AEP Texas Central Company 2006 10-K
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, 2006
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
|
|
0-18135
|
|
AEP
Generating
Company (An
Ohio Corporation)
|
|
31-1033833
|
|
0-346
|
|
AEP
Texas
Central Company (A
Texas Corporation)
|
|
74-0550600
|
|
0-340
|
|
AEP
Texas North Company (A
Texas Corporation)
|
|
75-0646790
|
|
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
|
|
1-6858
|
|
Kentucky
Power Company (A
Kentucky Corporation)
|
|
61-0247775
|
|
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 with respect to American Electric
Power
Company, Inc. and Appalachian 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 with respect to AEP Generating Company,
AEP Texas Central Company, AEP Texas North Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company,
Ohio 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 with respect to American Electric
Power
Company, Inc., AEP Generating Company, AEP Texas Central Company,
AEP
Texas North Company, Appalachian Power Company, Columbus Southern
Power
Company, Indiana Michigan Power Company, Kentucky Power Company,
Ohio
Power Company, Public Service Company of Oklahoma and Southwestern
Electric Power Company, 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 if disclosure of delinquent filers with respect to
Appalachian Power Company or Ohio 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 or Ohio
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, or a non-accelerated filer.
See
definition of ‘accelerated filer and large accelerated filer’ in Rule
12b-2 of the Exchange Act. (Check One)
|
|
|
Large
accelerated filer x
|
Accelerated
filer o
|
Non-accelerated
filer o
|
|
|
|
Indicate
by check mark whether AEP Generating Company, AEP Texas Central Company,
AEP Texas North Company, Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern
Electric Power Company are large accelerated filers, accelerated
filers,
or non-accelerated filers. See definition of ‘accelerated filer and large
accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check
One)
|
|
|
Large
accelerated filer o
|
Accelerated
filer o
|
Non-accelerated
filer x
|
|
|
|
Indicate
by check mark if the registrants are shell companies, as defined
in Rule
12b-2 of the Exchange Act.
|
Yes
o
|
No.
x
|
AEP
Generating Company, AEP Texas Central Company, AEP Texas North Company, Columbus
Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company
and Public Service Company of Oklahoma 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
|
AEP
Generating Company
|
|
None
|
|
|
AEP
Texas Central Company
|
|
None
|
|
|
AEP
Texas North Company
|
|
None
|
|
|
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
|
Kentucky
Power Company
|
|
None
|
|
|
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
|
AEP
Generating Company
|
|
None
|
AEP
Texas Central Company
|
|
None
|
AEP
Texas North Company
|
|
None
|
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
|
Kentucky
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, Non-Voting, $100 par value
|
|
|
4.65%
Cumulative Preferred Stock, Non-Voting, $100 par value
|
|
|
5.00%
Cumulative Preferred Stock, Non-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, 2006, 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, 2006
|
AEP
Generating Company
|
|
None
|
|
1,000
|
|
|
|
|
($1,000
par value)
|
AEP
Texas Central Company
|
|
None
|
|
2,211,678
|
|
|
|
|
($25
par value)
|
AEP
Texas North Company
|
|
None
|
|
5,488,560
|
|
|
|
|
($25
par value)
|
American
Electric Power Company, Inc.
|
|
$13,492,667,933
|
|
396,674,736
|
|
|
|
|
($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)
|
Kentucky
Power Company
|
|
None
|
|
1,009,000
|
|
|
|
|
($50
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, directly or indirectly, all of the common
stock of AEP Generating Company, AEP Texas Central Company, AEP Texas North
Company, Appalachian Power Company, Columbus Southern Power Company, Indiana
Michigan Power Company, Kentucky 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, 2006:
|
Part
II
|
AEP
Generating Company
|
|
AEP
Texas Central Company
|
|
AEP
Texas North Company
|
|
American
Electric Power Company, Inc.
|
|
Appalachian
Power Company
|
|
Columbus
Southern Power Company
|
|
Indiana
Michigan Power Company
|
|
Kentucky
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 2007
Annual Meeting of Shareholders
|
Part
III
|
|
|
Portions
of Information Statements of the following companies for 2007 Annual
Meeting of Shareholders:
|
Part
III
|
Appalachian
Power Company
|
|
Ohio
Power Company
|
|
This
combined Form 10-K is separately filed by AEP Generating Company, AEP Texas
Central Company, AEP Texas North Company, American Electric Power Company,
Inc.,
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Kentucky 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
|
|
Page
Number
|
|
Glossary
of Terms
|
i
|
|
Forward-Looking
Information
|
iii
|
PART
I
|
1
|
|
Business
|
|
|
|
General
|
1
|
|
|
Utility
Operations
|
8
|
|
|
MEMCO
Operations
|
23
|
|
|
Generation
and Marketing
|
24
|
|
|
Other
|
24
|
1
|
A
|
Risk
Factors
|
25
|
1
|
B
|
Unresolved
Staff Comments
|
37
|
2
|
|
Properties
|
38
|
|
|
Generation
Facilities
|
38
|
|
|
Transmission
and Distribution Facilities
|
40
|
|
|
Titles
|
41
|
|
|
System
Transmission Lines and Facility Siting
|
41
|
|
|
Construction
Program
|
41
|
|
|
Potential
Uninsured Losses
|
45
|
3
|
|
Legal
Proceedings
|
45
|
4
|
|
Submission
Of Matters To A Vote Of Security Holders
|
45
|
|
|
Executive
Officers of the Registrant
|
45
|
PART
II
|
5
|
|
Market
For Registrant’s Common Equity, Related Stockholder Matters
And
Issuer Purchases Of Equity Securities
|
48
|
6
|
|
Selected
Financial Data
|
49
|
7
|
|
Management’s
Discussion And Analysis Of Financial Condition And Results
Of Operations
|
49
|
7
|
A
|
Quantitative
And Qualitative Disclosures About Market Risk
|
49
|
8
|
|
Financial
Statements And Supplementary Data
|
50
|
9
|
|
Changes
In And Disagreements With Accountants On Accounting And
Financial Disclosure
|
50
|
9
|
A
|
Controls
And Procedures
|
50
|
9
|
B
|
Other
Information
|
50
|
PART
III
|
10
|
|
Directors,
Executive Officers and Corporate Governance
|
51
|
11
|
|
Executive
Compensation
|
52
|
12
|
|
Security
Ownership Of Certain Beneficial Owners And Management and Related
Stockholder Matters
|
53
|
13
|
|
Certain
Relationships And Related Transactions, and Director
Independence
|
54
|
14
|
|
Principal
Accounting Fees And Services
|
55
|
PART
IV
|
15
|
|
Exhibits,
Financial Statement Schedules
|
57
|
|
|
Financial
Statements
|
57
|
|
|
Signatures
|
58
|
|
|
Index
to Financial Statement Schedules
|
S-1
|
|
|
Report
of Independent Registered Public Accounting Firm
|
S-2
|
|
|
Exhibit
Index
|
E-1
|
GLOSSARY
OF TERMS
The
following abbreviations or acronyms used in this Form 10-K are defined
below:
Abbreviation
or Acronym
|
Definition
|
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
|
AEPSC
or Service Corporation
|
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
|
Cardinal
Station
|
Generating
facility co-owned by Buckeye and OPCo
|
CERCLA
|
Comprehensive
Environmental Response, Compensation and Liability Act of
1980
|
CG&E
|
The
Cincinnati Gas & Electric Company, an unaffiliated utility
company
|
Cook
Plant
|
The
Donald C. Cook Nuclear Plant (2,143 MW), 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
|
Dow
|
The
Dow Chemical Company, and its affiliates collectively, unaffiliated
companies
|
DP&L
|
The
Dayton Power and Light Company, an unaffiliated utility
company
|
EMF
|
Electric
and Magnetic Fields
|
EPA
|
United
States Environmental Protection Agency
|
EPACT
|
The
Energy Policy Act of 2005
|
ERCOT
|
Electric
Reliability Council of Texas
|
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
|
I&M
Power Agreement
|
Unit
Power Agreement Between AEGCo and I&M, dated March 31,
1982
|
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
|
KPCo
|
Kentucky
Power Company, a public utility subsidiary of AEP
|
LLWPA
|
Low-Level
Waste Policy Act of 1980
|
LPSC
|
Louisiana
Public Service Commission
|
MEMCO
|
AEP
MEMCO LLC
|
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
|
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
|
OPCo
|
Ohio
Power Company, a public utility subsidiary of AEP
|
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
|
PSO
|
Public
Service Company of Oklahoma, a public utility subsidiary of
AEP
|
PUCO
|
Public
Utilities Commission of Ohio
|
PUCT
|
Public
Utility Commission of Texas
|
PUHCA
|
Public
Utility Holding Company Act of 1935, as amended (repealed effective
February 8, 2006)
|
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
|
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
|
TCA
|
Transmission
Coordination Agreement dated January 1, 1997 by and among, PSO, SWEPCo,
TCC, TNC and AEPSC, which allocated costs and benefits through September
2005 in connection with the operation of the transmission assets
of the
four public utility subsidiaries
|
TCC
|
AEP
Texas Central Company, formerly Central Power and Light Company,
a public
utility subsidiary of AEP
|
TEA
|
Transmission
Equalization 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
|
Texas
Act
|
Texas
electric restructuring legislation
|
TNC
|
AEP
Texas North Company, formerly West Texas Utilities Company, a public
utility subsidiary of AEP
|
Tractebel
|
Tractebel
Energy Marketing, Inc.
|
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 AEP and certain of its registrant subsidiaries contains
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. Although AEP and each of its registrant subsidiaries
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:
·
|
Electric
load and customer growth.
|
·
|
Weather
conditions, including storms.
|
·
|
Available
sources and costs of, and transportation for, fuels and the
creditworthiness of fuel suppliers and transporters.
|
·
|
Availability
of generating capacity and the performance of our generating
plants.
|
·
|
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 when needed at acceptable
prices and terms and to recover those costs 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.
|
·
|
Timing
and resolution of pending and future rate cases, negotiations and
other
regulatory decisions (including rate or other recovery for new
investments, transmission service and environmental
compliance).
|
·
|
Resolution
of litigation (including pending Clean Air Act enforcement actions
and
disputes arising from the bankruptcy of Enron Corp. and related
matters).
|
·
|
Our
ability to constrain operation and maintenance costs.
|
·
|
The
economic climate and growth in our service territory and changes
in market
demand and demographic patterns.
|
·
|
Inflationary
and interest rate trends.
|
·
|
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 AEP has
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, and other
energy-related commodities.
|
·
|
Changes
in utility regulation, including the potential for new legislation
or
regulation in Ohio and or Virginia and membership in and integration
into
regional transmission organizations.
|
·
|
Accounting
pronouncements periodically issued by accounting standard-setting
bodies.
|
·
|
The
performance of our pension and other postretirement benefit
plans.
|
·
|
Prices
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, the ERCOT area
of
Texas and, as of December 31, 2006, Virginia 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 member 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, 2006, the subsidiaries of AEP had a total of 20,442 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 949,000 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, 2006, APCo and its wholly owned
subsidiaries had 2,461 employees. Among the principal industries served by
APCo
are coal mining, primary metals, chemicals and textile mill products. In
addition to its AEP System interconnections, APCo also is interconnected with
the following unaffiliated utility companies: Carolina Power & Light
Company, Duke Energy Corporation 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 742,000 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, 2006, CSPCo had
1,233 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 food processing, chemicals, primary metals,
electronic machinery and paper products. In addition to its AEP System
interconnections, CSPCo also is interconnected with the following unaffiliated
utility companies: CG&E, 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 582,000 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,
2006, I&M had 2,643 employees. Among the principal industries served are
primary metals, transportation equipment, electrical and electronic machinery,
fabricated metal products, rubber and miscellaneous plastic products and
chemicals and allied products. Since 1975, I&M has leased and operated the
assets of the municipal system of the City of Fort Wayne, Indiana. In addition
to its AEP System interconnections, I&M also is interconnected with the
following unaffiliated utility companies: Central Illinois Public Service
Company, CG&E, Commonwealth Edison Company, Consumers Energy Company,
Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas
and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc.
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 176,000 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, 2006, KPCo had 466 employees. In addition to its AEP System
interconnections, KPCo also 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.
Kingsport
Power Company (organized
in Virginia in 1917) provides electric service to approximately 46,000 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, 2006, Kingsport Power Company had 60 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 712,000 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, 2006, OPCo had 2,330 employees. Among the principal industries
served by OPCo are primary metals, rubber and plastic products, stone, clay,
glass and concrete products, petroleum refining and chemicals. In addition
to
its AEP System interconnections, OPCo also is interconnected with the following
unaffiliated utility companies: CG&E, 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 520,000 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, 2006, PSO had 1,233
employees. Among the principal industries served by PSO are natural gas and
oil
production, oil refining, steel processing, aircraft maintenance, paper
manufacturing and timber products, glass, chemicals, cement, plastics, aerospace
manufacturing, telecommunications, and rubber goods. In addition to its AEP
System interconnections, PSO also is interconnected with Ameren Corporation,
Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern
Public Service Co. 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 456,000 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, 2006, SWEPCo had 1,545 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 also
interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp.
and
Oklahoma Gas & Electric Co. SWEPCo is a member of SPP.
TCC
(organized
in Texas in 1945) is engaged in the transmission and distribution of electric
power to approximately 738,000 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, 2006, TCC
had 1,224 employees. Among the principal industries served by TCC are oil and
gas extraction, food processing, apparel, metal refining, chemical and petroleum
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 189,000 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 a 20-year agreement. At
December 31, 2006, TNC had 386 employees. Among the principal industries served
by TNC are 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,
2006, WPCo had 61 employees.
AEGCo (organized
in Ohio in 1982) is an electric generating company. AEGCo sells power at
wholesale to I&M 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 System companies. The executive officers
of AEP and certain of its public utility subsidiaries are employees of AEPSC.
At
December 31, 2006, AEPSC had 5,961 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, 2006 are as follows:
Description
|
|
|
AEP
System(a)
|
|
|
APCo
|
|
|
CSPCo
|
|
|
I&M
|
|
|
KPCo
|
|
|
|
(in
thousands)
|
UTILITY
OPERATIONS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Sales
|
|
$
|
3,688,000
|
|
$
|
695,141
|
|
$
|
632,878
|
|
$
|
389,185
|
|
$
|
156,547
|
|
Commercial
Sales
|
|
|
2,643,000
|
|
|
349,869
|
|
|
569,865
|
|
|
303,540
|
|
|
93,659
|
|
Industrial
Sales
|
|
|
2,422,000
|
|
|
476,964
|
|
|
193,740
|
|
|
350,282
|
|
|
140,627
|
|
Total
Other Retail Sales
|
|
|
297,000
|
|
|
78,103
|
|
|
24,171
|
|
|
25,637
|
|
|
8,650
|
|
Total
Retail
|
|
|
9,050,000
|
|
|
1,600,077
|
|
|
1,420,654
|
|
|
1,068,644
|
|
|
399,483
|
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System
Sales
|
|
|
2,355,000
|
|
|
473,811
|
|
|
260,996
|
|
|
492,182
|
|
|
111,638
|
|
Transmission
|
|
|
269,000
|
|
|
28,545
|
|
|
16,949
|
|
|
23,139
|
|
|
6,855
|
|
Total
Wholesale
|
|
|
2,624,000
|
|
|
502,356
|
|
|
277,945
|
|
|
515,321
|
|
|
118,493
|
|
Other
Electric Revenues
|
|
|
264,000
|
|
|
43,206
|
|
|
16,943
|
|
|
17,170
|
|
|
8,456
|
|
Other
Operating Revenues
|
|
|
128,000
|
|
|
9,797
|
|
|
5,467
|
|
|
32,181
|
|
|
1,148
|
|
Sales
To Affiliates
|
|
|
-
|
|
|
238,592
|
|
|
85,726
|
|
|
343,631
|
|
|
58,287
|
|
Total
Utility Operating Revenues
|
|
|
12,066,000
|
|
|
2,394,028
|
|
|
1,806,735
|
|
|
1,976,947
|
|
|
585,867
|
|
OTHER
|
|
|
556,000
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
TOTAL
REVENUES
|
|
$
|
12,622,000
|
|
$
|
2,394,028
|
|
$
|
1,806,735
|
|
$
|
1,976,947
|
|
$
|
585,867
|
|
Description
|
|
OPCo
|
|
PSO
|
|
SWEPCo
|
|
TCC(b)
|
|
TNC(b)
|
|
|
|
(in
thousands)
|
|
UTILITY
OPERATIONS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
Sales
|
|
$
|
542,406
|
|
$
|
506,360
|
|
$
|
399,931
|
|
$
|
242,081
|
|
$
|
56,821
|
|
Commercial
Sales
|
|
|
356,768
|
|
|
363,401
|
|
|
335,182
|
|
|
194,696
|
|
|
28,622
|
|
Industrial
Sales
|
|
|
536,244
|
|
|
333,369
|
|
|
268,554
|
|
|
40,186
|
|
|
8,643
|
|
Total
Other Retail Sales
|
|
|
33,183
|
|
|
94,123
|
|
|
6,867
|
|
|
9,513
|
|
|
11,613
|
|
Total
Retail
|
|
|
1,468,601
|
|
|
1,297,253
|
|
|
1,010,534
|
|
|
486,476
|
|
|
105,699
|
|
Wholesale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-System
Sales
|
|
|
483,888
|
|
|
52,913
|
|
|
257,362
|
|
|
17,226
|
|
|
148,034
|
|
Transmission
|
|
|
21,546
|
|
|
16,209
|
|
|
38,044
|
|
|
81,667
|
|
|
36,328
|
|
Total
Wholesale
|
|
|
505,434
|
|
|
69,122
|
|
|
295,406
|
|
|
98,893
|
|
|
184,362
|
|
Other
Electric Revenues
|
|
|
32,244
|
|
|
18,174
|
|
|
80,713
|
|
|
38,471
|
|
|
5,869
|
|
Other
Operating Revenues
|
|
|
16,478
|
|
|
5,242
|
|
|
2,741
|
|
|
34,421
|
|
|
315
|
|
Sales
to Affiliates
|
|
|
702,118
|
|
|
51,993
|
|
|
42,445
|
|
|
6,403
|
|
|
33,225
|
|
Total
Utility Operating Revenues
|
|
|
2,724,875
|
|
|
1,441,784
|
|
|
1,431,839
|
|
|
664,664
|
|
|
329,470
|
|
OTHER
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
TOTAL
REVENUES
|
|
$
|
2,724,875
|
|
$
|
1,441,784
|
|
$
|
1,431,839
|
|
$
|
664,664
|
|
$
|
329,470
|
|
(a)
|
Includes
revenues of other subsidiaries not shown. Intercompany transactions
have
been eliminated, including $309,814,000 of AEGCo’s revenues for the year
ended December 31, 2006.
|
(b)
|
TCC
and TNC revenues from distribution and transmission services to REPs
are
reflected in retail classes of
customer.
|
EPACT
AND THE REPEAL OF PUHCA
EPACT
was
signed into law on August 8, 2005. Among other things, EPACT repealed PUHCA,
effective February 8, 2006. PUHCA regulated many significant aspects of a
registered holding company system, such as the AEP System. PUHCA limited the
operations of a registered holding company system to a single integrated public
utility system and such other businesses as were incidental or necessary to
the
operations of the system. PUHCA also required that transactions between
associated companies in a registered holding company system be performed at
cost, with limited exceptions. As a result of PUHCA’s repeal, utility holding
companies, including the AEP system, are no longer limited to a single
integrated public utility system. Further, utility holding companies are no
longer restricted from acquiring businesses that may not be related to the
utility business. Jurisdiction over certain holding company related activities
has been transferred to the FERC, including the issuances of securities by
public utilities, 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 FERC and state regulators will be permitted
to review the books and records of any company within a holding company system.
EPACT
contains key provisions affecting the electric power industry. These provisions
include tax changes for the utility industry, incentives for emissions
reductions and federal insurance and incentives to build new nuclear power
plants. It gives the FERC “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 greenhouse
gases. FERC has issued regulations implementing EPACT. We do not expect
compliance with these regulations to have a material adverse impact on our
financial condition and results of operations.
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 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.
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, 2006, 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 would be considered an
immediate termination event. See Management’s
Financial Discussion and Analysis of Results of Operations,
included in the 2006 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
In
September 2005, Moody’s upgraded AEP’s senior unsecured rating to Baa2 from Baa3
and its commercial paper rating to Prime-2 from Prime-3. There were no changes
in the ratings or rating outlook for AEP or AEP’s rated subsidiaries by Moody’s
since that time. S&P did not change the ratings of AEP or its rated
subsidiaries during 2006; it did improve our business risk profile rating from
six to five. Fitch placed TNC on negative outlook in April 2006 but has made
no
other changes to the ratings of AEP or its rated subsidiaries during
2006.
See
Management’s
Financial Discussion and Analysis of Results of Operations,
included in the 2006 Annual Reports, under the heading entitled Financial
Condition for
additional information with respect to the credit ratings of the registrants
other than AEGCo.
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 are potentially material to the AEP system
include:
· |
Global
climate change and legislative responses to it, including limitations
on
CO2
emissions. See Management’s
Financial Discussion and Analysis of Results of Operations
under
the headings entitled Environmental
Matters - Potential Regulation of
CO2
Emissions.
|
· |
The
CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits
and
reporting as to air emissions. See Management’s
Financial Discussion and Analysis of Results of Operations
under
the headings entitled Environmental
Matters - Clean
Air Act Requirements and
Estimated
Air Quality Environmental Investments.
|
· |
Litigation
with the federal and certain state governments and certain special
interest groups regarding whether modifications to or maintenance
of
certain coal-fired generating plants required additional permitting
or
pollution control technology, and/or whether emissions from coal-fired
generating plants cause or contribute to global climate changes.
See
Management’s
Financial Discussion and Analysis of Results of Operations
under
the heading entitled Environmental
Matters -
Environmental
Litigation and
Note 6 to the consolidated financial statements entitled Commitments,
Guarantees and Contingencies,
included in the 2006 Annual Reports, for further
information.
|
· |
Rules
issued by the EPA and certain states that require substantial reductions
in SO2,
mercury and NOx emissions, which have compliance dates that take
effect
periodically through as late as 2018. AEP is installing (and has
installed) emission control technology and is taking other measures
to
comply with required reductions. See Management’s
Financial Discussion and Analysis of Results of Operations
under
the headings entitled Environmental
Matters - Clean Air Act Requirements
and Estimated
Air Quality Environmental Investments included
in the 2006 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. AEP does not, however, anticipate
that
any of its currently identified CERCLA-related issues will result
in
material costs or penalties to the AEP System. See Note 6 to the
consolidated financial statements entitled Commitments,
Guarantees and Contingencies,
included in the 2006 Annual Reports, under the heading entitled
The
Comprehensive Environmental Response Compensation and Liability
Act
(Superfund)
and State Remediation for
further information.
|
· |
The
Federal Clean Water Act, which prohibits the discharge of pollutants
into
waters of the United States except pursuant to appropriate permits.
In
July 2004, the EPA adopted a new Clean Water Act rule to reduce the
number
of fish and other aquatic organisms killed at once-through cooled
power
plants. See Management’s
Financial Discussion and Analysis of Results of
Operations,
included in the 2006 Annual Reports, under the heading entitled
Environmental
Matters - Clean
Water Act Regulations
for additional information.
|
· |
Solid
and hazardous waste laws and regulations, which govern the management
and
disposal of certain wastes. The majority of solid waste created from
the
combustion of coal and fossil fuels is fly ash and other coal combustion
byproducts, which the EPA has determined are not hazardous waste
subject
to RCRA.
|
In
addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions. See Management’s
Financial Discussion and Analysis of Results of Operations
under
the heading entitled Environmental
Matters,
included in the 2006 Annual Reports, for
further information with respect to environmental issues.
If
our
expenditures for pollution control technologies, replacement generation and
associated operating costs are not recoverable from customers through regulated
rates (in regulated jurisdictions) or market prices (in deregulated
jurisdictions), 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 2006 Annual Reports, for further information with respect to
environmental matters.
Environmental
Investments
Investments
related to improving AEP System plants’ environmental performance and compliance
with air and water quality standards during 2004, 2005 and 2006 and the current
estimates for 2007, 2008 and 2009 are shown below, in each case excluding AFUDC
or capitalized interest. Substantial investments in addition to the amounts
set
forth below are expected by the System in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls in order to comply with air and water quality standards which
have been or may be adopted. Future investments could be significantly greater
if litigation regarding whether AEP properly installed emission control
equipment on its plants is resolved against any AEP subsidiaries or emissions
reduction requirements are accelerated or otherwise become more onerous or
if
CO2
becomes
regulated. 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 2006 Annual Reports, for more information regarding this litigation
and
environmental expenditures in general.
Historical
and Projected Environmental Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
|
Actual
|
|
|
Actual
|
|
|
Actual
|
|
|
Estimate
|
|
|
Estimate
|
|
|
Estimate
|
|
(in
thousands)
|
AEGCo
|
|
$
|
6,500
|
|
$
|
1,400
|
|
$
|
1,400
|
|
$
|
1,400
|
|
$
|
900
|
|
$ |
1,300
|
|
APCo
|
|
|
159,100
|
|
|
231,200
|
|
|
532,800
|
|
|
305,200
|
|
|
215,100
|
|
|
164,200
|
|
CSPCo
|
|
|
23,200
|
|
|
32,200
|
|
|
138,900
|
|
|
112,000
|
|
|
133,400
|
|
|
36,200
|
|
I&M
|
|
|
11,800
|
|
|
62,900
|
|
|
23,200
|
|
|
4,800
|
|
|
18,900
|
|
|
16,100
|
|
KPCo
|
|
|
2,700
|
|
|
13,100
|
|
|
(12,400
|
)
|
|
2,600
|
|
|
14,600
|
|
|
14,800
|
|
OPCo
|
|
|
133,000
|
|
|
458,600
|
|
|
660,800
|
|
|
498,800
|
|
|
104,500
|
|
|
30,300
|
|
PSO
|
|
|
100
|
|
|
200
|
|
|
500
|
|
|
2,500
|
|
|
12,000
|
|
|
18,300
|
|
SWEPCo
|
|
|
4,000
|
|
|
11,900
|
|
|
21,000
|
|
|
7,100
|
|
|
17,300
|
|
|
16,600
|
|
TCC
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
TNC
|
|
|
0
|
|
|
(100
|
)
|
|
0
|
|
|
700
|
|
|
4,600
|
|
|
2,800
|
|
AEP
System
|
|
$
|
340,400
|
|
$
|
811,400
|
|
$
|
1,366,200
|
|
$
|
935,100
|
|
$
|
521,300
|
|
$
|
300,600
|
|
Figures
set forth in parentheses reflect amounts invested and later expensed as a result
of project cancellation or significant delay.
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 several years 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 35,000 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 and OPCo are parties to the Interconnection Agreement
defining how they share the costs and benefits associated with their generating
plants. This sharing is based upon each company’s “member-load-ratio.” The
Interconnection Agreement has been approved by the FERC.
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 AEP East companies.
As of
December 31, 2006, the member-load-ratios were as follows:
|
Peak
Demand
(MW)
|
Member-Load
Ratio
(%)
|
APCo
|
6,943
|
30.2
|
CSPCo
|
4,425
|
19.3
|
I&M
|
4,650
|
20.3
|
KPCo
|
1,665
|
7.3
|
OPCo
|
5,260
|
22.9
|
The
Ohio
Act was enacted in 2001. To comply with that law CSPCo and OPCo functionally
separated their generation business from their remaining operations. They plan
to remain functionally separated through at least December 31, 2008 as
authorized by their rate stabilization plans approved by the PUCO. CSPCo and
OPCo have been involved in discussions with various stakeholders in Ohio about
potential legislation to address the period following the expiration of the
rate
stabilization plans. See Note 4 to the consolidated financial statements,
entitled Rate
Matters,
included in the 2006 Annual Reports, for more information.
Since
1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System
Interim Allowance Agreement (Allowance Agreement), which provides, among other
things, for the transfer of 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, 2004,
2005 and 2006:
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
(in
thousands)
|
APCo
|
|
$
|
239,400
|
|
$
|
288,000
|
|
$
|
319,500
|
|
CSPCo
|
|
|
284,900
|
|
|
285,600
|
|
|
281,700
|
|
I&M
|
|
|
(141,500
|
)
|
|
(197,400
|
)
|
|
(146,100
|
)
|
KPCo
|
|
|
31,600
|
|
|
42,200
|
|
|
38,800
|
|
OPCo
|
|
|
(414,400
|
)
|
|
(418,400
|
)
|
|
(493,900
|
)
|
PSO,
SWEPCo, and AEPSC are parties to a Restated and Amended Operating Agreement
originally dated as of January 1, 1997 (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 the business operations of TCC and TNC incompatible with the CSW Operating
Agreement. As a result, with FERC approval, these companies 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, 2004,
2005
and 2006:
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
(in
thousands)
|
PSO
|
|
$
|
55,000
|
|
$
|
27,600
|
|
$
|
(15,300
|
)
|
SWEPCo
|
|
|
(59,800
|
)
|
|
(27,500
|
)
|
|
9,900
|
|
TCC
|
|
|
1,100
|
|
|
0
|
|
|
0
|
|
TNC
|
|
|
3,700
|
|
|
(100
|
)
|
|
5,400
|
|
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. In Ohio and Virginia, such
rates
are based on a statutory formula as those jurisdictions continue to transition
to the use of market rates for generation. 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, which has been approved by the FERC, 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. The separation of the generation
business undertaken by TCC and TNC to comply with the Texas Act has also made
the business operations of TCC and TNC incompatible with the System Integration
Agreement. As a result, with FERC approval, these two companies have been
removed from this 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.
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 entering
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, 2006, counterparties and exchanges have posted approximately $156 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 $110 million with counterparties and
exchanges). Since open trading contracts are valued based on changes in market
power prices, exposures change daily.
Fuel
Supply
The
following table shows the sources of power generated by the AEP
System:
|
2004
|
2005
|
2006
|
Coal
and Lignite
|
83%
|
83%
|
85%
|
Natural
Gas
|
5%
|
6%
|
6%
|
Nuclear
|
12%
|
10%
|
9%
|
Hydroelectric
and other
|
1%
|
1%
|
<1%
|
Variations
in the generation of nuclear power are primarily related to refueling and
maintenance outages in addition to the sale of TCC’s share of a nuclear
generating unit in May 2005. Variations in the generation of natural gas power
are primarily related to the availability of cheaper alternatives to fulfill
certain power requirements and the deactivation or sale of certain gas-fired
plants owned by TCC and TNC. Price increases in one or more fuel sources
relative to other fuels generally result in increased use of other
fuels.
Coal
and Lignite:
AEP’s
public utility subsidiaries procure coal and lignite under a combination of
purchasing arrangements including long-term contracts, affiliate operations,
short-term, and spot agreements with various producers and coal trading firms.
The price for most solid fuels generally has been increasing. Management has
responded to increases in the price of coal by rebalancing the coal used in
its
generating facilities with products from different coal regions and sources
that
have different heat and sulfur contents. This rebalancing is an ongoing process
that is expected to continue,
primarily enabled by the installation of scrubbers at many of our generating
facilities.
Management believes, but cannot provide assurances, 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 or leases more than 7,000 railcars, 600 barges, 15
towboats and a coal handling terminal with 20 million tons of annual capacity
to
move and store coal for use in its generating facilities. See MEMCO 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
following table shows the amount of coal and lignite delivered to the AEP System
during the past three years and the average delivered price of spot coal
purchased by System companies:
|
2004
|
2005
|
2006
|
Total
coal delivered to AEP operated plants (thousands of tons)
|
71,778
|
75,063
|
77,897
|
Average
price per ton of purchased coal
|
$28.96
|
$32.67
|
$35.37
|
The
coal
supplies at AEP System plants vary from time to time depending on various
factors, including customers’ usage of electric power, space limitations, the
rate of consumption at particular plants, labor issues and weather conditions
which may interrupt deliveries. At December 31, 2006, the System’s coal
inventory was approximately 44 days of normal usage. This estimate assumes
that
the total supply would be utilized through the operation of plants that use
coal
most efficiently.
In
cases
of emergency or shortage, system companies have developed programs to conserve
coal supplies at their plants. Such programs have been filed and reviewed with
officials of federal and state agencies and, 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 over
104
billion
cubic
feet of natural gas during 2006 for generating power. A majority 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.
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 until it decides that deliveries
under long-term supply contracts are warranted.
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 initiated a project to study the use of dry
cask storage.
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 SNF disposal program. The estimated cost of decommissioning and disposal
of low-level radioactive waste for the Cook Plant ranges from $733 million
to
$1.3 billion in 2006 nondiscounted dollars. At December 31, 2006, the total
decommissioning trust fund balance for the Cook Plant was $974 million. 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;
|
· |
Limited
availability to date of significant experience in decommissioning
such
facilities;
|
· |
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.
See
Note
10 to the consolidated financial statements, entitled Nuclear,
included in the 2006 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 South
Carolina and Utah operate low-level radioactive waste disposal sites and
currently accept low-level radioactive waste from Michigan. I&M’s access to
the South Carolina facility is currently allowed through the end of fiscal
year
2008. There is currently no set date limiting I&M’s access to the Utah
facility.
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 and 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 2007, 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
AEGCo:
Since
its
formation in 1982, AEGCo’s business has consisted of the ownership and financing
of its 50% interest in Unit 1 of the Rockport Plant and, since 1989, its 50%
leasehold interest in Unit 2 of the Rockport Plant. Substantially all of the
operating revenues of AEGCo are derived from the sale of capacity and energy
associated with its interest in the Rockport Plant to I&M and KPCo pursuant
to unit power agreements, which have been approved by the FERC.
The
I&M Power Agreement 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 as a demand charge for the right to receive such power (and
as
an energy charge for any associated energy taken by I&M). When added to
amounts received by AEGCo from any other sources, such amounts will be at least
sufficient to enable AEGCo to pay all its operating and other expenses,
including a rate of return on the common equity of AEGCo as approved by FERC,
currently 12.16%. The I&M Power 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 which I&M would have paid AEGCo under the
terms of the I&M Power Agreement for such entitlement. The KPCo unit power
agreement expires in December 2022.
AEGCo
and
AEP have entered into a capital funds agreement pursuant to which, among other
things, AEP has unconditionally agreed to make cash capital contributions,
or in
certain circumstances subordinated loans, to AEGCo to the extent necessary
to
enable AEGCo to (i) maintain such an equity component of capitalization as
required by governmental regulatory authorities; (ii) provide its proportionate
share of the funds required to permit commercial operation of the Rockport
Plant; (iii) enable AEGCo to perform all of its obligations, covenants and
agreements under, among other things, all loan agreements, leases and related
documents to which AEGCo is or becomes a party (AEGCo Agreements); and (iv)
pay
all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations)
under
the AEGCo Agreements, other than indebtedness, obligations or liabilities owing
to AEP. The capital funds agreement will terminate after all AEGCo obligations
have been paid in full.
OVEC: AEP
and
several unaffiliated utility companies jointly own OVEC. The aggregate equity
participation of AEP in OVEC is 43.47%. Until September 1, 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 on March 12, 2026. AEP and the other owners
have
been evaluating the need for environmental investments related to their
ownership interests, which are material. In December 2006, OVEC’s Board of
Directors authorized interim capital expenditures totaling $366 million in
order
to complete detailed engineering and begin construction of flue gas
desulfurization (sulfur dioxide scrubber) projects and the associated scrubber
waste disposal landfills. If approved, the estimated total cost to complete
the
projects would be slightly in excess of $1 billion, which OVEC would expect
to
finance through issuing debt. With the expiration of that provision,
Buckeye is entitled to receive and must pay for power up to its proportionate
share of the station.
Buckeye:
On
October 1, 2004, AEP joined PJM, and the Buckeye transmission service over
the
AEP System was transferred under the PJM Open Access Transmission Tariff (OATT).
The Cardinal Station Agreement between OPCO and Buckeye contains a provision
that expired in May 2006. Under that provision, Buckeye was entitled to receive,
and was obligated to pay for, the excess of its maximum one-hour coincident
peak
demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of
the
generating units which Buckeye currently owns in the Cardinal Station. Such
demand, which occurred on July 25, 2005, was recorded at 1,434,807
kilowatts. With
the
expiration of that provision, Buckeye is entitled to receive and must pay for
power in amounts equal to its proportionate share of the
station.
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 established and approved by the
state
utility commissions of the states in which they operate, and in some instances,
approved by the FERC. See Regulation—Rates.
The
FERC regulates and approves the rates for wholesale transmission transactions.
See Item
1 - Business/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 - Business/Utility Operations - Competition.
AEP
Transmission Pool
Transmission
Equalization Agreement: APCo,
CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single
interconnected and coordinated system and are parties to the TEA, defining
how
they share the costs and benefits associated with their relative ownership
of
the extra-high-voltage transmission system (facilities rated 345kV and above)
and certain facilities operated at lower voltages (138kV up to 345kV). The
TEA
has been approved by the FERC. Sharing under the TEA 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, 2006 are set forth above in the section
titled ELECTRIC GENERATION - AEP Power Pool and CSW Operating
Agreement.
The
following table shows the net (credits) or charges allocated among the parties
to the TEA during the years ended December 31, 2004, 2005 and 2006:
|
|
2004
|
|
2005
|
|
2006
|
|
|
|
(in
thousands)
|
APCo
|
|
$
|
(500
|
)
|
$
|
8,900
|
|
$
|
(16,000
|
)
|
CSPCo
|
|
|
37,700
|
|
|
34,600
|
|
|
46,000
|
|
I&M
|
|
|
(40,800
|
)
|
|
(47,000
|
)
|
|
(37,000
|
)
|
KPCo
|
|
|
(6,100
|
)
|
|
(3,500
|
)
|
|
(2,000
|
)
|
OPCo
|
|
|
9,700
|
|
|
7,000
|
|
|
9,000
|
|
Transmission
Coordination Agreement: PSO,
SWEPCo, TCC, TNC and AEPSC are parties to the TCA. The TCA has been approved
by
the FERC and establishes a coordinating committee, which is charged with the
responsibility of (i) overseeing the coordinated planning of the transmission
facilities of the AEP West companies, 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.
Under
the
TCA, the AEP West companies have delegated to AEPSC the responsibility of
monitoring the reliability of their transmission systems and administering
the
AEP OATT on their behalf. Prior to September 2005, the TCA also provided for
the
allocation among the AEP West companies of revenues collected for transmission
and ancillary services provided under the AEP OATT. Since then, 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 among the parties
to the TCA prior to September 2005, and pursuant to the SPP OATT and ERCOT
protocols as described above during the years ended December 31, 2004, 2005
and
2006:
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
|
(in
thousands)
|
PSO
|
|
$
|
8,100
|
|
$
|
3,500
|
|
$
|
1,800
|
|
SWEPCo
|
|
|
13,800
|
|
|
5,200
|
|
|
(1,900
|
)
|
TCC
|
|
|
(12,200
|
)
|
|
(3,800
|
)
|
|
1,100
|
|
TNC
|
|
|
(9,700
|
)
|
|
(4,900
|
)
|
|
(1,000
|
)
|
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 - Business/Utility operations - 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
TEA
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
On
April
24, 1996, the FERC issued orders 888 and 889. These orders require each public
utility that owns or controls interstate transmission facilities to 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 orders also
require utilities to functionally unbundle their services, by requiring them
to
use their own tariffs in making off-system and third-party sales. As part of
the
orders, the FERC issued a pro-forma
tariff
that reflects the Commission’s views on the minimum non-price terms and
conditions for non-discriminatory transmission service. In addition, the orders
require all transmitting utilities to establish an OASIS, which electronically
posts transmission information such as available capacity and prices, and
require utilities to comply with Standards of Conduct that prohibit utilities’
system operators from providing non-public transmission information to the
utility’s merchant energy employees. The orders also allow a utility to seek
recovery of certain prudently incurred stranded costs that result from unbundled
transmission service.
In
December 1999, FERC issued Order 2000, which provides for the voluntary
formation of RTOs, entities created to operate, plan and control utility
transmission assets. Order 2000 also prescribes certain characteristics and
functions of acceptable RTO proposals. As a condition of FERC’s approval in 2000
of AEP’s merger with CSW, AEP was required to transfer functional control of its
transmission facilities to one or more RTOs. The AEP East Companies integrated
into PJM (a FERC-approved RTO) on October 1, 2004.
SWEPCo
and PSO are members of the SPP. In February 2004, the FERC conditionally
approved SPP as an RTO. In October 2004, the FERC issued an order granting
RTO
status to SPP subject to certain filings. The APSC and LPSC have
ordered the utilities in those states, including our utilities, to analyze
and
submit to them the costs and benefits of RTO options available to the utilities.
Certain states in the region have undertaken and released a study investigating
the costs and benefits of SPP developing into a RTO that administers energy
and
associated markets. On August 10, 2006, the APSC issued an order approving,
among other things, SWEPCo’s participation in SPP, subject to certain reporting
and continuing oversight conditions.
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 2006 Annual Reports under the heading entitled RTO
Formation/Integration Costs and
Transmission Rate Proceedings at the FERC
for a
discussion of public utility subsidiary participation in RTOs.
REGULATION
General
Except
for retail generation sales in Ohio, Virginia and the ERCOT area of Texas,
AEP’s
public utility subsidiaries’ retail rates and certain other matters are subject
to traditional regulation by the state utility commissions. While still
regulated, retail sales in Michigan are now made at unbundled rates. See
Item
1 - Utility Operations - Electric Restructuring and Customer Choice Legislation
and
Rates,
below.
AEP’s subsidiaries are also subject to regulation by the FERC under the FPA.
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 contains key provisions
affecting the electric power industry such as giving the FERC “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 greenhouse gases.
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 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 as part of a transition to customer choice of
generation suppliers, 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.
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. In Ohio,
rates are transitioning from bundled cost-based rates for electric service
to
unbundled cost-based rates for transmission and distribution service on the
one
hand, and market pricing for and/or customer choice of generation on the other.
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. While the historical framework remains in a portion of AEP’s
service territory, recovery of increased fuel costs through a fuel adjustment
clause is no longer provided for in Ohio.
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.
Indiana:
I&M
provides retail electric service in Indiana at bundled rates approved by the
IURC. While rates are set on a cost-of-service basis, I&M’s base rates are
capped through June 30, 2007. Its fuel recovery rate is capped through that
time
period at a level that automatically increased in January 2006 and January
2007.
I&M expects, however, that its actual fuel costs will exceed the capped fuel
rates permitted through June 30, 2007.
Ohio:
CSPCo
and
OPCo each operated as a functionally separated utility and provided “default”
retail electric service to customers at unbundled rates pursuant to the Ohio
Act
through December 31, 2006. The PUCO approved the rate stabilization plans filed
by CSPCo and OPCo (which, among other things, address default retail generation
service rates from January 1, 2006 through December 31, 2008). The
Ohio
Supreme Court vacated and remanded
the
PUCO’s approval of the rate stabilization plans. In response, the PUCO issued an
order requiring CSPCo and OPCo to make additional filings and holding that
their
rate stabilization plans remained in effect. CSPCo and OPCo have submitted
proposals with the PUCO addressing the matters identified by the PUCO. Retail
generation rates will be determined consistent with the rate stabilization
plan
until December 31, 2008. CSPCo and OPCo are providing and will continue to
provide distribution services to retail customers at rates approved by the
PUCO.
These rates will be frozen (with certain exceptions, including automatic annual
increases in generation rates of 3% and 7% for CSPCo and OPCo, respectively)
from their levels as of December 31, 2005 through December 31, 2008.
Transmission services will continue to be provided at rates established by
the
FERC. CSPCo and OPCo have been involved in discussions with various stakeholders
in Ohio about potential legislation to address the period following the
expiration of the rate stabilization plans. See Note 4 to the consolidated
financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports, for more information.
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 the amount included in base rates are recovered 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 when new annual factors are established. In November
2006, PSO filed a request with the OCC seeking an increase in base rates and
other rate relief. The OCC has not yet ruled on this filing. See Note 4 to
the
consolidated financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports, for information regarding current rate
proceedings.
Texas: TCC
has
sold all of its generation assets and TNC has transferred its active generation
capacity to a non-utility affiliate pursuant to a 20-year agreement. TCC and
TNC
serve most of their retail customers in the ERCOT area of Texas through
non-affiliated REPs. TCC and TNC provide retail 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. In November 2006, TCC and TNC filed requests with the PUCT seeking
increases in the rates charged to REPs for delivering electricity over their
transmission and distribution lines. The PUCT has not ruled on the filings.
See
Note 4 to the consolidated financial statements, entitled Rate
Matters included
in the 2006 Annual Reports, for information on current rate proceedings. In
August 2006, the PUCT delayed competition in the SPP area of Texas until at
least January 1, 2011. As such, SWEPCo’s Texas operations continue to operate
and to be regulated as a traditional bundled utility with both base and fuel
rates.
Virginia: APCo
provides retail electric service in Virginia at unbundled rates. In February
2007, the Virginia legislature adopted amendments to its previously-enacted
electric restructuring law. The amendments would cut two years off of the
transition period (from 2010 to 2008) after which rates for retail generation
supply would return to a form of cost-based regulation. The Governor of Virginia
has not yet signed this legislation. APCo’s unbundled generation, transmission
(which reflect FERC-approved transmission rates) and distribution rates, as
well
as its functional separation plan, were approved by the VSCC in December 2001.
APCO’s base rates are capped at their mid-1999 levels until the end of the
transition period (now December 31, 2010), or sooner if the VSCC finds that
a
competitive market for generation exists in Virginia, but APCo is permitted
to
seek two changes to its capped rates through December 31, 2010. In addition,
APCo is entitled to annual rate changes to recover the incremental costs it
incurs for transmission and distribution reliability and compliance with state
or federal environmental laws or regulations. In May 2006, APCo filed a request
with the VSCC seeking an increase in base rates. Hearings on this request were
held in December 2006. APCo expects a ruling in 2007. APCo is entitled to
adjustments to fuel rates through 2010 to recover its actual fuel costs, the
fuel component of its purchased power costs and certain capacity charges. APCo
recovers its generation capacity charges through capped base rates. In November
2006, the VSCC approved APCo’s previous request to recover additional
environmental and reliability-related costs. See Note 4 to the consolidated
financial statements, entitled Rate
Matters,
included in the 2006 Annual Reports, for additional information on these
matters.
West
Virginia:
APCo
and
WPCo provide retail electric service at bundled rates approved by the WVPSC.
West Virginia generally allows for timely recovery of fuel costs. In July 2006,
the WVPSC approved an increase in the retail rates of APCo and WPCo and the
reactivation of their suspended operative fuel clause and other recovery
mechanisms. See Note 4 to the consolidated financial statements, entitled
Rate
Matters,
included in the 2006 Annual Reports, for additional information on current
rate
proceedings.
Other
Jurisdictions:
The
public utility subsidiaries of AEP also provide service at regulated bundled
rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled
rates in Michigan.
The
following table illustrates the current rate regulation status of the states
in
which the public utility subsidiaries of AEP operate:
|
|
|
|
|
|
Fuel
Clause Rates(6)
|
|
|
|
|
|
|
|
|
|
|
Off-System
Sales Profits
|
|
Percentage
of AEP
System
|
|
|
Status
of Base Rates for
|
|
|
|
Shared
with
|
|
Retail
|
Jurisdiction
|
|
Power
Supply
|
|
Energy
Delivery
|
|
Status
|
|
Ratepayers
|
|
Revenues(1)
|
|
|
|
|
|
|
|
|
|
|
|
Ohio
|
|
See
footnote 2
|
|
Distribution
frozen through 2008(2)
|
|
None
|
|
Not
applicable
|
|
32%
|
|
|
|
|
|
|
|
|
|
|
|
Oklahoma
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes
|
|
14%
|
|
|
|
|
|
|
|
|
|
|
|
Texas
ERCOT
|
|
Not
applicable (3)
|
|
Not
capped or frozen
|
|
Not
applicable
|
|
Not
applicable
|
|
7%
|
|
|
|
|
|
|
|
|
|
|
|
Texas
SPP
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes
|
|
5%
|
|
|
|
|
|
|
|
|
|
|
|
Indiana
|
|
Capped
until 6/30/07
|
|
Capped
until 6/30/07
|
|
Capped
until 6/30/07 (4)
|
|
No
|
|
10%
|
|
|
|
|
|
|
|
|
|
|
|
Virginia
|
|
Capped
until as late as 12/31/10(5)
|
|
Capped
until as late as 12/31/10(5)
|
|
Active
|
|
No
|
|
9%
|
|
|
|
|
|
|
|
|
|
|
|
West
Virginia
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
No
|
|
9%
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
above base levels
|
|
4%
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
above and below base levels
|
|
4%
|
|
|
|
|
|
|
|
|
|
|
|
Arkansas
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
above base levels
|
|
3%
|
|
|
|
|
|
|
|
|
|
|
|
Michigan
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
Yes,
in some areas
|
|
2%
|
|
|
|
|
|
|
|
|
|
|
|
Tennessee
|
|
Not
capped or frozen
|
|
Not
capped or frozen
|
|
Active
|
|
No
|
|
1%
|
(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,
2006.
|
|
|
(2)
|
The
PUCO has approved the rate stabilization plan filed by CSPCo and
OPCo that
began after the market development period and extends through December
31,
2008 during which OPCo’s retail generation rates will increase 7% annually
and CSPCo’s retail generation rates will increase 3% annually.
Distribution rates are frozen, with certain exceptions, through December
31, 2008. The rate stabilization plans have been the subject of
litigation. At the PUCO’s request, CSPCo and OPCo have submitted proposals
addressing those matters identified by the commission.
See Note 4 to the Consolidated Financial Statements, entitled Rate
Matters.
|
|
|
(3)
|
TCC
and TNC are no longer in the retail generation supply business. Retail
electric service in the ERCOT area of Texas is provided to most customers
through unaffiliated REPs with TCC and TNC providing only regulated
delivery services. SWEPCo and an affiliated REP provide retail electric
service in the SPP area of Texas. All customers of the affiliated
REP were
transferred to SWEPCo with the first billing cycle in February
2007.
|
|
|
(4)
|
Fuel
rates capped through June 2007 billing month subject to certain events
at
the Cook Plant.
|
|
|
(5)
|
Legislation
passed in 2004 capped base rates until December 31, 2010 and expanded
the
rate change opportunities to one full rate case (including generation,
transmission and distribution) between July 1, 2004 and June 30,
2007
(which has been filed) and one additional full rate case between
July 1,
2007 and December 31, 2010. The law also permits APCo to recover,
on a
timely basis, incremental costs incurred on and after July 1, 2004
for
transmission and distribution reliability purposes and to comply
with
state and federal environmental laws and regulations. In
February 2007, the Virginia legislature adopted amendments to its
previously-enacted electric restructuring law. The amendments would
cut
two years off of the transition period (from 2010 to 2008) after
which
rates for retail generation supply would return to a form of cost-based
regulation. The Governor of Virginia has not yet signed this legislation.
|
|
|
(6)
|
Includes,
where applicable, fuel and fuel portion of purchased
power.
|
FERC
Under
the
FPA, FERC regulates rates for interstate sales at wholesale, transmission of
electric power, accounting and other matters, including construction and
operation of hydroelectric projects. FERC regulations require AEP to provide
open access transmission service at FERC-approved rates. FERC also regulates
unbundled transmission service to retail customers. 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 FERC, under which much of its
wholesale marketing activity takes place.
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 FERC and state regulators are permitted
to
review the books and records of any company within a holding company system.
EPACT gives the FERC “backstop” transmission siting authority as well as
increased utility merger oversight.
ELECTRIC
RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION
Certain
states in AEP’s service area have adopted restructuring or customer choice
legislation. In general, this legislation provides for a transition from bundled
cost-based rate regulated electric service to unbundled cost-based rates for
transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier. At a minimum, this legislation
allows retail customers to select alternative generation suppliers. Electric
restructuring and/or customer choice began on January 1, 2001 in Ohio and on
January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric
restructuring in the SPP area of Texas has been delayed by the PUCT until at
least 2011. AEP’s public utility subsidiaries operate in both the ERCOT and SPP
areas of Texas. See Note 4 to the consolidated financial statements entitled
Rate
Matters for
additional information.
Ohio
Restructuring
The
Ohio
Act requires vertically integrated electric utility companies that are in the
business of providing competitive retail electric service in Ohio to separate
their generating functions from their transmission and distribution functions.
Following the market development period (which ended December 31, 2005), retail
customers receive distribution and, where applicable, transmission service
from
the incumbent utility whose distribution rates are approved by the PUCO and
whose transmission rates are based on rates established by the FERC. The PUCO
approved CSPCo’s and OPCo’s rate stabilization plans that, among other things,
addressed default generation service rates from January 1, 2006 through December
31, 2008. See Item
1 - Utility Operations - Regulation—FERC for
a
discussion of FERC regulation of transmission rates, Regulation—Rates—Ohio
and
Note
4 to the consolidated financial statements entitled
Rate
Matters,
included in the 2006 Annual Reports,
for
a
discussion of the impact of restructuring on distribution rates. The PUCO
authorized CSPCo and OPCo to remain functionally separated through the end
of
that three-year period. The Supreme Court of Ohio vacated and remanded the
PUCO’s order authorizing the rate stabilization plans. In response, the PUCO
issued an order in August 2006 requiring CSPCo and OPCo to make additional
filings and holding that the rate stabilization plans remained in effect. CSPCo
and OPCo have submitted proposals with the PUCO addressing the matters
identified by the PUCO. CSPCo and OPCo have been involved in discussions with
various stakeholders in Ohio about potential legislation to address the period
following the expiration of the rate stabilization plans.
Texas
Restructuring
Signed
into law in June of 1999, the Texas Act substantially amended the regulatory
structure governing electric utilities in Texas in order to allow retail
electric competition for customers. Among other things, the Texas
Act:
|
·
|
gave
Texas customers the opportunity to choose their REP beginning January
1,
2002 (delayed until at least 2011 in the SPP portion of
Texas),
|
|
·
|
required
each utility to legally separate into a REP, a power generation company,
and a transmission and distribution utility,
and
|
|
·
|
required
that REPs provide electricity at generally unregulated rates, except
that
until January 1, 2007 the prices that may be charged to residential
and
small commercial customers by REPs affiliated with a utility within
the
affiliated utility’s service area are set by the PUCT, until certain
conditions in the Texas Act are met.
|
The
Texas
Act provides each affected utility an opportunity to recover its generation
related regulatory assets and stranded costs resulting from the legal separation
of the transmission and distribution utility from the generation facilities
and
the related introduction of retail electric competition. Regulatory assets
consist of the Texas jurisdictional amount of generation-related regulatory
assets and liabilities in the audited financial statements as of December 31,
1998. Stranded costs consist of the positive excess of the net regulated book
value of generation assets (as of December 31, 2001) over the market value
of
those assets, taking specified factors into account, as ultimately determined
in
a PUCT true-up proceeding.
In
May
2005, TCC filed its stranded cost quantification application, or true-up
proceeding,
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. Other parties
have
appealed the PUCT’s final order as unwarranted or too large; TCC has appealed
seeking additional recovery consistent with the Texas Act and related rules.
In
a preliminary ruling filed in February 2007, the Texas state district court
adjudicating the appeal of the final order in the true-up proceeding found
that
the PUCT erred in several respects, including the method used to determine
stranded costs and the awarding of certain carrying costs. Following the
preliminary ruling, the court granted a rehearing of the issue regarding the
method to determine stranded costs. That rehearing is scheduled for late March
2007. TCC intends to appeal any final adverse rulings regarding the PUCT’s order
in the true-up proceedings.
After
PUCT approval, in October 2006 TCC issued $1.74 billion of securitization bonds,
including additional issuance and carrying costs through the date of issuance.
The PUCT authorized negative competition transition charges in the amount of
$356 million in October 2006. TCC is required to refund this amount to its
ratepayers. For
a
discussion of (i) regulatory assets and stranded costs subject to recovery
by
TCC and (ii) rate adjustments made after implementation of restructuring to
allow recovery of certain costs by or with respect to TCC and TNC, see Note
4 to
the consolidated financial statements entitled Rate
Matters
included
in the 2006 Annual Reports.
Michigan
Customer Choice
Customer
choice commenced for I&M’s Michigan customers on January 1, 2002. Rates for
retail electric service for I&M’s Michigan customers were unbundled (though
they continue to be regulated) to allow customers the ability to evaluate the
cost of generation service for comparison with other suppliers. At December
31,
2006, none of I&M’s Michigan customers have elected to change suppliers and
no alternative electric suppliers are registered to compete in I&M’s
Michigan service territory.
Virginia
Restructuring
In
April
2004, the Governor of Virginia signed legislation that extends the transition
period for electricity restructuring, including capped rates, through December
31, 2010. The legislation provides specified cost recovery opportunities during
the capped rate period, including two optional general base rate changes and
an
opportunity for timely recovery, through a separate rate mechanism, of certain
incremental environmental and reliability costs incurred on and after July
1,
2004. In
February 2007, the Virginia legislature adopted amendments to its
previously-enacted electric restructuring law. The amendments would cut two
years off of the transition period (from 2010 to 2008) after which rates for
retail generation supply would return to a form of cost-based regulation. The
Governor of Virginia has not yet signed this legislation.
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 in recent years 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 the various state
commissions. Occasionally, these rates are first negotiated, and then filed
with
the state commissions. The public utility subsidiaries of AEP believe that
they
are unlikely to be materially adversely affected by this
competition.
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.
MEMCO
OPERATIONS
Our
MEMCO
business 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 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 have also served AEP utility subsidiary
affiliates. 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. The MEMCO operations include
approximately 2,038 barges, 37 towboats and 10 harbor boats that we own or
lease.
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. Since
1980, the industry has experienced 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 business segment consists of non-utility generating
assets and as of January 2007, a competitive power supply and energy trading
business. We enter into short and long-term transactions to buy or sell
capacity, energy, and ancillary services primarily in the ERCOT market. The
assets utilized in this segment include approximately 791 MW of domestic wind
power and gas-fired generation facilities (of which AEP ownership is
approximately 551 MW) and, since January 2007, 377 MW of coal-fired capacity
obtained from TNC’s interest in the Oklaunion power station. TNC has entered
into a 20-year power agreement transferring this generating capacity to a
non-utility affiliate that we operate in order to comply with the separation
requirements of the Texas Act. The power obtained from the Oklaunion power
station is to be 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.
OTHER
Gas
Operations
In
January 2005, we sold a 98% controlling interest in HPL and related assets
with
the remaining 2% interest being sold to the buyer in November 2005. See Note
8
to the consolidated financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments, and Assets Held for
Sale,
included in the 2006 Annual Reports for more information. As a result,
management anticipates that our gas marketing operations will be limited to
managing our obligations with respect to the gas transactions entered into
before these sales.
Plaquemine
Cogeneration Facility
Pursuant
to an agreement with Dow, AEP constructed an 880 MW cogeneration facility
(“Facility”)
at
Dow’s
chemical facility in Plaquemine, Louisiana that achieved commercial operation
status in 2004. Dow
used
a portion of the energy produced by the Facility and sold the excess power
to
us. We agreed to sell up to all of the excess 800 MW to Tractebel.
That power agreement is currently being litigated. See Note 6 to the
consolidated financial statements entitled Commitments,
Guarantees and Contingencies.
In
November 2006, we sold our interest in the Facility to Dow. Negotiations for
the
sale resulted in an after-tax impairment of approximately $136 million. See
Note
8 to the consolidated financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments and Assets Held for Sale.
For
information regarding other non-core investments, see Note 8 to the consolidated
financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments and Assets Held for Sale,
included
in the 2006 Annual Reports.
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. Many 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.
Our
request for rate recovery of additional costs may not be approved in
Virginia. (Applies
to AEP and APCo.)
APCo
filed a request with the VSCC in May 2006 seeking a net increase in base rates
of $198 million to recover increasing costs, including a return on equity of
11.5%. APCo also requested to apply its off-system sales margins (currently
credited to customers through base rates) to the fuel factor where they can
be
adjusted annually. APCo also requested to retain a portion of the off-system
sales margins. In May 2006, the VSCC issued an order placing the net requested
base rate increase into effect as of October 2, 2006, subject to refund. In
October 2006, the VSCC staff filed direct testimony recommending a base rate
increase of $13 million with a return on equity of 9.9% and no off-system sales
margin sharing. Other intervenors have recommended base rate increases ranging
from $42 million to $112 million. APCo has filed rebuttal testimony and hearings
were held in December 2006. If the VSCC denies the
requested rate recovery, it could adversely impact future results of operations
and cash flows.
Our
request for rate recovery of additional costs may not be approved in
Texas. (Applies
to AEP, TCC and TNC.)
TCC
and
TNC have filed requests with the PUCT to increase their transmission and
distribution rates. The rate requests include the amounts charged for the
delivery of electricity over TCC´s and TNC´s transmission and distribution
lines. TCC is seeking approval of an $81 million increase, which includes the
expiration of $20 million in billing credits that the PUCT required in approving
the merger of CSW into AEP. The credits have been in place since 2000. TNC
is
seeking approval of a $25 million increase, which includes the expiration of
$6.2 million in billing credits. TCC and TNC are requesting a return on equity
of 11.25% with a capital structure of approximately 60% debt/40% equity. If
the
PUCT denies the
requested rate recovery, it could adversely impact future results of operations
and cash flows.
Our
request for rate recovery of additional costs may not be approved in
Oklahoma. (Applies
to AEP and PSO.)
PSO
filed
a request with the OCC in November, 2006 seeking approval of a $50 million
overall increase in base rates, an annually adjusted rate mechanism to recover
the expected significant investment PSO will be making in new facilities,
several new and restructured tariffs to allow PSO to begin to reduce the
relationship between its revenues and its sales volumes, and to implement some
demand side management tariffs. PSO´s planned investments over the next five
years include new generation facilities ($1.12 billion), new and refurbished
transmission substations and lines ($302 million) and new distribution lines
and
equipment ($582 million). If the OCC denies the
requested rate recovery, it could adversely impact future results of operations
and cash flows.
We
may not be able to recover all of our fuel costs in Indiana.
(Applies
to AEP and I&M.)
I&M
entered into a settlement agreement which the IURC approved
in 2005. The
approved settlement caps fuel rates through June 2007 at increasing rates during
agreed-upon intervals. I&M has experienced a cumulative under-recovery of
fuel costs through December 2006. If future fuel costs through June 30, 2007
continue to exceed the agreed-upon caps, future results of operations and cash
flows would be adversely affected.
The
rates that SWEPCo may charge its customers may be reduced.
(Applies to SWEPCo.)
At
the
time of the CSW merger, SWEPCO agreed to file with the LPSC detailed financial
information typically utilized in a revenue requirement filing on a periodic
basis in order to demonstrate the lack of adverse impact from the merger. The
first such filing was in October 2002 and the second was in April 2004. Both
filings indicated SWEPCo’s rates should not be reduced. In April 2006, the LPSC
and SWEPCo agreed to update the financial information based on a 2005 test
year.
SWEPCo filed financial review schedules in May 2006 showing a return on equity
of 9.44% compared to the previously authorized return on equity of 11.1%. In
July 2006, consultants to the LPSC staff filed direct testimony recommending
a
base rate reduction in the range of $12 million to $20 million for SWEPCo’s
Louisiana jurisdiction customers, which included a 10% return on equity. The
recommended reduction range is subject to SWEPCo validating certain on-going
operations and maintenance expense levels and the recommended base rate
reduction does not include the impact of a proposed consolidated federal income
tax adjustment, which would increase the proposed rate reduction. SWEPCo filed
rebuttal testimony in October 2006 refuting the consultants’ recommendations. In
December 2006, the LPSC staff’s consultants filed reply testimony asserting that
SWEPCo’s Louisiana base rates are excessive by $17 million which includes a
proposed return on equity of 9.8%. SWEPCo filed testimony in the first quarter
of 2007. Hearings are expected to occur in early 2007. A decision is expected
in
mid-to-late 2007. At this time, management is unable to predict the outcome
of
this proceeding. If a rate reduction were ultimately ordered, it would adversely
impact future results of operations and cash flows.
The
amount that PSO
seeks to recover for fuel costs is currently being
reviewed. (Applies
to PSO.)
In
2002,
PSO experienced a $44 million under-recovery of fuel costs resulting from a
reallocation among AEP West companies of purchased power costs for periods
prior
to January 1, 2002. In July 2003, PSO filed with the OCC offering to collect
the
under-recovery over 18 months. An intervenor, the staff of the OCC and the
Attorney General of Oklahoma have made filings indicating that recovery should
be reduced substantially or disallowed altogether. These filings disputed the
allocation of AEP System off-system sales margins pursuant to an agreement
approved by FERC. In September 2003, the OCC expanded the case to include a
full
review of PSO’s 2001 fuel and purchased power practices. The allocation issue
was referred to an ALJ. The ALJ recommended that the OCC lacks authority to
examine whether PSO deviated from the FERC allocation methodology and that
any
such complaints should be addressed at the FERC. The OCC conducted a hearing
on
the jurisdictional matter in January 2005 but has not issued a decision.
If
the
OCC determines, as a result of the review, that a portion of PSO’s fuel and
purchased power costs should not be recovered, there could be an adverse effect
on PSO’s results of operations, cash flows and possibly financial condition.
The
internal allocation of AEP System off-system sales margins has been challenged.
(Applies
to APCo, CSPCo, I&M, KPCo and OPCo.)
Off-system
sales margins are allocated among the AEP System companies pursuant to a
FERC-approved agreement among those companies entered into at the time of the
merger with CSW. In November 2005, we filed with the FERC a proposed allocation
methodology to be used in 2006 and beyond. The original allocations have been
challenged in different forums, including PSO’s fuel clause recovery proceeding
before the OCC. In general, the challenges assert that AEP West companies,
acquired in the merger with CSW, are being allocated a disproportionately small
amount of the off-system sales margins. An ALJ in the OCC proceeding and,
separately, a federal district court in Texas have each held that the FERC
is
the only appropriate adjudicator of such challenges. This holding has been
affirmed by a federal appellate court. No proceeding questioning the allocation
of our off-system sales is currently before the FERC; the OCC, however, has
yet
to rule on whether it has jurisdiction over this issue. If the FERC or another
entity of competent authority were to retroactively allocate additional
off-system sales margins to the AEP West companies, the AEP East companies
may
be required to pay money to the AEP West companies. Any such payments
could
have an adverse effect on the results of operations, cash flows and possibly
financial condition of the AEP
East
companies.
The
base rates that certain of our utilities charge are currently capped or
frozen.
(Applies to AEP, CSPCo, I&M and OPCo.)
Base
rates charged to customers in Michigan and Ohio are currently either frozen
or
capped. To the extent our costs in these states exceed the applicable cap or
frozen rate, those costs are not recoverable from customers.
Certain
of our revenues and results of operations are subject to risks that are beyond
our control. (Applies
to each registrant.)
Unless
mitigated by timely and adequate regulatory recovery, the cost of repairing
damage to our utility facilities due to storms, natural disasters, wars,
terrorist acts and other catastrophic events, in excess of insurance coverage,
when applicable, may adversely impact our revenues, operating and capital
expenses and results of operations. Such events may also create additional
risks
related to the supply and/or cost of equipment and materials.
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 2,143 MW, or 6% of our generation capacity. 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 a 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 transmission regulatory 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
regulatory structures in various regional power markets. Problems or delays
that
may arise in the operation of new regional transmission organization (RTO)
power
markets, may restrict our ability to sell power produced by our generating
capacity to certain markets if there is insufficient transmission capacity
available to fully support market operation. The rules governing the various
regional power markets may also change from time to time which could affect
our
costs or revenues. Because it remains unclear which companies will be
participating in the various regional power markets, or the manner in which
RTOs
will evolve or the regions they will cover, we are unable to assess fully the
impact that these power markets may have on our business.
AEP
East
companies joined PJM on October 1, 2004. SWEPCo and PSO are members of SPP.
In
February 2004, FERC granted RTO status to SPP, subject to fulfilling specified
requirements. In October 2004, the FERC issued an order granting final RTO
status to SPP subject to certain filings.
The
LPSC
has ordered the utilities subject to its jurisdiction, including SWEPCo, to
analyze and submit to them the costs and benefits of RTO options available
to
the utilities. Certain states in the region have undertaken and released a
study
investigating the costs and benefits of SPP developing into a RTO that
administers energy and associated markets.
To
the
extent we are faced with conflicting state and Federal requirements as to our
participation in RTOs, it could adversely affect our ability to operate and
recover transmission costs from retail customers. Management is unable to
predict the outcome of these transmission regulatory actions and proceedings
or
their impact on the timing and operation of RTOs, our transmission operations
or
future results of operations and cash flows.
The
amount we charged third parties for using our transmission facilities has been
reduced, is subject to refund and may not be completely restored in the
future. (Applies
to AEP and AEP
East companies.)
In
July
2003, the FERC issued an order directing PJM and the 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. The elimination of the T&O rates
reduces the transmission service revenues collected by the RTOs and thereby
reduces the revenues received by transmission owners under the RTOs’ revenue
distribution protocols. 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.
Intervenors objected to this decision; therefore the SECA fees we collected
($220
million) are
subject to refund. Approximately
$19 million of the SECA revenues that we billed were never collected. The AEP
East zone public utilities filed a motion with the FERC to force payment of
these SECA billings.
A
hearing
was held in May 2006 to determine whether any of the SECA revenues should be
refunded. In August 2006, the ALJ issued an initial decision, finding that
the
rate design for the recovery of SECA charges was flawed and that a large portion
of the “lost revenues” reflected in the SECA rates were not recoverable. The ALJ
found that the SECA rates charged were unfair, unjust and discriminatory, and
that new compliance filings and refunds should be made. The ALJ also found
that
unpaid SECA rates must be paid in the recommended reduced amount. The FERC
has
not ruled on the matter. If the FERC upholds the decision of the ALJ, up to
$126
million of collected SECA rates could be refunded by the AEP East zone public
utilities. We have recorded provisions in the aggregate amount of $37 million
related to the potential refund of SECA rates pending settlement negotiations
with various intervenors.
SECA
transition rates expired at the end of March 2006
and did
not fully compensate AEP for ongoing lost T&O revenues.
As a
result of rate relief in certain jurisdictions, however, approximately 85%
of
the ongoing
lost T&O revenues
are now
being recovered from native load customers of AEP East companies in those
jurisdictions.
The
portion attributable to Virginia is being collected subject to
refund.
In
addition to seeking retail rate recovery from native load customers in the
applicable states, AEP and another member of PJM have filed an application
with
the FERC seeking compensation from other unaffiliated members of PJM for the
costs associated with those members’ use of our respective transmission assets.
A
majority of PJM members have filed in opposition to the proposal. Hearings
were
held in April 2006. An ALJ recommended a rate design that would result in
greater recovery for AEP than the proposal AEP had submitted. The ALJ also
recommended, however, that the design be phased-in, which could limit the amount
of recovery for AEP. The FERC has not yet ruled on this matter. Management
cannot at this time estimate the outcome of these proceedings.
Rate
regulation may delay or deny full recovery of 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. Additionally, there may also be a delay between the timing of when
these costs are incurred and when these costs are recovered. While rate
regulation is premised on providing a reasonable opportunity to earn a
reasonable rate of return on invested capital, there can be no assurance 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.
We
operate in a non-uniform and fluid regulatory environment.
(Applies to each registrant.)
In
addition to the multiple levels of state regulation at the states in which
we
operate, our business is subject to extensive federal regulation. There can
be
no assurance that (1) the federal legislative and regulatory initiatives (which
have occurred over the past few years and which have generally facilitated
competition in the energy sector) will continue or will not be reversed or
(2)
state regulation will not become significantly more restrictive. Further
alteration of the regulatory landscape in which we operate will impact the
effectiveness of our business plan and may, because of the continued
uncertainty, harm our financial condition and results of
operations.
At
times, demand for power could exceed our supply capacity.
(Applies to each registrant other than TCC and TNC.)
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. We may not always have
the
ability to pass these costs on to our customers because some of the states
we
operate in do not allow us to increase our rates in response to increased fuel
cost charges. 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
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 other than AEGCo.)
Following
the bankruptcy of Enron, the credit ratings agencies initiated a thorough review
of the capital structure and the quality and stability of earnings of energy
companies, including us. The agencies revised ratings at that time. Further
negative ratings actions could constrain the capital available to our industry
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. 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.
If
Moody’s or S&P
were
to
downgrade the long-term rating of any of the registrants,
particularly below investment grade, the borrowing costs of that registrant
would increase, which would diminish its financial results. In addition, the
registrant’s potential pool of investors and funding sources could
decrease.
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.
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 would be subject to regulatory or contractual
restrictions.
Our
operating results may fluctuate on a seasonal and quarterly
basis.
(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.
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.
Changes
in commodity prices 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
heavily exposed to changes in the price and availability of 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 heavily
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 our
projected needs for the next two years and for much of the projected needs
for
periods beyond that. At some point, however, we may have to obtain additional
allowances and 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.
The
price
trends for coal, natural gas and emission allowances have shown material
increases 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, the prices we can charge our retail
customers in some jurisdictions are capped.
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.
In
certain jurisdictions, we have limited ability to pass on our fuel costs to
our
customers.
(Applies to AEP, CSPCo, I&M and OPCo.)
We
are
exposed to risk from changes in the market prices of coal, natural gas, and
emissions allowances used to generate power where generation is no longer
regulated or where existing fuel clauses are suspended or frozen. The prices
of
coal, natural gas and emissions allowances have increased materially in the
recent past. The protection afforded by retail fuel clause recovery mechanisms
has been eliminated by the implementation of customer choice in Ohio, which
represents approximately 20% of our fuel costs. Because the risk of generating
costs cannot be passed through to customers as a matter of right in Ohio, we
retain these risks. We also have a fuel cap in Indiana that may not allow us
to
fully recover our fuel costs there. If we cannot recover an amount sufficient
to
cover our actual fuel costs, our results of operations and cash flows would
be
adversely affected.
We
are exposed to losses resulting from the bankruptcy of Enron
Corp.
(Applies to AEP.)
On
June
1, 2001, we purchased Houston Pipe Line Company (“HPL”) from Enron Corp.
(“Enron”). Later that year, Enron and its subsidiaries filed bankruptcy
proceedings in the U.S. Bankruptcy Court for the Southern District of New York.
Various HPL related contingencies and indemnities from Enron remained unsettled
at the date of Enron’s bankruptcy. In
connection with the 2001 acquisition of HPL, we entered into an agreement with
BAM Lease Company, which granted HPL the exclusive right to use approximately
65
BCF of cushion gas required for the normal operation of the Bammel gas storage
facility. At the time of our acquisition of HPL, Bank of America (“BOA”) and
certain other banks (together with BOA, “BOA Syndicate”) and Enron entered into
an agreement granting HPL the exclusive use of 65 BCF of cushion gas.
Additionally, Enron and the BOA Syndicate released HPL from all prior and future
liabilities and obligations in connection with the financing arrangement.
After
the
Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default
by Enron under the terms of the financing arrangement. We purchased 10 BCF
of
gas from Enron and are currently litigating the rights to the remaining 55
BCF
of cushion gas.
In
February 2004, in connection with BOA’s dispute, Enron filed Notices of
Rejection regarding the cushion gas use agreement and other incidental
agreements. We have objected to Enron’s attempted rejection of these agreements.
In 2005 we sold HPL, including the Bammel gas storage facility. We indemnified
the purchaser for damages, if any, arising from the litigation with BOA. The
case in federal court in Texas is set for trial beginning April 2007.
Management
is unable to predict the final resolution of these disputes, however the impact
on results of operations, cash flows and financial condition could be
material.
Risks
Relating To State Restructuring
In
Ohio, our costs may not be recovered and rates may be reduced.
(Applies
to AEP, OPCo and CSPCo)
In
January 2005, the PUCO approved rate stabilization plans (“RSPs”) for CSPCo and
OPCo. The RSPs provide, among other things, for CSPCo and OPCo to raise their
generation rates on an annual basis through 2008 by 3% and 7%, respectively.
The
RSPs also provide for possible additional annual generation rate increases
of up
to an average of 4% per year for specified costs. The RSPs also provide that
CSPCo and OPCo can recover certain environmental carrying costs, PJM-related
administrative costs and certain congestion costs. In 2006, CSPCo and OPCo
collected an additional estimated $244 million in gross margin as a result
of
the RSPs. This amount is expected to increase in 2007 and 2008.
In
2005,
the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that
challenged the validity of the RSPs under Ohio’s electricity restructuring law.
In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP orders for CSPCo and
OPCo and remanded the case to the PUCO for further proceedings.
In
August
2006, the PUCO directed CSPCo and OPCo to file a plan providing an option for
customer participation in the electric market through competitive bids or other
reasonable means. The PUCO also held that the RSPs shall remain effective.
Accordingly, the Ohio companies continued collecting RSP revenues. In September
2006, CSPCo and OPCo submitted their proposals to provide additional options
for
customer participation in the electric market. If the PUCO were to reverse
or
limit the RSPs, our results of operations and cash flows could be adversely
affected.
Some
laws and regulations governing restructuring in Virginia have not yet been
interpreted or adopted and could harm our business, operating results and
financial condition.
(Applies to AEP and APCo.)
Virginia
restructuring legislation was enacted in 1999 providing for retail choice of
generation suppliers to be phased in over two years beginning January 1,
2002. It required jurisdictional utilities to unbundle their power supply and
energy delivery rates and to file functional separation plans by January 1,
2002. APCo filed its plan with the VSCC and, following VSCC approval of a
settlement agreement, now operates in Virginia as a functionally separated
electric utility charging unbundled rates for its retail sales of electricity.
The settlement agreement addressed functional separation, leaving decisions
related to legal separation for later VSCC consideration. While the electric
restructuring law in Virginia established the general framework governing the
retail electric market, it required the VSCC to issue rules and determinations
implementing the law. Some of the regulations governing the retail electric
market have not yet been adopted by the VSCC. When the regulations are developed
and adopted, compliance with them may harm our business, results of operations
and financial condition. In
February 2007, the Virginia legislature adopted amendments to its electric
restructuring law. The amendments would cut two years off of the transition
period (from 2010 to 2008) after which rates for retail generation supply would
return to a form of cost-based regulation. The Governor of Virginia has not
yet
signed this legislation.
There
is uncertainty as to our recovery of stranded costs resulting from industry
restructuring in Texas.
(Applies to AEP and TCC.)
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 the
generation assets of TCC 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 Act
and related rules, other parties have appealed the PUCT’s final order as
unwarranted or too large. In a preliminary ruling filed in February 2007, the
Texas state district court adjudicating the appeal of the final order in the
true-up proceeding found that the PUCT erred in several respects, including
the
method used to determine stranded costs and the awarding of certain carrying
costs. Following the preliminary ruling, the court granted a rehearing of the
issue regarding the method to determine stranded costs. That rehearing is
scheduled for late March 2007. TCC intends to appeal any final adverse rulings
regarding the PUCT’s order in the true-up proceeding. If
the
district court judge’s preliminary determination that TCC used an improper
method to value its stranded costs is ultimately upheld on appeal, it could
substantially reduce TCC’s stranded costs. We cannot estimate the amount of any
potential impact at this time, but it could exceed TCC’s common shareholder’s
equity at December 31, 2006. Any reduction of the recovery authorized in the
PUCT’s order could have a material adverse effect on results of operations, cash
flows and possibly financial condition.
Collection
of our revenues in Texas is concentrated in a limited number of
REPs. (Applies
to AEP, TCC and TNC.)
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 sixty REPs. The two
largest customers of TCC accounted for 29% of its operating revenues in 2006;
the three largest customers of TNC accounted for 50% of its operating revenues
in 2006. Adverse economic conditions, structural problems in the new 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 environmental laws are significant, and the cost of
compliance with future environmental laws could harm our cash flow and
profitability.
(Applies to each registrant other than TCC and TNC.)
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. 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 results
of
operations 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. All of our estimates are subject to significant uncertainties
about the outcome of several interrelated assumptions and variables, including
timing of implementation, required levels of reductions, allocation requirements
of the new rules, and our selected compliance alternatives. As a result, we
cannot estimate our compliance costs with certainty. The actual costs to comply
could differ significantly from the estimates. All of the costs are incremental
to our current investment base and operating cost structure.
If
Federal and/or State requirements are imposed on electric utility companies
mandating further emission reductions, including limitations on
CO2
emissions,
such requirements could make some of our electric generating units uneconomical
to maintain or operate. (Applies
to each registrant other than TCC and TNC.)
Emissions
of nitrogen and sulfur oxides, mercury and particulates from fossil fueled
generating plants are potentially subject to increased regulations, controls
and
mitigation expenses. Environmental advocacy groups, other organizations and
some
agencies in the United States are focusing considerable attention on carbon
dioxide emissions from power generation facilities and their potential role
in
climate change. Although several bills have been introduced in Congress that
would compel CO2
emission
reductions, none have advanced through the legislature. Future changes in
environmental regulations governing these pollutants could make some of our
electric generating units uneconomical to maintain or operate. In addition,
any
legal obligation that would require us to substantially reduce our emissions
beyond present levels could require extensive mitigation efforts and, in the
case of CO2
legislation, would raise uncertainty about the future viability of fossil fuels,
particularly coal, as an energy source for new and existing electric generation
facilities. While mandatory requirements for further emission reductions from
our fossil fleet do not appear to be imminent, we continue to monitor regulatory
and legislative developments in this area.
Governmental
authorities may assess penalties on us if it is determined that we have not
complied with environmental laws and regulations. (Applies
to each registrant other than TCC and TNC.)
If
we
fail to comply with environmental laws and regulations, even if caused by
factors beyond our control, that failure may result in the assessment of civil
or criminal penalties and fines against us. Recent lawsuits by the EPA and
various states filed against us highlight the environmental risks faced by
generating facilities, in general, and coal-fired generating facilities, in
particular.
Since
1999, we have been involved in litigation regarding generating plant emissions
under the CAA. The EPA and a number of states alleged that we and other
unaffiliated utilities modified certain units at coal-fired generating plants
in
violation of the CAA. The EPA filed complaints against certain AEP subsidiaries
in U.S. District Court for the Southern District of Ohio. A separate lawsuit
initiated by certain special interest groups was consolidated with the EPA
case.
The alleged modification of the generating units occurred over a 20-year period.
A
bench
trial on the liability issues was held during July 2005. Briefing has concluded,
but the court is holding the case in abeyance until the U.S. Supreme Court
rules
on a similar case. No decision has been issued.
Additionally, in July 2004 attorneys general of eight states and others sued
AEP
and other utilities alleging that carbon dioxide emissions from power generating
facilities constitute a public nuisance under federal common law. The trial
court dismissed the suits and plaintiffs have appealed the dismissal. While
we
believe the claims are without merit, the costs associated with reducing carbon
dioxide emissions could harm our business and our results of operations and
financial position.
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
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.
Our
revenues and results of operations from selling power are subject to market
risks that are beyond our control.
(Applies to each registrant other than TCC and TNC.)
We
sell
power from our generation facilities into the spot market or other competitive
power markets or 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, we are generally not guaranteed any rate of return on our capital
investments 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 may
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, 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 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:
· |
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 other than AEG, TCC and TNC.)
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 of 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 other than TCC and TNC.)
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 other than TCC and TNC.)
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 other than AEG, TCC and TNC.)
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.
ITEM
1B.
UNRESOLVED
STAFF COMMENTS
None.
ITEM
2. PROPERTIES
GENERATION
FACILITIES
GENERAL
At
December 31, 2006, 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
|
|
Hydro
MW
|
|
Nuclear
MW
|
|
Lignite
MW
|
|
Oil
MW
|
|
Total
MW
|
AEGCo
|
|
1
|
(a)
|
|
1,300
|
|
|
|
|
|
|
|
|
|
|
|
1,300
|
APCo
|
|
17
|
(b)(c)
|
|
5,073
|
|
528
|
|
681
|
|
|
|
|
|
|
|
6,282
|
CSPCo
|
|
6
|
(d)
|
|
2,345
|
|
857
|
|
|
|
|
|
|
|
|
|
3,202
|
I&M
|
|
9
|
(a)
|
|
2,295
|
|
|
|
15
|
|
2,143
|
|
|
|
|
|
4,453
|
KPCo
|
|
1
|
|
|
1,060
|
|
|
|
|
|
|
|
|
|
|
|
1,060
|
OPCo
|
|
8
|
(b)(c)(e)
|
|
8,472
|
|
|
|
26
|
|
|
|
|
|
|
|
8,498
|
PSO
|
|
8
|
(f)
|
|
1,018
|
|
3,238
|
|
|
|
|
|
|
|
25
|
|
4,281
|
SWEPCo
|
|
9
|
(g)
|
|
1,848
|
|
1,821
|
|
|
|
|
|
842
|
|
|
|
4,511
|
TCC
|
|
1
|
(f)(h)
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
54
|
TNC
|
|
11
|
(f)
|
|
377
|
|
1,014
|
(i)
|
|
|
|
|
|
|
10
|
(j)
|
1,401
|
TOTALS:
|
|
66
|
|
|
23,842
|
|
7,458
|
|
722
|
|
2,143
|
|
842
|
|
35
|
|
35,042
|
System
Percentage
|
|
68.0%
|
|
21.3%
|
|
2.1% |
|
6.1%
|
|
2.4%
|
|
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. In
December 2006, AEGCo agreed to buy Lawrenceburg Generating Station,
a
1,096 MW gas-fired unit in Indiana from Public Service Electric and
Gas
Company. Assuming receipt of regulatory approvals, the acquisition
is
expected to close in the second quarter of
2007.
|
(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 CG&E and DP&L. Its percentage
ownership interest is reflected in this table. In November 2006,
CSPCo
agreed to buy Darby Electric Generating Station, a 480 MW gas-fired
unit
in Ohio from DP&L. Assuming receipt of regulatory approvals, the
acquisition is expected to close in the first half of
2007.
|
(e)
|
The
scrubber facilities at the General James M. Gavin Plant are leased.
OPCo
is permitted to terminate the lease as early as
2010.
|
(f) |
As
of December 31, 2006, PSO, TCC and TNC, along with Oklahoma Municipal
Power Authority and The Public Utilities Board of the City of Brownsville,
Texas, jointly owned the Oklaunion power station. Their respective
ownership interests are reflected in this table. In February 2007,
TCC
sold its interest in Oklaunion to The Public Utilities Board of the
City
of Brownsville, Texas. In order to comply with the separation requirements
of the Texas Act, in January 2007, TNC entered into a 20-year power
agreement transferring its generating capacity in the Oklaunion power
station to a non-utility affiliate.
|
(g)
|
SWEPCo
owns generating units in common with unaffiliated parties. Only its
ownership interest is reflected in this
table.
|
(h)
|
Under
the Texas Act, TCC has exited the generation business. As a result,
in
February 2007 TCC sold the last of its generation
facilities.
|
(i)
|
TNC’s
gas fired generation is
deactivated.
|
(j)
|
TNC’s
oil fired generation is
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
|
1,036,000
|
|
1,107,000
|
Net
Capacity Factors (a)
|
|
|
|
2006
|
80.4%
|
|
86.5%
|
2005
|
88.8%
|
|
97.1%
|
2004
|
97.0%
|
|
81.6%
|
2003
(b)
|
73.5%
|
|
74.5%
|
(a)
|
Net
Capacity Factor values since 2004 reflect Nominal Net Electrical
Rating in
Kilowatts of 1,036,000 (Unit 1) and 1,107,000 (Unit 2). Net Capacity
Factor values for 2003 and earlier, however, reflect previous Nominal
Net
Electrical Rating in Kilowatts of 1,020,000 (Unit 1) and 1,090,000
(Unit
2).
|
(b)
|
The
capacity factors for both units of the Cook Plant were reduced in
2003 due
to an unplanned maintenance outage to implement upgrades to the traveling
water screens system following a fish intrusion.
|
Costs
associated with the operation (excluding 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. I&M may also incur costs and experience reduced output at Cook
Plant, because of the design criteria prevailing at the time of construction
and
the age of the plant’s systems and equipment. Nuclear industry-wide and Cook
Plant initiatives have contributed to slowing the growth of operating and
maintenance costs at these plants. However, 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.
In
addition to the generating facilities described above, AEP has ownership
interests in other electrical generating facilities. Information concerning
these facilities at December 31, 2006 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)
|
Sweeny
|
Natural
gas
|
Texas
|
480
|
50%
|
Qualifying
Facility (b)
|
Trent
Wind Farm
|
Wind
|
Texas
|
150
|
100%
|
Exempt
Wholesale Generator (a)
|
Total
|
|
|
791
|
|
|
(a) As
defined under rules issued pursuant to EPACT.
(b) |
As
defined under the Public Utility Regulatory Policies Act of
1978.
|
See
Note
8 to the consolidated financial statements entitled Acquisitions,
Dispositions, Discontinued Operations, Impairments and Assets Held for Sale,
included
in the 2006 Annual Reports, for a discussion of AEP’s disposition of independent
power producer and foreign generation assets.
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)
|
223,076
|
(b)
|
|
2,116
|
|
APCo
|
51,579
|
|
|
734
|
|
CSPCo
(a)
|
15,443
|
|
|
—
|
|
I&M
|
21,985
|
|
|
615
|
|
Kingsport
Power Company
|
1,356
|
|
|
—
|
|
KPCo
|
10,897
|
|
|
258
|
|
OPCo
|
30,723
|
|
|
509
|
|
PSO
|
21,149
|
|
|
—
|
|
SWEPCo
|
20,693
|
|
|
—
|
|
TCC
|
29,432
|
|
|
—
|
|
TNC
|
18,120
|
|
|
—
|
|
WPCo
|
1,699
|
|
|
—
|
|
(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.
Substantially
all the fixed physical properties and franchises of SWEPCo, except for limited
exceptions, are subject to the lien of its mortgage and deed of trust securing
its first mortgage bonds.
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
GENERAL
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 $3.5 billion, $3.0 billion and $3.0 billion of construction
expenditures for 2007, 2008 and 2009, respectively. 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.
PROPOSED
TRANSMISSION FACILITIES
PJM
Project
AEP
has
filed a proposal with the FERC and the PJM to build a new 765kV transmission
line stretching from West Virginia to New Jersey. The proposed transmission
corridor will span approximately 550 miles and is designed to reduce PJM
congestion costs through enhancing transfer capability and also to reduce
transmission line losses. It also is expected to improve reliability in the
eastern transmission grid. AEP´s proposed transmission line, called the AEP
Interstate Project, would originate at AEP´s Amos transmission station in Putnam
County, WV, connect through Doubs Station in Frederick County, MD and terminate
at the Deans Station in Middlesex County, NJ. The proposed route follows a
corridor conceptually identified by PJM as a transmission route needed to
address transmission congestion within the PJM footprint. Exact routing of
the
line would be determined after PJM approves the project. AEP will work with
PJM,
other affected transmission owners and stakeholders throughout the siting
process. It is expected that a new AEP subsidiary, AEP Transmission Co., LLC,
will own the line and undertake construction of the project. The projected
costs
are approximately $3 billion, which may be shared with other stakeholders.
The
anticipated in-service date is 2015 assuming three years to site and acquire
rights-of-way and five years to build the line. This projected in-service date
also assumes approval by PJM in mid-2007 followed by approval by FERC on initial
rates by the end of 2007.
AEP
also
has filed with the DOE in its efforts to designate National Interest Electric
Transmission Corridors (NIETC). EPACT provides for NIETC designation for areas
that are experiencing electric energy transmission capacity constraints or
congestion that adversely affects consumers. In August 2006, the DOE issued
the
“National Interest Electric Transmission Congestion Study”. In this study, DOE
indicated that the mid-Atlantic Coastal area, which the AEP project is designed
to reinforce, is one of the two most critical congestion areas in the nation.
This finding should help AEP to obtain early NIETC designation as promulgated
by
EPACT. In October 2006, we filed comments with the DOE encouraging corridor
designation that is consistent with the proposed line.
In
July
2006, pursuant to a request by AEP, the FERC clarified that the project
qualifies for incentive rate treatment, provided that the new line is included
in PJM’s formal Regional Transmission Expansion Plan to be finalized in 2007.
The approved incentives include, (a) a return on equity set at the high end
of
the “zone of reasonableness”; (b) the option to timely recover the cost of
capital associated with construction work in progress; and (c) the ability
to
defer expense and recover costs incurred during the pre-construction and
pre-operating period. Since the FERC has clarified that the project qualifies
for these rate incentives, we expect to propose rates that will capture the
incentives in future FERC rate filings.
ERCOT
Joint Venture
In
November 2006 AEP announced a memorandum of understanding with MidAmerican
Energy Holdings Co. (MidAmerican) to form a joint venture company to build
and
own new electric transmission assets in ERCOT. In
January 2007, we signed a participation agreement with MidAmerican to form
a
joint venture company, Electric Transmission Texas LLC (ETT), to fund, own
and
operate electric transmission assets in ERCOT. ETT filed with the PUCT in
January 2007 requesting regulatory approval to operate as an electric
transmission utility in Texas, to transfer from TCC to ETT approximately $76
million of transmission assets currently under construction, to sell or transfer
ownership of ETT as discussed below, and to establish a wholesale transmission
tariff for ETT. ETT also requested approval of initial rates based on an 11.25%
return on equity.
Upon
receipt of all required regulatory approvals, respective subsidiaries of AEP
and
of MidAmerican each will acquire a 50% equity ownership in ETT. The anticipated
utility capitalization structure of ETT is approximately 40% equity and 60%
debt. AEP
and
MidAmerican expect ETT to invest in additional transmission projects in ERCOT.
The companies anticipate in excess of $1 billion in projects could be included
in the new company during the next several years. TCC also made a regulatory
filing at the FERC in February 2007 regarding the transfer of transmission
assets from TCC to ETT. In
February 2007, ETT filed a proposal with the PUCT that addresses the Competitive
Renewable Energy Zone initiative of the Texas legislature. The proposal outlines
the opportunities for additional significant investment in transmission assets
in Texas. The joint venture is anticipated to begin operations in the
second half of 2007, subject to regulatory approval from the PUCT and the
FERC.
Completed
Project
APCo
has
completed construction of the Wyoming-Jacksons
Ferry 765kV
transmission line that was placed in -service on June 20, 2006.
PROPOSED
GENERATION FACILITIES
IGCC
Projects
In
conjunction with an environmental impact study issued in August 2004, we
announced plans to construct a synthesis-gas-fired plant or plants of
approximately 1,200 MW of capacity in the next five to six years utilizing
integrated gasification combined cycle (IGCC) technology. We originally
estimated construction and other direct costs would equal approximately $1.2
billion for each nominal 629 MW facility. We currently expect these estimates
to
be exceeded in amounts that are not yet determinable and that may be material.
We are currently completing front-end engineering and design on the facilities
pursuant to an agreement with General Electric and Bechtel Power Corporation
and
are working with state regulators and legislators to establish a framework
for
expedient recovery of this significant investment in new clean coal technology.
The
plans
are contingent upon receiving adequate cost recovery through rates approved
by
the applicable commission prior to beginning construction. In
January 2006, APCo filed a petition with the WVPSC requesting its approval
of a
Certificate of Public Convenience and Necessity to construct a 600 MW IGCC
plant
adjacent to APCo’s existing Mountaineer generating station in Mason County, WV.
In January 2007, the WVPSC issued an order setting a deadline of December 3,
2007 for it to rule on APCo’s filing.
In
March
2005, OPCo and CSPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a new 600 MW IGCC power
plant
using clean-coal technology. The application proposed for cost recovery
associated with the IGCC plant in three phases. In April 2006, the PUCO issued
an order authorizing OPCo and CSPCo to implement Phase 1 of their cost recovery
proposal. In June 2006, the PUCO issued another order approving a tariff to
recover Phase 1 pre-construction costs. In its June order, the PUCO indicated
that if the Ohio companies have not commenced continuous construction of the
IGCC plant within five years of the order, all charges collected for
pre-construction costs must be refunded to Ohio ratepayers with interest. The
PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings
are
held. No date for a further hearing has been set.
SWEPCo
Projects
In
December 2005, SWEPCo sought proposals for new peaking, intermediate and base
load generation to be online between 2008 and 2011. In May 2006, SWEPCo
announced plans to construct new generation. SWEPCo will build up to 480 MW
of
simple-cycle natural gas combustion turbine peaking generation in Tontitown,
Arkansas. SWEPCo also will build a 480 MW combined-cycle natural gas fired
plant
at its existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also
plans to build a new 600 MW base load coal plant, of which its investment will
be 73%, in Hempstead County, Arkansas by 2011. Preliminary cost estimates for
the new facilities are approximately $1.4 billion. These new facilities are
subject to regulatory approvals from SWEPCo’s three state commissions—APSC, LPSC
and the PUCT. The peaking generation facility in Tontitown, Arkansas has been
approved by all three state commissions. Construction of all of these units
is
expected to begin in 2007.
PSO
Projects
In
September 2005, PSO sought proposals for new peaking generation to be online
in
2008. In December 2005, PSO sought proposals for base load generation to be
online in 2011. PSO received and evaluated proposals with oversight from a
neutral third party. In March 2006, PSO announced plans to add 170 MW of peaking
generation to its Riverside Station plant in Jenks, Oklahoma. PSO will construct
and operate two 85 MW simple-cycle natural gas combustion turbines at the Jenks
facility. In March 2006, PSO announced plans to add 170 MW of peaking generation
to its Southwestern Station plant in Anadarko, Oklahoma. PSO will construct
and
operate two 85 MW simple-cycle natural gas combustion turbines at that facility.
Combined preliminary cost estimates for these additions are approximately $120
million. In July 2006, PSO announced plans to enter a joint venture with
Oklahoma Gas and Electric Company (“OG&E”) and Oklahoma Municipal Power
Authority. OG&E will construct and operate a new 950 MW coal-fueled
electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the
new
unit. Preliminary cost estimates for 100% of the new facility are approximately
$1.8 billion. The unit is expected to be online no later than the first half
of
2012. These new facilities are subject to regulatory approval from the OCC.
Construction of all of these units is expected to begin in 2007.
Other
Our
significant planned environmental investments in emission control installations
at existing coal-fired plants and our commitment to IGCC technology reinforce
our belief that coal will be a lower-emission domestic energy source of the
future and further signals our commitment to invest in clean, environmentally
safe technology. For additional information regarding anticipated environmental
expenditures, see Management’s
Financial Discussion and Analysis of Results of Operations under
the
heading entitled Environmental
Matters.
CONSTRUCTION
EXPENDITURES
The
following table shows construction expenditures (including environmental
expenditures) during 2004, 2005 and 2006 and current estimates of 2007, 2008
and
2009 construction expenditures, in each case excluding AFUDC, capitalized
interest and assets acquired under leases.
|
2004
Actual
|
2005
Actual
|
2006
Actual
|
2007
Estimate
|
2008
Estimate
|
2009
Estimate
|
|
(in
thousands)
|
AEP
Systems (a)
|
$1,536,400
|
(b)
|
$2,501,600
|
(c)
|
$3,522,100
|
(d)
|
$3,440,300
|
(e)
|
$3,026,300
|
$2,974,100
|
AEGCo
|
15,700
|
|
15,200
|
|
10,000
|
|
18,000
|
|
28,300
|
34,100
|
APCo
|
435,900
|
|
634,000
|
|
922,700
|
|
663,600
|
|
531,200
|
460,900
|
CSPCo
|
148,200
|
|
171,600
|
|
315,100
|
|
337,200
|
|
354,300
|
232,600
|
I&M
|
173,400
|
|
317,100
|
|
306,900
|
|
252,000
|
|
264,300
|
293,800
|
KPCo
|
38,000
|
|
60,300
|
|
57,400
|
|
70,500
|
|
114,500
|
100,100
|
OPCo
|
339,200
|
|
733,400
|
|
968,700
|
|
832,000
|
|
367,800
|
389,200
|
PSO
|
90,800
|
|
139,700
|
|
245,200
|
|
318,600
|
|
329,600
|
465,900
|
SWEPCo
|
95,300
|
|
151,200
|
|
330,300
|
|
537,300
|
|
605,200
|
539,700
|
TCC
|
109,400
|
|
186,300
|
|
273,200
|
|
240,600
|
|
213,700
|
273,100
|
TNC
|
35,700
|
|
64,800
|
|
67,900
|
|
142,600
|
|
187,900
|
148,900
|
(a) |
Includes
expenditures of other subsidiaries not shown. The figures reflect
construction expenditures, not investments in subsidiary companies.
Excludes discontinued operations.
|
(b) |
Excludes
Cash Flow Statement Adjustments (Statement of Cash Flow Including
AFUDC
Debt Equals $1,636,200)
|
(c) |
Excludes
$293 million for the purchase of two generating plants and Cash Flow
Statement Adjustments (Statement of Cash Flow Including AFUDC Debt
Equals
$2,403,800)
|
(d) |
Excludes
Cash Flow Statement Adjustments (Statement of Cash Flow Including
AFUDC
Debt Equals $3,528,000)
|
(e) |
Excludes
$427 million for the purchase of two generating
plants.
|
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 10 to the consolidated financial statements entitled Nuclear
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 and SWEPCo . None.
AEGCo,
CSPCo, I&M, KPCo, PSO, TCC and TNC. 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, 2007.
Name
|
|
Age
|
|
Office
(a)
|
Michael
G. Morris
|
|
60
|
|
Chairman
of the Board, President and Chief Executive Officer of AEP and of
AEPSC
|
Nicholas
K. Akins
|
|
46
|
|
Executive
Vice President of AEP and Executive Vice President-Generation of
AEPSC
|
Carl
L. English
|
|
60
|
|
President-AEP
Utilities of AEP and of AEPSC
|
Thomas
M. Hagan
|
|
62
|
|
Executive
Vice President of AEP and Executive Vice President-AEP Utilities-West
of
AEPSC
|
John
B. Keane
|
|
60
|
|
Senior
Vice President, General Counsel, Chief Compliance Officer and Secretary
of
AEP and Senior Vice President and General Counsel of
AEPSC
|
Holly
K. Koeppel
|
|
48
|
|
Executive
Vice President and Chief Financial Officer of AEP and of
AEPSC
|
Robert
P. Powers
|
|
52
|
|
Executive
Vice President of AEP and Executive Vice President-AEP Utilities-East
of
AEPSC
|
Susan
Tomasky
|
|
53
|
|
Executive
Vice President of AEP and Executive Vice President-Shared Services
of
AEPSC
|
(a) |
Before
joining AEPSC in his current position in January 2004, Mr. Morris
was
Chairman of the Board, President and Chief Executive Officer of Northeast
Utilities (1997-2003). Messrs. Akins, Hagan, and Powers and Ms. Tomasky
and Ms. Koeppel have been employed by AEPSC or System companies in
various
capacities (AEP, as such, has no employees) for the past five years.
Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became executive
officers of AEP effective with their promotions to Executive Vice
President on September 9, 2002, October 24, 2001, November 18, 2002
and
January 26, 2000, respectively. As a result of AEP’s realignment of its
executive management team in July 2004, Mr. Keane became an executive
officer of AEP. Before joining AEPSC in his current position in July
2004,
Mr. Keane was President of Bainbridge Crossing Advisors. Before that,
he
was Vice President-Administration for Northeast Utilities (1998-2002).
Mr.
English joined AEP as President-Utility Group and became an executive
officer of AEP on August 1, 2004. Before joining AEPSC in his current
position in August 2004, Mr. English was President and Chief Executive
Officer of Consumers Energy gas division (1999-2004). As a result
of AEP’s
realignment of management in August 2006, Mr. Akins became an executive
officer of AEP. All of the above officers are appointed annually
for a
one-year term by the board of directors of AEP, the board of directors
of
AEPSC, or both, as the case may be.
|
APCo,
OPCo and SWEPCo .
The
names of the executive officers of APCo, OPCo and SWEPCo, the positions they
hold with these companies, their ages as of February 1, 2007, and a brief
account of their business experience during the past five years appear below.
The directors and executive officers of APCo, OPCo and SWEPCo are elected
annually to serve a one-year term.
Name
|
|
Age
|
|
Position
|
|
Period
|
Michael
G. Morris (a)(b)
|
|
60
|
|
Chairman
of the Board, President, Chief Executive Officer and Director of
AEP and
AEPSC
|
|
2004-Present
|
|
|
|
|
Chairman
of the Board, Chief Executive Officer and Director of APCo, OPCo
and
SWEPCo
|
|
2004-Present
|
|
|
|
|
Chairman
of the Board, President and Chief Executive Officer of Northeast
Utilities
|
|
1997-2003
|
Nicholas
K. Akins (a)
|
|
46
|
|
Executive
Vice President of AEP
|
|
2006-Present
|
|
|
|
|
Executive
Vice President-Generation and Director of AEPSC
|
|
2006-Present
|
|
|
|
|
Vice
President and Director of APCo and OPCo
|
|
2006-Present
|
|
|
|
|
Director
of SWEPCo
|
|
2006-Present
|
|
|
|
|
President
and Chief Operating Officer of SWEPCo
|
|
2004-2006
|
|
|
|
|
Vice
President-Energy Market Services of AEPSC
|
|
2002-2004
|
|
|
|
|
Vice
President-Energy Delivery Business Development of AEPSC
|
|
2001-2002
|
Carl
L. English (c)
|
|
60
|
|
President-AEP
Utilities of AEP
|
|
2004-Present
|
|
|
|
|
President-AEP
Utilities and Director of AEPSC
|
|
2004-Present
|
|
|
|
|
Director
and Vice President of APCo, OPCo and SWEPCo
|
|
2004-Present
|
|
|
|
|
President
and Chief Executive Officer of Consumers Energy gas
division
|
|
1999-2004
|
Thomas
M. Hagan (d)
|
|
62
|
|
Executive
Vice President of AEP
|
|
2006-Present
|
|
|
|
|
Executive
Vice President-AEP Utilities-West
|
|
2004-Present
|
|
|
|
|
Director
of AEPSC
|
|
2002-Present
|
|
|
|
|
Vice
Chairman of the Board of SWEPCo
|
|
2004-Present
|
|
|
|
|
Vice
President and Director of SWEPCo
|
|
2002-Present
|
|
|
|
|
Vice
President and Director of APCo and OPCo
|
|
2002-2004
|
|
|
|
|
Executive
Vice President of AEP
|
|
2004
|
|
|
|
|
Executive
Vice President-Shared Services of AEPSC
|
|
2002-2004
|
|
|
|
|
Senior
Vice President-Governmental Affairs of AEPSC
|
|
2000-2002
|
John
B. Keane (e)
|
|
60
|
|
Senior
Vice President, General Counsel, Chief Compliance Officer and Secretary
of
AEP
|
|
2004-Present
|
|
|
|
|
Senior
Vice President, General Counsel and Director of AEPSC
|
|
2004-Present
|
|
|
|
|
Director
of APCo, OPCo and SWEPCo
|
|
2004-Present
|
|
|
|
|
President
of Bainbridge Crossing Advisors
|
|
2003-2004
|
|
|
|
|
Vice
President-Administration-Northeast Utilities
|
|
1998-2002
|
Holly
K. Koeppel (a)
|
|
48
|
|
Executive
Vice President and Chief Financial Officer of AEP and
AEPSC
|
|
2006-Present
|
|
|
|
|
Director
of AEPSC
|
|
2003-Present
|
|
|
|
|
Executive
Vice President-AEP Utilities-East of AEPSC
|
|
2004-Present
|
|
|
|
|
Vice
President of APCo and OPCo
|
|
2003-Present
|
|
|
|
|
Director
of APCo and OPCo
|
|
2004-Present
|
|
|
|
|
Chief
Financial Officer of APCo, OPCo and SWEPCo
|
|
2006-Present
|
|
|
|
|
Vice
President and Director of SWEPCO
|
|
2006-Present
|
|
|
|
|
Executive
Vice President of AEP
|
|
2004
|
|
|
|
|
Executive
Vice President-Commercial Operations of AEPSC
|
|
2002-2004
|
|
|
|
|
Senior
Vice President-Corporate Development of AEPSC
|
|
2002
|
Robert
P. Powers (f)
|
|
52
|
|
Executive
Vice President of AEP
|
|
2004-Present
|
|
|
|
|
Executive
Vice President-AEP Utilities East of AEPSC
|
|
2006-Present
|
|
|
|
|
Director
of AEPSC
|
|
2001-Present
|
|
|
|
|
Executive
Vice President-Generation of AEPSC
|
|
2003-2006
|
|
|
|
|
Director
and Vice President of APCo and OPCo
|
|
2001-Present
|
|
|
|
|
Director
and Vice President of SWEPCo
|
|
2001-2006
|
|
|
|
|
Executive
Vice President-Nuclear Generation and Technical Services of
AEPSC
|
|
2001-2003
|
Susan
Tomasky (c)
|
|
53
|
|
Executive
Vice President of AEP
|
|
2004-Present
|
|
|
|
|
Executive
Vice President-Shared Services of AEPSC
|
|
2006-Present
|
|
|
|
|
Chief
Financial Officer and Vice President of AEP
|
|
2001-2006
|
|
|
|
|
Executive
Vice President-Chief Financial Officer of AEPSC
|
|
2004-2006
|
|
|
|
|
Director
of AEPSC
|
|
1998-Present
|
|
|
|
|
Vice
President and Director of APCo, OPCo and SWEPCo
|
|
2000-Present
|
|
|
|
|
Executive
Vice President-Policy, Finance and Strategic Planning of
AEPSC
|
|
2001-2004
|
(a)
|
Messrs.
Morris and Akins and Ms. Koeppel are directors of AEGCo, CSPCo, I&M,
KPCo, PSO, TCC and TNC.
|
|
|
(b)
|
Mr.
Morris is a director of Cincinnati Bell, Inc. and The Hartford Financial
Services Group, Inc.
|
|
|
(c)
|
Mr.
English and Ms. Tomasky are directors of CSPCo, I&M, KPCo, PSO, TCC
and TNC.
|
|
|
(d)
|
Mr.
Hagan is a director of PSO, TCC and TNC.
|
|
|
(e)
|
Mr.
Keane is a director of AEGCo, CSPCo, KPCo, PSO, TCC and
TNC.
|
|
|
(f)
|
Mr.
Powers is a director of AEGCo, CSPCo, I&M, KPCo, PSO, TCC and
TNC.
|
APCo:
Name
|
|
Age
|
|
Position
|
|
Period
|
Dana
E. Waldo
|
|
55
|
|
President
and Chief Operating Officer of APCo and Kingsport Power
Company
|
|
2004-Present
|
|
|
|
|
President
of Wheeling Power Company
|
|
2005-Present
|
|
|
|
|
President
and Chief Executive Officer of West Virginia Roundtable
|
|
1999-2004
|
OPCo:
Name
|
|
Age
|
|
Position
|
|
Period
|
Kevin
E. Walker
|
|
43
|
|
President
and Chief Operating Officer of CSPCo and OPCo
|
|
2004-Present
|
|
|
|
|
President
of WPCo
|
|
2004-2005
|
|
|
|
|
Vice
President of Consolidated Edison (New York)
|
|
2001-2004
|
SWEPCo:
Name
|
|
Age
|
|
Position
|
|
Period
|
Venita
McCellon-Allen
|
|
47
|
|
President
and Chief Operating Officer of SWEPCo
|
|
2006-Present
|
|
|
|
|
Director
and Senior Vice President-Shared Services of AEPSC
|
|
2004-2006
|
|
|
|
|
Director
of APCo, I&M, OPCo, SWEPCo and TCC
|
|
2004-2006
|
|
|
|
|
Senior
Vice President-Human Resources for Baylor Health Care
Systems
|
|
2000-2004
|
PART
II
ITEM
5. MARKET
FOR REGISTRANTS’ COMMON EQUITY,
RELATED
STOCKHOLDER MATTERS
AND
ISSUER PURCHASES OF EQUITY SECURITIES
AEP.
The
information required by this item is incorporated herein by reference to the
material under AEP Common
Stock and Dividend Information in
the
2006 Annual Report.
AEGCo,
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
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 2006, 2005
and
2004 are incorporated by reference to the material under Statements
of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss)
in
the
2006 Annual Reports.
The
following table provides information about purchases by AEP (or its
publicly-traded subsidiaries) during the quarter ended December 31, 2006 of
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
|
|
10/01/06
- 10/31/06 (a)(b)
|
|
|
177
|
|
$
|
68.08
|
|
|
-
|
|
$
|
-
|
|
11/01/06
- 11/30/06 (c)
|
|
|
17
|
|
|
83.50
|
|
|
-
|
|
|
-
|
|
12/01/06
- 12/31/06
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Total
|
|
|
194
|
|
$
|
69.43
|
|
|
-
|
|
$
|
-
|
|
(a)
|
OPCo
repurchased 2 shares of its 4.50% cumulative preferred stock, in
privately-negotiated transactions outside of an announced
program
|
(b)
|
TCC
repurchased 175 shares of its 4.20% cumulative preferred stock,
in
privately-negotiated transactions outside of an announced
program.
|
(c)
|
SWEPCo
repurchased 17 shares of its 5.00% cumulative preferred stock,
in
privately-negotiated transactions outside of an announced
program.
|
ITEM
6. SELECTED
FINANCIAL DATA
AEGCo,
CSPCo,
I&M, KPCo, PSO, TCC and TNC. Omitted
pursuant to Instruction I(2)(a).
AEP,
APCo, OPCo and SWEPCo.
The
information required by this item is incorporated herein by reference to the
material under Selected
Consolidated Financial Data in
the
2006 Annual Reports.
ITEM
7. MANAGEMENT’S
DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION
AND
RESULTS OF OPERATION
AEGCo,
CSPCo, I&M, KPCo, PSO, TCC and TNC.
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
2006 Annual Reports.
AEP,
APCo, OPCo 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
2006 Annual Reports.
ITEM
7A.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES
ABOUT MARKET RISK
AEGCo,
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC.
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
2006 Annual Reports.
ITEM
8. FINANCIAL
STATEMENTS
AND
SUPPLEMENTARY DATA
AEGCo,
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
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
AEGCo,
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC. None.
ITEM
9A. CONTROLS
AND PROCEDURES
During
2006, management, including the principal executive officer and principal
financial officer of each of American Electric Power Company, Inc. (“AEP”), AEP
Generating Company, AEP Texas Central Company, AEP Texas North Company,
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Kentucky Power Company, Ohio Power Company, Public Service
Company of Oklahoma and Southwestern Electric Power Company (each, together
with
AEP, a “Registrant” and collectively, together with AEP, 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, 2006, 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 2006 that materially affected, or
are
reasonably likely to materially affect, the Registrants’ internal controls over
financial reporting.
Additional
information required by this item of AEP, as a large accelerated filer, is
incorporated by reference to Management’s
Report on Internal Control over Financial Reporting,
included in the 2006 Annual Report.
ITEM
9B. OTHER
INFORMATION
None.
PART
III
ITEM
10. DIRECTORS,
EXECUTIVE OFFICERS
AND
CORPORATE GOVERNANCE
AEGCo,
CSPCo,
I&M, KPCo, PSO, TCC and TNC. 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 2007 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 2007
annual meeting of shareholders.
APCo
and OPCo:
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
2007
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 and OPCo 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 and OPCo. 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 or OPCo, 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.
SWEPCo:
Directors
and Executive Officers.
The
names of the directors and executive officers of SWEPCo, the positions they
hold
with SWEPCo, their ages as of February 1, 2007, and a brief account of their
business experience during the past five years appear below or under the caption
Executive
Officers of the Registrants in
Part
I, Item 4 of this report.
Name
|
|
Age
|
|
Position
|
|
Period
|
Stephen
P. Smith (a)
|
|
45
|
|
Senior
Vice President and Treasurer of AEP
|
|
2004-Present
|
|
|
|
|
Vice
President and Director of APCo, OPCo and SWEPCo
|
|
2004-Present
|
|
|
|
|
Director
of AEPSC
|
|
2004-Present
|
|
|
|
|
Senior
Vice President and Treasurer of AEPSC
|
|
2003-Present
|
|
|
|
|
Treasurer
of AEPSC, APCo, OPCo and SWEPCo
|
|
2003-Present
|
|
|
|
|
President
and Chief Operating Officer-Corporate Services for
NiSource
|
|
1999-2003
|
Dennis
E. Welch (b)
|
|
55
|
|
Senior
Vice President of AEP
|
|
2005-Present
|
|
|
|
|
Director
of APCo, OPCo and SWEPCo
|
|
2005-Present
|
|
|
|
|
Senior
Vice President-Environment and Safety and Director of
AEPSC
|
|
2005-Present
|
|
|
|
|
President
of Yankee Gas Services Company
|
|
2001-2005
|
(a) Mr.
Smith
is a director of AEGCo, CSPCo, KPCo, PSO, TCC and TNC.
(b) Mr.
Welch
is a director of CSPCo, KPCo, PSO, TCC and TNC.
Audit
Committee. 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
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
its Chief Executive Officer, Chief Financial Officer or principal accounting
officer, SWEPCo 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
AEGCo,
CSPCo,
I&M, KPCo, PSO, TCC and TNC. 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 and
the
performance graph of the definitive proxy statement of AEP for the 2007 annual
meeting of shareholders.
APCo
and OPCo.
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 2007 annual meeting
of
stockholders.
SWEPCo.
The
information required by this item is incorporated herein by reference to the
material under Executive
Compensation of
the
definitive proxy statement of AEP for the 2007 annual meeting of shareholders.
ITEM
12. SECURITY
OWNERSHIP OF CERTAIN
BENEFICIAL
OWNERS AND MANAGEMENT AND
RELATED
STOCKHOLDER MATTERS
AEGCo,
CSPCo,
I&M, KPCo, PSO, TCC and TNC. 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 2007 annual meeting of
shareholders.
APCo
and OPCo.
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 2007 annual meeting
of
stockholders.
SWEPCo.
All
7,536,640 outstanding shares of Common Stock, $18 par value, of SWEPCo are
directly and beneficially held by AEP. Holders of the Cumulative Preferred
Stock
of SWEPCo generally have no voting rights, except with respect to certain
corporate actions and in the event of certain defaults in the payment of
dividends on such shares.
The
table
below shows the number of shares of AEP Common Stock and stock-based units
that
were beneficially owned, directly or indirectly, as of January 1, 2006, by
each
director and nominee of SWEPCo and each of the executive officers of SWEPCo
named in the summary compensation table, and by all directors and executive
officers of SWEPCo as a group. It is based on information provided to SWEPCo
by
such persons. No such person owns any shares of any series of the Cumulative
Preferred Stock of SWEPCo. Unless otherwise noted, each person has sole voting
power and investment power over the number of shares of AEP Common Stock and
stock-based units set forth opposite his or her name. Fractions of shares and
units have been rounded to the nearest whole number.
Name
|
|
Shares
(a)
|
|
Stock
Units
(b)
|
|
Total
|
Nicholas
K. Akins
|
|
15,900
|
|
|
1,574
|
|
17,474
|
Carl
L. English
|
|
13,610
|
|
|
12,351
|
|
25,961
|
Thomas
M. Hagan
|
|
166,708
|
|
|
28,971
|
|
195,679
|
John
B. Keane
|
|
6,804
|
|
|
6,174
|
|
12,978
|
Holly
K. Koeppel
|
|
36,967
|
|
|
33,617
|
|
70,584
|
Venita
McCellon-Allen
|
|
4,536
|
|
|
4,066
|
|
8,602
|
Michael
G. Morris
|
|
438,498
|
(c)
|
|
161,008
|
|
599,506
|
Stephen
P. Smith
|
|
19,000
|
|
|
9,814
|
|
28,814
|
Susan
Tomasky
|
|
208,572
|
|
|
41,144
|
|
249,716
|
Dennis
E. Welch
|
|
3,333
|
|
|
10,398
|
|
13,731
|
All
Directors and
Executive
Officers
|
|
913,928
|
(d)
|
|
309,117
|
|
1,223,045
|
|
AEP
Retirement Savings
Plan
|
Name
|
(Share
Equivalents)
|
Nicholas
K. Akins
|
—
|
Carl
L. English
|
—
|
Thomas
M. Hagan
|
5,715
|
John
B. Keane
|
—
|
Holly
K. Koeppel
|
267
|
Venita
McCellon-Allen
|
—
|
Michael
G. Morris
|
—
|
Stephen
P. Smith
|
—
|
Susan
Tomasky
|
4,238
|
Dennis
E. Welch
|
—
|
All
Directors and Executive
Officers
|
10,220
|
With
respect to the share equivalents held in the AEP Retirement Savings Plan, such
persons have sole voting power, but the investment/disposition power is subject
to the terms of the Plan. Also, includes the following numbers of shares
attributable to options exercisable within 60 days: Mr. Akins, 15,900; Mr.
Hagan, 150,500; Ms. Koeppel, 36,700; Mr. Morris, 149,000; Mr. Smith, 16,500;
Ms.
Tomasky, 204,334; and Mr. Welch, 3,333.
(a) Includes
share equivalents held in the AEP Retirement Savings Plan in the amounts
listed.
(b) This
column includes amounts deferred in stock units and held under AEP’s various
director and officer benefit plans.
(c) Represents
less than 1% of the total number of shares outstanding.
(d) Includes
restricted shares with different vesting schedules and accrued
dividends.
EQUITY
COMPENSATION PLAN INFORMATION
Information
regarding the equity compensation plan is incorporated by reference from the
definitive proxy statement of AEP for the 2007 annual meeting of
shareholders.
ITEM
13. CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
AEGCo,
CSPCo,
I&M, KPCo, PSO, TCC and TNC. 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 2007 annual meeting of
shareholders.
APCo,
OPCo
and SWEPCo: Certain
Relationships and Related Transactions. None.
Director
Independence.
None of
the directors of APCo, OPCo 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, 2006 and December 31, 2005, and fees billed for
other services rendered by Deloitte & Touche LLP during those
periods.
|
|
|
2006
|
|
|
2005
|
|
Audit
Fees (1)
|
|
|
|
|
|
|
|
Financial
Statements
|
|
$
|
8,564,000
|
|
$
|
8,469,000
|
|
Internal
Control over financial reporting
|
|
|
4,080,000
|
|
|
4,210,000
|
|
Total
Audit Fees
|
|
|
12,644,000
|
|
|
12,679,000
|
|
Audit-Related
Fees (2)
|
|
|
822,000
|
|
|
581,000
|
|
Tax
Fees (3)
|
|
|
703,000
|
|
|
1,116,000
|
|
TOTAL
|
|
$
|
14,169,000
|
|
$
|
14,376,000
|
|
(1)
|
Audit
fees in 2005 and 2006 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
2 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 and statutory
audits and audit-related work in connection with acquisitions and
dispositions.
|
|
|
(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
and OPCo.
The
information required by this item is incorporated herein by reference to the
definitive information statement of each company for the 2007 annual meeting
of
stockholders.
AEGCo,
CSPCo,
I&M, KPCo, PSO, SWEPCo, TCC and TNC.
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 2007 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, 2005 and 2006, 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 definitive proxy statement of AEP for the 2007 annual meeting of
shareholders.
|
|
AEGCo
|
|
CSPCo
|
|
I&M
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
Audit
Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Statement Audits
|
|
$
|
162,474
|
|
$
|
165,550
|
|
$
|
786,264
|
|
$
|
672,646
|
|
$
|
841,074
|
|
$ |
755,644
|
|
Sarbanes-Oxley
404
|
|
|
97,512
|
|
|
100,619
|
|
|
451,248
|
|
|
465,626
|
|
|
426,768
|
|
|
440,366
|
|
Audit
Fees - Other
|
|
|
57,739
|
|
|
29,628
|
|
|
179,792
|
|
|
145,287
|
|
|
276,523
|
|
|
139,603
|
|
Audit
Fees Subtotal
|
|
|
317,725
|
|
|
295,797
|
|
|
1,417,304
|
|
|
1,283,559
|
|
|
1,544,365
|
|
|
1,335,613
|
|
Audit-Related
Fees
|
|
|
5,513
|
|
|
0
|
|
|
31,755
|
|
|
55,500
|
|
|
248,233
|
|
|
5,500
|
|
Tax
Fees
|
|
|
1,350
|
|
|
2,250
|
|
|
22,913
|
|
|
23,100
|
|
|
26,216
|
|
|
30,350
|
|
TOTAL
|
|
$
|
324,588
|
|
$
|
298,047
|
|
$
|
1,471,972
|
|
$
|
1,362,159
|
|
$
|
1,818,814
|
|
$
|
1,371,463
|
|
|
|
KPCo
|
|
PSO
|
|
SWEPCo
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
Audit
Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Statement Audits
|
|
$
|
488,070
|
|
$
|
446,615
|
|
$
|
293,625
|
|
$
|
416,418
|
|
$
|
336,039
|
|
$
|
483,761
|
|
Sarbanes-Oxley
404
|
|
|
247,656
|
|
|
255,547
|
|
|
238,272
|
|
|
245,864
|
|
|
276,216
|
|
|
285,438
|
|
Audit
Fees - Other
|
|
|
107,136
|
|
|
71,972
|
|
|
111,144
|
|
|
89,098
|
|
|
133,580
|
|
|
99,190
|
|
Audit
Fees Subtotal
|
|
|
842,862
|
|
|
774,134
|
|
|
643,041
|
|
|
751,380
|
|
|
745,835
|
|
|
868,389
|
|
Audit-Related
Fees
|
|
|
15,638
|
|
|
0
|
|
|
16,772
|
|
|
5,500
|
|
|
87,657
|
|
|
5,500
|
|
Tax
Fees
|
|
|
8,945
|
|
|
10,550
|
|
|
18,804
|
|
|
21,400
|
|
|
22,134
|
|
|
20,400
|
|
TOTAL
|
|
$
|
867,445
|
|
$
|
784,684
|
|
$
|
678,617
|
|
$
|
778,280
|
|
$
|
855,626
|
|
$
|
894,289
|
|
|
|
TCC
|
|
TNC
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
Audit
Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Statement Audits
|
|
$
|
332,124
|
|
$
|
512,496
|
|
$
|
122,019
|
|
$
|
175,723
|
|
Sarbanes-Oxley
404
|
|
|
310,896
|
|
|
320,802
|
|
|
163,608
|
|
|
168,821
|
|
Audit
Fees - Other
|
|
|
242,977
|
|
|
170,027
|
|
|
42,018
|
|
|
48,337
|
|
Audit
Fees Subtotal
|
|
|
885,997
|
|
|
1,003,325
|
|
|
327,645
|
|
|
392,881
|
|
Audit-Related
Fees
|
|
|
60,113
|
|
|
0
|
|
|
6,029
|
|
|
0
|
|
Tax
Fees
|
|
|
23,079
|
|
|
28,900
|
|
|
9,795
|
|
|
15,250
|
|
TOTAL
|
|
$
|
969,189
|
|
$ |
1,032,225
|
|
$
|
343,469
|
|
$
|
408,131
|
|
PART
IV
ITEM
15. EXHIBITS,
FINANCIAL STATEMENT SCHEDULES
The
following documents are filed as a part of this report:
|
Page
|
1. Financial
Statements:
|
|
The
following financial statements have been incorporated herein by reference
pursuant to Item 8.
|
|
AEGCo:
|
|
Statements
of Income for the years ended December 31, 2006, 2005 and 2004; Statements
of Retained Earnings for the years ended December 31, 2006, 2005
and 2004;
Balance Sheets as of December 31, 2006 and 2005; Statements of Cash
Flows
for the years ended December 31, 2006, 2005 and 2004; Notes to Financial
Statements of Registrant Subsidiaries; Report of Independent Registered
Public Accounting Firm.
|
|
AEP
and Subsidiary Companies:
|
|
Reports
of Independent Registered Public Accounting Firm; Management’s Report on
Internal Control over Financial Reporting; Consolidated Statements
of
Operations for the years ended December 31, 2006, 2005 and 2004;
Consolidated Balance Sheets as of December 31, 2006 and 2005; Consolidated
Statements of Cash Flows for the years ended December 31, 2006, 2005
and
2004; Consolidated Statements of Changes in Common Shareholders’ Equity
and Comprehensive Income (Loss) for the years ended December 31,
2006,
2005 and 2004; Notes to Consolidated Financial Statements.
|
|
APCo,
CSPCo, I&M, OPCo, SWEPCo, TNC and TCC:
|
|
Consolidated
Statements of Income (or Statements of Operations) for the years
ended
December 31, 2006, 2005 and 2004; Consolidated Statements of Changes
in
Common Shareholder’s Equity and Comprehensive Income (Loss) for the years
ended December 31, 2006, 2005 and 2004; Consolidated Balance Sheets
as of
December 31, 2006 and 2005; Consolidated Statements of Cash Flows
for the
years ended December 31, 2006, 2005 and 2004; Notes to Financial
Statements of Registrant Subsidiaries; Report of Independent Registered
Public Accounting Firm.
|
|
KPCo
and PSO:
|
|
Statements
of Income for the years ended December 31, 2006, 2005 and 2004; Statements
of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss)
for the years ended December 31, 2006, 2005 and 2004; Balance Sheets
as of
December 31, 2006 and 2005; Statements of Cash Flows for the years
ended
December 31, 2006, 2005 and 2004; Notes to Financial Statements of
Registrant Subsidiaries; Report of Independent Registered Public
Accounting Firm.
|
|
2. Financial
Statement Schedules:
|
|
Financial
Statement Schedules are listed in the Index to Financial Statement
Schedules (Certain schedules have been omitted because the required
information is contained in the notes to financial statements or
because
such schedules are not required or are not applicable). Report of
Independent Registered Public Accounting Firm
|
S-1
|
3. Exhibits:
|
|
Exhibits
for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
are listed in the Exhibit Index beginning on page E-1 and are incorporated
herein by reference
|
E-1
|
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/
Holly
K. Koeppel
|
|
|
(Holly
K. Koeppel, Executive Vice President
|
|
|
and
Chief Financial Officer)
|
Date:
February 28, 2007
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
28, 2007
|
(Michael
G. Morris)
|
|
Chief
Executive Officer
|
|
|
|
|
And
Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Holly
K. Koeppel
|
|
Executive
Vice President and
|
|
February
28, 2007
|
(Holly
K. Koeppel)
|
|
Chief
Financial Officer
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Joseph
M. Buonaiuto
|
|
Senior
Vice President, Controller and
|
|
February
28, 2007
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*E.
R. Brooks
|
|
|
|
|
*Donald
M. Carlton
|
|
|
|
|
*Ralph
D. Crosby, Jr.
|
|
|
|
|
*John
P. DesBarres
|
|
|
|
|
*Robert
W. Fri
|
|
|
|
|
*Linda
A. Goodspeed
|
|
|
|
|
*William
R. Howell
|
|
|
|
|
*Lester
A. Hudson, Jr.
|
|
|
|
|
*Lionel
L. Nowell, III
|
|
|
|
|
*Richard
L. Sandor
|
|
|
|
|
*Donald
G. Smith
|
|
|
|
|
*Kathryn
D. Sullivan
|
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/
Holly
K. Koeppel
|
|
|
|
February
28, 2007
|
|
(Holly
K. Koeppel, 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.
|
By:
|
/s/
Holly
K. Koeppel
|
|
|
(Holly
K. Koeppel, Vice President
and
Chief Financial Officer)
|
Date:
February 28, 2007
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
28, 2007
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Holly
K. Koeppel
|
|
Vice
President,
|
|
February
28, 2007
|
(Holly
K. Koeppel)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Joseph
M. Buonaiuto
|
|
Controller
and
|
|
February
28, 2007
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*
Nicholas K. Akins
|
|
|
|
|
*
John B. Keane
|
|
|
|
|
*
Robert P. Powers
|
|
|
|
|
*
Stephen P. Smith
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/
Holly
K. Koeppel
|
|
|
|
February
28, 2007
|
|
(Holly
K. Koeppel, 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.
|
AEP
Texas Central Company
|
|
AEP
Texas North Company
|
|
Public
Service Company of Oklahoma
|
|
Southwestern
Electric Power Company
|
|
By:
|
/s/
Holly
K. Koeppel
|
|
|
(Holly
K. Koeppel, Vice President
and
Chief Financial Officer)
|
Date:
February 28, 2007
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
28, 2007
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Holly
K. Koeppel
|
|
Vice
President,
|
|
February
28, 2007
|
(Holly
K. Koeppel)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Joseph
M. Buonaiuto
|
|
Controller
and
|
|
February
28, 2007
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*Nicholas
K. Akins
|
|
|
|
|
*Carl
L. English
|
|
|
|
|
*Thomas
M. Hagan
|
|
|
|
|
*John
B. Keane
|
|
|
|
|
*Stephen
P. Smith
|
|
|
|
|
*Susan
Tomasky
|
|
|
|
|
*Dennis
E. Welch
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/
Holly
K. Koeppel
|
|
|
|
February
28, 2007
|
|
(Holly
K. Koeppel, 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
|
|
Kentucky
Power Company
|
|
Ohio
Power Company
|
|
By:
|
/s/
Holly
K. Koeppel
|
|
|
(Holly
K. Koeppel, Vice President
and
Chief Financial Officer)
|
Date:
February 28, 2007
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
28, 2007
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Holly
K. Koeppel
|
|
Vice
President,
|
|
February
28, 2007
|
(Holly
K. Koeppel)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
|
|
/s/
Joseph
M. Buonaiuto
|
|
Controller
and
|
|
February
28, 2007
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*Nicholas
K. Akins
|
|
|
|
|
*Carl
L. English
|
|
|
|
|
*John
B. Keane
|
|
|
|
|
*Robert
P. Powers
|
|
|
|
|
*Stephen
P. Smith
|
|
|
|
|
*Susan
Tomasky
|
|
|
|
|
*Dennis
E. Welch
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/
Holly
K. Koeppel
|
|
|
|
February
28, 2007
|
|
(Holly
K. Koeppel, 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/
Holly
K. Koeppel
|
|
|
(Holly
K. Koeppel Vice President
and
Chief Financial Officer)
|
Date:
February 28, 2007
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
28, 2007
|
(Michael
G. Morris)
|
|
Chief
Executive Officer and Director
|
|
|
|
|
|
|
|
(ii) Principal
Financial Officer:
|
|
|
|
|
/s/
Holly
K. Koeppel
|
|
Vice
President,
|
|
February
28, 2007
|
(Holly
K. Koeppel)
|
|
Chief
Financial Officer and Director
|
|
|
|
|
|
|
|
(iii) Principal
Accounting Officer:
|
|
|
|
|
/s/
Joseph
M. Buonaiuto
|
|
Controller
and
|
|
February
28, 2007
|
(Joseph
M. Buonaiuto)
|
|
Chief
Accounting Officer
|
|
|
|
|
|
|
|
(iv) A
Majority of the Directors:
|
|
|
|
|
|
|
|
|
|
*Nicholas
K. Akins
|
|
|
|
|
*K.
G. Boyd
|
|
|
|
|
*Carl
L. English
|
|
|
|
|
*Allen
R. Glassburn
|
|
|
|
|
*Joann
M. Grevenow
|
|
|
|
|
*Patrick
C. Hale
|
|
|
|
|
*Marc
E. Lewis
|
|
|
|
|
*Helen
J. Murray
|
|
|
|
|
*Robert
P. Powers
|
|
|
|
|
*Susanne
M. Moorman Rowe
|
|
|
|
|
*Susan
Tomasky
|
|
|
|
|
|
|
|
|
|
*By:
|
/s/
Holly
K. Koeppel
|
|
|
|
February
28, 2007
|
|
(Holly
K. Koeppel, Attorney-in-Fact)
|
|
|
|
|
INDEX
TO FINANCIAL STATEMENT SCHEDULES
|
Page
|
|
|
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
|
S-2
|
|
|
The
following financial statement schedules are included in this report
on the
pages indicated:
|
|
|
|
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-3
|
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-3
|
AEP
TEXAS NORTH COMPANY
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-3
|
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-4
|
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-4
|
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-4
|
KENTUCKY
POWER COMPANY
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-5
|
OHIO
POWER COMPANY CONSOLIDATED
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-5
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-5
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
Schedule
II — Valuation and Qualifying Accounts and Reserves
|
S-6
|
We
have
audited the consolidated financial statements of American Electric Power
Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2006
and 2005, and for each of the three years in the period ended December 31,
2006,
management's assessment of the effectiveness of the Company's internal control
over financial reporting as of December 31, 2006, and the effectiveness of
the
Company's internal control over financial reporting as of December 31, 2006,
and
have issued our reports thereon dated February 28, 2007 (which reports express
unqualified opinions and, with respect to the report on the consolidated
financial statements, includes an explanatory paragraph concerning the adoption
of new accounting pronouncements in 2004, 2005 and 2006); such consolidated
financial statements and reports are included in your 2006 Annual Report and
are
incorporated herein by reference. Our audits also included the
consolidated financial statement schedule of the Company listed in Item
15. This consolidated financial statement schedule is the responsibility
of the Company's management. Our responsibility is to express an opinion
based on our audits. In our opinion, such consolidated financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material respects, the
information set forth therein.
/s/
Deloitte & Touche LLP
Columbus,
Ohio
February
28, 2007
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We
have
audited the financial statements of AEP Texas Central Company and subsidiaries,
AEP Texas North Company and subsidiary, Appalachian Power Company and
subsidiaries, Columbus Southern Power Company and subsidiaries, Indiana Michigan
Power Company and subsidiaries, Kentucky Power Company, Ohio Power Company
Consolidated, Public Service Company of Oklahoma and Southwestern Electric
Power
Company Consolidated (collectively the “Companies”) as of December 31, 2006 and
2005, and for each of the three years in the period ended December 31, 2006,
and
have issued our reports thereon dated February 28, 2007 (which
reports express unqualified opinions and include an explanatory paragraph
concerning the adoption of new accounting pronouncements in 2004, 2005 and
2006
where applicable);
such
financial statements and reports are included in the Companies’ 2006 Annual
Reports and are incorporated herein by reference. Our audits also included
the financial statement schedules of the Companies
listed in Item 15. These financial statement schedules are the
responsibility of the Companies’ management. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial
statement schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly, in all material respects, the
information set forth therein.
/s/
Deloitte & Touche LLP
Columbus,
Ohio
February
28, 2007
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
30,553
|
|
$
|
29,831
|
|
$
|
1,001
|
|
$
|
31,557
|
|
$
|
29,828
|
|
Year Ended December 31, 2005
|
|
|
77,175
|
|
|
27,384
|
|
|
24
|
|
|
74,030
|
|
|
30,553
|
|
Year Ended December 31, 2004
|
|
|
123,685
|
|
|
39,766
|
|
|
7,989
|
|
|
94,265
|
|
|
77,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARIES
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
143
|
|
$
|
(29
|
) (c) |
|
$
|
-
|
|
$
|
65
|
|
$
|
49
|
|
Year Ended December 31, 2005
|
|
|
3,493
|
|
|
29
|
|
|
|
-
|
|
|
3,379
|
|
|
143
|
|
Year Ended December 31, 2004
|
|
|
1,710
|
|
|
3,493
|
|
|
|
-
|
|
|
1,710
|
|
|
3,493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Includes a credit of $29 thousand from a
true-up adjustment as a result of changes to the System Integration
Agreement and the CSW
Operating Agreement.
|
|
AEP
TEXAS NORTH COMPANY AND SUBSIDIARY
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
18
|
|
$
|
(9
|
) (c) |
|
$
|
-
|
|
$
|
-
|
|
$
|
9
|
|
Year Ended December 31, 2005
|
|
|
787
|
|
|
14
|
|
|
|
-
|
|
|
783
|
|
|
18
|
|
Year Ended December 31, 2004
|
|
|
175
|
|
|
787
|
|
|
|
-
|
|
|
175
|
|
|
787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Includes a credit of $14 thousand from a
true-up adjustment as a result of changes to the System Integration
Agreement and the CSW
Operating Agreement.
|
|
APPALACHIAN
POWER COMPANY AND SUBSIDIARIES
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
1,805
|
|
$
|
4,012
|
|
$
|
999
|
|
$
|
2,482
|
|
$
|
4,334
|
|
Year Ended December 31, 2005
|
|
|
5,561
|
|
|
3,304
|
|
|
21
|
|
|
7,081
|
|
|
1,805
|
|
Year Ended December 31, 2004
|
|
|
2,085
|
|
|
3,059
|
|
|
4,201
|
|
|
3,784
|
|
|
5,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COLUMBUS
SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
1,082
|
|
$
|
189
|
|
$
|
-
|
|
$
|
725
|
|
$
|
546
|
|
Year Ended December 31, 2005
|
|
|
674
|
|
|
408
|
|
|
-
|
|
|
-
|
|
|
1,082
|
|
Year Ended December 31, 2004
|
|
|
531
|
|
|
577
|
|
|
187
|
|
|
621
|
|
|
674
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INDIANA
MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
898
|
|
$
|
208
|
|
$
|
-
|
|
$
|
505
|
|
$
|
601
|
|
Year Ended December 31, 2005
|
|
|
187
|
|
|
819
|
|
|
-
|
|
|
108
|
|
|
898
|
|
Year Ended December 31, 2004
|
|
|
531
|
|
|
195
|
|
|
90
|
|
|
629
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
KENTUCKY
POWER COMPANY
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
147
|
|
$
|
80
|
|
$
|
-
|
|
$
|
-
|
|
$
|
227
|
|
Year Ended December 31, 2005
|
|
|
34
|
|
|
146
|
|
|
-
|
|
|
33
|
|
|
147
|
|
Year Ended December 31, 2004
|
|
|
736
|
|
|
43
|
|
|
27
|
|
|
772
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OHIO
POWER COMPANY CONSOLIDATED
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
1,517
|
|
$
|
243
|
|
$
|
-
|
|
$
|
936
|
|
$
|
824
|
|
Year Ended December 31, 2005
|
|
|
93
|
|
|
1,425
|
|
|
-
|
|
|
1
|
|
|
1,517
|
|
Year Ended December 31, 2004
|
|
|
789
|
|
|
122
|
|
|
89
|
|
|
907
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PUBLIC
SERVICE COMPANY OF OKLAHOMA
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
240
|
|
$
|
(81
|
) (c) |
|
$
|
-
|
|
$
|
154
|
|
$
|
5
|
|
Year Ended December 31, 2005
|
|
|
76
|
|
|
164
|
|
|
|
-
|
|
|
-
|
|
|
240
|
|
Year Ended December 31, 2004
|
|
|
37
|
|
|
21
|
|
|
|
55
|
|
|
37
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Includes a credit of $81 thousand from a
true-up adjustment as a result of changes to the System Integration
Agreement and the CSW
Operating Agreement.
|
|
SOUTHWESTERN
ELECTRIC POWER COMPANY CONSOLIDATED
SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
Charged
to Costs and Expenses
|
|
|
Charged
to Other Accounts (a)
|
|
Deductions
(b)
|
|
Balance
at End of Period
|
|
|
|
(in
thousands)
|
|
Deducted
from Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
Provision for
|
|
|
|
|
|
|
|
|
|
|
|
|
Uncollectible Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
$
|
548
|
|
$
|
(37
|
)
(c) |
|
$
|
-
|
|
$
|
381
|
|
$
|
130
|
|
Year Ended December 31, 2005
|
|
|
45
|
|
|
534
|
|
|
|
-
|
|
|
31
|
|
|
548
|
|
Year Ended December 31, 2004
|
|
|
2,093
|
|
|
(2,079
|
) |
|
|
134
|
|
|
103
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Recoveries on accounts previously written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
Uncollectible accounts written off.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Includes a credit of $95 thousand from a
true-up adjustment as a result of changes to the System Integration
Agreement and the CSW
Operating Agreement.
|
|
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: AEGCo File
No. 0-18135
|
|
|
3(a)
|
|
Articles
of Incorporation of AEGCo.
|
|
Registration
Statement on Form 10 for the Common Shares of AEGCo, Ex
3(a).
|
3(b)
|
|
Copy
of the Code of Regulations of AEGCo, amended as of June 15,
2000.
|
|
2000
Form 10-K, Ex 3(b).
|
10(a)
|
|
Capital
Funds Agreement dated as of December 30, 1988 between AEGCo and
AEP.
|
|
Registration
Statement No. 33-32752, Ex 28(a).
|
10(b)(1)
|
|
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(b)(2)
|
|
Unit
Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and
KPCo.
|
|
Registration
Statement No. 33-32752, Ex 28(b)(2).
|
10(c)
|
|
Lease
Agreements, dated as of December 1, 1989, between AEGCo and Wilmington
Trust Company, as amended.
|
|
Registration
Statement No. 33-32752, Ex 28(c)(1-6)(C);
1993
Form 10-K, Ex 10(c)(1-6)(B).
|
*13
|
|
Copy
of those portions of the AEGCo 2006 Annual Report, which are incorporated
by reference in this filing.
|
|
|
*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: AEP‡ File
No. 1-3525
|
|
|
3(a)
|
|
Composite
of the Restated Certificate of Incorporation of AEP, dated January
13,
1999.
|
|
1998
Form 10-K, Ex 3(c).
|
3(b)
|
|
By-Laws
of AEP, as amended through December 15, 2003
|
|
2003
Form 10-K, Ex 3(d).
|
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
|
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,.
|
|
2002
Form 10-K; Ex 10(b)
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)
|
|
Transmission
Coordination Agreement, dated October 29, 1998, among PSO, TCC,
TNC,
SWEPCo and AEPSC.
|
|
2002
Form 10-K; Ex 10(d).
|
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)
|
|
Lease
Agreement dated January 20, 1995 between OPCo and JMG Funding,
Limited
Partnership, and amendment thereto (confidential treatment requested)
|
|
OPCo
1994 Form 10-K, Ex 10(l)(2).
|
10(h)
|
|
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(i)
|
|
AEP
Accident Coverage Insurance Plan for directors.
|
|
1985
Form 10-K, Ex 10(g)
|
*†10(j)(1)
|
|
AEP
Retainer Deferral Plan for Non-Employee Directors, effective January
1,
2005, as amended February 9, 2007.
|
|
Form
10-Q, Ex. 10(b), March 31, 2005
|
†10(j)(2)
|
|
AEP
Stock Unit Accumulation Plan for Non-Employee Directors, as
amended.
|
|
2003
Form 10-K, Ex 10(k)(2).
|
*†10(j)(2)(A)
|
|
First
Amendment to AEP Stock Unit Accumulation Plan for Non-Employee
Directors
dated as of February 9, 2007
|
|
|
†10(k)(1)(A)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January
1,
2001.
|
|
2000
Form 10-K, Ex 10(j)(1)(A)
|
†10(k)(1)(B)
|
|
Guaranty
by AEP of AEPSC Excess Benefits Plan.
|
|
1990
Form 10-K, Ex 10(h)(1)(B)
|
†10(k)(1)(C)
|
|
First
Amendment to AEP System Excess Benefit Plan, dated as of March
5,
2003.
|
|
2002
Form 10-K; Ex 10(1)(1)(c)
|
*†10(k)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated
as of
January 1, 2005 (Non-Qualified), as amended December 28,
2006.
|
|
|
†10(k)(3)
|
|
Service
Corporation Umbrella Trust for Executives.
|
|
1993
Form 10-K, Ex 10(g)(3).
|
†10(l)(1)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December
15,
2003.
|
|
2003
Form 10-K, Ex 10(m)(1).
|
†10(l)(2)
|
|
Memorandum
of agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
2000
Form 10-K, Ex 10(s)
|
†10(l)(3)
|
|
Letter
Agreement dated June 23, 2000 between AEPSC and Holly K.
Koeppel.
|
|
2002
Form 10-K; Ex 10(m)(3)(A)
|
†10(l)(4)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K; Ex 10(m)(4)
|
†10(l)(5)
|
|
Letter
Agreements dated June 4, 2004 and June 9, 2004 between AEPSC and
Carl
English
|
|
Form
10-Q, Ex 10(b), September 30, 2004
|
*†10(l)(6)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC
and John B.
Keane
|
|
|
†10(m)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan.
|
|
1996
Form 10-K, Ex 10(i)(1)
|
†10(n)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
Form
10-Q, Ex 10, September 30, 1998
|
†10(n)(2)
|
|
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)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated
as of
January 1, 2005, as amended December 28, 2006.
|
|
|
†10(p)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan
dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(r)
|
†10(q)
|
|
Nuclear
Key Contributor Retention Plan dated May 1, 2000.
|
|
2002
Form 10-K; Ex 10(s)
|
†10(r)
|
|
AEP
Change In Control Agreement, effective January 1, 2006.
|
|
Form
8-K, Ex 1, dated January 3, 2006
|
†10(s)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan
|
|
Form
8-K, Item 1.01, dated April 26, 2005.
|
†10(s)(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(s)(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(s)(4)
|
|
AEP
System Stock Ownership Requirement Plan, (as Amended and Restated
Effective January 1, 2005), as amended December 28, 2006
|
|
|
†10(t)(1)
|
|
Central
and South West System Special Executive Retirement Plan as amended
and
restated effective July 1, 1997.
|
|
CSW
1998 Form 10-K, Ex 18, File No. 1-1443
|
†10(t)(2)
|
|
Certified
Board Resolutions of AEP Utilities, Inc. (formerly CSW) of July
16,
1996.
|
|
2003
Form 10-K, Ex 10(v)(3).
|
†10(t)(3)
|
|
Central
and South West Corporation Executive Deferred Savings Plan as amended
and
restated effective as of January 1, 1997.
|
|
CSW
1998 Form 10-K, Ex 24, File No. 1-1443.
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the AEP 2006 Annual Report (for the fiscal
year ended
December 31, 2006) 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.
|
|
|
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)
|
|
By-Laws
of APCo, amended as of October 24, 2001.
|
|
2001
Form 10-K, Ex 3(e).
|
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)
|
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.
|
|
Registration
Statement No. 2-60015, Ex 5(c);
Registration
Statement No. 2-67728, Ex 5(a)(3)(B);
1992
Form 10-K, Ex 10(a)(2)(B);
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);
AEP
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.
|
|
AEP
1985 Form 10-K, Ex 10(b);
AEP
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.
|
|
AEP
1996 Form 10-K, Ex 10(l), File No. 1-3525.
|
†10(f)
|
|
|
|
AEP
1996 Form 10-K, Ex 10(i)(1), File No. 1-3525.
|
†10(g)(1)(A)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January
1,
2001.
|
|
AEP
2000 Form 10-K, Ex 10(j)(1)(A), File No. 1-3525.
|
†10(g)(1)(B)
|
|
First
Amendment to AEP System Excess Benefit Plan, dated as of March
5,
2003.
|
|
2002
Form 10-K; Ex 10(h)(1)(B).
|
*†10(g)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated
as of
January 1, 2005 (Non-Qualified), as amended December 28,
2006.
|
|
2005
Form 10-K; Ex 10(g)(2)
|
†10(g)(3)
|
|
Umbrella
Trust for Executives.
|
|
AEP
1993 Form 10-K, Ex 10(g)(3), File No. 1-3525.
|
†10(h)(1)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December
15,
2003.
|
|
2003
Form 10-K, Ex 10(i)(1).
|
†10(hi)(2)
|
|
Memorandum
of Agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
AEP
2000 Form 10-K, Ex 10(s), File No. 1-3525.
|
†10(hi)(3)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K; Ex 10(i)(3).
|
†10(h)(4)
|
|
Letter
Agreements dated June 4, 2004 and June 9, 2004 between AEPSC and
Carl
English
|
|
AEP
Form 10-Q, Ex 10(b), September 30, 2004
|
*†10(h)(5)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC
and John B.
Keane
|
|
|
†10(i)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
AEP
Form 10-Q, Ex 10, September 30, 1998, File No. 1-3525.
|
†10(i)(2)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K; Ex 10(j)(2).
|
†10(j)
|
|
AEP
Change In Control Agreement, effective January 1, 2006.
|
|
Form
8-K, Ex 1 dated January 3, 2006,
|
†10(k)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Ex 10.1, dated April 26, 2005.
|
†10(k)(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), dated November 5, 2004.
|
†10(k)(3)
|
|
Form
of Restricted Stock Unit Agreement furnished to participants of
the AEP
System Long-Term Incentive Plan, as amended.
|
|
AEP
Form 10-Q, Ex 10(a), March 31, 2005
|
*†10(k)(4)
|
|
AEP
System Stock Ownership Requirement Plan, (as Amended and Restated
Effective January 1, 2005), as amended December 28, 2006
|
|
|
†10(l)(1)
|
|
Central
and South West System Special Executive Retirement Plan as amended
and
restated effective July 1, 1997.
|
|
CSW
1998 Form 10-K, Ex 18, File No. 1-1443.
|
†10(l)(2)
|
|
Certified
Board Resolutions of AEP Utilities, Inc. (formerly CSW) of July
16,
1996.
|
|
2003
Form 10-K, Ex 10(n)(3).
|
*†10(m)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated
as of
January 1, 2005, as amended December 28, 2006.
|
|
2003
Form 10-K, Ex 10(o)(1);
Form
10-Q, Ex 10(b), June 30, 2005.
|
†10(n)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan
dated
August 1, 1998.
|
|
2002
Form 10-K; Ex 10(p).
|
†10(o)
|
|
Nuclear
Key Contributor Retention Plan dated May 1, 2000.
|
|
2002
Form 10-K; Ex 10(q).
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the APCo 2006 Annual Report (for the fiscal
year
ended December 31, 2006) which are incorporated by reference in
this
filing.
|
|
|
21
|
|
List
of subsidiaries of APCo
|
|
AEP
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)
|
|
Code
of Regulations and By-Laws of CSPCo.
|
|
1987
Form 10-K, Ex 3(d).
|
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).
|
4(c)
|
|
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)
|
4(b)
|
|
Company
Order and Officer’s Certificate to Deutsche Bank Trust Company Americas,
dated October 14, 2005, establishing terms of 5.85% senior Notes,
Series
F, due 2035.
|
|
Form
8-K, Ex 4(a), dated October 14, 2005.
|
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.
|
|
Registration
Statement No. 2-60015, Ex 5(c);
Registration
Statement No. 2-67728, Ex 5(a)(3)(B);
1992
Form 10-K, Ex 10(a)(2);
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 AEPSC, as amended.
|
|
Registration
Statement No. 2-52910, Ex 5(a);
Registration
Statement No. 2-61009, Ex 5(b);
AEP
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.
|
|
AEP
1985 Form 10-K, Ex 10(b), File No. 1-3525;
AEP
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.
|
|
AEP
1996 Form 10-K, Ex 10(l), File No. 1-3525.
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the CSPCo 2006 Annual Report (for the fiscal
year
ended December 31, 2006) which are incorporated by reference in
this
filing.
|
|
|
21
|
|
List
of subsidiaries of CSPCo
|
|
AEP
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)
|
|
By-Laws
of I&M, amended as of November 28, 2001.
|
|
2001
Form 10-K, Ex 3(d).
|
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).
|
4(b)
|
|
Company
Order and Officer’s Certificate to The Bank of New York, dated November
14, 2006, establishing terms of 6.05% Senior Notes, Series H, due
2037.
|
|
Form
8-K, Ex. 4(a), dated November 14, 2006
|
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.
|
|
Registration
Statement No. 2-60015, Ex 5(c);
Registration
Statement No. 2-67728, Ex 5(a)(3)(B);
1992
Form 10-K, Ex 10(a)(2);
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)
|
|
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);
AEP
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.
|
|
AEP
1985 Form 10-KEx 10(b), File No. 1-3525;
AEP
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.
|
|
AEP
1996 Form 10-K, Ex 10(l), File No. 1-3525.
|
10(f)
|
|
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 2006 Annual Report (for the fiscal year
ended December 31, 2006) which are incorporated by reference in
this
filing.
|
|
|
21
|
|
List
of subsidiaries of I&M.
|
|
AEP
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: KPCo‡ File
No. 1-6858
|
|
|
3(a)
|
|
Restated
Articles of Incorporation of KPCo.
|
|
1991
Form 10-K, Ex 3(a).
|
3(b)
|
|
By-Laws
of KPCo, amended as of June 15, 2000.
|
|
2000
Form 10-K, Ex 3(b).
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of September 1, 1997,
between
KPCo and Bankers Trust Company, as Trustee.
|
|
Registration
Statement No. 333-75785, Ex 4(a)(b)(c)(d);
Registration
Statement No. 333-87216, Ex 4(e)(f);
2002
Form 10-K, Ex 4(c)(d)(e)
2003
Form 10-K, Ex4(b).
|
10(a)
|
|
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);
AEP
1990 Form 10-K, Ex 10(a)(3), File No. 1-3525.
|
10(b)
|
|
Transmission
Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
with AEPSC as agent, as amended.
|
|
AEP
1985 Form 10-K, Ex 10(b), File No. 1-3525.
AEP
1988 Form 10-K, Ex 10(b)(2), File No. 1-3525.
|
10(c)(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(c)(1)
|
10(c)(2)
|
|
PJM
West Reliability Assurance Agreement among Load Serving Entities
in the
PJM West service area.
|
|
2004
Form 10-K, Ex 10(c)(2)
|
10(c)(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(c)(3)
|
10(d)
|
|
Modification
No. 1 to the AEP System Interim Allowance Agreement, dated July
28, 1994,
among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
|
|
AEP
1996 Form 10-K, Ex 10(l), File No. 1-3525,.
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the KPCo 2006 Annual Report (for the fiscal
year
ended December 31, 2006) which are incorporated by reference in
this
filing.
|
|
|
*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)
|
|
Code
of Regulations of OPCo.
|
|
1990
Form 10-K, Ex 3(d).
|
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).
|
4(b)
|
|
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).
|
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
Form 10-K, Ex 10(a)(1)(F), File No. 1-3457;
APCo
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.
|
|
Registration
Statement No. 2-60015, Ex 5(c);
Registration
Statement No. 2-67728, Ex 5(a)(3)(B);
Form
10-K, Ex 10(a)(2);
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);
AEP
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.
|
|
AEP
1985 Form 10-K, Ex 10(b), File No. 1-3525,
AEP
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.
|
|
AEP
1996 Form 10-K, Ex 10(l), File No. 1-3525.
|
10(f)(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(f)(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(g)
|
|
Lease
Agreement dated January 20, 1995 between OPCo and JMG Funding,
Limited
Partnership, and amendment thereto (confidential treatment
requested).
|
|
1994
Form 10-K, Ex 10(l)(2).
|
†10(h)
|
|
AEP
System Senior Officer Annual Incentive Compensation Plan.
|
|
AEP
1996 Form 10-K, Ex 10(i)(1), File No. 1-3525.
|
†10(i)(1)(A)
|
|
AEP
System Excess Benefit Plan, Amended and Restated as of January
1,
2001.
|
|
AEP
2000 Form 10-K, Ex 10(j)(1)(A), File No. 1-3525.
|
†10(i)(1)(B)
|
|
First
Amendment to AEP System Excess Benefit Plan, dated as of March
5,
2003.
|
|
2002
Form 10-K; Ex 10(i)(1)(B)
|
*†10(i)(2)
|
|
AEP
System Supplemental Retirement Savings Plan, Amended and Restated
as of
January 1, 2005 (Non-Qualified), as amended December 28,
2006.
|
|
2005
Form 10-K, Ex. 10(i)(2)
|
†10(i)(3)
|
|
Umbrella
Trust for Executives.
|
|
AEP
1993 Form 10-K, Ex 10(g)(3), File No. 1-3525.
|
†10(j)(1)
|
|
Employment
Agreement between AEP, AEPSC and Michael G. Morris dated December
15,
2003.
|
|
2003
Form 10-K, Ex 10(j)(1).
|
†10(j)(2)
|
|
Memorandum
of agreement between Susan Tomasky and AEPSC dated January 3,
2001.
|
|
AEP
2000 Form 10-K, Ex 10(s), File No. 1-3525.
|
†10(j)(3)
|
|
Employment
Agreement dated July 29, 1998 between AEPSC and Robert P.
Powers.
|
|
2002
Form 10-K, Ex 10(j)(3).
|
†10(j)(4)
|
|
Letter
Agreements dated June 4, 2004 and June 9, 2004 between AEPSC and
Carl
English
|
|
AEP
Form 10-Q, Ex 10(b), September 30, 2004, File No.
1-3525,
|
*†10(j)(5)
|
|
Letter
Agreements dated June 14, 2004 and June 17, 2004 between AEPSC
and John B.
Keane
|
|
|
†10(k)(1)
|
|
AEP
System Survivor Benefit Plan, effective January 27, 1998.
|
|
AEP
Form 10-Q, Ex 10, September 30, 1998, File No. 1-3525.
|
†10(k)(2)
|
|
First
Amendment to AEP System Survivor Benefit Plan, as amended and restated
effective January 31, 2000.
|
|
2002
Form 10-K; Ex 10(k)(2).
|
†10(l)
|
|
AEP
Change In Control Agreement, effective January 1, 2006.
|
|
Form
8-K, Ex 1, dated January 3, 2006.
|
†10(m)(1)
|
|
Amended
and Restated AEP System Long-Term Incentive Plan.
|
|
Form
8-K, Ex. 10.1, dated April 26, 2005..
|
†10(m)(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), dated November 5, 2004, File No.
1-3525.
|
†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)(4)
|
|
AEP
System Stock Ownership Requirement Plan, (as Amended and Restated
Effective January 1, 2005), as amended December 28, 2006
|
|
|
†10(n)(1)
|
|
Central
and South West System Special Executive Retirement Plan as amended
and
restated effective July 1, 1997.
|
|
CSW
1998 Form 10-K, Ex 18, File No. 1-1443.
|
†10(n)(2)
|
|
Certified
Board Resolutions of AEP Utilities, Inc. (formerly CSW) of July
16,
1996.
|
|
2003
Form 10-K, Ex 10(o)(3).
|
*†10(o)
|
|
AEP
System Incentive Compensation Deferral Plan Amended and Restated
as of
January 1, 2005, as amended December 28, 2006.
|
|
2003
Form 10-K, Ex 10(p)(1);
Form
10-Q, Ex. 10(b), June 30, 2005.
|
†10(p)
|
|
AEP
System Nuclear Performance Long Term Incentive Compensation Plan
dated
August 1, 1998.
|
|
2002
Form 10-K, Ex 10(q).
|
†10(q)
|
|
Nuclear
Key Contributor Retention Plan dated May 1, 2000.
|
|
2002
Form 10-K, Ex 10(r).
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the OPCo 2006 Annual Report (for the fiscal
year
ended December 31, 2006) which are incorporated by reference in
this
filing.
|
|
|
21
|
|
List
of subsidiaries of OPCo.
|
|
AEP
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)
|
|
Restated
Certificate of Incorporation of PSO.
|
|
CSW
1996 Form U5S, Ex B-3.1, File No. 1-1443.
|
3(b)
|
|
By-Laws
of PSO (amended as of June 28, 2000).
|
|
2002
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, Exs 4(a)(b);
Registration
Statement No. 333-114665, Ex 4(b)(c);
Registration
Statement No. 333-133548, Ex 4(b)(c).
|
4(b)
|
|
Sixth
Supplemental Indenture, dated as of August 10, 2006 between PSO
and The
Bank of New York, as Trustee, establishing terms of the 6.15% Senior
Notes, Series F, due 2016
|
|
Form
8-K, Ex 4(a), dated August 11, 2006
|
10(a)
|
|
Restated
and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued
on
February 10, 2006, Effective May 1, 2006..
|
|
2002
Form 10-K, Ex 10(a)
Form
10-Q, Ex 10(a), March 31, 2006.
|
10(b)
|
|
Transmission
Coordination Agreement, dated October 29, 1998, among PSO, TCC,
TNC,
SWEPCo and AEPSC.
|
|
2002
Form 10-K, Ex 10(b).
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the PSO 2006 Annual Report (for the fiscal
year ended
December 31, 2006) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of PSO.
|
|
AEP
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)
|
|
Restated
Certificate of Incorporation, as amended through May 6, 1997, including
Certificate of Amendment of Restated Certificate of
Incorporation.
|
|
Form
10-Q, Ex 3.4, March 31, 1997.
|
3(b)
|
|
By-Laws
of SWEPCo (amended as of April 27, 2000).
|
|
Form
10-Q, Ex 3.3, March 31, 2000.
|
4(a)
|
|
Indenture,
dated February 1, 1940, between SWEPCo and Continental Bank, National
Association and M. J. Kruger, as Trustees, as amended and
supplemented.
|
|
Registration
Statement No. 2-60712, Ex 5.04;
Registration
Statement No. 2-61943, Ex 2.02;
Registration
Statement No. 2-66033, Ex 2.02;
Registration
Statement No. 2-71126, Ex 2.02;
Registration
Statement No. 2-77165, Ex 2.02;
Form
U-1 No. 70-7121, Ex 4;
Form
U-1 No. 70-7233, Ex 3;
Form
U-1 No. 70-7676, Ex 3;
Form
U-1 No. 70-7934, Ex 10;
Form
U-1 No. 72-8041, Ex 10(b);
Form
U-1 No. 70-8041, Ex 10(c);
Form
U-1 No. 70-8239, Ex 10(a).
|
4(b)
|
|
SWEPCO-obligated,
mandatorily redeemable preferred securities of subsidiary trust
holding
solely Junior Subordinated Debentures of SWEPCo:
(1) Subordinated
Indenture, dated as of September 1, 2003, between SWEPCo and the
Bank of
New York, as Trustee.
(2) Amended
and Restated Trust Agreement of SWEPCo Capital Trust I, dated as
of
September 1, 2003, among SWEPCo, as Depositor, the Bank of New
York, as
Property Trustee, The Bank of New York (Delaware), as Delaware
Trustee,
and the Administrative Trustees.
(3) Guarantee
Agreement, dated as of September 1, 2003, delivered by SWEPCo for
the
benefit of the holders of SWEPCo Capital Trust I’s Preferred
Securities.
(4) First
Supplemental Indenture dated as of October 1, 2003, providing for
the
issuance of Series B Junior Subordinated Debentures between SWEPCo,
as
Issuer and the Bank of New York, as Trustee
(5) Agreement
as to Expenses and Liabilities, dated as of October 1, 2003 between
SWEPCo
and SWEPCo Capital Trust I (included in Item (4) above as Ex
4(f)(i)(A).
|
|
2003
Form 10-K, Ex 4(b).
|
4(c)
|
|
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).
|
4(e)
|
|
Fourth
Supplemental Indenture, dated as of June 28, 2005 between SWEPCo
and The
Bank of New York, as Trustee, establishing terms of 4.90% Senior
Notes,
Series D, due 2015.
|
|
Form
8-K, Ex 4(a), dated June 30, 2005
|
4(f)
|
|
Fifth
Supplemental Indenture, dated as of January 11, 2007 between SWEPCo
and
The Bank of New York, as Trustee, establishing terms of 5.55% Senior
Notes, Series E, due 2017.
|
|
Form
8-K, Ex 4(a), dated January 11, 2007
|
10(a)
|
|
Restated
and Amended Operating Agreement, among PSO, TCC, TNC, SWEPCo and
AEPSC,
Issued on February 10, 2006, Effective May 1, 2006..
|
|
2002
Form 10-K; Ex 10(a)
Form
10-Q, Ex 10(a), March 31, 2006.
|
10(b)
|
|
Transmission
Coordination Agreement, dated October 29, 1998, among PSO, TCC,
TNC,
SWEPCo and AEPSC.
|
|
2002
Form 10-K; Ex 10(b).
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the SWEPCo 2006 Annual Report (for the fiscal
year
ended December 31, 2006) which are incorporated by reference in
this
filing.
|
|
|
21
|
|
List
of subsidiaries of SWEPCo.
|
|
AEP
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: TCC‡ File
No. 0-346
|
|
|
3(a)
|
|
Restated
Articles of Incorporation Without Amendment, Articles of Correction
to
Restated Articles of Incorporation Without Amendment, Articles
of
Amendment to Restated Articles of Incorporation, Statements of
Registered
Office and/or Agent, and Articles of Amendment to the Articles
of
Incorporation.
|
|
Form
10-Q, Ex 3.1, March 31, 1997.
|
3(b)
|
|
Articles
of Amendment to Restated Articles of Incorporation of TCC dated
December
18, 2002.
|
|
2002
Form 10-K; Ex 3(b).
|
3(c)
|
|
By-Laws
of TCC (amended as of April 19, 2000).
|
|
2000
Form 10-K, Ex 3(b).
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of November 15, 1999,
between
TCC and The Bank of New York, as Trustee, as amended and
supplemented.
|
|
2000
Form 10-K, Ex 4(c)(d)(e).
|
4(b)
|
|
Indenture
(for unsecured debt securities), dated as of February 1, 2003,
between TCC
and Bank One, N.A., as Trustee.
|
|
2003
Form 10-K, Ex 4(d).
|
4(c)
|
|
First
Supplemental Indenture, dated as of February 1, 2003, between TCC
and Bank
One, N.A., as Trustee, establishing the terms of 5.50% Senior Notes,
Series A, due 2013 and 5.50% Senior Notes, Series D, due
2013.
|
|
2003
Form 10-K, Ex 4(e).
|
4(d)
|
|
Second
Supplemental Indenture, dated as of February 1, 2003, between TCC
and Bank
One, N.A., as Trustee, establishing the terms of 6.65% Senior Notes,
Series B, due 2033 and 6.65% Senior Notes, Series E, due
2033.
|
|
2003
Form 10-K, Ex 4(f).
|
4(e)
|
|
Third
Supplemental Indenture, dated as of February 1, 2003, between TCC
and Bank
One, N.A., as Trustee, establishing the terms of 3.00% Senior Notes,
Series C, due 2005 and 3.00% Senior Notes, Series F, due
2005.
|
|
2003
Form 10-K, Ex 4(g).
|
4(f)
|
|
Fourth
Supplemental Indenture, dated as of February 1, 2003, between TCC
and Bank
One, N.A., as Trustee, establishing the terms of Floating Rate
Notes,
Series A, due 2005 and Floating Rate Notes, Series B, due
2005.
|
|
2003
Form 10-K, Ex 4(h).
|
4(g)
|
|
Series
Supplement, dated as of October 11, 2006 between AEP Texas Central
Transition Funding II LLC and The Bank of New York, as Trustee,
establishing the Series A Transition Bonds
|
|
Form
8-K, Item 8.01, dated October 11, 2006, Ex 4.2.
|
10(a)
|
|
Transmission
Coordination Agreement, dated October 29, 1998, among PSO, TCC,
TNC,
SWEPCo and AEPSC.
|
|
2002
Form 10-K; Ex 10(b).
|
10(b)
|
|
Purchase
and Sale Agreement, dated as of September 3, 2004, by and between
TCC and
City of San Antonio (acting by and through the City Public Service
Board
of San Antonio) and Texas Genco, L.P.
|
|
Form
10-Q, Ex. 10(a), September 30, 2004.
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the TCC 2006Annual Report (for the fiscal
year ended
December 31, 2006) which are incorporated by reference in this
filing.
|
|
|
21
|
|
List
of subsidiaries of TCC.
|
|
AEP
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: TNC‡ File
No. 0-340
|
|
|
3(a)
|
|
Restated
Articles of Incorporation, as amended, and Articles of Amendment
to the
Articles of Incorporation.
|
|
1996
Form 10-K, Ex 3.5.
|
3(b)
|
|
Articles
of Amendment to Restated Articles of Incorporation of TNC dated
December
17, 2002.
|
|
2002
Form 10-K; Ex 3(b).
|
3(c)
|
|
By-Laws
of TNC (amended as of May 1, 2000).
|
|
Form
10-Q, Ex 3.4, March 31, 2000.
|
4(a)
|
|
Indenture
(for unsecured debt securities), dated as of February 1, 2003,
between TNC
and Bank One, N.A., as Trustee.
|
|
2003
Form 10-K, Ex 4(b).
|
4(b)
|
|
First
Supplemental Indenture, dated as of February 1, 2003, between TNC
and Bank
One, N.A., as Trustee, establishing the terms of 5.50% Senior Notes,
Series A, due 2013 and 5.50% Senior Notes, Series D, due 2013.
|
|
2003
Form 10-K, Ex 4(c).
|
10(a)
|
|
Transmission
Coordination Agreement, dated October 29, 1998, among PSO, TCC,
TNC,
SWEPCo and AEPSC.
|
|
2002
Form 10-K; Ex 10(b).
|
*12
|
|
Statement
re: Computation of Ratios.
|
|
|
*13
|
|
Copy
of those portions of the TNC 2006 Annual Report (for the fiscal
year ended
December 31, 2006) which are incorporated by reference in this
filing.
|
|
|
*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.