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 filero	Non-accelerated filero
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 filero	Non-accelerated filerx
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 registrantsas 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 andNote 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 tocustomer 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:

·   weather conditions;

·   seasonality;

·   power usage;

·   illiquid markets;

·   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;

·   labor disputes;

·   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 Analysisof 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.

AEP Generating 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
* 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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 theCompanies 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:AEGCoFile 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 System Senior Officer Annual Incentive Compensation Plan	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.

EX-10.(J)(1)

  
    
      AEP Retainer Deferral Plan, Amended






  
    

EX-10.(J)(2)(A)

EXHIBIT 10(j)(2)(A)

First Amendment to

American Electric Power Company, Inc.

Stock Unit Accumulation Plan

For Non-Employee Directors

(As Amended December 10, 2003)

This Amendment is made to the American Electric Power Company, Inc. Stock Unit Accumulation Plan For Non-Employee Directors (the “Plan”) to clarify the manner in which the provisions for the payment of a Participant’s Account have been modified to better assure compliance with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended.

1.New Sections 3.17 and 3.18 are added to the Plan to read as follows:

“3.17“First Date Available” means the date of the Participant’s Termination.

3.18“Code” means the Internal Revenue Code of 1986, as amended.”

2.Article 6 of the Plan is amended effective January 1, 2005 to read as follows:

“Article 6

Payment of Stock Units

6.1Manner of Payment Upon Termination

(a)   All amounts credited to a Participant’s Account shall be paid to the Participant in accordance with the Participant’s effective election in one of the following forms

(i)   A single lump sum distribution

(A)   as of the First Date Available; or

(B)   as of the fifth anniversary of the First Date Available; or

(ii)   In five (5) annual installments commencing

(A)   as of the First Date Available; or

(B)   as of the fifth anniversary of the First Date Available; or

(iii)   In ten (10) annual installments commencing as of the First Date Available.

(b)   For this purpose, a Participant’s election under Section 6.1 shall not be effective unless all of the following requirements are satisfied.

(i)   The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

(ii)   The election is submitted timely. For purposes of this Section 6.1(b)(ii), a distribution election will be considered “timely” only if it satisfies the requirements of (A), (B) or (C), below, as may be applicable:

(A)   Within 30 days after the beginning of his or her initial term of office as a Director; or

(B)   During the 2007 Distribution Election Period, but only with regard to the last distribution election form submitted by such Participant during such a period as is applicable to that Participant. For this purpose, the “2007 Distribution Election Period” shall be such period during which one or more Participants are given the opportunity to select among the options set forth in Section 6.1(a), provided that such period shall end no later than December 31, 2007 or, with respect to a particular Participant, such earlier date of such Participant’s Termination; or

(C)   At least one year prior to the date of the Participant’s Termination.

(iii)   Unless submitted under the terms and conditions described in Section 6.1(b)(ii)(A) or (B), the election makes a permissible change in the distribution option selected. A change in the distribution option will be considered permissible for purposes of the immediately preceding sentence only if the new distribution election selects an option that results in the deferral of the first scheduled payment by at least 5 years. For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 6.1(a) shall be treated as a single payment as of the first scheduled payment date.

(iv)   If the Participant is submitting the election pursuant to paragraph (b)(ii)(B) to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account, the newly selected option may not defer payments that the Participant would have received in 2007 if not for the new distribution election nor cause payments to be made in 2007 if not for the new distribution election.

(c)   For purposes of this Section 6.1(b), if a Participant’s effective distribution election form was submitted using the options that had been made available under the Plan as in effect prior to January 1, 2005 [i.e., as either (A) a single lump-sum payment, or in annual installment payments over not more than ten years; (B) commencing within 10 days after the date of the Participant’s Termination or up to five years after the Participant’s Termination], then:

(i)   If the Participant’s Termination occurs prior to the expiration of the 2007 Distribution Election Period last applicable to the Participant, the Participant’s effective distribution election form shall be given full effect; and

(ii)   If the Participant’s Termination occurs after the expiration of the 2007 Distribution Election Period last applicable to such Participant, the Participant shall be considered to have elected the corresponding option as set forth in Section 6.1(a).

(d)   If a Participant fails to submit an effective distribution election with regard to his Account that satisfies the requirements of Section 6.1(b)(ii)(A) (upon commencement of initial term) or Section 6.1(b)(ii)(B) (during an applicable 2007 Distribution Election Period), as applicable, by the applicable due date, such Participant shall be considered to have elected a distribution of his or her Account in a single lump sum as of the First Date Available.”

6.2Manner of Payment Upon Death

Notwithstanding the Participant’s election, if a Participant dies while amounts remain credited to the Participant’s Account, the balance of the Account will be paid in a lump sum in cash as soon as reasonably practicable after the date of the Participant’s death to the Beneficiary or the Participant’s estate, as the case may be.

6.3Determination of Cash Payments Attributable to Stock Units

The amount to be distributed pursuant to Section 6.1 or 6.2 shall be based upon the value of the Stock Units in the Participant’s Account determined as of the applicable distribution date (or, if that is not a business day, then as of the next business day thereafter) and shall be paid to such Participant as soon as administratively practicable thereafter. The value of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the applicable distribution date.

6.4Avoiding Violation of Applicable Law

Notwithstanding any provision of this Article to the contrary, payment to a Participant will be delayed at any time that the Company reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Company reasonably anticipates that the making of such payment will not cause such violation.”

3.The definition of “Change in Control” set forth in Article 10 of the Plan is amended effective January 1, 2005 to read as follows:

“A “Change in Control” means a change in control of the Company as provided under Section 409A(a)(2)(A)(v) of the Code.”

Signed this 9th day of February, 2007.

AMERICAN ELECTRIC POWER COMPANY, INC.

By          /s/ Jeffrey D. Cross

Jeffrey D. Cross, Assistant Secretary

EX-10.(K)(2)

EXHIBIT 10(k)(2)

AMERICAN ELECTRIC POWER SYSTEM

SUPPLEMENTAL RETIREMENT SAVINGS PLAN

AMENDED AND RESTATED AS OF JANUARY 1, 2005

ARTICLE I

Purposes and Effective Date

1.1 The American Electric Power System Supplemental Retirement Savings Plan is established to provide to eligible employees a tax-deferred savings opportunity otherwise not available to them under the terms of the American Electric Power System Retirement Savings Plan because of contribution restrictions imposed by the Internal Revenue Code.

1.2 The original effective date of the American Electric Power System Supplemental Retirement Savings Plan is January 1, 1994. The Plan was most recently amended and restated effective January 1, 2005 pursuant to a document that was signed on June 16, 2005 and then subsequently changed pursuant to an Amendment that was signed on December 19, 2005. Except as otherwise specified herein, the effective date of this Amended and Restated American Electric Power System Supplemental Retirement Savings Plan is January 1, 2005.

ARTICLE II

DEFINITIONS

2.1 “Account” means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Contributions allocated to a Participant's Account and to record any related Investment Income on the Fund or Funds selected by the Participant. The portion of the Account attributable to Compensation earned and vested prior to January 1, 2005 (excluding, for this purpose incentive compensation attributable to 2004 that was subject to discretionary adjustment and first available for payment subsequent to December 31, 2004) shall be referred to as the Participant’s “Legacy SRSP Account Balance.” The portion of the Account attributable to Compensation other than that described in the immediately preceding sentence shall be referred to as the Participant’s “Active SRSP Account Balance.”

2.2 “Applicable Federal Rate” means 120% of the applicable federal long-term rate, with monthly compounding (as prescribed under Section 1274(d) of the Code), published for the December immediately prior to the Plan Year.

2.3 “Claims Reviewer” means the person or committee designated by American Electric Power Service Corporation (or by a duly authorized person) as responsible for the review of claims for benefits under the Plan in accordance with Section 7.1. Until changed, the Claims Reviewer shall be the Director - Compensation and Executive Benefits.

2.4 “Code” means the Internal Revenue Code of 1986, as amended from time to time.

2.5 “Committee” means the committee designated by American Electric Power Service Corporation (or by a duly authorized person) as responsible for the administration of the Plan.

2.6 “Company” means the American Electric Power Service Corporation and its subsidiaries and affiliates.

2.7 “Company Contributions” means the matching contributions made by the Company pursuant to section 3.2.

2.8 “Compensation” means the sum of a Participant's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e)(3) of the Code and contributions to this Plan, overtime pay and incentive compensation paid pursuant to the terms of annual incentive compensation plans up to a Plan Year maximum of two million dollars ($2,000,000), but effective only with respect to such sums paid on or after September 1, 2004,¹  provided that Compensation shall not include non-annual bonuses (such as but not limited to project bonuses and sign-on bonuses), severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of base salary, base wage, overtime pay or annual incentive compensation. For this purpose, safety focus payouts shall be considered paid pursuant to the terms of an annual incentive plan, although such payouts may be determined and paid on a quarterly basis. Notwithstanding anything stated in the preceding sentences to the contrary, Compensation shall be determined after any deferral thereof pursuant to the American Electric Power System Stock Ownership Requirement Plan, as amended, or pursuant to a pay reduction agreement under the American Electric Power System Incentive Compensation Deferral Plan, as amended. .

2.9 “Contributions” means, as the context may require, Participant Contributions and Company Contributions.

2.10 “Corporation” means the American Electric Power Company, Inc., a New York corporation.

2.11 “Eligible Employee” means any employee of the Company who is designated by the Company as eligible to participate in this Plan, provided that effective for deferral election periods that begin after June 1, 2005, such employee must be employed at exempt salary grade 28 or higher. Individuals not directly compensated by the Company or who are not treated by the Company as an active employee shall not be considered Eligible Employees.

2.12 “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time.

2.13 “Executive Officer” means Participant who, with respect to AEP, is subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, as amended.

2.14 “First Date Available” or “FDA” means (a) with respect to Key Employees, the last day of the month coincident with or next following the date that is six (6) months after the date of the Participant’s or Former Participant’s Termination; and (b) with respect to all other Participants and Former Participants, the last day of the month coincident with or next following the date that is one (1) month after the date of the Participant’s Termination; provided, however, that the FDA with respect to an Executive Officer shall be no earlier than the December 31 of the calendar year of such Executive Officer’s Termination.

2.15 “Former Participant” means a Participant whose employment has Terminated or a Participant who is no longer an Eligible Employee, but whose Account has a balance greater than zero.

2.16 “Fund” means, except as the Committee may otherwise specify, the Interest Bearing Account andthe investment options made available to participants in the Savings Plan, as revised from time to time. The investment options under the Savings Plan were revised effective on or about July 5, 2006 in connection with a transition of the recordkeeping and trustee services from Fidelity Management Trust Company to affiliates of JP Morgan Chase Bank, NA. The investments made available through the self-directed brokerage account option thereupon being offered under the Savings Plan shall not be available to Participants in this Plan.

2.17 “Investment Income” means with respect to Participant Contributions and Company Contributions the earnings, gains and losses that would be attributable to the investment of such Contributions in a Fund or Funds.

2.18 “Interest Bearing Account” means an investment option to be made available to Participants in this Plan in which the Contributions attributed to this option are credited with interest at the Applicable Federal Rate.

2.19 “Key Employee” means a Participant who, determined as of such time as is consistent with guidance provided under Section 409A(a)(2)(B)(i) of the Code, (a) held the office of Vice President or higher with AEP or one of its subsidiaries or affiliates; (b) was employed at exempt salary grade 34 or higher; or (c) otherwise was determined by the Committee to be a “specified employee” described in Section 409A(a)(2)(B)(i) of the Code.

2.20 “Next Date Available” or “NDA” means the June 30 of the calendar year immediately following the calendar year in which falls the Participant’s Termination.

2.21 “Participant” means an Eligible Employee who elects to defer part or all of his or her Incentive Compensation. Except to the extent otherwise specified in this Plan, references to a Participant shall be considered to include a Former Participant.

2.22 “Participant Contributions” means contributions made by the Participant pursuant to an executed Pay Reduction Agreement subject to the Participant Contribution limits contained in Article III.

2.23 “Pay Reduction Agreement” means an agreement between the Company and the Participant in which the Participant irrevocably elects to reduce his or her Compensation for the Plan Year and the Company agrees to treat the amount of the Compensation reduction as a Participant Contribution to this Plan.

2.24 “Plan” means this American Electric Power System Supplemental Retirement Savings Plan, as amended from time to time.

2.25 “Plan Year” means the twelve-month period commencing each January 1 and ending the following December 31.

2.26 “Savings Plan” means the American Electric Power System Retirement Savings Plan, a plan intended to be qualified under section 401(a) of the Code, as amended from time to time.

2.27 “Termination” means termination of employment with the Company and its subsidiaries and affiliates for any reason; provided, however, that the determination as to the circumstances that will be considered a Termination shall be made in a manner consistent with the requirements imposed under Code 409A(a)(2) and the regulations issued thereunder.

2.28 “2005 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article V, provided that any such period shall end no later than December 31, 2005.

2.29 “2006 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article V, provided that any such period shall end no later than December 31, 2006.

ARTICLE III

PARTICIPATION

3.1 An Eligible Employee shall become a Participant by timely submitting a Pay Reduction Agreement during an applicable deferral election period to defer part of the Eligible Employee’s Compensation to which such election relates. The Pay Reduction Agreement shall be in such form as may reasonably be required by the Committee and shall be executed at the time and in the manner prescribed by the Committee.

3.2 For purposes of Section 3.1, the election period during which Compensation may be subject to an effective deferral election shall be determined as follows:

(a)To the extent that the Compensation is “performance-based compensation” (within the meaning of Section 409A(a)(4)(B)(iii) of the Code) that is based on services performed over a period of at least 12 months, the election period shall end no later than six (6) months before the end of the performance period.

(b)To the extent that the Compensation is not described in paragraph (a), the election period shall end on or before December 31 of the calendar year prior to the year in which the services on which the Compensation is based are to be performed.

(c)Notwithstanding (a) and (b), in the case of the first year in which an Eligible Employee becomes eligible to participate in the Plan, the election period shall end within 30 days after the date such Eligible Employee became eligible to participate and such election shall apply only with respect to services to be performed subsequent to the election.

No election shall be effective to defer any Compensation that would otherwise be paid to the Participant before the period for which the Pay Reduction Agreement is effective.

Notwithstanding the foregoing, the deferral election period for an Eligible Employee identified by the Company as having an inadequate opportunity to enroll in the Plan with regard to the 2005 calendar year shall be extended into January 2005, provided that such election shall be applied only to Compensation that had not been paid nor become payable at the time the election is submitted.

3.3 If a deferral election is not made by the end of the election period prescribed by the Company with regard to certain Compensation that may be earned by an Eligible Employee, no portion of such Compensation shall be deferred for such Eligible Employee.

3.4 Participant Contributions made by a Participant pursuant to an executed Pay Reduction Agreement shall be made by payroll deductions from such Compensation payable to the Participant to which the Pay Reduction Agreement relates. Participant Contributions are to be made in multiples of one (1) whole percentage of Compensation, not to exceed 20 percent of Compensation for any pay date. The maximum Participant Contribution for any pay date shall not exceed the difference between (a) twenty percent (20%) of the Participant's Compensation for the pay date, and (b) the aggregate amount of the Participant's Before-Tax and After-Tax contributions to the Savings Plan for the same pay date.

3.5 Subject to the limitation contained in section 3.6, the Company shall credit to the Plan on behalf of each Participant an amount equal to 75% of the amount contributed to the Plan by the Participant, not in excess of 6% of a Participant's Compensation as of each pay date.

3.6 The amount of Company Contributions credited to the Plan on behalf of a Participant in combination with the contributions made by the Company to the Savings Plan on behalf of the Participant as of each pay date during a Plan Year, shall, in the aggregate be equal to the lesser of (a) 75% of the Participant Contributions made by the Participant to this Plan and the Savings Plan as of that pay date, or (b) 4.5% of the Participant's Compensation paid as of that pay date. If the aggregate contributions exceed the lesser limitation described in the preceding sentence, the Company Contributions credited to the Participant's Account under this Plan shall be reduced until the aggregate Company Contributions made under both the Savings Plan and this Plan do not exceed the limitation.

3.7 Participant Contributions and Company Contributions shall be credited to the Participant’s Account as follows:

(a)Contributions related to Compensation that had been earned and vested prior to January 1, 2005 have been credited to the Participant’s Legacy SRSP Account Balance. No additional Contributions shall be credited to a Legacy SRSP Account Balance.

(b)Contributions related to Compensation that is earned or vested on or after January 1, 2005 shall be credited to the Participant’s Active SRSP Account Balance. This shall include the Contributions under this Plan relating to incentive compensation attributable to 2004 that was subject to discretionary adjustment and first available for payment subsequent to December 31, 2004.

3.8The Termination (or any subsequent re-employment) of a Participant after such Participant has submitted an election to defer any Compensation shall not affect the terms of such election with respect to the Compensation to which such election relates, subject, however, to the provisions for the distribution of any such deferred Compensation pursuant to the provisions of Article V.

ARTICLE IV

INVESTMENT OF CONTRIBUTIONS

4.1 Participant Contributions and Company Contributions (without regard to whether such Contributions have been allocated to such Participant’s Legacy SRSP Account Balance or Active SRSP Account Balance) shall be credited with earnings as if invested in the Funds selected by the Participant. To the extent the Participant fails to select Funds for the investment of Contributions under the Plan, the Participant shall be deemed to have selected the Interest Bearing Account. The Participant may change the selected Funds by providing notification in accordance with the Plan’s procedures. Any change in the Funds selected by the Participant shall be implemented in accordance with the Plan’s procedures.

4.2 A Participant may elect to transfer all or a portion of the amounts credited to his Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan’s procedures. Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan’s procedures.

4.3 The amount credited to each Participant's Account shall be determined daily based upon the fair market value of the Fund or Funds to which that Account is allocated. The fair market value calculation for a Participant's Account shall be made after all Contributions, withdrawals, distributions, Investment Income and transfers for the day are recorded. A Participant’s Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Account is zero and the Committee anticipates no additional Contributions from such Participant.

4.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the Contributions credited to a Participant's Account and the investment of those Contributions in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company. In the event that the Company becomes insolvent, the Participants shall be considered as general unsecured creditors of the Company. The Participant’s rights to benefits under this Plan shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge encumbrance, attachment or garnishment by creditors of any Participant or any beneficiary.

ARTICLE V

DISTRIBUTIONS

5.1Upon a Participant’s termination of employment with the Company and its subsidiaries and affiliates for any reason, the Company shall cause the Participant to be paid the full amount credited to his or her Account in accordance with the following rules:

(a)Legacy SRSP Account Balance. Amounts that are credited to the Participant's Legacy SRSP Account Balance:

(1) Shall be distributed to the Participant in one of the following optional forms as selected by the Participant:

(A) A single lump-sum payment, or

(B) In annual installment payments over not less than two nor more than ten years.

(2) Shall be paid in the form of distribution selected by the Participant pursuant to paragraph (1) shall commence within 60 days after the date elected by the Participant on an effective distribution election form. Such date elected by the Participant shall be either (A) the date of the Participant’s Termination (provided, however, if the Participant was an Executive Officer at the time of his or her Termination, the earliest commencement date (for account valuation purposes) shall be December 31 of the year of such Executive Officer’s Termination) or (2) the first, second, third, fourth or fifth anniversary of the Participant’s Termination, as selected by the Participant.

Each Participant shall select the form of distribution [as set forth in paragraph (1)] and benefit commencement date [as set forth in paragraph (2)] with regard to the amounts that are credited to the Participant's Legacy SRSP Account Balance when the Participant first elects to participate in the Plan. The Participant may amend his or her distribution election with regard to amounts that are credited to the Participant's Legacy SRSP Account Balance at any time prior to the date that is at least twelve (12) months prior to the Participant's Termination by submitting a distribution election form in accordance with the Plan’s procedures. If the Participant has not submitted an effective distribution election with regard to amounts that are credited to the Participant's Legacy SRSP Account Balance at the time of his Termination, the distribution of the amounts that are credited to the Participant's Legacy SRSP Account Balance shall be in the form of a single lump sum payment made within 60 days after the Participant's Termination. Notwithstanding the preceding sentence, distribution to a Participant who was an Executive Officer at the time of his Termination, but who has not submitted an effective distribution election with regard to amounts that are credited to the Participant's Legacy SRSP Account Balance at the time of his Termination, shall be in the form of a single lump sum payment within 60 days after the December 31 of the calendar year of the Participant’s Termination.

(b)Active SRSP Account Balance. With regard to the Participant’s Active SRSP Account Balance the following rules shall apply:

(1) Form of Distribution. The Company shall cause the Participant to be paid the full amount credited to his or her Active SRSP Account Balance in accordance with his or her effective election in one of the following forms:

(A) A single lump sum distribution

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(B) In five (5) annual installments commencing

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(C) In ten (10) annual installments commencing.

(i) as of the First Date Available; or

(ii) as of the Next Date Available.

(2) Effective Election. For this purpose, a Participant’s election with respect to the distribution of his or her Active SRSP Account Balance shall not be effective unless all of the following requirements are satisfied.

(A) The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

(B) The election is submitted timely. For purposes of this paragraph, a distribution election will be considered “timely” only if it is submitted prior to the Participant’s Termination and it satisfies the requirements of (i), (ii), (iii) or (iv), below, as may be applicable:

(i) Submitted within the applicable election period (as determined in accordance with Section 3.2), but only if the distribution election is submitted in connection with the Participant’s initial deferral election under this Plan; or

(ii) Submitted during the 2005 Distribution Election Period, but only with regard to the first distribution election form submitted by such Participant during that period; or

(iii) Submitted during the 2006 Distribution Election Period by a Participant who then has an Active SRSP Account Balance but who was not an Eligible Employee for purposes of a deferral election for 2006 by reason of the change in the definition of Eligible Employee set forth in Section 2.11, but only with regard to the last distribution election form submitted by such Participant during that period; or

(iv) If the Participant is submitting the election to change the timing or form of distribution that is then in effect with respect to the Participant’s Active SRSP Account Balance other than an effective distribution election submitted as part of the 2005 Distribution Election Period or 2006 Distribution Election Period, such election must be submitted at least one year prior to the date of the Participant’s Termination.

(C) If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iv) to change the timing or form of distribution that is then in effect with respect to the Participant’s Active SRSP Account Balance (i.e., the Participant is not submitting an election with his initial deferral election [(B)(i)] nor during the 2005 or 2006 Distribution Election Period [(B)(ii) & (B)(iii)], the newly selected option must result in the further deferral of the first scheduled payment from the Participant’s Active Account balance by at least 5 years. For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 5.1(b)(1) shall be treated as a single payment as of the first scheduled payment date. The requirement included in the prior plan document that the newly elected option not result in the acceleration of any scheduled payment under the replaced option shall be disregarded.

(D) If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Active SRSP Account Balance, the newly selected option may not defer payments that the Participant would have received in 2006 if not for the new distribution election nor cause payments to be made in 2006 if not for the new distribution election.

(3) If a Participant fails to submit an effective distribution election with regard to his Active SRSP Account Balance that satisfies the requirements of Section 5.1(b)(2)(B)(i) (with his timely initial deferral election) or Section 5.1(b)(2)(B)(ii) (during the 2005 Distribution Election Period) or Section 5.1(b)(2)(B)(iii) (during the 2006 Distribution Election Period), as applicable, by the date of such initial deferral election or the last day of the 2005 or 2006 Distribution Election Period, respectively, as applicable, such Participant shall be considered to have elected a distribution of his or her Active SRSP Account Balance in a single lump sum as of the First Date Available.

(4) Notwithstanding any other provision of this Plan to the contrary, if a Participant whose Termination occurs on or before June 30, 2005 fails to submit an effective distribution election with regard to his Active SRSP Account Balance that satisfies the requirements of this Section 5.1(b), the deferral election with respect to Contributions credited to such Participant’s Active SRSP Account Balance shall terminated and the entire balance of such Participant’s Active SRSP Account Balance shall be distributed to such Participant in a single lump sum as soon as administratively practicable after the Termination of such Participant.

5.2(a)For purposes of this Article, the amount to be distributed to a Participant shall be based upon the value of such individual’s Legacy SRSP Account Balance or Active SRSP Account Balance (as applicable) determined as of the applicable distribution date (or, if that is not a business day, then as of the immediately preceding business day) and shall be paid to such individual as soon as administratively practicable thereafter.

(b)Notwithstanding any other provision of this Article,

(1) if the Aggregate Account of a Participant who is not a Key Employee is $10,000 or less on the date of the Participant’s Termination, the full value of the Account shall be distributed as of the First Date Available in a single, lump sum distribution regardless of the form elected by such Participant, provided that all similar arrangements taken into account in determining the Aggregate Account also provide for such a lump sum distribution that is paid on or before the later of (i) December 31 of the calendar year in which occurs the Participant’s Termination, or (ii) the 15th day of the third month following the Participant’s Termination. For this purpose, the term “Aggregate Account” means the entirety of the Participant’s interest in this Plan as well as all other similar arrangements that would constitute a nonqualified deferred compensation plan for purposes of Code Section 409A and the regulations issued thereunder. Provided, however,

(2) payment to a Participant under any provision of this Plan will be delayed at any time that the Committee reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Committee reasonably anticipates that the making of such payment will not cause such violation.

5.3 If an annual distribution is selected, the amount to be distributed in any one-year shall be determined by dividing the Participant’s Legacy SRSP Account Balance or Active SRSP Account Balance (as appropriate) by the number of years remaining in the elected distribution period. The Participant electing annual distributions shall have the right to direct changes in the investment of the Account in a Fund or Funds in accordance with Article IV until the amount credited to the Account is reduced to zero.

ARTICLE VI

BENEFICIARIES

6.1 Each Participant may designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission of a beneficiary designation shall be made by the Participant’s completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee. A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee. If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect. If a Participant fails to designate a beneficiary, or if none of the beneficiaries named by the Participant survive the Participant, the Participant’s Account will be paid to the Participant’s estate. Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant’s death, the designation of a Participant’s spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant’s marriage to that spouse.

6.2 Distribution to a Participant’s beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution.

ARTICLE VII

CLAIMS PROCEDURE

Section 7.1The following procedures shall apply with respect to claims for benefits under the Plan.

(a)Any Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Claims Reviewer, specifying the basis for the claim. The Claims Reviewer shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Claims Reviewer determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

(b)If the Claims Reviewer renders an adverse benefit determination under paragraph (a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant:

(1) the specific reasons for the denial of the claim;

(2) specific reference to the provisions of the Plan upon which the denial of the claim was based;

(3) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and

(4) an explanation of the review procedure specified in Section 7.2, and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.

Section 7.2The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.

(a)Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant’s claim for benefits. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant’s case in person or by an authorized representative at such hearing.

(b)The claimant shall be notified of the Committee’s benefit determination on review within sixty days after receipt of the claimant’s request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

(c)The Committee shall provide a claimant with written or electronic notification of the Plan’s benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant:

(1) the specific reason(s) for the adverse determination;

(2) reference to the specific provisions of the Plan on which the determination was based;

(3) a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits; and

(4) a statement of the claimant’s right to bring an action under Section 502(a) of ERISA.

ARTICLE VIII

ADMINISTRATION

8.1 The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan; (ii) to establish reasonable procedures with which Participants must comply to exercise any right or privilege established hereunder; and (iii) to be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.

8.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

8.3 The Company shall maintain, or cause to be maintained, records showing the individual balances of each Participant's Account. Statements setting forth the value of the amount credited to the Participant's Account as of a particular date shall be made available to each Participant no less often than quarterly. The maintenance of the Account records and the distribution of statements may be delegated to a recordkeeper by either the Company or the Committee.

ARTICLE IX

AMENDMENT OR TERMINATION

The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of Contributions under the Plan. Notwithstanding the foregoing provisions of this Article, no modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant or beneficiary under the Plan as of the date of such modification, termination, discontinuance or suspension.

ARTICLE X

MISCELLANEOUS

10.1 Nothing in the Plan shall (a) interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time; nor (b) confer upon a Participant any right to continue in the employ of the Company.

10.2 In the event the Committee, in its sole discretion, shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary.

10.3 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold from any distribution hereunder all amounts determined by the Company as required by law or otherwise as determined by the Company to be then due and payable by the Participant or his beneficiary to the Company.

10.4 The Company intends the following with respect to this Plan: (1) Section 451(a) of the Code would apply to the Participant's recognition of gross income as a result of participation herein; (2) the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received; (3) the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed; (4) the provisions of Parts 2, 3, and 4 of Subtitle B of Title I of ERISA shall not be applicable; and (5) the design and administration of the Plan are intended to comply with the requirements of Section 409A of the Code, to the extent such section is effective and applicable to amounts deferred hereunder. However, no Eligible Employee, Participant, Former Participant, beneficiary or any other person shall have any recourse against the Corporation, the Company, the Committee or any of their affiliates, employees, agents, successors, assigns or other representatives if any of those conditions are determined not to be satisfied.

10.5 The Plan shall be construed and administered according to the applicable provisions of ERISA and the laws of the State of Ohio.

American Electric Power Service Corporation has caused this amendment and restatement of the American Electric Power System Supplemental Retirement Savings Plan to be signed as of this 28th day of December, 2006.

AMERICAN ELECTRIC POWER SERVICE CORPORATION

By:/s/ Genevieve A. Tuchow

Genevieve A. Tuchow

Vice President, Human Resources

¹   Such limitation on Compensation is an increase from the $1,000,000 limitation that had been in effect with respect to such sums paid prior to September 1, 2004.

EX-10.(L)(6)

EXHIBIT 10(l)(6)

Mr. John B. Keane

49 Bainbridge Rd

West Hartford, CT 06119

June 14, 2004

Dear Jack,

Per our prior discussions, I’m very interested in having you as a key executive on the management team at AEP. I would like you to become our Senior Vice President, General Counsel and Secretary. In this position you would report directly to me and your office would be located in our corporate headquarters in Columbus, Ohio. Your start date would be July 1 or earlier if you are available.

As discussed, your salary would initially be $350,000, reviewed annually, and you would participate in an annual incentive compensation plan with an incentive target of 50% of your base earnings. Actual annual incentive awards may range from 0 - 200% of your incentive target and awards are generally paid by the middle of March after year-end results are confirmed and awards approved.

You would also receive 15,000 AEP restricted stock units upon hire. These would vest, subject to your continued AEP employment, in one-third increments on the first through the third anniversary of the grant date.

You would also be eligible to participate in our Long-Term Incentive Plan. This plan currently provides a mix of stock options and performance shares with the awards granted toward the end of the year following approval by the Human Resources Committee of AEP’s Board of Directors.

Should you find this offer acceptable, we would need to continue the employment process. Melinda Ackerman, our SVP of Human Resources, would need to contact you to finalize the employment process (application, physical examination and drug test) and would provide a summary of AEP’s executive benefits, discuss temporary housing, relocation benefits, etc.

I look forward to hearing from you.

Sincerely,

/s/ Michael G. Morris

Michael G. Morris

C: Melinda S. Ackerman

Mr. John B. Keane

49 Bainbridge Rd

West Hartford, CT 06119

June 17, 2004

Dear Jack:

In reply to your letter of June 16 and the discussion with Melinda Ackerman, in addition to the provisions of my employment offer to you dated June 14, we will provide the following:

1. You will be eligible for a lump-sum severance payment, less applicable tax withholdings, equal to your annual base salary in effect on the date of your termination if, for any reason other than cause, the company terminates your employment with AEP within three years of your date of hire. Such payment would be conditioned upon your agreement to release AEP from any and all claims involving your employment with or termination from AEP.

2. As a key AEP executive you will also be eligible for AEP’s Change-in-Control Agreement. While this agreement is currently being revised due to a recently passed shareholders’ proposal, a confirmation letter and the document will be provided upon revision and approval by the Human Resources Committee of the AEP Board of Directors.

3. In recognition of your prior experience, your cash balance account under the pension plans shall be credited with an amount such that the total cash credit under these plans (the AEP Retirement Plan and the AEP Excess Benefit Plan) shall be the maximum permitted under such plans as amended from time to time (currently 8.5%) on all eligible earnings. Eligible earnings may not currently exceed the greater of $1,000,000 or two time your base rate, annually. All other provisions of the two plans as in effect from time to time shall apply to your participation therein. The specifics of each of the benefit plans will be provided and reviewed with you by the Human Resources staff.

I believe this addresses your concerns. However, please feel free to give us a call should there be additional questions. I look forward to seeing you on July 1.

Sincerely,

/s/ Michael G. Morris

Michael G. Morris

C: Melinda S. Ackerman

EX-10.(O)

EXHIBIT 10(o)

AMERICAN ELECTRIC POWER SYSTEM

INCENTIVE COMPENSATION DEFERRAL PLAN

(As Amended and Restated Effective January 1, 2005)

ARTICLE I

PURPOSE AND EFFECTIVE DATE

1.1 The American Electric Power System Incentive Compensation Deferral Plan (the “Plan”) was established by American Electric Power Service Corporation and such subsidiaries and affiliates designated by the Company for participation in the Plan (“AEP”) to allow Eligible Employees to elect to defer receipt of all or a portion of their Incentive Compensation until after their termination of employment.

1.2 The Plan was most recently amended and restated effective January 1, 2005 pursuant to a document that was signed on June 16, 2005. Except as otherwise specifically provided herein, the effective date of the Plan, as amended and restated by this document, is January 1, 2005.

ARTICLE II

DEFINITIONS

2.1 “Account” means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Participant deferrals of Incentive Compensation and to record any related Investment Income on the Fund or Funds selected by the Participant or Former Participant. The portion of the Account attributable to Incentive Compensation earned and vested prior to January 1, 2005 (excluding, for this purpose Incentive Compensation attributable to 2004 that was subject to discretionary adjustment and first available for payment subsequent to December 31, 2004) shall be referred to as the Participant’s “Legacy Account Balance.” The portion of the Account attributable to Incentive Compensation other than that described in the immediately preceding sentence shall be referred to as the Participant’s “Active Account Balance.”

2.2 “Base Compensation” means an employee’s regular annual base salary or wage rate determined without regard to any salary or wage reductions made pursuant to sections 125 or 402(e)(3) of the Code or participant contributions pursuant to a pay reduction agreement under the American Electric Power System Supplemental Retirement Savings Plan, as amended.

2.3 “Claims Reviewer” means the person or committee designated by American Electric Power Service Corporation (or by a duly authorized person) as responsible for the review of claims for benefits under the Plan in accordance with Section 8.1. Until changed, the Claims Reviewer shall be the Director - Compensation and Executive Benefits.

2.4 “Code” means the Internal Revenue Code of 1986 as amended from time to time.

2.5 “Committee” means the committee designated by the American Electric Power Service Corporation (or by a duly authorized person) as responsible for the administration of the Plan. Until changed, the Committee shall consist of the employees of the Company holding the following positions: employees of the Company holding the following positions: head of the Human Resources department (currently, Vice President Human Resources); the employee to whom the head of the Human Resources department reports (currently, Executive Vice President - Shared Services) and the chief financial officer of the Company. The Committee may authorize any person or persons to act on its behalf with full authority in regard to any of its duties and hereunder other than those set forth in Section 8.2.

2.6 “Company” means American Electric Power Service Corporation.

2.7 “Eligible Employee” means any employee of AEP is designated by the Company as eligible to participate in this Plan, provided that effective for deferral election periods that begin after January 1, 2005, such employee must be employed at exempt salary grade 28 or higher. Individuals not directly compensated by AEP or who are not treated by AEP as an active employee shall not be considered Eligible Employees.

2.8 “Executive Officer” means Participant who, with respect to AEP, is subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, as amended.

2.9 “First Date Available” or “FDA” means (a) with respect to Key Employees, the last day of the month coincident with or next following the date that is six (6) months after the date of the Participant’s or Former Participant’s Termination; and (b) with respect to all other Participants and Former Participants, the last day of the month coincident with or next following the date that is one (1) month after the date of the Participant’s Termination; provided, however, that the FDA with respect to an Executive Officer shall be no earlier than the December 31of the calendar year of such Executive Officer’s Termination.

2.10 “Former Participant” means a Participant whose employment with AEP has terminated or a Participant who is no longer an Eligible Employee, but whose Account has a balance greater than zero.

2.11 “Fund” means the investment options made available to participants in the American Electric Power System Retirement Savings Plan, as revised from time to time, except as the Committee may specify otherwise. The investment options under the American Electric Power System Retirement Savings Plan were revised effective on or about July 5, 2006 in connection with a transition of the recordkeeping and trustee services from Fidelity Management Trust Company to affiliates of JP Morgan Chase Bank, NA. The investments made available through the self-directed brokerage account option thereupon being offered under the American Electric Power System Retirement Savings Plan shall not be available to Participants in this Plan.

2.12 “Incentive Compensation” means incentive compensation payable pursuant to the terms of annual and long-term incentive compensation plans approved by the Committee for inclusion in the Plan, provided that such incentive compensation shall be determined (a) without regard to (i) any salary or wage reductions made pursuant to sections 125 or 402(e)(3) of the Code or (ii) participant contributions pursuant to a pay reduction agreement under the American Electric Power System Supplemental Retirement Savings Plan, as amended, but (b) after any deferral thereof pursuant to the American Electric Power System Stock Ownership Requirement Plan, as amended. Incentive Compensation will not include Base Compensation, non-annual bonuses compensation (such as but not limited to project bonuses and sign-on bonuses), severance pay, or relocation payments.

2.13 “Investment Income” means, with respect to Incentive Compensation deferred under this Plan, the earnings, gains and losses that would be attributable to the investment of such deferrals in a Fund or Funds.

2.14 “Key Employee” means a Participant or Former Participant who, determined as of such time as is consistent with guidance provided under Section 409A(a)(2)(B)(i) of the Code, (a) held the office of Vice President or higher with AEP or one of its subsidiaries or affiliates; (b) was employed at exempt salary grade 34 or higher; or (c) otherwise was determined by the Committee to be a “specified employee” described in Section 409A(a)(2)(B)(i) of the Code.

2.15 “Next Date Available” or “NDA” means the June 30 of the calendar year immediately following the calendar year in which falls the Participant’s Termination.

2.16 “Participant” means an Eligible Employee who elects to defer part or all of his or her Incentive Compensation. Except to the extent otherwise specified in this Plan, references to a Participant shall be considered to include a Former Participant.

2.17 “Plan Year” means the twelve-month period commencing each January 1 and ending the following December 31.

2.18 “Retire” means that a Participant terminates employment with AEP and its subsidiaries and affiliates after both attaining age 55 and the completing five years of service with AEP.

2.19 “Termination” means termination of employment with AEP and its subsidiaries and affiliates for any reason; provided, however, that the determination as to the circumstances that will be considered a Termination shall be made in a manner consistent with the requirements imposed under Code 409A(a)(2) and the regulations issued thereunder.

2.20 “2005 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article VI, provided that any such period shall end no later than December 31, 2005.

2.21 “2006 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article VI, provided that any such period shall end no later than December 31, 2006.

2.22 ”Applicable Tax Payments” means the following types of taxes that AEP may withhold and pay that are applicable to the amount credited to the Participant’s Account:

(a)Federal Insurance Contributions Act (FICA) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2) (the “FICA Amount”);

(b)Income tax at source on wages imposed under Code Section 3401 or the corresponding withholding provisions of applicable state, local and foreign tax laws as a result of the payment of the FICA Amount; and

(c)The additional income tax at source on wages attributable to pyramiding Code Section 3401 wages and taxes;

provided, however, that the total Applicable Tax Payments may not exceed such limits as may be applicable to comply with the requirements of Code Section 409A.

ARTICLE III

ADMINISTRATION

3.1 The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan; (ii) to establish reasonable procedures with which Participants, Former Participant and beneficiaries must comply to exercise any right or privilege established hereunder; and (iii) to be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.

3.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

3.3 The Company shall maintain, or cause to be maintained, records showing the individual balances in each Participant’s Account. Statements setting forth the value of the amount credited to the Participant's Account as of a particular date shall be made available to each Participant no less often than quarterly. The maintenance of the Account records and the distribution of statements may be delegated to a recordkeeper by either the Company or the Committee.

ARTICLE IV

PARTICIPATION

4.1 An Eligible Employee shall become a Participant by making a deferral election during an applicable election period on a form prescribed by the Company to defer part or all of the Eligible Employee’s Incentive Compensation to which such election relates, provided that such election shall not result in the deferral of Incentive Compensation in excess of an amount that allows for the current payment of Applicable Tax Payments.

4.2 For purposes of Section 4.1, the election period during which Incentive Compensation may be subject to an effective deferral election shall be determined as follows:

(a)To the extent that the Incentive Compensation is “performance-based compensation” (within the meaning of Section 409A(a)(4)(B)(iii) of the Code) that is based on services performed over a period of at least 12 months, the election period shall end no later than six (6) months before the end of the performance period.

(b)To the extent that the Incentive Compensation is not described in Section 4.2(a), the election period shall end on or before December 31 of the calendar year prior to the year in which the services on which the Incentive Compensation is based are to be performed.

(c)Notwithstanding (a) and (b), in the case of the first year in which an Eligible Employee becomes eligible to participate in the Plan, the election period shall end within 30 days after the date such Eligible Employee became eligible to participate and such election shall apply only with respect to services to be performed subsequent to the election.

4.3 If a deferral election is not made by the end of the election period prescribed by the Company with regard to certain Incentive Compensation that may be earned by an Eligible Employee, no portion of such Incentive Compensation shall be deferred for such Eligible Employee.

4.4 Incentive Compensation that is deferred under this Plan shall be credited to the Participant’s Account as follows:

(a)Deferred Incentive Compensation that had been earned and vested prior to January 1, 2005 has been credited to the Participant’s Legacy Account Balance. No additional amounts of Incentive Compensation that is deferred under the terms of this Plan shall be credited to a Legacy Account Balance.

(b)Deferred Incentive Compensation that is earned or vested on or after January 1, 2005 shall be credited to the Participant’s Active Account Balance. This shall include the deferral under this Plan of Incentive Compensation attributable to 2004 that was subject to discretionary adjustment and first available for payment subsequent to December 31, 2004.

4.5The Termination (or any subsequent re-employment) of a Participant after such Participant has submitted an election to defer any Incentive Compensation shall not affect the terms of such election with respect to the Incentive Compensation to which such election relates, subject, however, to the provisions for the distribution of any such deferred Incentive Compensation pursuant to the provisions of Article VI.

ARTICLE V

INVESTMENT OF DEFERRED AMOUNTS

5.1 Amounts credited to the Participant’s Account (without regard to whether such Account is allocated to such Participant’s Legacy Account Balance or Active Account Balance) shall be further credited with earnings as if invested in the Funds selected by the Participant. To the extent the Participant fails to select Funds for the investment of Contributions under the Plan, the Participant shall be deemed to have selected the Managed Income Fund option. The Participant may change the selected Funds by providing notification in accordance with the Plan’s procedures. Any change in the Funds selected by the Participant shall be implemented in accordance with the Plan’s procedures.

5.2 A Participant may elect to transfer all or a portion of the amounts credited to his Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan’s procedures. Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan’s procedures.

5.3 The amount credited to each Participant's Account shall be determined daily based upon the fair market value of the Fund or Funds to which that Account is allocated. The fair market value calculation for a Participant's Account shall be made after all deferrals, distributions, Investment Income and transfers for the day are recorded. A Participant’s Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Account is zero and the Committee anticipates no additional contributions from such Participant.

5.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the deferrals credited to a Participant's Account and the investment of those deferrals in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company. In the event that the Company becomes insolvent, the Participants shall be considered as general unsecured creditors of the Company. A Participant’s rights to benefits under this Plan shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge encumbrance, attachment or garnishment by creditors of any Participant or any beneficiary.

ARTICLE VI

DISTRIBUTIONS

6.1 Upon a Participant’s termination of employment with AEP and its subsidiaries and affiliates for any reason, the Company shall cause the Participant or the Former Participant to be paid the full amount credited to his or her Account in accordance with the following rules:

(a)Legacy Account Balance. With regard to the Participant’s Legacy Account Balance

(1) Pre-Retirement Cash-Out. If the Participant has not Retired, the Company shall cause the Participant to be paid the full amount credited to his or her Legacy Account Balance in a single lump sum. The payment shall be made within 60 days after the Participant’s Termination.

(2) Post-Retirement As Elected. If the Participant has Retired, amounts that are credited to the Participant's Legacy Account Balance:

(A) Shall be distributed to the Participant in one of the following optional forms as selected by the Participant:

(i) A single lump-sum payment, or

(ii) In annual installment payments over not less than two nor more than ten years.

(B) Shall be paid in the form of distribution selected by the Participant pursuant to paragraph (A) shall commence within 60 days after the date elected by the Participant on an effective distribution election form. Such date elected by the Participant shall be either (1) the date of the Participant’s Retirement (provided, however, if the Participant was an Executive Officer at the time of his or her Retirement, the earliest commencement date (for account valuation purposes) shall be December 31 of the year of such Executive Officer’s Retirement) or (2) the first, second, third, fourth or fifth anniversary of the Participant’s Retirement, as selected by the Participant.

Each Participant shall be provided the opportunity to select the form of distribution [as set forth in paragraph (A)] and benefit commencement date [as set forth in paragraph (B)] with regard to the amounts that are credited to the Participant's Legacy Account Balance when the Participant first elects to participate in the Plan. The Participant may amend his or her distribution election with regard to amounts that are credited to the Participant's Legacy Account Balance at any time prior to the date that is at least twelve (12) months prior to the Participant's Retirement by submitting a distribution election form in accordance with the Plan’s procedures; provided that a modification to the Participant’s distribution election with regard to amounts that are credited to the Participant's Legacy Account Balance submitted after such 12 month period will be effective if submitted no later than June 30, 2005, but only if the Participant remains employed for at least ninety (90) days following the submission of such distribution election. If the Participant has not submitted an effective distribution election with regard to amounts that are credited to the Participant's Legacy Account Balance at the time of his Retirement, the distribution of the amounts that are credited to the Participant's Legacy Account Balance shall be in the form of a single lump sum payment made within 60 days after the Participant's Retirement. Notwithstanding the preceding sentence, distribution to a Participant who was an Executive Officer at the time of his Retirement, but who has not submitted an effective distribution election with regard to amounts that are credited to the Participant's Legacy Account Balance at the time of his Retirement, shall be in the form of a single lump sum payment within 60 days after the December 31 of the calendar year of the Participant’s Retirement.

(3) One-Time Request for In-Service Withdrawal (Penalty Applies). A Participant shall be entitled to receive, upon a written request to the Committee that is effective between April 1 and December 31 of any Plan Year, a lump sum distribution from his or her Legacy Account Balance of an amount equal to or greater than 25% of the Participant’s Legacy Account Balance as of the date of the request. The date of the request shall be the date the Committee or the Committee’s representative receives the request. The lump sum amount to be paid to the Participant shall be subject to a 10% early withdrawal penalty, which penalty shall reduce the amount to be distributed to the Participant or Former Participant. The Participant or Former Participant shall forfeit the amount of the 10% withdrawal penalty. The lump sum amount shall be paid within 60 days after the Committee receives the withdrawal request. Any Participant who elects to receive a benefit under this paragraph shall not be considered an Eligible Employee with respect to the deferral election periods that apply to such Participant during the three year period that begins as of the date the amount is paid to such Participant under this Section, and such Participant shall not be entitled to request any additional withdrawals under this paragraph prior to the Participant’s termination of employment. Any effective deferral elections that have already been submitted by such participant in accordance with Article IV shall be given full force and effect.

(b)Active Account Balance. With regard to the Participant’s Active Account Balance the following rules shall apply:

(1) Form of Distribution. The Company shall cause the Participant or the Former Participant to be paid the full amount credited to his or her Active Account Balance in accordance with his or her effective election in one of the following forms:

(A) A single lump sum distribution

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(B) In five (5) annual installments commencing

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(C) In ten (10) annual installments commencing.

(i) as of the First Date Available; or

(ii) as of the Next Date Available.

(2) Effective Election. For this purpose, a Participant’s election with respect to the distribution of his or her Active Account Balance shall not be effective unless all of the following requirements are satisfied.

(A) The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

(B) The election is submitted timely. For purposes of this paragraph, a distribution election will be considered “timely” only if it is submitted prior to the Participant’s Termination and it satisfies the requirements of (i), (ii), (iii) or (iv), below, as may be applicable:

(i) Submitted within the applicable election period set forth in Section 4.2, but only if the distribution election is submitted in connection with the Participant’s initial deferral election under this Plan; or

(ii) Submitted during the 2005 Distribution Election Period, but only with regard to the first distribution election form submitted by such Participant during that period; or

(iii) Submitted during the 2006 Distribution Election Period by a Participant who then has an Active Account Balance but who was not an Eligible Employee for purposes of a deferral election for 2006 by reason of the change in the definition of Eligible Employee set forth in Section 2.7, but only with regard to the last distribution election form submitted by such Participant during that period; or

(iv) If the Participant is submitting the election to change the timing or form of distribution that is then in effect with respect to the Participant’s Active Account Balance other than an effective distribution election submitted as part of the 2005 Distribution Election Period or 2006 Distribution Election Period, such election must be submitted at least one year prior to the date of the Participant’s Termination.

(C) If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iv) to change the timing or form of distribution that is then in effect with respect to the Participant’s Active Account Balance (i.e., the Participant is not submitting an election with his initial deferral election [(B)(i)] nor during the 2005 or 2006 Distribution Election Period [(B)(ii) & (B)(iii)], the newly selected option must result in the further deferral of the first scheduled payment from the Participant’s Active Account balance by at least 5 years. For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 6.1(b)(1) shall be treated as a single payment as of the first scheduled payment date. The requirement included in the prior plan document that the newly elected option not result in the acceleration of any scheduled payment under the replaced option shall be disregarded.

(D) If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Active Account Balance, the newly selected option may not defer payments that the Participant would have received in 2006 if not for the new distribution election nor cause payments to be made in 2006 if not for the new distribution election.

(3) If a Participant fails to submit an effective distribution election with regard to his Active Account Balance that satisfies the requirements of Section 6.1(b)(2)(B)(i) (with his timely initial deferral election) or Section 6.1(b)(2)(B)(ii) (during the 2005 Distribution Election Period) or Section 6.1(b)(2)(B)(iii) (during the 2006 Distribution Election Period), as applicable, by the date of such initial deferral election or the last day of the 2005 or 2006 Distribution Election Period, respectively, as applicable, such Participant shall be considered to have elected a distribution of his or her Active Account Balance in a single lump sum as of the First Date Available.

(4) Notwithstanding any other provision of this Plan to the contrary, if a Participant whose Termination occurs on or before June 30, 2005 fails to submit an effective distribution election with regard to his Active Account Balance that satisfies the requirements of this Section 6.1(b), the deferral election with respect to Contributions credited to such Participant’s Active Account Balance shall terminated and the entire balance of such Participant’s Active Account Balance shall be distributed to such Participant in a single lump sum as soon as administratively practicable after the Termination of such Participant.

6.2(a)For purposes of this Article, the amount to be distributed to a Participant or Former Participant shall be based upon the value of such individual’s Legacy Account Balance or Active Account Balance (as applicable) determined as of the applicable distribution date (or, if that is not a business day, then as of the immediately preceding business day) and shall be paid to such individual as soon as administratively practicable thereafter.

(b)Notwithstanding any other provision of this Article,

(i) if the Aggregate Account of a Participant who is not a Key Employee is $10,000 or less on the date of the Participant’s Termination, the full value of the Account shall be distributed as of the First Date Available in a single, lump sum distribution regardless of the form elected by such Participant, provided that all similar arrangements taken into account in determining the Aggregate Account also provide for such a lump sum distribution that is paid on or before the later of (i) December 31 of the calendar year in which occurs the Participant’s Termination, or (ii) the 15th day of the third month following the Participant’s Termination. For this purpose, the term “Aggregate Account” means the entirety of the Participant’s interest in this Plan as well as all other similar arrangements that would constitute a nonqualified deferred compensation plan for purposes of Code Section 409A and the regulations issued thereunder. Provided, however,

(ii) Payment to a Participant under any provision of this Plan will be delayed at any time that the Committee reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Committee reasonably anticipates that the making of such payment will not cause such violation.

6.3 If an annual distribution is selected, the amount to be distributed in any one-year shall be determined by dividing the Participant’s Legacy Account Balance or Active Account Balance (as appropriate) by the number of years remaining in the elected distribution period. The Participant electing annual distributions shall have the right to direct changes in the investment of the Account in a Fund or Funds in accordance with Article V until the amount credited to the Account is reduced to zero.

ARTICLE VII

BENEFICIARIES

7.1 Each Participant may designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission of a beneficiary designation shall be made by the Participant’s completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee. A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee. If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect. If a Participant fails to designate a beneficiary, or if all beneficiaries named by the Participant do not survive the Participant, the Participant’s Account will be paid to the Participant’s estate. Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant’s death, the designation of a Participant’s spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant’s marriage to that spouse.

7.2 Distribution to a Participant’s beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution.

ARTICLE VIII

CLAIMS PROCEDURE

Section 8.1 The following procedures shall apply with respect to claims for benefits under the Plan.

(a)Any Participant or Former Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Claims Reviewer, specifying the basis for the claim. The Claims Reviewer shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Claims Reviewer determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

(b)If the Claims Reviewer renders an adverse benefit determination under Section 8.1(a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant:

(1) The specific reasons for the denial of the claim;

(2) Specific reference to the provisions of the Plan upon which the denial of the claim was based;

(3) A description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and

(4) An explanation of the review procedure specified in Section 8.2, and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.

Section 8.2 The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.

(a)Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant’s claim for benefits. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant’s case in person or by an authorized representative at such hearing.

(b)The claimant shall be notified of the Committee’s benefit determination on review within sixty days after receipt of the claimant’s request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render the benefit determination.

(c)The Committee shall provide a claimant with written or electronic notification of the Plan’s benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant:

(1) The specific reason(s) for the adverse determination;

(2) Reference to the specific provisions of the Plan on which the determination was based;

(3) A statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits; and

(4) A statement of the claimant’s right to bring an action under Section 502(a) of ERISA.

ARTICLE IX

MISCELLANEOUS PROVISIONS

9.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold applicable federal, state and local taxes, Social Security taxes and Medicare taxes from any distribution hereunder to the extent that such taxes are then payable.

9.2 In the event the Committee, in its sole discretion, shall find that a Participant, Former Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary.

9.3 The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of deferral contributions under the Plan.; provided that no such modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant or beneficiary under the Plan as of the date of such modification, termination, discontinuance or suspension.

9.4 Nothing in the Plan shall interfere with or limit in any way the right of AEP to terminate any Participant’s employment at any time, or confer upon a Participant any right to continue in the employ of AEP.

9.5 The Company intends the following with respect to this Plan: (1) Section 451(a) of the Code would apply to the Participant's recognition of gross income as a result of participation herein; (2) the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received; (3) the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed; (4) the provisions of Parts 2, 3, and 4 of Subtitle B of Title I of ERISA shall not be applicable; and (5) the design and administration of the Plan are intended to comply with the requirements of Section 409A of the Code, to the extent such section is effective and applicable to amounts deferred hereunder. However, no Eligible Employee, Participant, Former Participant, beneficiary or any other person shall have any recourse against the Corporation, the Company, the Committee or any of their affiliates, employees, agents, successors, assigns or other representatives if any of those conditions are determined not to be satisfied.

9.6 The Plan shall be construed and administered according to the applicable provisions of ERISA and the laws of the State of Ohio.

American Electric Power Service Corporation has caused this amendment and restatement of the American Electric Power System Incentive Compensation Deferral Plan to be signed as of this 28th day of December, 2006.

AMERICAN ELECTRIC POWER SERVICE CORPORATION

By:/s/ Genevieve A. Tuchow

Genevieve A. Tuchow

Vice President, Human Resources

EX-10.(S)(4)

EXHIBIT 10(s)(4)

AMERICAN ELECTRIC POWER SYSTEM

STOCK OWNERSHIP REQUIREMENT PLAN

(As Amended and Restated Effective January 1, 2005)

ARTICLE I

PURPOSE AND EFFECTIVE DATE

1.1 The Human Resources Committee (“HRC”) of the Board of Directors of American Electric Power Company, Inc. believes that it is critical to AEP’s long-term success to effectively align the long-term financial interests of senior executives with those of AEP’s shareholders and that an effective alignment is best accomplished by substantial, long-term stock ownership. The American Electric Power System Stock Ownership Requirement Plan (the “Plan”) was established by American Electric Power Service Corporation (the “Company”) and such subsidiaries of the Parent Corporation that have Eligible Employees to facilitate the achievement and maintenance of Minimum Stock Ownership Requirements assigned to Eligible Employees.

1.2 The effective date of the Plan, as amended and restated by this document, is January 1, 2005. This document amends and restates the Plan as most recently amended and restated by a document that was executed on June 5, 2006.

ARTICLE II

DEFINITIONS

2.1 “Account” means the separate memo account established and maintained by the Committee (or the recordkeeper employed by the Company) to record the number of Shares and Share Equivalents that have been designated in accordance with the terms of this Plan to satisfy all Minimum Stock Ownership Requirements assigned to a Participant.

2.2 “AEP” means the Parent Corporation and its direct and indirect subsidiaries.

2.3 “Annual Incentive Compensation” means incentive compensation payable pursuant to the terms of an annual incentive compensation plan approved by the Committee for inclusion in the Plan, provided that such annual incentive compensation shall be determined without regard to any salary or wage reductions made pursuant to sections 125 or 402(e)(3) of the Code or participant contributions pursuant to a pay reduction agreement under the American Electric Power System Supplemental Retirement Savings Plan, as amended or the American Electric Power System Incentive Compensation Deferral Plan. Annual Incentive Compensation will not include an employee’s base pay, non-annual bonuses (such as but not limited to project bonuses and sign-on bonuses), severance pay, or relocation payments.

2.4 ”Applicable Tax Payments” means the following types of taxes that AEP may withhold and pay that are applicable to the amount then credited to the Career Share Account:

(a)Federal Insurance Contributions Act (FICA) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2) (the “FICA Amount”);

(b)Income tax at source on wages imposed under Code Section 3401 or the corresponding withholding provisions of applicable state, local and foreign tax laws as a result of the payment of the FICA Amount; and

(c)The additional income tax at source on wages attributable to pyramiding Code Section 3401 wages and taxes;

provided, however, that the total Applicable Tax Payments may not exceed such limits as may be applicable to comply with the requirements of Code Section 409A.

2.5 “Career Share Account” means a separate memo account that is a subset of the Account that is maintained to identify the Career Share Units used to satisfy a Participant’s Minimum Stock Ownership Requirements.

2.6 “Career Share Units” or “Career Shares” means the Share Equivalents tracked in a Participant’s Career Share Account in order to determine whether and when the Participant has satisfied his or her Minimum Stock Ownership Requirements. Phantom stock units that become earned and vested under the Long-Term Incentive Plan represent an example of an award that may become Career Shares under the terms of this Plan. Career Shares also have been referred to as “Phantom Stock Units” in Company communications.

2.7 “Claims Reviewer” means the person or committee designated by the Company (or by a duly authorized person) as responsible for the review of claims for benefits under the Plan in accordance with Section 8.1. Until changed, the Claims Reviewer shall be the Company’s employee who is the head of the Executive Benefits area of the Human Resources department.

2.8 “Code” means the Internal Revenue Code of 1986 as amended from time to time.

2.9 “Committee” means the committee designated by the Company (or by a duly authorized person) as responsible for the administration of the Plan. Until changed, the Committee shall consist of the employees of the Company holding the following positions: chief executive officer of the Company; head of the Human Resources department (currently, Vice President Human Resources); the employee to whom the head of the Human Resources department reports (currently, Executive Vice President - Shared Services) and the chief financial officer of the Company. The Committee may authorize any person or persons to act on its behalf with full authority in regard to any of its duties and hereunder other than those set forth in Section 9.2.

2.10 “Common Stock” means the common stock, $6.50 par value, of the Parent Corporation.

2.11 “Company” means American Electric Power Service Corporation.

2.12 “Eligible Employee” means any employee of AEP who is hired into or promoted to a position that is eligible to be assigned a Minimum Stock Ownership Requirement, and only so long as a Minimum Stock Ownership Requirement applies. At the date of execution of this document, a Minimum Stock Ownership Requirement is assigned to those employees employed at exempt salary grade 36 or higher. An individual who is not directly compensated by AEP or who is not treated by AEP as an active employee shall not be considered an Eligible Employee.

2.13 “First Date Available” or “FDA” means the last day of the month coincident with or next following the date that is six (6) months after the date of the Participant’s Termination.

2.14 “Incentive Compensation Deferral Plan” means the American Electric Power System Incentive Compensation Deferral Plan, as amended from time to time.

2.15 “Long Term Incentive Plan” or “LTIP” means the American Electric Power System Long-Term Incentive Plan, as amended from time to time, including any successor plan or plans. The LTIP that is in effect as of the date this Plan is executed is entitled the “Amended and Restated American Electric Power System Long-Term Incentive Plan - April 26, 2005.”

2.16 “Market Value” means the closing price of a Share, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transactions on the date in question or, if the Share shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded.

2.17 “Minimum Stock Ownership Requirement” or “MSOR” means the targeted aggregate number of Shares and Share Equivalents specified under the terms of this Plan as applicable to the Participant. Participants may be assigned multiple minimum stock ownership requirements. Any MSOR assigned to a Participant shall no longer be applicable to such Participant after the date of the Participant’s Termination.

2.18 “MSOR Window Period” means the period that begins as of the date a particular MSOR is effective with respect to an Eligible Employee (or Participant, with regard to any increase in his or her MSOR) and ends on the five (5) year anniversary of that date.

2.19 “Next Date Available” or “NDA” means the June 30 of the calendar year immediately following the calendar year in which falls the Participant’s Termination.

2.20 “Parent Corporation” means American Electric Power Company, Inc., a New York corporation, and any successor thereto.

2.21 “Participant” is defined in Article IV.

2.22 “Performance-Based Compensation” has the meaning set forth in Section 409A(a)(4)(B)(iii) of the Code.

2.23 “Performance Shares” means performance shares or performance share units (or other similar types of equity incentive compensation) awarded under the American Electric Power System Performance Share Incentive Plan or the Long-Term Incentive Plan. Reference in this Plan to the “12/10/2003 Performance Share Awards” shall be deemed to refer to the Performance Shares that were issued with a grant date of December 10, 2003 and subject to a performance period from December 10, 2003 through December 31, 2004.

2.24 “Phantom Stock Units” are also referred to as “Career Shares.” See definition of “Career Share Units,” above.

2.25 “Plan Year” means the twelve-month period commencing each January 1 and ending the following December 31.

2.26 “Share” means a share of common stock of the Parent Corporation, and includes, but is not limited to, such shares as may be purchased directly by or for the Participant or through the American Electric Power Company, Inc. Dividend Reinvestment and Direct Stock Purchase Plan or issued in connection with the Participant’s performance of services for AEP, such as pursuant to the American Electric Power System Long-Term Incentive Plan.

2.27 “Share Equivalent” is determined by reference to the amount credited to the Participant’s Career Share Account under this Plan and to the Participant’s AEP Stock Fund accounts maintained in connection with the American Electric Power Retirement Savings Plan, the American Electric Power System Supplemental Retirement Savings Plan, and the American Electric Power System Incentive Compensation Deferral Plan. To the extent that the amount credited under these arrangements are not otherwise reported under the terms of the applicable plan as a number of shares of Common Stock, the number of Share Equivalents attributable to such amount shall be determined by dividing the dollar amount so credited by the Market Value of a Share determined as of the applicable valuation date. No certificates shall have been issued with respect to such Share Equivalents.

2.28 “Termination” means termination of employment with AEP and its subsidiaries and affiliates for any reason; provided, however, that the determination as to the circumstances that will be considered a Termination shall be made in a manner consistent with the requirements imposed under Code 409A(a)(2) and the regulations issued thereunder.

2.29 “Vested” means, for purposes of this Plan, that the Participant would not forfeit the Shares or Share Equivalents upon the termination of the Participant’s employment with AEP for reasons other than the Participant’s death.

2.30 “2006 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article VII, provided that any such period shall end no later than December 31, 2006.

ARTICLE III

ADMINISTRATION

3.1 The Plan shall be administered by the Committee. The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan and (ii) to establish reasonable procedures with which Participants, Former Participant and beneficiaries must comply to exercise any right or privilege established hereunder. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.

3.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

3.3 The Company shall maintain, or cause to be maintained, records showing the individual balances in each Participant’s Account, including each Participant’s Career Share Account. Statements setting forth the value of the amount credited to the Participant's Account shall be made available to each Participant no less often than once per year. The maintenance of the Account records and the distribution of statements may be delegated to a recordkeeper by either the Company or the Committee.

ARTICLE IV

PARTICIPATION

An Eligible Employee shall become a Participant as of the date that the Eligible Employee is first assigned a Minimum Stock Ownership Requirement.

ARTICLE V

SATISFACTION OF MINIMUM STOCK OWNERSHIP REQUIREMENT

5.1 Accounts. The Committee shall establish and maintain an Account for each Participant that will record the number of Shares and Share Equivalents that have been designated in accordance with the terms of this Plan to satisfy the Minimum Stock Ownership Requirement applicable to such Participant.

5.2 Share Commitment Designated by Participant.

(a)A Participant may from time to time designate that certain Shares or Share Equivalents that are owned by the Participant or otherwise credited to the Participant be credited to the Account of such Participant. A Participant shall be permitted to so designate any Shares or Share Equivalents only to the extent the following requirements have been satisfied:

(i)   The Shares or Share Equivalents have been earned by the Participant, if applicable;

(ii)   The Shares or Share Equivalents are then Vested;

(iii)   The Shares or Share Equivalents are not automatically allocated to the Participant’s Career Share Account pursuant to Section 5.3, below; and

(iv)   The Shares or Share Equivalents are not encumbered, pledged or hypothecated in any way.

(b)Any designation made by a Participant under this Section shall be made in writing and in a form that is satisfactory to the Committee.

5.3 Accrual of Career Shares.

(a)Determination Date. For purposes of this Section 5.3, the term “Determination Date” means

(i) the date that is six months prior to the end of the performance period, with respect to an award of Performance Shares that qualifies as Performance-Based Compensation and that is based on services performed over a period of at least 12 months; or

(ii) the June 30 that falls within the calendar year to which Annual Incentive Compensation relates (or the date six months prior to the end of the performance period, with respect to Annual Incentive Compensation that is not based on a calendar year), provided that such Annual Incentive Compensation qualifies as Performance-Based Compensation that is based on services performed over a period of at least 12 months; or

(iii) to the extent that the awarded Performance Shares or the Annual Incentive Compensation are not Performance-Based Compensation that is based on services performed over a period of at least 12 months, the later of (A) the December 31 immediately prior to the year in which the services on which the Performance Shares or Annual Incentive Compensation is based are to be performed, or (B) the date the Participant first became an Eligible Employee

(b)Participant Has Not Satisfied MSOR.

(i) If a Participant has not satisfied his or her MSOR on or before the Determination Date applicable to Performance Shares that have been awarded to such Participant, the Participant’s Career Share Account shall be credited with the number of Shares or Share Equivalents that become earned and Vested (reduced, however, to the extent of any Applicable Tax Payments) by the Participant as a result of the award of such Performance Shares; and

(ii) If a Participant has not satisfied the applicable MSOR on or before the Determination Date that falls after the final year of the Participant’s MSOR Window Period, the Participant’s Career Share Account shall be credited with the number of Shares or Share Equivalents, as appropriate, attributable to 25% (50%, effective beginning January 1, 2006) of the Annual Incentive Compensation that becomes earned and Vested by the Participant.

If the same Determination Date applies to both the Performance Shares and the Annual Incentive Compensation for a particular Participant, the determination of whether the Participant has satisfied an applicable MSOR as of that Determination Date shall be made by applying the provisions of subsection (b)(i) of this Section before applying the provisions of subsection (b)(ii) of this Section. The Participant’s Career Share Account shall be credited even if the Participant shall have satisfied his or her MSOR or shall have ceased to remain an Eligible Employee during the period between the Determination Date and the date the Performance Shares or Annual Incentive Compensation are earned and Vested. However, if a Participant shall have no MSOR as of an applicable Determination Date by reason of the Participant’s having ceased to remain an Eligible Employee, the payment or deferral of the amounts that become payable to the Participant relative to Annual Incentive Compensation or as a result of an award of Performance Shares to which such Determination Date applies shall be determined in accordance with other plans and programs as may apply, including, for example, the Incentive Compensation Deferral Plan.

(c)Participant Has Satisfied MSOR. If a Participant has satisfied his or her MSOR on or before the applicable Determination Date, the payment or deferral of the amounts that become payable to the Participant relative to Annual Incentive Compensation or as a result of an award of Performance Shares shall be determined in accordance with other plans and programs as may apply, including, for example, the Incentive Compensation Deferral Plan.

5.4 Holding Requirement For Exercised Stock Options. If a Participant has not satisfied the applicable MSOR on or before the close of the related MSOR Window Period, then, the Participant shall be required to retain until Termination all Shares acquired through stock options exercised by the Participant between the date immediately following the close of such MSOR Window Period until the date the Participant has satisfied such MSOR; provided, however, the Participant shall be permitted to cause the sale of such Shares as would allow the Participant to cover the costs and applicable taxes directly associated with such exercises. However, the retention requirement set forth in this Section 5.4 shall not apply once and so long as the Participant has no MSOR by reason of the Participant’s having ceased to remain an Eligible Employee.

ARTICLE VI

CAREER SHARE ACCOUNT

DIVIDENDS AND ADJUSTMENTS

6.1 Reinvestment of Dividends. Effective on each dividend payment date with respect to the Common Stock, the Career Share Account of a Participant shall be credited with an additional number of whole and fractional Share Equivalents, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Share Equivalents then credited to such Career Share Account, divided by the Market Value on the dividend payment date.

6.2 Adjustments. The number of Share Equivalents credited to a Participant’s Career Share Account shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock.

ARTICLE VII

CAREER SHARE ACCOUNT

DISTRIBUTIONS

7.1 Upon a Participant’s Termination for any reason, the Company shall cause the Participant to be paid the full amount credited to his or her Career Share Account in accordance with the following rules:

(a)Cash or Stock. Payments may be made in cash, shares of Common Stock, or a combination of both as elected by the Participant on a form that is acceptable to the Company and submitted within a reasonable period of time before the distribution is scheduled to commence. Cash payments of Career Shares shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the applicable distribution date (i.e., the Participant’s date of Termination, deferred distribution date, respective installment payment dates or the date of the Participant’s death, as the case may be).

(b)Timing and Form of Distribution. Except as otherwise provided in Section 7.2, the following rules shall apply with regard to the timing and form of the distributions to be made from the Participant’s Career Share Account:

(1) Form of Distribution. The Company shall cause the Participant to be paid the full amount credited to his or her Active Career Share Account in accordance with his or her effective election in one of the following forms:

(A) A single lump sum distribution

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(B) In five (5) annual installments commencing

(i) as of the First Date Available; or

(ii) as of the Next Date Available; or

(iii) as of the fifth anniversary of the First Date Available; or

(iv) as of the fifth anniversary of the Next Date Available; or

(C) In ten (10) annual installments commencing.

(i) as of the First Date Available; or

(ii) as of the Next Date Available.

(2) Effective Election. For this purpose, a Participant’s election with respect to the distribution of his or her Career Share Account shall not be effective unless all of the following requirements are satisfied.

(A) The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

(B) The election is submitted timely. For purposes of this paragraph, a distribution election will be considered “timely” only if it is submitted prior to the Participant’s Termination and it satisfies the requirements of (i), (ii) or (iii), below, as may be applicable:

(i) Submitted no later than the first Determination Date after June 30, 2006 with respect to a Participant who had neither a 12/10/2003 Performance Share Award nor any amount credited to his Career Share Account as of June 30, 2006; or

(ii) Submitted during a 2006 Distribution Election Period that is applicable to the Participant, but only with regard to the distribution election form last submitted by such Participant before the expiration of that period; or

(iii) If the Participant is submitting the election to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account other than an effective distribution election submitted as part of the 2006 Distribution Election Period, such election must be submitted at least one year prior to the date of the Participant’s Termination.

(C) If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account (i.e., the Participant is not submitting an election with his initial applicable Determination Date [(B)(i)] nor during the applicable 2006 Distribution Election Period [(B)(ii)], the newly selected option must result in the further deferral of the first scheduled payment by at least 5 years. For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 7.1(b)(1) shall be treated as a single payment as of the first scheduled payment date.

(D) If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(ii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Career Share Account, the newly selected option may not defer payments that the Participant would have received in 2006 if not for the new distribution election nor cause payments to be made in 2006 if not for the new distribution election.

(3) For purposes of this Section 7.1(b), if a Participant’s effective distribution election form was submitted using the options that had been made available under the Plan as in effect prior to January 1, 2005 [i.e., as either (A) a single lump-sum payment, or in annual installment payments over not less than two nor more than ten years; (B) commencing within 60 days after the date of the Participant’s Termination or the first, second, third, fourth or fifth anniversary of the Participant’s Termination], then:

(A) If the Participant’s Termination occurs prior to the expiration of the 2006 Distribution Election Period last applicable to the Participant, the Participant’s effective distribution election form shall be given full effect. Solely for purposes of this paragraph (3)(A), a participant’s distribution election form shall be considered effective notwithstanding the requirement of Section 7.1(b)(2)(B)(iii) (which requires that a form be submitted at least one year prior to the date of the Participant’s Termination), provided that such form had become effective prior to the Participant’s Termination in accordance with the terms applicable to such election form at the time it was submitted by the Participant; and

(B) If the Participant’s Termination occurs after the expiration of the last applicable 2006 Distribution Election Period, the Participant shall be considered to have elected the corresponding option as set forth in Schedule A attached to this Plan.

(4) If the provisions of Section 7.1(b)(3) are not applicable to a Participant and the Participant fails to submit an effective distribution election with regard to his Career Share Account that satisfies the requirements of Section 7.1(b)(2)(B)(i) (by his initial applicable Determination Date) or Section 7.1(b)(2)(B)(ii) (during an applicable 2006 Distribution Election Period), as applicable, by such Determination Date or the last day of the 2006 Distribution Election Period, respectively, such Participant shall be considered to have elected a distribution of his or her Career Share Account in a single lump sum as of the First Date Available.

7.2Events Affecting Timing or Amount of Distributions.

(a)“Election” To Accelerate Payment of Career Shares Attributable to 12/10/2003 Performance Share Award. Notwithstanding any provision of Section 7.1 to the contrary, if a Participant had not satisfied his or her MSOR on or before June 30, 2004 (the Determination Date applicable to the 12/10/2003 Performance Share Awards), but as of June 30, 2006 either (i) does satisfy his or her applicable MSOR(s) or (ii) has no applicable MSOR because the participant is longer an Eligible Employee, the Participant will be deemed to have elected as of June 30, 2006 a lump sum payment with respect to the Share or Share Equivalents that would have been credited to the Participant’s Career Share Account as a result of the 12/10/2003 Performance Share Award. Such payment shall be made as of the date that the 12/10/2003 Performance Share Awards otherwise would have become payable if the Participant were not a participant in this Plan.

(b)Avoiding Violation of Applicable Law. Notwithstanding any provision of Section 7.1 to the contrary, payment to a Participant will be delayed at any time that the Company reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Company reasonably anticipates that the making of such payment will not cause such violation.

ARTICLE VIII

BENEFICIARIES

8.1 Each Participant may designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission of a beneficiary designation shall be made by the Participant’s completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee. A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee. If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect. If a Participant fails to designate a beneficiary, or if all beneficiaries named by the Participant do not survive the Participant, the Participant’s Account will be paid to the Participant’s estate. Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant’s death, the designation of a Participant’s spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant’s marriage to that spouse.

8.2 Distribution to a Participant’s beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution.

ARTICLE IX

CLAIMS PROCEDURE

Section 9.1 The following procedures shall apply with respect to claims for benefits under the Plan.

(a)Any Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Claims Reviewer, specifying the basis for the claim. The Claims Reviewer shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Claims Reviewer determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial ninety day period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

(b)If the Claims Reviewer renders an adverse benefit determination under Section 8.1(a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant:

(1) The specific reasons for the denial of the claim;

(2) Specific reference to the provisions of the Plan upon which the denial of the claim was based;

(3) A description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and

(4) An explanation of the review procedure specified in Section 9.2, and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.

Section 9.2 The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.

(a)Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim. If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant’s claim for benefits. If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant’s case in person or by an authorized representative at such hearing.

(b)The claimant shall be notified of the Committee’s benefit determination on review within sixty days after receipt of the claimant’s request for review, unless the Committee determines that special circumstances require an extension of time for processing the review. If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period. Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render the benefit determination.

(c)The Committee shall provide a claimant with written or electronic notification of the Plan’s benefit determination on review. The determination of the Committee shall be final and binding on all interested parties. Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant:

(1) The specific reason(s) for the adverse determination;

(2) Reference to the specific provisions of the Plan on which the determination was based;

(3) A statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits; and

(4) A statement of the claimant’s right to bring an action under Section 502(a) of ERISA.

ARTICLE X

MISCELLANEOUS PROVISIONS

10.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold applicable federal, state and local taxes, Social Security taxes and Medicare taxes from any deferral and distribution hereunder to the extent that such taxes are then payable.

10.2 In the event the Committee, in its sole discretion, shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary.

10.3 The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of deferral contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant or beneficiary under the Plan as of the date of such modification, termination, discontinuance or suspension.

10.4 Nothing in the Plan shall interfere with or limit in any way the right of AEP to terminate any Participant’s employment at any time, or confer upon a Participant any right to continue in the employ of AEP.

10.5 The Company intends the following with respect to this Plan: (1) Section 451(a) of the Code would apply to the Participant's recognition of gross income as a result of participation herein; (2) the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received; (3) the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed; (4) the provisions of Parts 2, 3, and 4 of Subtitle B of Title I of ERISA shall not be applicable; and (5) the design and administration of the Plan are intended to comply with the requirements of Section 409A of the Code, to the extent such section is effective and applicable to amounts deferred hereunder. However, no Eligible Employee, Participant, beneficiary or any other person shall have any recourse against the Corporation, the Company, the Committee or any of their affiliates, employees, agents, successors, assigns or other representatives if any of those conditions are determined not to be satisfied.

10.6 The Plan shall be construed and administered according to the applicable provisions of ERISA and the laws of the State of Ohio.

American Electric Power Service Corporation has caused this amendment and restatement of the American Electric Power System Stock Ownership Requirement Plan to be signed as of this 28th day of December, 2006.

AMERICAN ELECTRIC POWER SERVICE CORPORATION

By:/s/ Genevieve A. Tuchow

Genevieve A. Tuchow,

Vice President, Human Resources

EX-12

EXHIBIT 12

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIAIRIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in millions except ratio data) 

	Year Ended December 31,
	2002			2003			2004			2005			2006
EARNINGS
Income Before Income Tax Expense,    Minority Interest Expense and Equity Earnings	$	814		$	872		$	1,684		$	1,453		$	1,477
Fixed Charges (as below)		1,048			1,050			989			916			1,002
Preference Security Dividend Requirements of    Consolidated Subsidiaries		(18	)		(15	)		(9	)		(10	)		(4	)
Total Earnings	$	1,844		$	1,907		$	2,664		$	2,359		$	2,475
FIXED CHARGES
Interest Expense	$	775		$	814		$	781		$	697		$	732
Credit for Allowance for Borrowed Funds Used    During Construction		32			24			22			36			82
Estimated Interest Element in Lease Rentals		223			197			177			173			184
Preference Security Dividend Requirements of    Consolidated Subsidiaries		18			15			9			10			4
Total Fixed Charges	$	1,048		$	1,050		$	989		$	916		$	1,002
Ratio of Earnings to Fixed Charges		1.75			1.81			2.69			2.57			2.47

EX-13

2006 Annual Reports

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

Southwestern Electric Power Company

Audited Financial Statements and

Management’s Financial Discussion and Analysis

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO ANNUAL REPORTS

Glossary of Terms
Forward-Looking Information
AEP Common Stock and Dividend Information
American Electric Power Company, Inc. and Subsidiary Companies:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis of Results of Operations
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Report of Independent Registered Public Accounting Firm
	Management’s Report on Internal Control Over Financial Reporting
	Consolidated Financial Statements
	Index to Notes to Consolidated Financial Statements
AEP Generating Company:
	Selected Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
AEP Texas Central Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
AEP Texas North Company and Subsidiary:
	Selected Consolidated Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Appalachian Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Columbus Southern Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Indiana Michigan Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Kentucky Power Company:
	Selected Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Ohio Power Company Consolidated:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Public Service Company of Oklahoma:
	Selected Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Southwestern Electric Power Company Consolidated:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Notes to Financial Statements of Registrant Subsidiaries
Combined Management’s Discussion and Analysis of Registrant Subsidiaries

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

  Term   Meaning

ADFIT	Accumulated Deferred Federal Income Taxes.
ADITC	Accumulated Deferred Investment Tax Credits.
AEGCo	AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent	American Electric Power Company, Inc.
AEP Consolidated	AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit	AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies.
AEP East companies	APCo, CSPCo, I&M, KPCo and OPCo.
AEPES	AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System	American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or   AEP Power Pool	Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEPSC	American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP West companies	PSO, SWEPCo, TCC and TNC.
AFUDC	Allowance for Funds Used During Construction.
ALJ	Administrative Law Judge.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
ARO	Asset Retirement Obligations.
CAA	Clean Air Act.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo	Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW	Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement	Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation. AEPSC acts as the agent.
CTC	Competition Transition Charge.
CWIP	Construction Work in Progress.
DETM	Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE	United States Department of Energy.
ECAR	East Central Area Reliability Council.
EDFIT	Excess Deferred Federal Income Taxes.
EITF	Financial Accounting Standards Board’s Emerging Issues Task Force.
ERCOT	Electric Reliability Council of Texas.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FIN 46	FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.”
FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”
GAAP	Accounting Principles Generally Accepted in the United States of America.
HPL	Houston Pipeline Company, a former AEP subsidiary.
IGCC	Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
IKEC	Indiana-Kentucky Electric Corporation, a subsidiary of OVEC.
IPP	Independent Power Producer.
IRS	Internal Revenue Service.
IURC	Indiana Utility Regulatory Commission.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG	JMG Funding LP.
KGPCo	Kingsport Power Company, an AEP electric distribution subsidiary.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KPSC	Kentucky Public Service Commission.
kV	Kilovolt.
KWH	Kilowatthour.
LIG	Louisiana Intrastate Gas, a former AEP subsidiary.
MISO	Midwest Independent Transmission System Operator.
MLR	Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
MWH	Megawatthour.
NOx	Nitrogen oxide.
Nonutility Money Pool	AEP System’s Nonutility Money Pool.
NRC	Nuclear Regulatory Commission.
NSR	New Source Review.
NYMEX	New York Mercantile Exchange.
OATT	Open Access Transmission Tariff.
OCC	Corporation Commission of the State of Oklahoma.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
OTC	Over the counter.
OVEC	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM	Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB	Price-to-Beat.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
PUHCA	Public Utility Holding Company Act.
PURPA	Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries	AEP subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
REP	Texas Retail Electric Provider.
Risk Management Contracts	Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant	A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.
RSP	Rate Stabilization Plan.
RTO	Regional Transmission Organization.
S&P	Standard and Poor’s.
SCR	Selective Catalytic Reduction.
SEC	United States Securities and Exchange Commission.
SECA	Seams Elimination Cost Allocation.
SFAS	Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71	Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 109	Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.”
SFAS 115	Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities.”
SFAS 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 143	Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
SFAS 158	Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159	Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA	System Integration Agreement.
SNF	Spent Nuclear Fuel.
SO2	Sulfur Dioxide.
SPP	Southwest Power Pool.
STP	South Texas Project Nuclear Generating Plant.
Sweeny	Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary.
TC	Transition Charge.
TCC	AEP Texas Central Company, an AEP electric utility subsidiary.
TEM	SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring Legislation	Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC	AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding	A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Utility Money Pool	AEP System’s Utility Money Pool.
VaR	Value at Risk, a method to quantify risk exposure.
Virginia SCC	Virginia State Corporation Commission.
WPCo	Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC	Public Service Commission of West Virginia.

FORWARD-LOOKING INFORMATION

This report made by AEP and 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, costs 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 we have contractual arrangements, including participants in the energy trading market.

· Actions of rating agencies, including changes in the ratings of debt.

· Volatility and changes in markets for electricity, natural gas 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.

AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:

Quarter Ended	High		Low		Quarter-End Closing Price		Dividend
December 31, 2006	$	43.13	$	36.49	$	42.58	$	0.39
September 30, 2006		37.30		34.10		36.37		0.37
June 30, 2006		35.19		32.27		34.25		0.37
March 31, 2006		38.48		33.96		34.02		0.37
December 31, 2005		40.80		35.57		37.09		0.37
September 30, 2005		39.84		36.34		39.70		0.35
June 30, 2005		37.00		33.79		36.87		0.35
March 31, 2005		36.34		32.25		34.06		0.35

AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2006, AEP had approximately 112,000 registered shareholders.

EX-21

  
    
      Subsidiaries of AEP






  
    

EX-23

EXHIBIT 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-39402, 333-46360, 333-128273, 333-66048, 333-62278 and 333-128043 on Form S-8, Post-Effective Amendment No. 3 to Registration Statement No. 33-01052 on Form S-8, Registration Statement Nos. 333-105532 and 333-121678 on Form S-3, and Pre-Effective Amendment No. 1 to Registration Statement No. 333-86050 on Form S-3 of our reports dated February 28, 2007, relating to the financial statements (and with respect to the report on those financial statements, expressed an unqualified opinion and included an explanatory paragraph concerning the Company’s adoption of new accounting pronouncements in 2004, 2005 and 2006) and financial statement schedule of American Electric Power Company, Inc. and subsidiary companies, and to management's report on the effectiveness of internal control over financial reporting appearing in and incorporated by reference in the Annual Report on Form 10-K of American Electric Power Company, Inc. and subsidiary companies for the year ended December 31, 2006.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2007

EX-24

Exhibit 24

POWER OF ATTORNEY

AMERICAN ELECTRIC POWER COMPANY, INC.

Annual Report on Form 10-K for the Fiscal Year Ended

December 31, 2006

The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint MICHAEL G. MORRIS, STEPHEN P. SMITH and HOLLY K. KOEPPEL, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2006, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24th day of January, 2007.

/s/ E. R. Brooks	/s/ William R. Howell
E. R. Brooks	William R. Howell
/s/ Donald M. Carlton	/s/ Lester A. Hudson, Jr.
Donald M. Carlton	Lester A. Hudson, Jr.
/s/ Ralph D. Crosby, Jr.	/s/ Michael G. Morris
Ralph D. Crosby, Jr.	Michael G. Morris
/s/ John P. DesBarres	/s/ Lionel L. Nowell, III
John P. DesBarres	Lionel L. Nowell, III
/s/ Robert W. Fri	/s/ Richard L. Sandor
Robert W. Fri	Richard L. Sandor
/s/ Linda A. Goodspeed	/s/ Donald G. Smith
Linda A. Goodspeed	Donald G. Smith
	/s/ Kathryn D. Sullivan
	Kathryn D. Sullivan

EX-31.(A)

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Michael G. Morris, certify that:

1. I have reviewed this annual report on Form 10-K of:

American Electric Power Company, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluations; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2007By: /s/ Michael G. Morris

Michael G. Morris

Chief Executive Officer

EX-31.(B)

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Holly K. Koeppel, certify that:

1. I have reviewed this annual report on Form 10-K of:

American Electric Power Company, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluations; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2007By: /s/ Holly K. Koeppel

       Holly K. Koeppel

       Chief Financial Officer

EX-32.(A)

EXHIBIT 32(a)

This Certificate is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

Of Title 18 of the United States Code

In connection with the Annual Report of the Companies (as defined below) on Form 10-K (the “reports”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I, Michael G. Morris, the chief executive officer of

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

Southwestern Electric Power Company

(the "Companies"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002 that, based on my knowledge (i) the Reports fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies.

/s/ Michael G. Morris

Michael G. Morris

Chief Executive Officer

February 28, 2007

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.(B)

EXHIBIT 32(b)

This Certificate is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

Of Title 18 of the United States Code

In connection with the Annual Report of the Companies (as defined below) on Form 10-K (the “reports”) for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I, Holly K. Koeppel, the chief financial officer of

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

Southwestern Electric Power Company

(the "Companies"), certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002 that, based on my knowledge (i) the Reports fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies.

/s/ Holly K. Koeppel

Holly K. Koeppel

Chief Financial Officer

February 28, 2007

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

COVER

American Electric Power

1 Riverside Plaza

Columbus, OH 43215

VIA EDGAR

Securities and Exchange Commission

Division of Corporation Finance

450 Fifth Street, N.W.

Washington, D.C. 20549-1004

Re: File No. 1-3525

American Electric Power Company, Inc.

Annual Report on Form 10-K

Dear Sirs:

On behalf of American Electric Power Company, Inc. (the "Company"), we are filing herewith, under the Securities Exchange Act of 1934, the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2006.

The financial statements in the 2006 Annual Report, incorporated herein by reference, do not reflect any change in any accounting principles or practices, or in the method of applying such principles or practices, from the financial statements included in the Company's 2005 Annual Report, except as indicated below:

A.   SFAS 123 (revised 2004) “Share Based Payment” (SFAS 123R)

We implemented SFAS 123R effective January 1, 2006. SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. We adopted SFAS 123R using the modified prospective method without materially affecting our results of operations, cash flows or financial condition.

B.   SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158)

We implemented SFAS 158 effective December 31, 2006. SFAS 158 requires employers to fully recognize the obligations associated with defined benefit pension plans and other postretirement employee benefit plans, which include retiree healthcare, in their balance sheets. We reported the effect of implementation of SFAS 158 as an adjustment to Accumulated Other Comprehensive Income offset by adjustments to SFAS 71 regulatory asset and deferred income tax asset.

For more detailed information regarding the above-mentioned accounting changes, please refer to Notes 2, 9 and 16 in the Notes to Consolidated Financial Statements within the 2006 Annual Report included in Item 8, “Financial Statements and Supplementary Data,” of the Form 10-K.

Very truly yours,

/s/ Thomas G. Berkemeyer

Assistant Secretary

(614) 716-1648