP)
In
December 2009, KPCo filed a base rate case with the Kentucky Public Service
Commission requesting an increase in its base rates by $124 million annually and
a 11.75% return on equity. If the Kentucky Public Service Commission
denies all or part of the requested rate recovery, it could reduce future net
income and cash flows and harm our financial condition.
Our request for rate recovery in
Michigan may not be approved in its entirety. (Applies to
I&M)
In
January 2010, I&M filed a base rate case with the Michigan Public Service
Commission seeking a $63 million increase in revenue, based on 11.75% return on
equity. If the Michigan Public Service Commission denies all or part of the
requested rate recovery, it could reduce future net income and cash flows and
harm our financial condition.
Our future access to assets used to
serve a major customer is in question. (Applies to
I&M)
Since
1975 I&M has leased certain energy delivery assets from the City of Fort
Wayne, Indiana under a long-term lease that expires on February 28,
2010. I&M has been negotiating with Fort Wayne to purchase the
remaining assets at the end of the lease, but no agreement has been
reached. Fort Wayne issued a technical notice of default under the
lease to I&M in August 2009. In October 2009, I&M filed for declaratory
and injunctive relief in Indiana state court. The court had ordered
additional mediation. I&M will seek recovery in rates for any
amount it may pay related to this dispute. At this time, management
cannot predict the outcome of this dispute. While management believes
any triggered costs should be recoverable from customers, any unrecovered costs
could reduce future net income and cash flows.
Oklahoma may require us to refund
fuel costs that we have collected. (Applies to PSO)
PSO
under-recovered $42 million of fuel costs resulting from a reallocation of
purchased power costs among AEP West companies for periods prior to
2002. PSO recovered the $42 million by offsetting it against an
existing fuel over-recovery during the period June 2007 through May
2008. An association of industrial consumers has contended that PSO
should not have collected the $42 million without specific OCC approval and that
the OCC should require PSO to refund what it collected through its fuel
clause. The OCC has heard the association’s appeal and a decision is
pending. If the OCC were to order PSO to refund all or a part of the
$42 million, it could reduce future net income and cash flows.
We may not recover costs incurred to
begin constructing generating plants that are canceled. (Applies to each
registrant)
Our
business plan for the construction of new generating units involves a number of
risks, including construction delays, nonperformance by equipment and
other third party suppliers, and increases in equipment and labor costs. To
limit the risks of these construction projects, we enter into equipment purchase
orders and construction contracts and incur engineering and design service costs
in advance of receiving necessary regulatory approvals and/or siting or
environmental permits. If any of these projects is canceled for any reason,
including our failure to receive necessary regulatory approvals and/or siting or
environmental permits, we could incur significant cancellation penalties under
the equipment purchase orders and construction contracts. In addition, if we
have recorded any construction work or investments as a regulatory asset we may
need to impair that asset in the event the project is canceled.
Rate regulation may delay or deny
full recovery of capital improvements, additions and other
costs.
(Applies to each registrant.)
Our
public utility subsidiaries currently provide service at rates approved by one
or more regulatory commissions. These rates are generally regulated
based on an analysis of the applicable utility’s expenses incurred in a test
year. Thus, the rates a utility is allowed to charge may or may not
match its expenses at any given time. There may also be a delay
between the timing of when these costs are incurred and when these costs are
recovered. Traditionally, we have financed capital investments and
improvements until the new asset was placed in service. Provided the
asset was found to be a prudent investment, the asset was then added to rate
base and entitled to a return through rate recovery. Long lead times
in construction, the high costs of plant and equipment and difficult capital
markets have heightened the risks involved in our capital investments and
improvements. While we are actively pursuing strategies to accelerate rate
recognition of investments and cash flow, including pre-approvals, a return on
construction work in progress, rider/trackers, formula rates and the inclusion
of future test-year projections into rates, there can be no assurance that these
will be adopted, that the applicable regulatory commission will judge all of our
costs to 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.
Our revenues and results of
operations are subject to risks that are beyond our
control.
(Applies to each registrant.)
Our
operations are structured to comply with all applicable federal and state laws
and regulations and we take measures to minimize the risk of significant
disruptions. Material disruptions at one or more of our operational
facilities, however, could negatively impact our revenues, operating and capital
expenditures and results of operations. Such events may also create
additional risks related to the supply and/or cost of equipment and
materials. We could experience unexpected but significant
interruption due to several events, including:
·
|
major
facility or equipment failure;
|
·
|
an
environmental event such as a serious spill or
release;
|
·
|
fires,
floods, droughts, earthquakes, hurricanes or other natural
disasters;
|
·
|
wars,
terrorist acts or threats and other catastrophic
events;
|
·
|
significant
health impairments or disease events,
and;
|
·
|
other
serious operational problems.
|
We are exposed to nuclear generation
risk. (Applies to AEP
and I&M.)
Through
I&M, we own the Cook Plant. It consists of two nuclear generating
units for a rated capacity of 2,191 MW, or 8-9% of the electricity we
generate. We are, therefore, subject to the risks of nuclear
generation, which include the following:
·
|
the
potential harmful effects on the environment and human health resulting
from the operation of nuclear facilities and the storage, handling and
disposal of radioactive materials such as spent nuclear
fuel;
|
·
|
limitations
on the amounts and types of insurance commercially available to cover
losses that might arise in connection with our nuclear
operations;
|
·
|
uncertainties
with respect to contingencies and assessment amounts if insurance coverage
is inadequate (federal law requires owners of nuclear units to purchase
the maximum available amount of nuclear liability insurance and
potentially contribute to the losses of others);
and,
|
·
|
uncertainties
with respect to the technological and financial aspects of decommissioning
nuclear plants at the end of their licensed
lives.
|
There can
be no assurance that I&M’s preparations or risk mitigation measures will be
adequate if and when these risks are triggered.
The NRC
has broad authority under federal law to impose licensing 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 or shut
down a unit, or both, 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 such as ours. In addition, although we have no reason
to anticipate a serious nuclear incident at our plants, if an incident did
occur, it could harm our results of operations or financial
condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit. Moreover, a major incident at any nuclear
facility in the U.S. could require us to make material contributory
payments.
The different regional power markets
in which we compete or will compete in the future have changing market and
transmission structures, which could affect our performance in these
regions. (Applies to each
registrant.)
Our
results are likely to be affected by differences in the market and transmission
structures in various regional power markets. The rules governing the
various regional power markets, including SPP and PJM, may also change from time
to time which could affect our costs or revenues. Because the manner
in which RTOs will evolve remains unclear, we are unable to assess fully the
impact that changes in these power markets may have on our
business.
The amount we charged third parties
for using our transmission facilities is subject to refund. (Applies to AEP, APCo,
CSPCo, I&M and OPCo.)
In July
2003, the FERC issued an order directing PJM and MISO to make compliance filings
for their respective tariffs to eliminate the transaction-based charges for
through and out (T&O) transmission service on transactions where the energy
is delivered within those RTOs. To mitigate the impact of lost
T&O revenues, the FERC approved temporary replacement seams elimination cost
allocation (SECA) transition rates beginning in December 2004 and extending
through March 2006. Because intervenors objected to this decision,
the SECA fees we collected ($220 million) are subject to refund.
In August
2006, an ALJ ruled that the SECA rates charged were unfair, unjust and
discriminatory, and that new compliance filings and refunds should be made. The
FERC has not ruled on the matter. If the FERC upholds the decision of
the ALJ, it would disallow $90 million of the AEP East companies’ remaining
unsettled $108 million of unsettled gross SECA revenues. AEP has
settled $112 million of SECA revenues for $10 million. We have recorded a
provision for estimated settlement refunds. Any payments in excess of
the reserve balance could harm our results of operations and financial
position.
We could be subject to higher costs
and/or penalties related to mandatory reliability standards. (Applies to each
registrant.)
As a
result of EPACT, owners and operators of the bulk power transmission system are
subject to mandatory reliability standards promulgated by the North American
Electric Reliability Corporation and enforced by the FERC. These standards,
which previously were being applied on a voluntary basis, became mandatory in
June 2007. The standards are based on the functions that need to be performed to
ensure the bulk power system operates reliably and is guided by reliability and
market interface principles. Compliance with new reliability standards may
subject us to higher operating costs and/or increased capital expenditures.
While we expect to recover costs and expenditures from customers through
regulated rates, there can be no assurance that the applicable commissions will
approve full recovery in a timely manner. If we were found not to be
in compliance with the mandatory reliability standards, we could be subject to
sanctions, including substantial monetary penalties, which likely would not be
recoverable from customers through regulated rates.
At times, demand for power could
exceed our supply capacity. (Applies to each
registrant.)
We are
currently obligated to supply power in parts of eleven states. From
time to time, because of unforeseen circumstances, the demand for power required
to meet these obligations could exceed our available generation
capacity. If this occurs, we would have to buy power from the
market. This would increase the pressure on our short-term debt
financing capacity in times of tight liquidity. We may not always
have the ability to pass these costs on to our customers, and the time lag
between incurring costs and recovery can be long. Since these
situations most often occur during periods of peak demand, it is possible that
the market price for power at that time would be very high. Even if a supply
shortage were brief, we could suffer substantial losses that could reduce our
results of operations.
Risks
Related to Market, Economic or Financial Volatility
If we are unable to access capital
markets on reasonable terms, it could have an adverse impact on our net income,
cash flows and financial condition. (Applies to each
registrant)
We rely
on access to capital markets as a significant source of liquidity for capital
requirements not satisfied by operating cash flows. Volatility and
reduced liquidity in the financial markets could affect our ability to raise
capital and fund our capital needs, including construction costs and refinancing
maturing indebtedness. In addition, if capital is available only on
less than reasonable terms or to borrowers whose creditworthiness is better than
ours, capital costs could increase materially. Restricted access to
capital markets and/or increased borrowing costs could have an adverse impact on
net income, cash flows and financial condition.
Downgrades in our credit ratings
could negatively affect our ability to access capital and/or to operate our
power trading businesses. (Applies to each
registrant)
The
credit ratings agencies periodically review our capital structure and the
quality and stability of our earnings. Any negative ratings actions
could constrain the capital available to us and could limit our access to
funding for our operations. Our business is capital intensive, and we
are dependent upon our ability to access capital at rates and on terms we
determine to be attractive. In periods of market turmoil, access to
capital is difficult for all borrowers. If our ability to access
capital becomes significantly constrained, our interest costs will likely
increase and our financial condition could be harmed and future results of
operations could be adversely affected.
Our power
trading business relies on the investment grade ratings of our individual public
utility subsidiaries’ senior unsecured long-term debt. Most of our
counterparties require the creditworthiness of an investment grade entity to
stand behind transactions. If those ratings were to decline below
investment grade, our ability to operate our power trading business profitably
would be diminished because we would likely have to deposit cash or cash-related
instruments which would reduce our profits.
Our pension plan requires additional
significant contributions. (Applies to each
registrant.)
The
performance of the capital markets affects the value of the assets that are held
in trust to satisfy future obligations under our defined benefit pension
plan. The volatility of the capital markets in recent years has led
to a decline in the market value of these assets. Also, a decline in interest
rates on corporate bonds in 2009 has impacted the benchmark discount rate in a
way that results in a higher calculated pension liability. Accordingly, our
future required contributions to fund obligations under our defined benefit plan
could increase significantly.
AEP has no income or cash flow apart
from dividends paid or other obligations due it from its
subsidiaries. (Applies to
AEP.)
AEP is a
holding company and has no operations of its own. Its ability to meet
its financial obligations associated with its indebtedness and to pay dividends
on its common stock is primarily dependent on the earnings and cash flows of its
operating subsidiaries, primarily its regulated utilities, and the ability of
its subsidiaries to pay dividends to, or repay loans from, AEP. Its
subsidiaries are separate and distinct legal entities that have no obligation
(apart from loans from AEP) to provide AEP with funds for its payment
obligations, whether by dividends, distributions or other payments. Payments to
AEP by its subsidiaries are also contingent upon their earnings and business
considerations. In addition, any payment of dividends, distributions or advances
by the utility subsidiaries to AEP could be subject to regulatory
restrictions. AEP indebtedness and common stock dividends are
effectively subordinated to all subsidiary indebtedness and preferred stock
obligations.
Our operating results may fluctuate
on a seasonal or quarterly basis and with general economic
conditions. (Applies to each
registrant.)
Electric
power generation is generally a seasonal business. In many parts of
the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks
during the winter. As a result, our overall operating results in the
future may fluctuate substantially on a seasonal basis. The pattern
of this fluctuation may change depending on the terms of power sale contracts
that we enter into. In addition, we have historically sold less
power, and consequently earned less income, when weather conditions are
milder. Unusually mild weather in the future could diminish our
results of operations and harm our financial condition. Conversely,
unusually extreme weather conditions could increase AEP’s results of operations
in a manner that would not likely be sustainable.
Further,
deteriorating economic conditions generally result in reduced consumption by our
customers, particularly industrial customers who may curtail operations or cease
production entirely, while an expanding economic environment generally results
in increased revenues. As a result, our overall operating results in
the future may fluctuate on the basis of prevailing economic
conditions. For example, off-system sales volumes decreased by 50%
and industrial KWH sales were down 16% in 2009, a period of prolonged diminished
economic activity.
Failure to attract and retain an
appropriately qualified workforce could harm our results of operations.
(Applies to each
registrant.)
Certain
events, such as an aging workforce without appropriate replacements, mismatch of
skillset or complement to future needs, or unavailability of contract resources
may lead to operating challenges and increased costs. The challenges include
lack of resources, loss of knowledge and a lengthy time period associated with
skill development. In this case, costs, including costs for contractors to
replace employees, productivity costs and safety costs, may rise. Failure to
hire and adequately train replacement employees, including the transfer of
significant internal historical knowledge and expertise to the new employees, or
the future availability and cost of contract labor may adversely affect the
ability to manage and operate our business. If we are unable to
successfully attract and retain an appropriately qualified workforce, our
results of operations could be negatively affected.
Parties we have engaged to provide
construction materials or services may fail to perform their obligations, which
could harm our results of operations. (Applies to each
registrant.)
Our
business plan calls for extensive investment in capital improvements and
additions, including the installation of environmental upgrades, construction of
additional generation units and transmission facilities as well as other
initiatives. We are exposed to the risk of substantial price
increases in the costs of 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.
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 and almost certainly cause delays in that and
related 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 would cause our financial
results to be diminished, and we might incur losses or delays in completing
construction.
For
example, in our continuing environmental investment program, we chose to
retrofit wet flue gas desulfurization systems on several of our units utilizing
the jet bubbling reactor technology. These include two co-owned units
each at the Kyger Creek and Clifty Creek plants, three co-owned units at the
Cardinal plant and one co-owned unit at the Conesville plant; and, in
preliminary stages, a unit each at our Muskingum River and Big Sandy
plants. Due to unfavorable operating results, we completed an
extensive review of the design and manufacture of jet bubbling reactor internal
components. Our review concluded that there are fundamental design
deficiencies and that inferior and/or inappropriate materials were selected for
the internal fiberglass components. We are negotiating with the
original equipment manufacturer to develop a repair or replacement corrective
action plan. We might incur losses or delays if the original equipment
manufacturer does not remediate the deficiencies in a timely
manner.
Changes in commodity prices and the
costs of transport may increase our cost of producing power or decrease the
amount we receive from selling power, harming our financial
performance. (Applies to each
registrant.)
We are
exposed to changes in the price and availability of coal and the price and
availability to transport coal because most of our generating capacity is
coal-fired. We have contracts of varying durations for the supply of
coal for most of our existing generation capacity, but as these contracts end or
otherwise are not honored, we may not be able to purchase coal on terms as
favorable as the current contracts. Similarly, we are exposed to
changes in the price and availability of emission allowances. We use
emission allowances based on the amount of coal we use as fuel and the
reductions achieved through emission controls and other
measures. According to our estimates, we have procured sufficient
emission allowances to cover nearly all of our projected needs for the next two
years as well as a majority of our needs beyond that timeframe. At
some future point, additional costs may be incurred if forthcoming regulation
changes require supplemental allowances for compliance. If and when
we obtain additional allowances those purchases may not be on as favorable terms
as those currently obtained.
We also
own natural gas-fired facilities, which increases our exposure to market prices
of natural gas. Natural gas prices tend to be more volatile than
prices for other fuel sources. Our ability to make off-system sales
at a profit is highly dependent on the price of natural gas. As the
price of natural gas falls, other market participants that utilize natural
gas-fired generation will be able to offer electricity at increasingly
competitive prices relative to our off-system sales prices, so the margins we
realize from sales will be lower and, on occasion, we may need to curtail
operation of marginal plants.
Prices
for coal, natural gas and emission allowances have shown material upward and
downward swings in the recent past. Changes in the cost of coal,
emission allowances or natural gas and changes in the relationship between such
costs and the market prices of power will affect our financial
results. Since the prices we obtain for power may not change at the
same rate as the change in coal, emission allowances or natural gas costs, we
may be unable to pass on the changes in costs to our customers.
In
addition, actual power prices and fuel costs will differ from those assumed in
financial projections used to value our trading and marketing transactions, and
those differences may be material. As a result, our financial results
may be diminished in the future as those transactions are marked to
market.
Risks
Relating to State Restructuring
There is uncertainty as to our
recovery of stranded costs resulting from industry restructuring in
Texas. (Applies to
AEP.)
Restructuring
legislation in Texas required utilities with stranded costs to use market-based
methods to value certain generating assets for determining stranded
costs. We elected to use the sale of assets method to determine the
market value of TCC’s generation assets for stranded cost
purposes. In general terms, the amount of stranded costs under this
market valuation methodology is the amount by which the book value of generating
assets, including regulatory assets and liabilities that were not securitized,
exceeds the market value of the generation assets, as measured by the net
proceeds from the sale of the assets. In May 2005, TCC filed its
stranded cost quantification application with the PUCT seeking recovery of $2.4
billion of net stranded generation costs and other recoverable true-up
items. A final order was issued in April 2006. In the
final order, the PUCT determined TCC’s net stranded generation costs and other
recoverable true-up items to be approximately $1.475 billion. We have
appealed the PUCT’s final order seeking additional recovery consistent with the
Texas Restructuring Legislation and related rules, other parties have appealed
the PUCT’s final order as unwarranted or too large. Management cannot
predict the ultimate outcome of any future court appeals or any future remanded
PUCT proceeding.
Collection of our revenues in Texas
is concentrated in a limited number of REPs. (Applies to
AEP.)
Our
revenues from the distribution of electricity in the ERCOT area of Texas are
collected from REPs that supply the electricity we distribute to their
customers. Currently, we do business with approximately seventy
REPs. In 2009, TCC’s largest customer accounted for 28% of its
operating revenue and its second largest customer accounted for 17% of its
operating revenue; TNC’s largest customer (a non-utility affiliate) accounted
for 30% of its operating revenues and its second largest customer accounted for
18% of its operating revenues. Adverse economic conditions,
structural problems in the Texas market or financial difficulties of one or more
REPs could impair the ability of these REPs to pay for our services or could
cause them to delay such payments. We depend on these REPs for timely
remittance of payments. Any delay or default in payment could
adversely affect the timing and receipt of our cash flows and thereby have an
adverse effect on our liquidity.
Risks
Related to Owning and Operating Generation Assets and Selling Power
Our costs of compliance with existing
environmental laws are significant. (Applies to each
registrant)
Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality, waste
management, natural resources and health and safety. Approximately
90% of the electricity generated by the AEP system is produced by the combustion
of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and
particulates from fossil fueled generating plants are potentially subject to
increased regulations, controls and mitigation expenses. Compliance
with these legal requirements requires us to commit significant capital toward
environmental monitoring, installation of pollution control equipment, emission
fees and permits at all of our facilities. These expenditures have
been significant in the past, and we expect that they will increase in the
future. Costs of compliance with environmental regulations could
adversely affect our net income and financial position, especially if emission
and/or discharge limits are tightened, more extensive permitting requirements
are imposed, additional substances become regulated and the number and types of
assets we operate increase. While we expect to recover our
expenditures for pollution control technologies, replacement generation and
associated operating costs from customers through regulated rates (in regulated
jurisdictions) or market prices, without such recovery those costs could reduce
our future net income and cash flows, and possibly harm our financial
condition.
Regulation of CO2 emissions, either through legislation or by
the Federal EPA, could materially increase costs to us and our customers or
cause some of our electric generating units to be uneconomical to operate or
maintain.(Applies to
each registrant)
In June
2009, the U.S. House of Representatives passed the American Clean Energy
Security Act (ACES). ACES is a comprehensive energy and global
warming bill that includes a number of provisions that would directly affect our
business, including energy efficiency and renewable electricity standards,
funding for carbon capture and sequestration demonstration projects, CO2 emission
standards, and an economy-wide cap and trade program for large sources of
CO2
emissions that would reduce emissions by 17% in 2020 and just over 80% by
2050 from 2005 levels. The Senate Environment and Public Works
Committee passed a bill out of committee in September. Costs of compliance with
the proposed legislation could adversely affect our net income and financial
position.
Separately,
in December 2009, the Federal EPA issued a final endangerment finding under the
CAA regarding emissions from motor vehicles. Several groups have
filed challenges to the endangerment finding. The endangerment
finding will lead to regulation of CO2 and other gases under
existing laws. Management believes some policy approaches being
discussed would have significant and widespread negative consequences for the
national economy and major U.S. industrial enterprises, including us and our
customers.
If
CO2
and other emission standards are imposed, the standards could require
significant increases in capital expenditures and operating costs which would
impact the ultimate retirement of older, less-efficient, coal-fired
units. While we expect that costs of complying with new CO2 and other
GHG emission standards will be treated like all other reasonable costs of
serving customers and should be recoverable from customers as costs of doing
business, without such recovery those costs could reduce our future net income
and cash flows and harm our financial condition.
Courts adjudicating nuisance and
other similar claims against us may order us to limit or reduce our
CO2 emissions. (Applies to each
registrant)
In 2004,
eight states and the City of New York filed an action in Federal District Court
for the Southern District of New York against AEP, Cinergy Corp, Xcel Energy,
Southern Company and Tennessee Valley Authority. The Natural
Resources Defense Council, on behalf of three special interest groups, filed a
similar complaint against the same defendants. The actions allege
that CO2 emissions
from the defendants’ power plants constitute a public nuisance under federal
common law due to impacts of global warming, and sought injunctive relief in the
form of specific emission reduction commitments from the
defendants. The Second Circuit Court of Appeals reinstated this
lawsuit on appeal after the lower court had dismissed it. Similarly,
in October 2009, the Fifth Circuit Court of Appeals reversed a decision by the
trial court dismissing state common law nuisance claims in a putative class
action by Mississippi residents asserting that CO2 emissions
exacerbated the effects of Hurricane Katrina.
The trial
courts adjudicating these reinstated nuisance claims may order the defendants,
including us, to limit or reduce CO2
emissions. This or similar remedies could require us to purchase
power from third parties to fulfill our commitments to supply power to our
customers. This could have a material impact on our
costs. While management believes such costs should be recoverable
from customers as costs of doing business, without such recovery those costs
could reduce our future net income and cash flows and harm our financial
condition.
If these
or other future actions are resolved against us, substantial modifications of
our existing coal-fired power plants could be required. In addition,
we could be required to invest significantly in additional emission control
equipment, accelerate the timing of capital expenditures, pay penalties and/or
halt certain operations. Moreover, our results of operations and
financial position could be reduced due to the timing of recovery of these
investments and the expense of ongoing litigation.
We may not fully recover the costs of
repairing or replacing damaged equipment in Cook Plant Unit
1. (Applies
to AEP and I&M)
Cook
Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman,
Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations,
which resulted in a fire on the electric generator. Unit 1 resumed
operations in December 2009 at reduced power, but repair of the property damage
and replacement of the turbine rotors and other equipment are estimated to cost
approximately $395 million. Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process.
In 2009,
I&M entered into a settlement agreement with intervenors to collect a prior
under-recovered fuel balance. Under the settlement agreement, a subdocket was
established to consider issues relating to the Unit 1 shutdown, the use of the
accidental outage insurance proceeds and I&M’s fuel procurement
practices. Management cannot predict the outcome of the subdocket
proceeding or future fuel clause proceedings, including the treatment of the
accidental outage insurance proceeds and whether any fuel clause revenues or
insurance proceeds recognized will have to be refunded which could reduce future
net income and cash flows.
Our revenues and results of
operations from selling power are subject to market risks that are beyond our
control. (Applies to each
registrant.)
We sell
power from our generation facilities into the spot market and other competitive
power markets on a contractual basis. We also enter into contracts to
purchase and sell electricity, natural gas, emission allowances and coal as part
of our power marketing and energy trading operations. With respect to
such transactions, the rate of return on our capital investments is not
determined through mandated rates, and our revenues and results of operations
are likely to depend, in large part, upon prevailing market prices for power in
our regional markets and other competitive markets. These market
prices can fluctuate substantially over relatively short periods of
time. Trading margins may erode as markets mature and there may be
diminished opportunities for gain should volatility decline. In
addition, the FERC, which has jurisdiction over wholesale power rates, as well
as RTOs that oversee some of these markets, may impose price limitations,
bidding rules and other mechanisms to address some of the volatility in these
markets. Power supply and other similar agreements entered into
during extreme market conditions may subsequently be held to be unenforceable by
a reviewing court or the FERC. Fuel and emissions prices may also be
volatile, and the price we can obtain for power sales may not change at the same
rate as changes in fuel and/or emissions costs. These factors could
reduce our margins and therefore diminish our revenues and results of
operations.
Volatility
in market prices for fuel and power may result from:
·
|
outages
of major generation or transmission
facilities;
|
·
|
transmission
or transportation constraints or
inefficiencies;
|
·
|
availability
of competitively priced alternative energy
sources;
|
·
|
demand
for energy commodities;
|
·
|
natural
gas, crude oil and refined products, and coal production
levels;
|
·
|
natural
disasters, wars, embargoes and other catastrophic events;
and
|
·
|
federal,
state and foreign energy and environmental regulation and
legislation.
|
Our power trading (including coal,
gas and emission allowances trading and power marketing) and risk management
policies cannot eliminate the risk associated with these
activities. (Applies to each
registrant.)
Our power
trading (including coal, gas and emission allowances trading and power
marketing) activities expose us to risks of commodity price movements. We attempt to manage our
exposure by establishing and enforcing risk limits and risk management
procedures. These
risk limits and risk management procedures may not work as planned and cannot
eliminate the risks associated with these activities. As a result, we cannot
predict the impact that our energy trading and risk management decisions may
have on our business, operating results or financial position.
We
routinely have open trading positions in the market, within guidelines we set,
resulting from the management of our trading portfolio. To the extent open
trading positions exist, fluctuating commodity prices can improve or diminish
our financial results and financial position.
Our power
trading and 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 the 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.
Our financial performance may be
adversely affected if we are unable to operate our pooled electric generating
facilities successfully. (Applies to each
registrant.)
Our
performance is highly dependent on the successful operation of our electric
generating facilities. Operating electric
generating facilities involves many risks, including:
·
|
operator
error and breakdown or failure of equipment or
processes;
|
·
|
operating
limitations that may be imposed by environmental or other regulatory
requirements;
|
·
|
fuel
supply interruptions caused by transportation constraints, adverse
weather, non-performance by our suppliers and other factors;
and
|
·
|
catastrophic
events such as fires, earthquakes, explosions, hurricanes, terrorism,
floods or other similar
occurrences.
|
A
decrease or elimination of revenues from power produced by our electric
generating facilities or an increase in the cost of operating the facilities
would adversely affect our results of operations.
Parties with whom we have contracts
may fail to perform their obligations, which could harm our results of
operations. (Applies to each
registrant.)
We are
exposed to the risk that counterparties that owe us money or power could breach
their obligations. Should the
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 that may exceed our contractual prices, which would
cause our financial results to be diminished and we might incur losses. Although our estimates
take into account the expected probability of default by a counterparty, our
actual exposure to a default by a counterparty may be greater than the estimates
predict.
We rely on electric transmission
facilities that we do not own or control. If these facilities do not provide us
with adequate transmission capacity, we may not be able to deliver our wholesale
electric power to the purchasers of our power. (Applies to each
registrant.)
We depend
on transmission facilities owned and operated by other unaffiliated power
companies to deliver the power we sell at wholesale. This dependence exposes
us to a variety of risks. If transmission is
disrupted, or transmission capacity is inadequate, we may not be able to sell
and deliver our wholesale power. If a region’s power
transmission infrastructure is inadequate, our recovery of wholesale costs and
profits may be limited. If restrictive
transmission price regulation is imposed, the transmission companies may not
have sufficient incentive to invest in expansion of transmission
infrastructure.
The FERC
has issued electric transmission initiatives that require electric transmission
services to be offered unbundled from commodity sales. Although these
initiatives are designed to encourage wholesale market transactions for
electricity and gas, access to transmission systems may in fact not be available
if transmission capacity is insufficient because of physical constraints or
because it is contractually unavailable. We also cannot predict
whether transmission facilities will be expanded in specific markets to
accommodate competitive access to those markets.
We do not fully hedge against price
changes in commodities. (Applies to each
registrant.)
We
routinely enter into contracts to purchase and sell electricity, natural gas,
coal and emission allowances as part of our power marketing and energy and
emission allowances trading operations. In connection with
these trading activities, we routinely enter into financial contracts, including
futures and options, over-the counter options, financially-settled swaps and
other derivative contracts. These activities expose
us to risks from price movements. If the values of the
financial contracts change in a manner we do not anticipate, it could harm our
financial position or reduce the financial contribution of our trading
operations.
We manage
our exposure by establishing risk limits and entering into contracts to offset
some of our positions (i.e., to hedge our exposure to demand, market effects of
weather and other changes in commodity prices). However, we do not
always 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 may be improved or diminished based upon our
success in the market.
Proposed financial derivatives
reforms could increase the liquidity needs and costs of our commercial trading
operations. (Applies to each
registrant.)
In 2009,
legislation was introduced in Congress to reform financial markets that could
significantly alter how over-the-counter (“OTC”) derivatives are
regulated. In December 2009, the U.S. House of Representatives
adopted legislation that would increase regulatory oversight of OTC energy
derivatives, including (1) requiring standardized OTC derivatives to be traded
on registered exchanges regulated by the CFTC, (2) imposing new and potentially
higher capital and margin requirements, and (3) authorizing the establishment of
overall volume and position limits. The legislation contains certain exceptions
that apply to end-users of energy commodities which could reduce, but not
eliminate, the applicability of these measures to us and other
end-users. These requirements would cause our OTC transactions to be
more costly and have an adverse effect on our liquidity due to additional
capital requirements. In addition, as these reforms aim to
standardize OTC products it could limit the effectiveness of our hedging
programs because we would have less ability to tailor OTC derivatives to match
the precise risk we are seeking to protect.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM
2. PROPERTIES
GENERATION
FACILITIES
UTILITY
OPERATIONS
At
December 31, 2009, the AEP System owned (or leased where indicated) generating
plants with net power capabilities (winter rating) shown in the following
table:
Company
|
|
Stations
|
|
Coal
MW
|
|
|
Natural
Gas
MW
|
|
|
Nuclear
MW
|
|
|
Lignite
MW
|
|
|
Hydro
MW
|
|
|
Oil
MW
|
|
|
Total
MW
|
|
AEGCo
|
|
|
2 |
|
(a)
|
|
|
1,310 |
|
|
|
1,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,496 |
|
APCo
|
|
|
17 |
|
(b)(c)
|
|
|
5,093 |
|
|
|
516 |
|
|
|
|
|
|
|
|
|
678 |
|
|
|
|
|
|
6,287 |
|
CSPCo
|
|
|
7 |
|
(d)
|
|
|
2,378 |
|
|
|
1,357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
3,738 |
|
I&M
|
|
|
9 |
|
(a)
|
|
|
2,305 |
|
|
|
|
|
|
|
2,191 |
(e) |
|
|
|
|
|
15 |
|
|
|
|
|
|
|
4,511 |
|
KPCo
|
|
|
1 |
|
|
|
|
1,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,060 |
|
OPCo
|
|
|
8 |
|
(b)(c)
|
|
|
8,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
8,493 |
|
PSO
|
|
|
8 |
|
(f)
|
|
|
1,026 |
|
|
|
3,552 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
4,603 |
|
SWEPCo
|
|
|
10 |
|
(g)
|
|
|
1,848 |
|
|
|
2,152 |
|
|
|
|
|
|
|
850 |
|
|
|
|
|
|
|
|
|
|
|
4,850 |
|
TNC
|
|
|
6 |
|
(f)(h)
|
|
|
377 |
|
|
|
262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System
Totals
|
|
|
68 |
|
|
|
|
23,864 |
|
|
|
9,025 |
|
|
|
2,191 |
|
|
|
850 |
|
|
|
719 |
|
|
|
36 |
|
|
|
36,685 |
|
Percentage
of System Totals
|
|
|
|
|
|
|
|
65.0 |
|
|
|
24.6 |
|
|
|
6.0 |
|
|
|
2.3 |
|
|
|
2.0 |
|
|
|
0.1 |
|
|
|
|
|
(a)
|
Unit
1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless
extended.
|
(b)
|
Unit
3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by
OPCo.
|
(c)
|
APCo
owns Units 1 and 3 and OPCo owns Units 2, 4 and 5 of Philip Sporn Plant,
respectively.
|
(d)
|
CSPCo
owns generating units in common with Duke Ohio and DP&L. Its
percentage ownership interest is reflected in this
table.
|
(e)
|
Cook
Unit 1 currently is not operating at the full capacity set forth
here. For further information, see Cook Nuclear Plant
below.
|
(f)
|
PSO
and TNC, along with Oklahoma Municipal Power Authority and The Public
Utilities Board of the City of Brownsville, Texas, are joint owners of the
Oklaunion power station. PSO and TNC’s ownership interest is reflected in
this portion of the table. TNC has transferred its interest to
a non-utility affiliate through
2027.
|
(g)
|
SWEPCo
owns generating units in common with Cleco Corporation and other
unaffiliated parties. Only its ownership interest is reflected in this
table.
|
(h)
|
TNC’s
gas-fired and oil-fired generation has been
deactivated.
|
Cook
Nuclear Plant
The
following table provides operating information relating to the Cook
Plant.
|
Cook
Plant
|
|
Unit
1
|
|
Unit
2
|
Year
Placed in Operation
|
1975
|
|
1978
|
Year
of Expiration of NRC License
|
2034
|
|
2037
|
Nominal
Net Electrical Rating in Kilowatts
|
1,084,000
|
|
1,107,000
|
Net
Capacity Factors (a)
|
|
|
|
2009
|
2.8%(b)
|
|
83.1%
|
2008
|
59.2%(b)
|
|
96.6%
|
2007
|
97.4%
|
|
83.8%
|
2006
|
80.4%
|
|
86.5%
|
(a)
|
Net
Capacity Factor values for Unit 1 in 2007 through 2009 reflect Nominal Net
Electrical Rating in Kilowatts of 1,084,000. The Net Capacity
Factor values for Unit 1 in 2006 reflect the previous Nominal Net
Electrical Rating in Kilowatts of 1,036,000. The Net Electrical
Rating changed in 2007 due to low pressure turbine
replacement.
|
(b)
|
Unit
1 Net Capacity Factor for 2008 and 2009 was impacted by a 2008 forced
outage caused by a low pressure turbine blade failure event. The reduced
capacity repaired turbine is projected to be replaced with a full capacity
turbine in late 2011.
|
Costs associated with the operation
(including fuel), maintenance and retirement of nuclear plants continue to be
more significant and less predictable than costs associated with other sources
of generation, in large part due to changing regulatory requirements and safety
standards, availability of nuclear waste disposal facilities and experience
gained in the operation of nuclear facilities. The ability of I&M
to obtain adequate and timely recovery of costs associated with the Cook Plant
is not assured. Such costs may include replacement power, any
unamortized investment at the end of the useful life of the Cook Plant (whether
scheduled or premature), the carrying costs of that investment and retirement
costs.
GENERATION
AND MARKETING
In
addition to the generating facilities described above, AEP has ownership
interests in other electrical generating facilities. Information concerning
these facilities at December 31, 2009 is listed below.
Facility
|
Fuel
|
Location
|
|
Capacity
Total MW
|
|
|
Owner-ship
Interest
|
|
Status
|
|
|
|
|
|
|
|
|
|
|
Desert
Sky Wind Farm
|
Wind
|
Texas
|
|
|
161 |
|
|
|
100 |
% |
Exempt
Wholesale Generator(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Trent
Wind Farm
|
Wind
|
Texas
|
|
|
150 |
|
|
|
100 |
% |
Exempt
Wholesale Generator(a)
|
Total
|
|
|
|
311 |
|
|
|
|
|
|
(a) As
defined under rules issued pursuant to EPACT.
TRANSMISSION AND
DISTRIBUTION FACILITIES
The
following table sets forth the total overhead circuit miles of transmission and
distribution lines of the AEP System and its operating companies and that
portion of the total representing 765kV lines:
|
Total
Overhead Circuit Miles of
Transmission
and Distribution Lines
|
|
Circuit
Miles of
765kV
Lines
|
AEP
System (a)
|
224,416
|
(b)
|
|
2,116
|
|
APCo
|
52,151
|
|
|
734
|
|
CSPCo
(a)
|
15,567
|
|
|
—
|
|
I&M
|
22,009
|
|
|
615
|
|
KgPCo
|
1,359
|
|
|
—
|
|
KPCo
|
11,044
|
|
|
258
|
|
OPCo
|
30,748
|
|
|
509
|
|
PSO
|
21,365
|
|
|
—
|
|
SWEPCo
|
21,497
|
|
|
—
|
|
TCC
|
29,610
|
|
|
—
|
|
TNC
|
17,362
|
|
|
—
|
|
WPCo
|
1,705
|
|
|
—
|
|
(a)
|
Includes
766 miles of 345,000-volt jointly owned
lines.
|
(b)
|
Includes
73 miles of overhead transmission lines not identified with an operating
company.
|
TITLES
The AEP
System’s generating facilities are generally located on lands owned in fee
simple. The greater portion of the transmission and distribution lines of the
System has been constructed over lands of private owners pursuant to easements
or along public highways and streets pursuant to appropriate statutory
authority. The rights of AEP’s public utility subsidiaries in the realty on
which their facilities are located are considered adequate for use in the
conduct of their business. Minor defects and irregularities customarily found in
title to properties of like size and character may exist, but such defects and
irregularities do not materially impair the use of the properties affected
thereby. AEP’s public utility subsidiaries generally have the right of eminent
domain which permits them, if necessary, to acquire, perfect or secure titles to
or easements on privately held lands used or to be used in their utility
operations. Recent legislation in Ohio and Virginia has restricted
the right of eminent domain previously granted for power generation
purposes.
SYSTEM TRANSMISSION LINES
AND FACILITY SITING
Laws in
the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas,
Tennessee, Virginia, and West Virginia require prior approval of sites of
generating facilities and/or routes of high-voltage transmission lines. We have
experienced delays and additional costs in constructing facilities as a result
of proceedings conducted pursuant to such statutes, and in proceedings in which
our operating companies have sought to acquire rights-of-way through
condemnation. These proceedings may result in additional delays and
costs in future years.
CONSTRUCTION
PROGRAM
With
input from its state utility commissions, the AEP System continuously assesses
the adequacy of its generation, transmission, distribution and other facilities
to plan and provide for the reliable supply of electric power and energy to its
customers. In this assessment process, assumptions are continually being
reviewed as new information becomes available, and assessments and plans are
modified, as appropriate. AEP forecasts approximately $2.2 billion of
construction expenditures, excluding AFUDC, for 2010. Estimated
construction expenditures are subject to periodic review and modification and
may vary based on the ongoing effects of regulatory constraints, environmental
regulations, business opportunities, market volatility, economic trends, and the
ability to access capital.
NEW
GENERATION
AEP is in
various stages of construction of the following generation
facilities:
Operating
Company
|
Project
Name
|
Location
|
Total
Projected Cost
(a)
|
Fuel
Type
|
Plant Type
|
Nominal
MW Capacity
|
Commercial
Operation Date (Projected)
|
|
|
|
(in
millions)
|
|
|
|
|
AEGCo
|
Dresden
(b)
|
OH
|
$321
(c)
|
Gas
|
Combined-cycle
|
580
|
2013
|
SWEPCo
|
Stall
|
LA
|
$389
|
Gas
|
Combined-cycle
|
500
|
2010
|
SWEPCo
|
Turk
(d)
|
AR
|
$1,622
(d)
|
Coal
|
Ultra-supercritical
|
600
|
2012
|
APCo
|
Mountaineer
|
WV
|
(e)
|
Coal
|
IGCC
|
629
|
(e)
|
CSPCo/OPCo
|
Great
Bend
|
OH
|
(e)
|
Coal
|
IGCC
|
629
|
(e)
|
(a)
|
Amount
excludes AFUDC.
|
(b)
|
In
September 2007, AEGCo purchased the partially completed Dresden plant from
Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85
million, which is included in the “Total Projected Cost” section
above.
|
(c)
|
During
2009, AEGCo suspended construction of the Dresden Plant. As a
result, AEGCo has stopped recording AFUDC and will resume recording AFUDC
once construction is resumed.
|
(d)
|
SWEPCo
owns approximately 73%, or 440 MW, totaling $1.2 billion in capital
investment. See “Turk Plant” section
below.
|
(e)
|
Construction
of IGCC plants is subject to regulatory
approvals.
|
Turk
Plant
SWEPCo is currently constructing the
Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical
generating unit in Arkansas, which is expected to be in-service in
2012. SWEPCo owns 73% of the Turk Plant and will operate the
completed facility. The Turk Plant is currently estimated to cost
$1.6 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.2
billion, excluding AFUDC. Several notices of appeal are outstanding
at the Arkansas Supreme Court and the PUCT. See Note 4 to the
consolidated financial statements entitled Rate Matters under the
heading Turk Plant for
more information.
TRANSMISSION
INITIATIVES
We
continue our pursuit of transmission opportunities throughout the
U.S. In 2009, we announced that our recently formed transmission
company, AEP Transmission Company, LLC, will pursue new transmission investments
within our retail service territories. We plan to invest
approximately $120 million in these projects in 2010. Through joint
ventures with various other companies, we have existing and/or planned
transmission projects and opportunities outside of our retail service
territories. See Management’s Financial Discussion
and Analysis of Results of Operations included in the 2009 Annual Reports
under the heading Transmission
Initiatives, for more information.
CONSTRUCTION
EXPENDITURES
The
following table shows construction expenditures (including environmental
expenditures) during 2007, 2008 and 2009 and a current estimate of 2010
construction expenditures, in each case excluding AFUDC, capitalized interest
and assets acquired under leases.
|
2007
Actual (b)
|
2008
Actual (c)
|
2009
Actual (d)
|
2010
Estimate
|
|
(in
thousands)
|
Total
AEP System (a)
|
$3,414,000
|
|
$3,981,200
|
|
$2,496,300
|
|
$2,181,200
|
|
APCo
|
715,700
|
|
755,800
|
|
446,600
|
|
380,500
|
|
CSPCo
|
330,800
|
|
435,700
|
|
280,100
|
|
256,100
|
|
I&M
|
282,400
|
|
372,400
|
|
357,900
|
|
265,200
|
|
OPCo
|
806,000
|
|
675,200
|
|
389,900
|
|
301,800
|
|
PSO
|
302,600
|
|
274,200
|
|
167,900
|
|
166,300
|
|
SWEPCo
|
516,800
|
|
689,300
|
|
475,800
|
|
446,200
|
|
(a)
|
Includes
expenditures of other subsidiaries not shown. The figures reflect
construction expenditures, not investments in subsidiary
companies. Excludes discontinued
operations.
|
(b)
|
Excludes
$512 million for the purchase of Lawrenceburg, Dresden (AEGCo) and Darby
(CSPCo) and Cash Flow Statement Adjustments (Statement of Cash Flow
Including AFUDC Debt Equals
$3,556,000).
|
(c)
|
Excludes
Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC
Debt Equals $3,800,000).
|
(d)
|
Excludes
Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC
Debt Equals $2,792,000).
|
The
System construction program is reviewed continuously and is revised from time to
time in response to changes in estimates of customer demand, business and
economic conditions, the cost and availability of capital, environmental
requirements and other factors. Changes in construction schedules and costs, and
in estimates and projections of needs for additional facilities, as well as
variations from currently anticipated levels of net earnings, Federal income and
other taxes, and other factors affecting cash requirements, may increase or
decrease the estimated capital requirements for the System’s construction
program.
POTENTIAL UNINSURED
LOSSES
Some
potential losses or liabilities may not be insurable or the amount of insurance
carried may not be sufficient to meet potential losses and liabilities,
including liabilities relating to damage to our generating plants and costs of
replacement power. Unless allowed to be recovered through rates, future losses
or liabilities which are not completely insured could have a material adverse
effect on results of operations and the financial condition of AEP and other AEP
System companies. For risks related to owning a nuclear generating unit, see
Note 6 to the consolidated financial statements entitled Commitments, Guarantees and
Contingencies under the heading Nuclear Contingencies for
information with respect to nuclear incident liability insurance.
ITEM
3. LEGAL PROCEEDINGS
For a
discussion of material legal proceedings, see Note 6 to the consolidated
financial statements, entitled Commitments, Guarantees and
Contingencies, incorporated by reference in Item 8.
ITEM
4. SUBMISSION OF MATTERS TO A
VOTE
OF
SECURITY HOLDERS
AEP, APCo, OPCo, PSO and SWEPCo.
None.
CSPCo and I&M. Omitted
pursuant to Instruction I(2)(c).
EXECUTIVE OFFICERS OF THE
REGISTRANTS
AEP. The following
persons are, or may be deemed, executive officers of AEP. Their ages
are given as of February 1, 2010.
Name
|
|
Age
|
|
Office (a)
|
Michael
G. Morris
|
|
63
|
|
Chairman
of the Board, President and Chief Executive Officer
|
Nicholas
K. Akins
|
|
49
|
|
Executive
Vice President
|
Carl
L. English
|
|
63
|
|
Chief
Operating Officer
|
John
B. Keane
|
|
63
|
|
Executive
Vice President, General Counsel and Secretary
|
Venita
McCellon-Allen
|
|
50
|
|
Executive
Vice President
|
Charles
R. Patton
|
|
50
|
|
Executive
Vice President
|
Robert
P. Powers
|
|
55
|
|
President-AEP
Utilities
|
Brian
X. Tierney
|
|
42
|
|
Executive
Vice President and Chief Financial Officer
|
Susan
Tomasky
|
|
56
|
|
President
– AEP Transmission
|
(a)
|
All
of the executive officers have been employed by AEPSC or System companies
in various capacities (AEP, as such, has no employees) for the past five
years. Mr. Akins became an executive officer of AEP in June
2006, Mr. English in August, 2004, Mr. Keane in July 2004, Ms.
McCellon-Allen in July 2008, Mr. Patton in October 2009, Mr. Powers in
October 2001, Mr. Tierney in January 2008 and Ms. Tomasky in January
2000. All of the above officers are appointed annually for a
one-year term by the board of directors of
AEP.
|
APCo, OPCo, PSO and
SWEPCo. The names of the executive officers of APCo, OPCo, PSO
and SWEPCo, the positions they hold with these companies, their ages as of
February 1, 2010, and a brief account of their business experience during the
past five years appear below. The directors and executive officers of APCo,
OPCo, PSO and SWEPCo are elected annually to serve a one-year term.
Name
|
|
Age
|
|
Position
|
|
Period
|
Michael
G. Morris (a)(b)
|
|
63
|
|
Chairman
of the Board, President, Chief Executive Officer and Director of
AEP
|
|
2004-Present
|
|
|
|
|
Chairman
of the Board, Chief Executive Officer and Director of APCo, OPCo, PSO and
SWEPCo
|
|
2004-Present
|
Nicholas
K. Akins (a)
|
|
49
|
|
Executive
Vice President of AEP
|
|
2006-Present
|
|
|
|
|
Vice
President and Director of APCo, OPCo, PSO
|
|
2006-Present
|
|
|
|
|
and
SWEPCo
|
|
|
|
|
|
|
President
and Chief Operating Officer of SWEPCo
|
|
2004-2006
|
Carl
L. English (a)
|
|
63
|
|
Chief
Operating Officer
|
|
2008-Present
|
|
|
|
|
President-AEP
Utilities of AEP
|
|
2004-2007
|
|
|
|
|
Director
and Vice President of APCo, OPCo, PSO and SWEPCo
|
|
2004-Present
|
John
B. Keane (c)
|
|
63
|
|
Executive
Vice President, General Counsel and Secretary of AEP
|
|
2004-Present
|
|
|
|
|
Director
of APCo, OPCo , PSO and SWEPCo
|
|
2004-Present
|
Venita
McCellon-Allen (a)
|
|
50
|
|
Executive
Vice President
|
|
2008-Present
|
|
|
|
|
Director
and Vice President of APCo and OPCo
|
|
2009-Present
|
|
|
|
|
Director
and Vice President of PSO and SWEPCo
|
|
2008-2009
|
|
|
|
|
President
and Chief Operating Officer of SWEPCo
|
|
2006-2008
|
|
|
|
|
Director
and Senior Vice President-Shared Services of AEPSC
|
|
2004-2006
|
|
|
|
|
Director
of APCo, OPCo and SWEPCo
|
|
2004-2006
|
Charles
R. Patton
|
|
50
|
|
Executive
Vice President
|
|
2009-Present
|
|
|
|
|
Senior
Vice President-Regulatory and Public Policy
|
|
2008-2009
|
|
|
|
|
President
and Chief Operating Officer of TCC and TNC
|
|
2004-2008
|
|
|
|
|
Director
and Vice President of PSO and SWEPCo
|
|
2009-Present
|
Robert
P. Powers (a)
|
|
55
|
|
President-AEP
Utilities of AEP
|
|
2008-Present
|
|
|
|
|
Executive
Vice President of AEP
|
|
2004-2007
|
|
|
|
|
Director
and Vice President of APCo and OPCo
|
|
2001-Present
|
|
|
|
|
Director
and Vice President of PSO and SWEPCo
|
|
2008-Present
|
Brian
X. Tierney (a)
|
|
42
|
|
Executive
Vice President
|
|
2008-Present
|
|
|
|
|
Chief
Financial Officer
|
|
2009-Present
|
|
|
|
|
Director
and Vice President of APCo and OPCo
|
|
2008-Present
|
|
|
|
|
Director
and Vice President of PSO and SWEPCo
|
|
2009-Present
|
|
|
|
|
Senior
Vice President—Commercial Operations of AEPSC
|
|
2005-2007
|
|
|
|
|
Senior
Vice President— Energy Marketing of AEPSC
|
|
2003-2005
|
Susan
Tomasky (a)
|
|
56
|
|
President-AEP
Transmission
|
|
2008-Present
|
|
|
|
|
Executive
Vice President of AEP
|
|
2004-Present
|
|
|
|
|
Chief
Financial Officer of AEP
|
|
2001-2006
|
|
|
|
|
Vice
President and Director of APCo, OPCo, PSO and SWEPCo
|
|
2000-Present
|
(a)
|
Messrs.
Morris, Akins, English, Powers and Tierney and Ms. McCellon-Allen and Ms.
Tomasky are directors of CSPCo and I&M.
|
(b)
|
Mr.
Morris is a director of Alcoa, Inc. and The Hartford Financial Services
Group, Inc.
|
(c)
|
Mr.
Keane is a director of CSPCo.
|
APCo:
Name
|
|
Age
|
|
Position
|
|
Period
|
Dana
E. Waldo
|
|
58
|
|
President
and Chief Operating Officer of APCo
|
|
2004-Present
|
OPCo:
Name
|
|
Age
|
|
Position
|
|
Period
|
Joseph
Hamrock
|
|
46
|
|
President
and Chief Operating Officer of CSPCo and OPCo
|
|
2008-Present
|
|
|
|
|
Senior
Vice President and Chief Information Officer of AEPSC
|
|
2003-2007
|
PSO:
Name
|
|
Age
|
|
Position
|
|
Period
|
Stuart
Solomon
|
|
48
|
|
President
and Chief Operating Officer of PSO
|
|
2004-Present
|
|
SWEPCo:
Name
|
|
Age
|
|
Position
|
|
Period
|
|
Paul
Chodak, III
|
|
46
|
|
President
and Chief Operating Officer of SWEPCo
|
|
2008-Present
|
|
|
|
|
Director-New
Generation of AEPSC
|
|
2007-2008
|
|
|
|
|
Director-Environmental
Programs of AEPSC
|
|
2004-2007
|
PART
II
ITEM
5. MARKET FOR REGISTRANTS’ COMMON
EQUITY,
RELATED
STOCKHOLDER MATTERS
AND
ISSUER PURCHASES OF EQUITY SECURITIES
AEP. In addition to the
discussion below, the remaining information required by this item is
incorporated herein by reference to the material under AEP Common Stock and Dividend
Information and Note 14 to the consolidated financial statements entitled
Financing Activities
under the heading Dividend Restrictions in the
2009 Annual Report.
APCo, CSPCo, I&M, OPCo, PSO and
SWEPCo. The common stock of these companies is held solely by AEP. The
amounts of cash dividends on common stock paid by these companies to AEP during
2009, 2008 and 2007 are incorporated by reference to the material under Statements of Changes in Common
Shareholder’s Equity and Comprehensive Income (Loss) and Note 14 to the
consolidated financial statements entitled Financing Activities under
the heading Dividend
Restrictions in the 2009 Annual Reports.
As
indicated in the following table, during the quarter ended December 31, 2009,
neither AEP (nor its publicly-traded subsidiaries) purchased equity securities
that are registered by AEP (or its publicly-traded subsidiaries) pursuant to
Section 12 of the Exchange Act:
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
|
Total
Number
of
Shares
Purchased
|
|
Average
Price
Paid
per
Share
|
|
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
|
|
10/01/09
– 10/31/09
|
|
|
-
|
|
$
|
-
|
|
|
-
|
|
$
|
-
|
|
11/01/09
– 11/30/09
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
12/01/09
– 12/31/09
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
|
|
|
-
|
|
$
|
-
|
|
|
-
|
|
$
|
-
|
|
ITEM
6. SELECTED FINANCIAL DATA
CSPCo and
I&M. Omitted pursuant to Instruction I(2)(a).
AEP, APCo, OPCo, PSO and
SWEPCo. The information required by this item is incorporated
herein by reference to the material under Selected Consolidated Financial Data
in the 2009 Annual Reports.
ITEM
7. MANAGEMENT’S DISCUSSION AND
ANALYSIS
OF
FINANCIAL CONDITION
AND
RESULTS OF OPERATION
CSPCo and
I&M. Omitted pursuant to Instruction I(2)(a). Management’s
narrative analysis of the results of operations and other information required
by Instruction I(2)(a) is incorporated herein by reference to the material under
Management’s Financial
Discussion and Analysis of Results of Operations in
the 2009 Annual Reports.
AEP, APCo, OPCo, PSO
and SWEPCo. The
information required by this item is incorporated herein by reference to the
material under Management’s
Financial Discussion and Analysis of Results of Operations in the 2009 Annual
Reports.
ITEM
7A. QUANTITATIVE AND
QUALITATIVE
DISCLOSURES
ABOUT MARKET RISK
AEP, APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo. The information required by this item is incorporated herein
by reference to the material under Management’s Financial Discussion
and Analysis of Results of Operations in the 2009 Annual
Reports.
ITEM
8. FINANCIAL STATEMENTS
AND
SUPPLEMENTARY DATA
AEP, APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo. The information required by this item is incorporated herein
by reference to the financial statements and financial statement schedules
described under Item 15 herein.
ITEM
9. CHANGES IN AND
DISAGREEMENTS WITH
ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
AEP, APCo, CSPCo, I&M, OPCo, PSO
and
SWEPCo. None.
ITEM
9A. CONTROLS AND
PROCEDURES
During
2009, management, including the principal executive officer and principal
financial officer of each of American Electric Power Company, Inc., Appalachian
Power Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company (each a “Registrant” and collectively the “Registrants”) evaluated
each respective Registrant’s disclosure controls and
procedures. Disclosure controls and procedures are defined as
controls and other procedures of the Registrants that are designed to ensure
that information required to be disclosed by the Registrants in the reports that
they file or submit under the Exchange Act are recorded, processed, summarized
and reported within the time periods specified in the Commission’s rules and
forms. Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Registrants in the reports that they file or submit under
the Exchange Act is accumulated and communicated to each Registrant’s
management, including the principal executive and principal financial officers,
or persons performing similar functions, as appropriate to allow timely
decisions regarding required disclosure.
As of
December 31, 2009, these officers concluded that the disclosure controls and
procedures in place are effective and provide reasonable assurance that the
disclosure controls and procedures accomplished their objectives. The
Registrants continually strive to improve their disclosure controls and
procedures to enhance the quality of their financial reporting and to maintain
dynamic systems that change as events warrant.
There
have been no changes in the Registrants’ internal control over financial
reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the
Exchange Act) during the fourth quarter of 2009 that materially affected, or are
reasonably likely to materially affect, the Registrants’ internal controls over
financial reporting.
Management
is required to assess and report on the effectiveness of its internal control
over financial reporting as of December 31, 2009. As a result of that
assessment, management determined that there were no material weaknesses as of
December 31, 2009 and, therefore, concluded that each Registrant’s internal
control over financial reporting was effective.
Additional
information required by this item of the Registrants is incorporated by
reference to Management’s
Report on Internal Control over Financial Reporting, included in the 2009
Annual Report of each Registrant.
ITEM
9B. OTHER INFORMATION
None.
PART
III
ITEM
10. DIRECTORS, EXECUTIVE
OFFICERS
AND
CORPORATE GOVERNANCE
CSPCo and I&M. Omitted
pursuant to Instruction I(2)(c).
AEP:
Directors, Director Nomination
Process and Audit Committee. The information required by this
item concerning directors and nominees for election as directors at AEP’s annual
meeting of shareholders (Item 401 of Regulation S-K), the director nomination
process (Item 407(c)(3)) and the audit committee (Item 407(d)(4) and (d)(5)) is
incorporated herein by reference to information contained in the definitive
proxy statement of AEP for the 2010 annual meeting of shareholders.
Executive
Officers. Reference also is made to the information under the
caption Executive Officers of
the Registrants in Part I, Item 4 of this report.
Code of
Ethics. AEP’s Principles of Business Conduct is the code of
ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer
and principal accounting officer. The Principles of Business Conduct is
available on AEP’s website at www.aep.com. The Principles
of Business Conduct will be made available, without charge, in print to any
shareholder who requests such document from Investor Relations, American
Electric Power Company, Inc., 1 Riverside Plaza, Columbus,
Ohio 43215.
If any substantive amendments to the
Principles of Business Conduct are made or any waivers are granted, including
any implicit waiver, from a provision of the Principles of Business Conduct, to
its Chief Executive Officer, Chief Financial Officer or principal accounting
officer, AEP will disclose the nature of such amendment or waiver on AEP’s
website, www.aep.com, or in a report on Form
8-K.
Beneficial Ownership Reporting
Compliance. The information required by this item is
incorporated herein by reference to information contained in the definitive
proxy statement of AEP for the 2010 annual meeting of shareholders.
APCo,
OPCo, PSO and SWEPCo:
Directors and Executive
Officers. The information required by this item is
incorporated herein by reference to the information in the definitive
information statement of each company for the 2010 annual meeting of
stockholders. Reference also is made to the information under the caption Executive Officers of the
Registrants in Part I, Item 4 of this report.
Audit
Committee. Each of APCo, OPCo, PSO and SWEPCo is a controlled
subsidiary of AEP and does not have a separate audit committee.
Code of
Ethics. AEP’s Principles of Business Conduct is the code of
ethics that applies to the Chief Executive Officer, Chief Financial Officer and
principal accounting officer of APCo, OPCo, PSO and SWEPCo The
discussion of AEP’s Principles of Business Conduct above is incorporated herein
by reference. If any substantive amendments to the Principles of
Business Conduct are made or any waivers are granted, including any implicit
waiver, from a provision of the Principles of Business Conduct, to the Chief
Executive Officer, Chief Financial Officer or principal accounting officer of
APCo, OPCo, PSO and SWEPCo, as applicable, that company will disclose the nature
of such amendment or waiver on AEP’s website, www.aep.com, or in a report
on Form 8-K.
ITEM
11. EXECUTIVE COMPENSATION
CSPCo and
I&M. Omitted pursuant to Instruction I(2)(c).
AEP. The information required
by this item is incorporated herein by reference to the material under Directors Compensation and Stock
Ownership, Executive Compensation of the definitive proxy statement of
AEP for the 2010 annual meeting of shareholders and the 2009 Annual Reports,
page (vi).
APCo, OPCo, PSO and SWEPCO.
The information required by this item is incorporated herein by reference to the
material under Executive
Compensation of the definitive information statement of each company for
the 2010 annual meeting of stockholders.
ITEM
12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL
OWNERS AND MANAGEMENT AND
RELATED
STOCKHOLDER MATTERS
CSPCo and I&M. Omitted
pursuant to Instruction I(2)(c).
AEP. The information required
by this item is incorporated herein by reference to the material under Share Ownership of Directors and
Executive Officers of the definitive proxy statement of AEP for the 2010
annual meeting of shareholders.
APCo, OPCo, PSO and SWEPCO.
The information required by this item is incorporated herein by reference to the
material under Share Ownership
of Directors and Executive Officers in the definitive information
statement of each company for the 2010 annual meeting of
stockholders.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
AND DIRECTOR INDEPENDENCE
CSPCo
and I&M: Omitted pursuant to Instruction
I(2)(c).
AEP: The
information required by this item is incorporated herein by reference to the
definitive proxy statement of AEP for the 2010 annual meeting of
shareholders.
APCo, OPCo, PSO and
SWEPCo: Certain Relationships and Related
Transactions. None.
Director
Independence. None of the directors of APCo, OPCo, PSO or
SWEPCo is independent because each director is either (i) an officer of the
company in which each serves as director, or (ii) an officer of
AEP.
ITEM
14. PRINCIPAL ACCOUNTING FEES AND
SERVICES
AEP. The following
table presents fees for professional audit services rendered by Deloitte &
Touche LLP for the audit of AEP’s annual financial statements for the years
ended December 31, 2009 and December 31, 2008, and fees billed for other
services rendered by Deloitte & Touche LLP during those
periods.
|
2009
|
|
2008
|
Audit
Fees (1)
|
$11,411,000
|
|
$11,762,000
|
Audit-Related
Fees (2)
|
1,680,000
|
|
1,184,000
|
Tax
Fees (3)
|
275,000
|
|
697,000
|
TOTAL
|
$13,366,000
|
|
$13,643,000
|
(1)
|
Audit
fees in 2008 and 2009 consisted primarily of fees related to the audit of
the Company’s annual consolidated financial statements, including each
registrant subsidiary. Audit fees also included auditing
procedures performed in accordance with Sarbanes-Oxley Act Section 404 and
the related Public Company Accounting Oversight Board Auditing Standard
Number 5 regarding the Company’s internal control over financial
reporting. This category also includes work generally only the
independent registered public accounting firm can reasonably be expected
to provide.
|
|
|
(2)
|
Audit
related fees consisted principally of regulatory, statutory, employee
benefit plan audits.
|
|
|
(3)
|
Tax
fees consisted principally of tax compliance services. Tax
compliance services are services rendered based upon facts already in
existence or transactions that have already occurred to document, compute,
and obtain government approval for amounts to be included in tax
filings.
|
APCo, OPCo, PSO and SWEPCo.
The information required by this item is incorporated herein by reference to the
definitive information statement of each company for the 2010 annual meeting of
stockholders.
CSPCo and I&M.
Each of
the above is a wholly-owned subsidiary of AEP and does not have a separate audit
committee. A description of the AEP Audit Committee pre-approval policies, which
apply to these companies, is contained in the definitive proxy statement of AEP
for the 2010 annual meeting of shareholders. The following table presents
directly billed fees for professional services rendered by Deloitte & Touche
LLP for the audit of these companies’ annual financial statements for the years
ended December 31, 2008 and 2009, and fees directly billed for other services
rendered by Deloitte & Touche LLP during those periods. Deloitte
& Touche LLP also provides additional professional and other services to the
AEP System, the cost of which may ultimately be allocated to these companies
though not billed directly to them. For a description of these fees and
services, see the description of principal accounting fees and services for AEP,
above.
|
CSPCo
|
I&M
|
|
2009
|
2008
|
2009
|
2008
|
Audit
Fees
|
$1,038,130
|
$1,092,225
|
$1,612,867
|
$1,681,029
|
Audit-Related
Fees
|
25,994
|
109,947
|
37,851
|
169,218
|
Tax
Fees
|
25,536
|
64,724
|
39,304
|
99,616
|
TOTAL
|
$1,089,660
|
$1,266,896
|
$1,690,022
|
$1,949,863
|
PART
IV
ITEM
15. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES
The
following documents are filed as a part of this
report:
|
|
1. Financial
Statements:
|
The
following financial statements have been incorporated herein by reference
pursuant to Item 8.
|
AEP
and Subsidiary Companies:
|
Reports
of Independent Registered Public Accounting Firm; Management’s Report on
Internal Control over Financial Reporting; Consolidated Statements of
Income for the years ended December 31, 2009, 2008 and 2007; Consolidated
Balance Sheets as of December 31, 2009 and 2008; Consolidated Statements
of Cash Flows for the years ended December 31, 2009, 2008 and 2007;
Consolidated Statements of Changes in Equity and Comprehensive Income
(Loss) for the years ended December 31, 2009, 2008 and 2007; Notes to
Consolidated Financial Statements.
|
APCo,
CSPCo and I&M:
|
Consolidated
Statements of Income for the years ended December 31, 2009, 2008 and 2007;
Consolidated Statements of Changes in Common Shareholder’s Equity and
Comprehensive Income (Loss) for the years ended December 31, 2009, 2008
and 2007; Consolidated Balance Sheets as of December 31, 2009 and 2008;
Consolidated Statements of Cash Flows for the years ended December 31,
2009, 2008 and 2007; Notes to Financial Statements of Registrant
Subsidiaries; Report of Independent Registered Public Accounting
Firm.
|
OPCo
and SWEPCo:
|
Consolidated
Statements of Income for the years ended December 31, 2009, 2008 and 2007;
Consolidated Statements of Changes in Equity and Comprehensive Income
(Loss) for the years ended December 31, 2009, 2008 and 2007; Consolidated
Balance Sheets as of December 31, 2009 and 2008; Consolidated Statements
of Cash Flows for the years ended December 31, 2009, 2008 and 2007; Notes
to Financial Statements of Registrant Subsidiaries; Report of Independent
Registered Public Accounting Firm.
|
PSO:
|
Statements
of Operations for the years ended December 31, 2009, 2008 and 2007;
Statements of Changes in Common Shareholder’s Equity and Comprehensive
Income (Loss) for the years ended December 31, 2009, 2008 and 2007;
Balance Sheets as of December 31, 2009 and 2008; Statements of Cash Flows
for the years ended December 31, 2009, 2008 and 2007; Notes to Financial
Statements of Registrant Subsidiaries; Report of Independent Registered
Public Accounting Firm.
|
2. Exhibits:
|
Exhibits
for AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo are listed in the
Exhibit Index beginning on page E-1 and are incorporated herein by
reference
|
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.
|
American
Electric Power Company, Inc.
|
|
|
|
|
|
|
|
By:
|
/s/ Brian X.
Tierney
|
|
|
(Brian
X. Tierney, Executive Vice President
|
|
|
and
Chief Financial Officer)
|
Date:
February 26, 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 dates indicated.
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
(i) Principal
Executive Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Michael
G. Morris
|
|
Chairman
of the Board, President,
|
|
February
26, 2010
|
(Michael
G. Morris)
|
|
Chief
Executive Officer
|
|
|
|
|
And
Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Brian X.
Tierney
|
|
Executive
Vice President and
|
|
February
26, 2010
|
(Brian
X. Tierney)
|
|
Chief
Financial Officer
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Joseph M.
Buonaiuto
|
|
Senior
Vice President, Controller and
|
|
February
26, 2010
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*E. R.
Brooks
|
|
|
|
|
*Donald M.
Carlton
|
|
|
|
|
* James F.
Cordes
|
|
|
|
|
*Ralph
D. Crosby, Jr.
|
|
|
|
|
*Linda A.
Goodspeed
|
|
|
|
|
*Thomas E. Hoaglin
|
|
|
|
|
*Lester A. Hudson,
Jr.
|
|
|
|
|
*Lionel
L. Nowell, III
|
|
|
|
|
*Richard
L. Sandor
|
|
|
|
|
*Kathryn D.
Sullivan
|
|
|
|
|
*Sara
Martinez Tucker
|
|
|
|
|
*John
F. Turner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/ Brian X.
Tierney
|
|
|
|
February
26, 2010
|
|
(Brian
X. Tierney, Attorney-in-Fact)
|
|
|
|
|
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 signature of the undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
|
Public
Service Company of Oklahoma
|
|
Southwestern
Electric Power Company
|
|
|
|
|
|
By:
|
/s/ Brian X.
Tierney
|
|
|
(Brian
X. Tierney, Vice President
and
Chief Financial Officer)
|
Date:
February 26, 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 dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
(i) Principal
Executive Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Michael
G. Morris
|
|
Chairman
of the Board,
|
|
February
26, 2010
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Brian X.
Tierney
|
|
Vice
President,
|
|
February
26, 2010
|
(Brian
X. Tierney)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Joseph M.
Buonaiuto
|
|
Controller
and
|
|
February
26, 2010
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*Nicholas
K. Akins
|
|
|
|
|
*Carl
L. English
|
|
|
|
|
*John
B. Keane
|
|
|
|
|
*Charles
R. Patton
|
|
|
|
|
*Robert
P. Powers
|
|
|
|
|
*Barbara
D. Radous
|
|
|
|
|
*Susan
Tomasky
|
|
|
|
|
*Dennis
E. Welch
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/ Brian X.
Tierney
|
|
|
|
February
26, 2010
|
|
(Brian
X. Tierney, Attorney-in-Fact)
|
|
|
|
|
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 signature of the undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
|
Appalachian
Power Company
|
|
Columbus
Southern Power Company
|
|
Ohio
Power Company
|
|
By:
|
/s/ Brian X.
Tierney
|
|
|
(Brian
X. Tierney, Vice President
and
Chief Financial Officer)
|
Date:
February 26, 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 dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
(i) Principal
Executive Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Michael
G. Morris
|
|
Chairman
of the Board,
|
|
February
26, 2010
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Brian X.
Tierney
|
|
Vice
President,
|
|
February
26, 2010
|
(Brian
X. Tierney)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Joseph M.
Buonaiuto
|
|
Controller
and
|
|
February
26, 2010
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*Nicholas
K. Akins
|
|
|
|
|
*Carl
L. English
|
|
|
|
|
*John
B. Keane
|
|
|
|
|
*Venita
mcCellon-Allen
|
|
|
|
|
*Robert
P. Powers
|
|
|
|
|
*Barbara
D. Radous
|
|
|
|
|
*Susan
Tomasky
|
|
|
|
|
*Dennis
E. Welch
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/ Brian X.
Tierney
|
|
|
|
February
26, 2010
|
|
(Brian
X. Tierney, Attorney-in-Fact)
|
|
|
|
|
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 signature of the undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
|
Indiana
Michigan Power Company
|
|
By:
|
/s/ Brian X.
Tierney
|
|
|
(Brian X. Tierney Vice
President
and
Chief Financial Officer)
|
Date:
February 26, 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 dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
(i) Principal
Executive Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Michael
G. Morris
|
|
Chairman
of the Board,
|
|
February
26, 2010
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Brian X.
Tierney
|
|
Vice
President,
|
|
February
26, 2010
|
(Brian
X. Tierney)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/ Joseph M.
Buonaiuto
|
|
Controller
and
|
|
February
26, 2010
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*Nicholas
K. Akins
|
|
|
|
|
*J.
Edward Ehler
|
|
|
|
|
*Carl
L. English
|
|
|
|
|
*Allen
R. Glassburn
|
|
|
|
|
*Joann
M. Grevenow
|
|
|
|
|
*scott
m. krawec
|
|
|
|
|
*Marc
E. Lewis
|
|
|
|
|
*venita
mcCellon-allen
|
|
|
|
|
*Helen
J. Murray
|
|
|
|
|
*Mark
a. peifer
|
|
|
|
|
*Robert
P. Powers
|
|
|
|
|
*Susanne
M. Moorman Rowe
|
|
|
|
|
*Susan
Tomasky
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/ Brian X.
Tierney
|
|
|
|
February
26, 2010
|
|
(Brian
X. Tierney, Attorney-in-Fact)
|
|
|
|
|
EXHIBIT
INDEX
The
documents listed below are being filed or have previously been filed on behalf
of the Registrants shown and are incorporated herein by reference to the
documents indicated and made a part hereof. Exhibits (“Ex”) not
identified as previously filed are filed herewith. Exhibits,
designated with a dagger (†), are management contracts or compensatory plans or
arrangements required to be filed as an Exhibit to this Form pursuant to Item
14(c) of this report.
Exhibit
Designation
|
|
Nature of Exhibit
|
|
Previously Filed as Exhibit
to:
|
REGISTRANT:
AEP‡ File No. 1-3525
|
|
|
*3(a)
|
|
Composite
of the Restated Certificate of Incorporation of AEP, dated April 28,
2009.
|
|
|
*3(b)
|
|
Composite
By-Laws of AEP, as amended as of April 28, 2009.
|
|
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of May 1, 2001, between AEP and
The Bank of New York, as Trustee.
|
|
Registration
Statement No. 333-86050, Ex 4(a)(b)(c)
Registration
Statement No. 333-105532, Ex 4(d)(e)(f)
|
4(b)
|
|
Purchase
Agreement dated as of March 8, 2005, between AEP and Merrill Lynch
International.
|
|
Form
10-Q, Ex 4(a), March 31, 2005
|
4(c)
|
|
Junior
Subordinated Indenture dated as of March 1, 2008 between AEP and The Bank
of New York as Trustee.
|
|
Registration
Statement 333-156387, Ex 4(c)(d)
|
4(d)
|
|
Second
Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31,
2008, among AEP, the banks, financial institutions and other institutional
lenders listed on the signature pages thereof, and JP Morgan Chase Bank,
N.A., as Administrative Agent.
|
|
Form
10-Q, Ex 10(a) September 30, 2008
|
4(e)
|
|
Second
Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31,
2008, among AEP, the banks, financial institutions and other institutional
lenders listed on the signature pages thereof, and Barclays Bank plc as
Administrative Agent.
|
|
Form
10-Q, Ex 10(b) September 30, 2008
|
4(f)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(c) September 30, 2008
|
4(g)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(d) September 30, 2008
|
4(h)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10 (e) September 30, 2008
|
4(i)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(f) September 30, 2008
|
10(a)
|
|
Interconnection
Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M
and with AEPSC, as amended.
|
|
Registration
Statement No. 2-52910, Ex 5(a)
Registration
Statement No. 2-61009, Ex 5(b)
1990
Form 10-K, Ex 10(a)(3)
|
10(b)
|
|
Restated
and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on
February 10, 2006, Effective May 1, 2006.
|
|
Form
10-Q, Ex 10(b), March 31, 2006
|
10(c)
|
|
Transmission
Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
with AEPSC as agent, as amended.
|
|
1985
Form 10-K, Ex 10(b)
1988
Form 10-K, Ex 10(b)(2)
|
*10(d)
|
|
Restated
and Amended Transmission Coordination Agreement, dated April 15, 2002,
among PSO, SWEPCo, TNC and AEPSC.
|
|
|
10(e)(1)
|
|
Amended
and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(e)(1)
|
10(e)(2)
|
|
PJM
West Reliability Assurance Agreement among Load Serving Entities in the
PJM West service area.
|
|
2004
Form 10-K, Ex 10(e)(2)
|
10(e)(3)
|
|
Master
Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(e)(3)
|
10(f)
|
|
Lease
Agreements, dated as of December 1, 1989, between AEGCo or I&M and
Wilmington Trust Company, as amended.
|
|
Registration
Statement No. 33-32752, Ex 28(c)(1-6)(C)
Registration
Statement No. 33-32753, Ex 28(a)(1-6)(C)
AEGCo
1993 Form 10-K, Ex 10(c)(1-6)(B)
I&M
1993 Form 10-K, Ex 10(e)(1-6)(B)
|
10(g)
|
|
Modification
No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
|
|
1996
Form 10-K, Ex 10(l)
|
10(h)
|
|
Consent
Decree with U.S. District Court.
|
|
Form
8-K, Ex 10.1 dated October 9, 2007
|
†10(i)
|
|
AEP
Accident Coverage Insurance Plan for Directors.
|
|
1985
Form 10-K, Ex 10(g)
|
†10(j)
|
|
AEP
Retainer Deferral Plan for Non-Employee Directors, effective January 1,
2005, as amended February 9, 2007.
|
|
2007
Form 10-K, Ex 10(j)(i)
|
†10(k)
|
|
AEP
Stock Unit Accumulation Plan for Non-Employee Directors, as
amended.
|
|
2003
Form 10-K, Ex 10(k)(2)
|
†10(k)(1)
|
|
First
Amendment to AEP Stock Unit Accumulation Plan for Non-Employee Directors
dated as of February 9, 2007.
|
|
2006
Form 10-K, Ex 10(j)(2)(A)
|
†10(l)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(l)(1)(A)
|
†10(l)(1)
|
|
Guaranty
by AEP of AEPSC Excess Benefits Plan.
|
|
1990
Form 10-K, Ex 10(h)(1)(B)
|
†10(l)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated as of
January 1, 2008 (Non-Qualified).
|
|
2008
Form 10-K, Ex 10(l)(2)
|
†10(l)(3)
|
|
AEPSC
Umbrella Trust for Executives.
|
|
1993
Form 10-K, Ex 10(g)(3)
|
†10(l)(3)(A)
|
|
First
Amendment to AEPSC Umbrella Trust for Executives.
|
|
2008
Form 10-K, Ex 10(l)(3)(A)
|
†10(m)(1)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
2003.
|
|
2003
Form 10-K, Ex 10(m)(1)
|
†10(m)(1)(A)
|
|
Amendment
to Employment Agreement between AEP, AEPSC and Michael G. Morris dated
December 9, 2008.
|
|
2008
Form 10-K, Ex 10(m)(1)(A)
|
†10(m)(2)
|
|
Memorandum
of agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
2000
Form 10-K, Ex 10(s)
|
†10(m)(3)
|
|
Letter
Agreement dated June 23, 2000 between AEPSC and Holly K.
Koeppel.
|
|
2002
Form 10-K, Ex 10(m)(3)(A)
|
†10(m)(4)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K, Ex 10(m)(4)
|
†10(m)(4)(A)
|
|
Amendment
to Employment Agreement dated December 9, 2008 between AEPSC and Robert P.
Powers.
|
|
2008
Form 10-K, Ex 10(m)(4)(A)
|
†10(m)(5)
|
|
Letter
Agreement dated June 9, 2004 between AEPSC and Carl
English.
|
|
Form
10-Q, Ex 10(b), September 30, 2004
|
†10(m)(6)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC and John B.
Keane.
|
|
2006
Form 10-K, Ex 10(l)(6)
|
†10(n)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan, amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(o)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
Form
10-Q, Ex 10, September 30, 1998
|
†10(o)(1)(A)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K, Ex 10(o)(2)
|
†10(o)(1)(B)
|
|
Second
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 1, 2008.
|
|
2008
Form 10-K, Ex 10(o)(1)(B)
|
†10(p)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated as of
January 1, 2008.
|
|
2008
Form 10-K, Ex 10(p)
|
†10(q)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(r)
|
†10(r)
|
|
Nuclear
Key Contributor Retention Plan Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(r)
|
*†10(s)
|
|
AEP
Change In Control Agreement, effective November 1, 2009.
|
|
|
†10(t)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Item 1.01, dated April 26, 2005
|
†10(t)(1)(A)
|
|
First
Amendment to Amended and Restated AEP System Long-Term Incentive
Plan.
|
|
2007
Form 10-K, Ex 10(t)(1)(A)
|
†10(t)(2)
|
|
Form
of Performance Share Award Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(c), September 30, 2004
|
†10(t)(3)
|
|
Form
of Restricted Stock Unit Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(a), March 31, 2005
|
†10(t)(3)(A)
|
|
Amendment
to Form of Restricted Stock Unit Agreement furnished to participants of
the AEP System Long-Term Incentive Plan, as amended.
|
|
2008
Form 10-K, Ex 10(t)(3)(A)
|
*†10(u)
|
|
AEP
System Stock Ownership Requirement Plan Amended and Restated Effective
January 1, 2010.
|
|
|
†10(v)
|
|
Central
and South West System Special Executive Retirement Plan Amended and
Restated effective January 1, 2009.
|
|
2008
Form 10-K, Ex 10(v)
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the AEP 2009 Annual Report (for the fiscal year ended
December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
*21
|
|
List
of subsidiaries of AEP.
|
|
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
101.INS
|
|
XBRL
Instance
|
|
|
101.SCH
|
|
XBRL
Taxonomy Extension Schema
|
|
|
101.CAL
|
|
XBRL
Taxonomy Extension Calculation
|
|
|
101.DEF
|
|
XBRL
Taxonomy Extension Definition
|
|
|
101.LAB
|
|
XBRL
Taxonomy Extension Labels
|
|
|
101.PRE
|
|
XBRL
Taxonomy Extension Presentation
|
|
|
REGISTRANT:
APCo‡ File No. 1-3457
|
|
|
3(a)
|
|
Composite
of the Restated Articles of Incorporation of APCo, amended as of March 7,
1997.
|
|
1996
Form 10-K, Ex 3(d)
|
3(b)
|
|
Composite
By-Laws of APCo, amended as of February 26, 2008.
|
|
2007
Form 10-K, Ex 3(b)
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of January 1, 1998, between APCo
and The Bank of New York, As Trustee.
|
|
Registration
Statement No. 333-45927, Ex 4(a)(b)
Registration
Statement No. 333-49071, Ex 4(b)
Registration
Statement No. 333-84061, Ex 4(b)(c)
Registration
Statement No. 333-100451, Ex 4(b)(c)(d)
Registration
Statement No. 333-116284, Ex 4(b)(c)
Registration
Statement No. 333-123348, Ex 4(b)(c)
Registration
Statement No. 333-136432, Ex 4(b)(c)(d)
Registration
Statement No. 333-161940, Ex 4(b)(c)(d)
|
4(b)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex10(c) September 30, 2008
|
4(c)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(d) September 30, 2008
|
4(d)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(e) September 30, 2008
|
4(e)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(f) September 30, 2008
|
10(a)(1)
|
|
Power
Agreement, dated October 15, 1952, between OVEC and United States of
America, acting by and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator of the Energy
Research and Development Administration, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(a)
Registration
Statement No. 2-63234, Ex 5(a)(1)(B) Registration Statement No 2-66301, Ex
5(a)(1)(C) Registration Statement No. 2-67728, Ex 5(a)(1)(D)
1989
Form 10-K, Ex 10(a)(1)(F)
1992
Form 10-K, Ex 10(a)(1)(B)
|
10(a)(2)
|
|
Inter-Company
Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring
Companies, as amended March 13, 2006.
|
|
2005
Form 10-K, Ex 10(a)(2)
|
10(a)(3)
|
|
Power
Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(e)
|
10(b)
|
|
Interconnection
Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M
and with AEPSC, as amended.
|
|
Registration
Statement No. 2-52910, Ex 5(a)
Registration
Statement No. 2-61009, Ex 5(b)
1990
Form 10-K, Ex 10(a)(3), File No. 1-3525
|
10(c)
|
|
Transmission
Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
with AEPSC as agent, as amended.
|
|
1985
Form 10-K, Ex 10(b)
1988
Form 10-K, Ex 10(b)(2)
|
10(d)(1)
|
|
Amended
and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(1)
|
10(d)(2)
|
|
PJM
West Reliability Assurance Agreement among Load Serving Entities in the
PJM West service area.
|
|
2004
Form 10-K, Ex 10(d)(2)
|
10(d)(3)
|
|
Master
Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(3)
|
10(e)
|
|
Modification
No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
|
|
1996
Form 10-K, Ex 10(l), File No. 1-3525
|
10(f)
|
|
Consent
Decree with U.S. District Court.
|
|
Form
8-K, Ex 10.1 dated October 9, 2007
|
†10(g)
|
|
AEP System Senior Officer Annual Incentive
Compensation Plan amended and restated effective December 13,
2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(h)(1)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(h)(1)
|
†10(h)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated as of
January 1, 2008 (Non-Qualified).
|
|
2008
Form 10-K, Ex 10(h)(2)
|
†10(h)(3)
|
|
AEPSC
Umbrella Trust for Executives.
|
|
1993
Form 10-K, Ex 10(g)(3), File No. 1-3525
|
†10(h)(3)(A)
|
|
First
Amendment to AEPSC Umbrella Trust for Executives.
|
|
2008
Form 10-K, Ex 10(h)(3)(A)
|
†10(i)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
2003.
|
|
2003
Form 10-K, Ex 10(m)(1)
|
†10(i)(A)
|
|
Amendment
to Employment Agreement between AEP, AEPSC and Michael G. Morris dated
December 9, 2008.
|
|
2008
Form 10-K, Ex 10(i)(A)
|
†10(i)(2)
|
|
Memorandum
of Agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
2000
Form 10-K, Ex 10(s), File No. 1-3525
|
†10(i)(3)
|
|
Letter
Agreement dated June 23, 2000 between AEPSC and Holly K.
Koeppel.
|
|
2002
Form 10-K, Ex 10(m)(3)(A)
|
†10(i)(4)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K, Ex 10(m)(4)
|
†10(i)(4)(A)
|
|
Amendment
to Employment Agreement dated December 9, 2008 between AEPSC and Robert P.
Powers.
|
|
2008
Form 10-K, Ex 10(i)(4)(A)
|
†10(i)(5)
|
|
Letter
Agreement dated June 9, 2004 between AEPSC and Carl
English.
|
|
Form
10-Q, Ex 10(b), September 30, 2004
|
†10(i)(6)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC and John B.
Keane.
|
|
2006
Form 10-K, Ex 10(h)(5)
|
†10(j)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan, amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(k)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
Form
10-Q, Ex 10, September 30, 1998
|
†10(k)(1)(A)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K, Ex 10(o)(2)
|
†10(k)(1)(B)
|
|
Second
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 1, 2008.
|
|
2008
Form 10-K, Ex 10(k)(1)(B)
|
*†10(l)
|
|
AEP
Change In Control Agreement, effective November 1, 2009.
|
|
|
†10(m)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Ex 10.1, dated April 26, 2005
|
10(m)(1)(A)
|
|
First
Amendment to Amended and Restated AEP System Long-Term Incentive
Plan.
|
|
2007
Form 10-K, Ex 10(l)(1)(A)
|
†10(m)(2)
|
|
Form
of Performance Share Award Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(c), November 5, 2004
|
†10(m)(3)
|
|
Form
of Restricted Stock Unit Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(a), March 31, 2005
|
†10(m)(3)(A)
|
|
Amendment
to Form of Restricted Stock Unit Agreement furnished to participants of
the AEP System Long-Term Incentive Plan, as amended.
|
|
2008
Form 10-K, Ex10(m)(3)(A)
|
*†10(n)
|
|
AEP
System Stock Ownership Requirement Plan Amended and Restated Effective
January 1, 2010.
|
|
|
†10(o)
|
|
Central
and South West System Special Executive Retirement Plan Amended and
Restated effective January 1, 2009.
|
|
2008
Form 10-K, Ex 10(n)
|
†10(p)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated as of
January 1, 2008.
|
|
2008
Form 10-K, Ex 10(o)
|
†10(q)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(r)
|
†10(r)
|
|
Nuclear
Key Contributor Retention Plan Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(q)
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the APCo 2009 Annual Report (for the fiscal year
ended December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of APCo.
|
|
2006
Form 10-K, Ex 21, File No. 1-3525
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
REGISTRANT:
CSPCo‡ File No. 1-2680
|
|
|
3(a)
|
|
Composite
of Amended Articles of Incorporation of CSPCo, dated May 19,
1994.
|
|
1994
Form 10-K, Ex 3(c)
|
3(b)
|
|
Amended
Code of Regulations of CSPCo.
|
|
Form
10-Q, Ex 3(b) June 30, 2008
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of September 1, 1997, between
CSPCo and Bankers Trust Company, as Trustee.
|
|
Registration
Statement No. 333-54025, Ex 4(a)(b)(c)(d)
Registration
Statement No. 333-128174, Ex 4(b)(c)(d)
Registration
Statement No. 333-150603. Ex 4(b)
|
4(b)
|
|
Indenture
(for unsecured debt securities), dated as of February 1, 2003, between
CSPCo and Bank One, N.A., as Trustee.
|
|
Registration
Statement No. 333-128174, Ex 4(e)(f)(g)
Registration
Statement No. 333-150603 Ex 4(b)
|
4(c)
|
|
Company
Order and Officer’s Certificate to Deutsche Bank Trust Company Americas,
dated May 16, 2008, establishing terms of 6.05% Senior Notes, Series G,
due 2018.
|
|
Form
8-K, Ex 4(a), dated May 16, 2008
|
4(d)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(c) September 30, 2008
|
4(e)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(d) September 30, 2008
|
4(f)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(e) September 30, 2008
|
4(g)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(f) September 30, 2008
|
10(a)(1)
|
|
Power
Agreement, dated October 15, 1952, between OVEC and United States of
America, acting by and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator of the Energy
Research and Development Administration, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(a)
Registration
Statement No. 2-63234, Ex 5(a)(1)(B)
Registration
Statement No. 2-66301, Ex 5(a)(1)(C)
Registration
Statement No. 2-67728, Ex 5(a)(1)(B)
APCo
1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo
1992 Form 10-K, Ex 10(a)(1)(B), File No.1-3457
|
10(a)(2)
|
|
Inter-Company
Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring
Companies, as amended March 13, 2006.
|
|
2005
Form 10-K, Ex 10(a)(2)
|
10(a)(3)
|
|
Power
Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(e)
|
10(b)(1)
|
|
Interconnection
Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M
and AEPSC, as amended.
|
|
Registration
Statement No. 2-52910, Ex 5(a)
Registration
Statement No. 2-61009, Ex 5(b)
1990
Form 10-K, Ex 10(a)(3), File No. 1-3525
|
10(b)(2)
|
|
Unit
Power Agreement, dated March 15, 2007 between AEGCo and
CSPCo.
|
|
2007
Form 10-K, Ex 10(b)(2)
|
10(c)
|
|
Transmission
Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo,
and with AEPSC as agent, as amended.
|
|
1985
Form 10-K, Ex 10(b), File No. 1-3525
1988
Form 10-K, Ex 10(b)(2) File No. 1-3525
|
10(d)(1)
|
|
Amended
and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(1)
|
10(d)(2)
|
|
PJM
West Reliability Assurance Agreement among Load Serving Entities in the
PJM West service area.
|
|
2004
Form 10-K, Ex 10(d)(2)
|
10(d)(3)
|
|
Master
Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(3)
|
10(e)
|
|
Modification
No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
|
|
1996
Form 10-K, Ex 10(l), File No. 1-3525
|
10(f)
|
|
Consent
Decree with U.S. District Court.
|
|
Form
8-K, Ex 10.1 dated October 9, 2007
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the CSPCo 2009 Annual Report (for the fiscal year
ended December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of CSPCo.
|
|
2006
Form 10-K, Ex 21, File No. 1-3525
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
REGISTRANT: I&M‡ File
No. 1-3570
|
|
|
3(a)
|
|
Composite
of the Amended Articles of Acceptance of I&M, dated of March 7,
1997.
|
|
1996
Form 10-K, Ex 3(c)
|
3(b)
|
|
Composite
By-Laws of I&M, amended as of February 26, 2008.
|
|
2007
Form 10-K, Ex 3(b)
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of October 1, 1998, between
I&M and The Bank of New York, as Trustee.
|
|
Registration
Statement No. 333-88523, Ex 4(a)(b)(c)
Registration
Statement No. 333-58656, Ex 4(b)(c)
Registration
Statement No. 333-108975, Ex 4(b)(c)(d)
Registration
Statement No. 333-136538, Ex 4(b)(c)
Registration
Statement No. 333-156182, Ex 4(b)
|
4(b)
|
|
Company
Order and Officer’s Certificate to The Bank of New York, dated January 15,
2009 establishing terms of 7.00% Senior Notes, Series I due
2019.
|
|
Form
8-K, Ex 4(a) dated January 15, 2009
|
4(c)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex.10(c) September 30, 2008
|
4(d)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex.10(d) September 30, 2008
|
4(e)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex.10(e) September 30, 2008
|
4(f)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex.10(f) September 30, 2008
|
10(a)(1)
|
|
Power
Agreement, dated October 15, 1952, between OVEC and United States of
America, acting by and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator of the Energy
Research and Development Administration, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(a)
Registration
Statement No. 2-63234, Ex 5(a)(1)(B)
Registration
Statement No. 2-66301, Ex 5(a)(1)(C)
Registration
Statement No. 2-67728, Ex 5(a)(1)(D)
APCo
1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo
1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
|
10(a)(2)
|
|
Inter-Company
Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring
Companies, as amended, March 13, 2006.
|
|
2005
Form 10-K, Ex 10(a)(2)
|
10(a)(3)
|
|
Power
Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(e)
|
10(a)(4)
|
|
Inter-Company
Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring
Companies, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(c)
Registration
Statement No. 2-67728, Ex 5(a)(3)(B)
APCo
1992 Form 10-K, Ex 10(a)(2)(B), File No. 1-3457
|
10(b)(1)
|
|
Interconnection
Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M, and OPCo
and with AEPSC, as amended.
|
|
Registration
Statement No. 2-52910, Ex 5(a)
Registration
Statement No. 2-61009, Ex 5(b)
1990
Form 10-K, Ex 10(a)(3), File No. 1-3525
|
10(b)(2)
|
|
Unit
Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as
amended.
|
|
Registration
Statement No. 33-32752, Ex 28(b)(1)(A)(B)
|
10(c)
|
|
Transmission
Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
with AEPSC as agent, as amended.
|
|
1985
Form 10-K, Ex 10(b), File No. 1-3525
1988
Form 10-K, File No. 1-3525, Ex 10(b)(2)
|
10(d)(1)
|
|
Amended
and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(1)
|
10(d)(2)
|
|
PJM
West Reliability Assurance Agreement among Load Serving Entities in the
PJM West service area.
|
|
2004
Form 10-K, Ex 10(d)(2)
|
10(d)(3)
|
|
Master
Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(3)
|
10(e)
|
|
Modification
No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
|
|
1996
Form 10-K, Ex 10(l), File No. 1-3525
|
10(f)
|
|
Consent
Decree with U.S. District Court.
|
|
Form
8-K, Ex 10.1 dated October 9, 2007
|
10(g)
|
|
Lease
Agreements, dated as of December 1, 1989, between I&M and Wilmington
Trust Company, as amended.
|
|
Registration
Statement No. 33-32753, Ex 28(a)(1-6)(C)
1993
Form 10-K, Ex 10(e)(1-6)(B)
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the I&M 2008 Annual Report (for the fiscal year
ended December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of I&M.
|
|
2006
Form 10-K, Ex 21, File No. 1-3525
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
REGISTRANT:
OPCo‡ File No.1-6543
|
|
|
3(a)
|
|
Composite
of the Amended Articles of Incorporation of OPCo, dated June 3,
2002.
|
|
Form
10-Q, Ex 3(e), June 30, 2002
|
3(b)
|
|
Amended
Code of Regulations of OPCo.
|
|
Form
10-Q, Ex 3(b), June 30, 2008
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of September 1, 1997, between
OPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas),
as Trustee.
|
|
Registration
Statement No. 333-49595, Ex 4(a)(b)(c)
Registration
Statement No. 333-106242, Ex 4(b)(c)(d)
Registration
Statement No. 333-75783, Ex 4(b)(c)
Registration
Statement No. 333-127913, Ex 4(b)(c)
Registration
Statement No. 333-139802, Ex 4(a)(b)(c)
Registration
Statement No. 333-139802, Ex 4(b)(c)(d)
|
4(b)
|
|
Company
Order and Officer’s Certificate to Deutsche Bank Trust Company Americas,
dated April 5, 2007, establishing terms of Floating Rate Notes, Series
B.
|
|
Form
8-K, Ex 4(a) dated April 5, 2007
|
*4(c)
|
|
Company
Order and Officer’s Certificate to Deutsche Bank Trust Company Americas,
dated September 24, 2009, establishing terms of 5.375% Senior Notes,
Series M due 2021.
|
|
Form
8-K, Ex 4(a) dated September 24, 2009
|
4(d)
|
|
Indenture
(for unsecured debt securities), dated as of February 1, 2003, between
OPCo and Bank One, N.A., as Trustee.
|
|
Registration
Statement No. 333-127913, Ex 4(d)(e)(f)
|
4(e)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(c) September 30, 2008
|
4(f)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(d) September 30, 2008
|
4(g)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(e) September 30, 2008
|
4(h)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(f) September 30, 2008
|
10(a)(1)
|
|
Power
Agreement, dated October 15, 1952, between OVEC and United States of
America, acting by and through the United States Atomic Energy Commission,
and, subsequent to January 18, 1975, the Administrator of the Energy
Research and Development Administration, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(a)
Registration
Statement No. 2-63234, Ex 5(a)(1)(B)
Registration
Statement No. 2-66301, Ex 5(a)(1)(C)
Registration
Statement No. 2-67728, Ex 5(a)(1)(D)
APCo
1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo
1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
|
10(a)(2)
|
|
Inter-Company
Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring
Companies, as amended, March 13, 2006.
|
|
2005
Form 10-K, Ex 10(a)(2)
|
10(a)(3)
|
|
Power
Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
Corporation, as amended.
|
|
Registration
Statement No. 2-60015, Ex 5(e)
|
10(b)
|
|
Interconnection
Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M and OPCo
and with AEPSC, as amended.
|
|
Registration
Statement No. 2-52910, Ex 5(a)
Registration
Statement No. 2-61009, Ex 5(b)
1990
Form 10-K, Ex 10(a)(3), File 1-3525
|
10(c)
|
|
Transmission
Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
with AEPSC as agent.
|
|
1985
Form 10-K, Ex 10(b), File No. 1-3525
1988
Form 10-K, Ex 10(b)(2), File No. 1-3525
|
10(d)(1)
|
|
Amended
and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(1)
|
10(d)(2)
|
|
PJM
West Reliability Assurance Agreement among Load Serving Entities in the
PJM West service area.
|
|
2004
Form 10-K, Ex 10(d)(2)
|
10(d)(3)
|
|
Master
Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
Company.
|
|
2004
Form 10-K, Ex 10(d)(3)
|
10(e)
|
|
Modification
No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
|
|
1996
Form 10-K, Ex 10(l), File No. 1-3525
|
10(f)
|
|
Consent
Decree with U.S. District Court.
|
|
Form
8-K, Item Ex 10.1 dated October 9, 2007
|
10(g)(1)
|
|
Amendment
No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968,
among OPCo, Buckeye and Cardinal Operating Company, and amendments
thereto.
|
|
1993
Form 10-K, Ex 10(f)
2003
Form 10-K, Ex 10(e)
|
10(g)(2)
|
|
Amendment
No. 9, dated July 1, 2003, to Station Agreement dated January 1, 1968,
among OPCo, Buckeye and Cardinal Operating Company, and amendments
thereto.
|
|
Form
10-Q, Ex 10(a), September 30, 2004
|
†10(h)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(i)(1)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(j)(1)
|
†10(i)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated as of
January 1, 2008. (Non-Qualified).
|
|
2008
Form 10-K, Ex 10(j)(2)
|
†10(i)(3)
|
|
AEPSC
Umbrella Trust for Executives.
|
|
1993
Form 10-K, Ex 10(g)(3), File No. 1-3525
|
†10(i)(3)(A)
|
|
First
Amendment to AEPSC Umbrella Trust for Executives.
|
|
2008
Form 10-K, Ex 10(j)(3)(A)
|
†10(j)(1)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
2003.
|
|
2003
Form 10-K, Ex 10(m)(1)
|
†10(j)(1)(A)
|
|
Amendment
to Employment Agreement between AEP, AEPSC and Michael G. Morris dated
December 9, 2008.
|
|
2008
Form 10-K, Ex 10(k)(1)(A )
|
†10(j)(2)
|
|
Memorandum
of agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
2000
Form 10-K, Ex 10(s), File No. 1-3525
|
†10(j)(3)
|
|
Letter
Agreement dated June 23, 2000 between AEPSC and Holly K.
Koeppel.
|
|
2002
Form 10-K, Ex 10(m)(3)(A)
|
†10(j)(4)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K, Ex 10(m)(4)
|
†10(j)(4)(A)
|
|
Amendment
to Employment Agreement dated December 9, 2008 between AEPSC and Robert P.
Powers.
|
|
2008
Form 10-K, Ex 10(k)(4)(A)
|
†10(j)(5)
|
|
Letter
Agreement dated June 9, 2004 between AEPSC and Carl
English.
|
|
Form
10-Q, Ex 10(b), September 30, 2004, File No. 1-3525
|
†10(j)(6)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC and John B.
Keane.
|
|
2006
Form 10-K, Ex 10(j)(5)
|
†10(k)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan, amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(l)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
Form
10-Q, Ex 10, September 30, 1998
|
†10(l)(1)(A)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K, Ex 10(o)(2)
|
†10(l)(1)(B)
|
|
Second
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 1, 2008.
|
|
2008
Form 10-K, Ex 10(m)(1)(B)
|
*†10(m)
|
|
AEP
Change In Control Agreement, effective November 1, 2009.
|
|
|
†10(n)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Ex 10.1, dated April 26, 2005
|
10(n)(1)(A)
|
|
First
Amendment to Amended and Restated AEP System Long-Term Incentive
Plan.
|
|
2007
Form 10-K, Ex 10(n)(1)(A)
|
†10(o)
|
|
Form
of Performance Share Award Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(c), November 5, 2004,
File
No. 1-3525
|
†10(p)(1)
|
|
Form
of Restricted Stock Unit Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(a), March 31, 2005
|
†10(p)(1)(A)
|
|
Amendment
to Form of Restricted Stock Unit Agreement furnished to participants of
the AEP System Long-Term Incentive Plan, as amended.
|
|
2008
Form 10-K, Ex 10(q)(1)(A)
|
*†10(q)
|
|
AEP System Stock
Ownership Requirement Plan Amended and Restated Effective January 1,
2010.
|
|
|
†10(r)
|
|
Central
and South West System Special Executive Retirement Plan Amended and
Restated effective January 1, 2009.
|
|
2008
Form 10, Ex 10(s)
|
†10(s)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated as of
January 1, 2008.
|
|
2008
Form 10, Ex 10(t)
|
†10(y)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(r)
|
†10(u)
|
|
Nuclear
Key Contributor Retention Plan Amended and Restated as of January 1,
2008.
|
|
2008
Form 10, Ex 10(v)
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the OPCo 2009 Annual Report (for the fiscal year
ended December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of OPCo.
|
|
2006
Form 10-K, Ex 21, File No. 1-3525
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
REGISTRANT: PSO‡ File
No. 0-343
|
|
|
3(a)
|
|
Certificate
of Amendment to Restated Certificate of Incorporation of
PSO.
|
|
Form
10-Q, Ex 3(a), June 30, 2008
|
3(b)
|
|
Composite
By-Laws of PSO amended as of February 26, 2008.
|
|
2007
Form 10-K, Ex 3 (b)
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of November 1, 2000, between PSO
and The Bank of New York, as Trustee.
|
|
Registration
Statement No. 333-100623, Ex 4(a)(b)
Registration
Statement No. 333-114665, Ex 4(b)(c)
Registration
Statement No. 333-133548, Ex 4(b)(c)
Registration
Statement No. 333-156319, Ex 4(b)(c)
|
*4(b)
|
|
Eighth
Supplemental Indenture, dated as of November 13, 2009 between PSO and The
Bank of New York Mellon, as Trustee, establishing terms of the 5.15%
Senior Notes, Series H, due 2019.
|
|
Form
8-K, Ex 4(a), dated November 13, 2009
|
4(c)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(c) September 30, 2008
|
4(d)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(d) September 30, 2008
|
4(e)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(e) September 30, 2008
|
4(f)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(f) September 30, 2008
|
10(a)
|
|
Restated
and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on
February 10, 2006, Effective May 1, 2006.
|
|
Form
10-Q, Ex 10(a), March 31, 2006
|
*10(b)
|
|
Restated
and Amended Transmission Coordination Agreement, dated April 15, 2002,
among PSO, SWEPCo, TNC and AEPSC.
|
|
|
†10(c)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(d)(1)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(d)(1)
|
†10(d)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated as of
January 1, 2008 (Non-Qualified).
|
|
2008
Form 10-K, Ex 10(d)(2)
|
†10(d)(3)
|
|
AEPSC
Umbrella Trust for Executives.
|
|
1993
Form 10-K, Ex 10(g)(3), File No. 1-3525
|
†10(d)(3)(A)
|
|
First
Amendment to AEPSC Umbrella Trust for Executives.
|
|
2008
Form 10-K, Ex 10(d)(3)(A)
|
†10(e)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
2003.
|
|
2003
Form 10-K, Ex 10(m)(1)
|
†10(e)(A)
|
|
Amendment
to Employment Agreement between AEP, AEPSC and Michael G. Morris dated
December 9, 2008.
|
|
2008
Form 10-K, Ex 10(e)(A)
|
†10(e)(2)
|
|
Memorandum
of Agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
2000
Form 10-K, Ex 10(s), File No. 1-3525
|
†10(e)(3)
|
|
Letter
Agreement dated June 23, 2000 between AEPSC and Holly K.
Koeppel.
|
|
2002
Form 10-K, Ex 10(m)(3)(A)
|
†10(e)(4)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K, Ex 10(m)(4)
|
†10(e)(4)(A)
|
|
Amendment
to Employment Agreement dated December 9, 2008 between AEPSC and Robert P.
Powers.
|
|
2008
Form 10-K, Ex 10(e)(4)(A)
|
†10(e)(5)
|
|
Letter
Agreement dated June 9, 2004 between AEPSC and Carl
English.
|
|
Form
10-Q, Ex 10(b), September 30, 2004
|
†10(e)(6)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC and John B.
Keane.
|
|
2006
Form 10-K, Ex 10(h)(5)
|
†10(f)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan, amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(g)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
Form
10-Q, Ex 10, September 30, 1998
|
†10(g)(1)(A)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K, Ex 10(o)(2)
|
†10(g)(1)(B)
|
|
Second
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 1, 2008.
|
|
2008
Form 10-K, Ex 10(g)(1)(B)
|
*†10(h)
|
|
AEP
Change In Control Agreement, effective November 1, 2009.
|
|
|
†10(i)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Ex 10.1, dated April 26, 2005
|
10(i)(1)(A)
|
|
First
Amendment to Amended and Restated AEP System Long-Term Incentive
Plan.
|
|
2007
Form 10-K, Ex 10(l)(1)(A
|
†10(i)(2)
|
|
Form
of Performance Share Award Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(c), November 5, 2004
|
†10(i)(3)
|
|
Form
of Restricted Stock Unit Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(a), March 31, 2005
|
†10(i)(3)(A)
|
|
Amendment
to Form of Restricted Stock Unit Agreement furnished to participants of
the AEP System Long-Term Incentive Plan, as amended.
|
|
2008
Form 10-K, Ex 10(i)(3)(A)
|
*†10(j)
|
|
AEP
System Stock Ownership Requirement Plan Amended and Restated Effective
January 1, 2010.
|
|
|
†10(k)
|
|
Central
and South West System Special Executive Retirement Plan Amended and
Restated effective January 1, 2009.
|
|
2008
Form 10-K, Ex 10(j)
|
†10(l)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated as of
January 1, 2008.
|
|
2008
Form 10-K, Ex 10(k)
|
†10(m)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(p)
|
†10(n)
|
|
Nuclear
Key Contributor Retention Plan Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(m)
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the PSO 2009 Annual Report (for the fiscal year ended
December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of PSO.
|
|
2006
Form 10-K, Ex 21, File No. 1-3525
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
REGISTRANT:
SWEPCo‡ File No. 1-3146
|
|
|
3(a)
|
|
Composite
of Amended Restated Certificate of Incorporation of
SWEPCo.
|
|
2008
Form 10-K, Ex 3(a)
|
3(b)
|
|
Composite
By-Laws of SWEPCo amended as of February 26, 2008.
|
|
2007
Form 10-K, Ex 3(b)
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of February 4, 2000, between
SWEPCo and The Bank of New York, as Trustee.
|
|
Registration
Statement No. 333-96213
Registration
Statement No. 333-87834, Ex 4(a)(b)
Registration
Statement No. 333-100632, Ex 4(b)
Registration
Statement No. 333-108045, Ex 4(b)
Registration
Statement No. 333-145669, Ex 4(c)(d)
Registration
Statement No. 333-161539, Ex 4(b)(c)
|
4(b)
|
|
$650
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(c) September 30, 2008
|
4(c)
|
|
Amendment,
dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(d) September 30, 2008
|
4(d)
|
|
$350
Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC,
APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders
named therein, the Swingline Bank party thereto, the LC Issuing Banks
party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(e) September 30, 2008
|
4(e)
|
|
Amendment,
dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP,
TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial
Lenders named therein, the Swingline Bank party thereto, the LC Issuing
Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative
Agent.
|
|
Form
10-Q, Ex 10(f) September 30, 2008
|
10(a)
|
|
Restated
and Amended Operating Agreement, among PSO, TCC, TNC, SWEPCo and AEPSC,
Issued on February 10, 2006, Effective May 1, 2006.
|
|
Form
10-Q, Ex 10(a), March 31, 2006
|
*10(b)
|
|
Restated
and Amended Transmission Coordination Agreement, dated April 15, 2002,
among PSO, SWEPCo, TNC and AEPSC.
|
|
|
†10(c)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(d)(1)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(d)(1)
|
†10(d)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated as of
January 1, 2008 (Non-Qualified).
|
|
2008
Form 10-K, Ex 10(d)(2)
|
†10(d)(3)
|
|
AEPSC
Umbrella Trust for Executives.
|
|
1993
Form 10-K, Ex 10(g)(3), File No. 1-3525
|
†10(d)(3)(A)
|
|
First
Amendment to AEPSC Umbrella Trust for Executives.
|
|
2008
Form 10-K, Ex 10(d)(3)(A)
|
†10(e)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
2003.
|
|
2003
Form 10-K, Ex 10(m)(1)
|
†10(e)(A)
|
|
Amendment
to Employment Agreement between AEP, AEPSC and Michael G. Morris dated
December 9, 2008.
|
|
2008
Form 10-K, Ex 10(e)(A)
|
†10(e)(2)
|
|
Memorandum
of Agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
2000
Form 10-K, Ex 10(s), File No. 1-3525
|
†10(e)(3)
|
|
Letter
Agreement dated June 23, 2000 between AEPSC and Holly K.
Koeppel.
|
|
2002
Form 10-K, Ex 10(m)(3)(A)
|
†10(e)(4)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K, Ex 10(m)(4)
|
†10(e)(4)(A)
|
|
Amendment
to Employment Agreement dated December 9, 2008 between AEPSC and Robert P.
Powers.
|
|
2008
Form 10-K, Ex 10(e)(4)(A)
|
†10(e)(5)
|
|
Letter
Agreement dated June 9, 2004 between AEPSC and Carl
English.
|
|
Form
10-Q, Ex 10(b), September 30, 2004
|
†10(e)(6)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC and John B.
Keane.
|
|
2006
Form 10-K, Ex 10(h)(5)
|
†10(f)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan, amended and
restated effective December 13, 2006.
|
|
Form
8-K, Ex 10.1 dated April 25, 2007
|
†10(g)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
Form
10-Q, Ex 10, September 30, 1998
|
†10(g)(1)(A)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K, Ex 10(o)(2)
|
†10(g)(1)(B)
|
|
Second
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 1, 2008.
|
|
2008
Form 10-K, Ex 10(g)(1)(B)
|
*†10(h)
|
|
AEP
Change In Control Agreement, effective November 1, 2009.
|
|
|
†10(i)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Ex 10.1, dated April 26, 2005
|
10(i)(1)(A)
|
|
First
Amendment to Amended and Restated AEP System Long-Term Incentive
Plan.
|
|
2007
Form 10-K, Ex 10(l)(1)(A
|
†10(i)(2)
|
|
Form
of Performance Share Award Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
AEP
Form 10-Q, Ex 10(c), November 5, 2004
|
†10(i)(3)
|
|
Form
of Restricted Stock Unit Agreement furnished to participants of the AEP
System Long-Term Incentive Plan, as amended.
|
|
Form
10-Q, Ex 10(a), March 31, 2005
|
†10(i)(3)(A)
|
|
Amendment
to Form of Restricted Stock Unit Agreement furnished to participants of
the AEP System Long-Term Incentive Plan, as amended.
|
|
2008
Form 10-K, Ex 10(i)(3)(A)
|
*†10(j)
|
|
AEP
System Stock Ownership Requirement Plan Amended and Restated Effective
January 1, 2010.
|
|
|
†10(k)
|
|
Central
and South West System Special Executive Retirement Plan Amended and
Restated effective January 1, 2009.
|
|
2008
Form 10-K, Ex 10(j)
|
†10(l)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated as of
January 1, 2008.
|
|
2008
Form 10-K, Ex 10(k)
|
†10(m)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(p)
|
†10(n)
|
|
Nuclear
Key Contributor Retention Plan Amended and Restated as of January 1,
2008.
|
|
2008
Form 10-K, Ex 10(m)
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the SWEPCo 2009 Annual Report (for the fiscal year
ended December 31, 2009) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of SWEPCo.
|
|
2006
Form 10-K, Ex 21, File No. 1-3525
|
*23
|
|
Consent
of Deloitte & Touche LLP.
|
|
|
*24
|
|
Power
of Attorney.
|
|
|
*31(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*31(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
*32(a)
|
|
Certification
of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
*32(b)
|
|
Certification
of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title
18 of the United States Code.
|
|
|
_______________
‡
Certain instruments defining the rights of holders of long-term debt of
the registrants included in the financial statements of registrants filed
herewith have been omitted because the total amount of securities
authorized thereunder does not exceed 10% of the total assets of
registrants. The registrants hereby agree to furnish a copy of
any such omitted instrument to the SEC upon
request.
|