UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
___________________
 
FORM 10-K
___________________
(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the fiscal year ended December 31, 2006

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the transition period from __________ to_________

Commission
File Number	 	Registrants; States of Incorporation;
 Address and Telephone Number	 	I.R.S. Employer
Identification Nos.	
 	1-3525	 	American Electric Power Company, Inc . (A New York Corporation)	 	13-4922640	
 	0-18135	 	AEP Generating Company (An Ohio Corporation)	 	31-1033833	
 	0-346	 	AEP Texas Central Company (A Texas Corporation)	 	74-0550600	
 	0-340	 	AEP Texas North Company (A Texas Corporation)	 	75-0646790	
 	1-3457	 	Appalachian Power Company (A Virginia Corporation)	 	54-0124790	
 	1-2680	 	Columbus Southern Power Company (An Ohio Corporation)	 	31-4154203	
 	1-3570	 	Indiana Michigan Power Company (An Indiana Corporation)	 	35-0410455	
 	1-6858	 	Kentucky Power Company (A Kentucky Corporation)	 	61-0247775	
 	1-6543	 	Ohio Power Company (An Ohio Corporation)	 	31-4271000	
 	0-343	 	Public Service Company of Oklahoma (An Oklahoma Corporation)	 	73-0410895	
 	1-3146	 	Southwestern Electric Power Company (A Delaware Corporation)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 716-1000	 	72-0323455	

Indicate by check mark if the registrants with respect to American Electric Power Company, Inc. and Appalachian Power Company, is each a well-known seasoned issuer, as defined in Rule 405 on the Securities Act.	Yes x	No. o	
 	 	 	
Indicate by check mark if the registrants with respect to AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 on the Securities Act.	Yes o	No. x	
 	 	 	
Indicate by check mark if the registrants with respect to American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.	Yes o	No. x	
 	 	 	
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.	Yes x	No. o	
 	 	 	
Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.	x	 	
 	 	 	
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)	 	 	
Large accelerated filer   x	Accelerated filer     o	Non-accelerated filer   o	
 	 	 	
Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, or non-accelerated filers. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)	 	 	
Large accelerated filer   o	Accelerated filer     o	Non-accelerated filer   x	
 	 	 	
Indicate by check mark if the registrants are shell companies, as defined in Rule 12b-2 of the Exchange Act.	Yes o	No. x	

AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

 
Securities registered pursuant to Section 12(b) of the Act:

Registrant	 	 
Title of each class	 	Name of each exchange
on which registered	
AEP Generating Company	 	None	 	 	
AEP Texas Central Company	 	None	 	 	
AEP Texas North Company	 	None	 	 	
American Electric Power Company, Inc.	 	Common Stock, $6.50 par value	 	New York Stock Exchange	
Appalachian Power Company	 	None	 	 	
Columbus Southern Power Company	 	None	 	 	
Indiana Michigan Power Company	 	6% Senior Notes, Series D, Due 2032	 	New York Stock Exchange	
Kentucky Power Company	 	None	 	 	
Ohio Power Company	 	None	 	 	
Public Service Company of Oklahoma	 	6% Senior Notes, Series B, Due 2032	 	New York Stock Exchange	
Southwestern Electric Power Company	 	None	 	 	

 
Securities registered pursuant to Section 12(g) of the Act:

Registrant	 	Title of each class	
AEP Generating Company	 	None	
AEP Texas Central Company	 	None	
AEP Texas North Company	 	None	
American Electric Power Company, Inc.	 	None	
Appalachian Power Company	 	4.50% Cumulative Preferred Stock, Voting, no par value	
Columbus Southern Power Company	 	None	
Indiana Michigan Power Company	 	None	
Kentucky Power Company	 	None	
Ohio Power Company	 	4.50% Cumulative Preferred Stock, Voting, $100 par value	
Public Service Company of Oklahoma	 	None	
Southwestern Electric Power Company	 	4.28% Cumulative Preferred Stock, Non-Voting, $100 par value	
 	 	4.65% Cumulative Preferred Stock, Non-Voting, $100 par value	
 	 	5.00% Cumulative Preferred Stock, Non-Voting, $100 par value	

 
 	 	Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants   as of June 30, 2006, the last trading date of the registrants’ most recently completed second fiscal quarter	 	 
Number of shares of common stock outstanding of the registrants at
December 31, 2006	
AEP Generating Company	 	None	 	1,000	
 	 	 	 	($1,000 par value)	
AEP Texas Central Company	 	None	 	2,211,678	
 	 	 	 	($25 par value)	
AEP Texas North Company	 	None	 	5,488,560	
 	 	 	 	($25 par value)	
American Electric Power Company, Inc.	 	$13,492,667,933	 	396,674,736	
 	 	 	 	($6.50 par value)	
Appalachian Power Company	 	None	 	13,499,500	
 	 	 	 	(no par value)	
Columbus Southern Power Company	 	None	 	16,410,426	
 	 	 	 	(no par value)	
Indiana Michigan Power Company	 	None	 	1,400,000	
 	 	 	 	(no par value)	
Kentucky Power Company	 	None	 	1,009,000	
 	 	 	 	($50 par value)	
Ohio Power Company	 	None	 	27,952,473	
 	 	 	 	(no par value)	
Public Service Company of Oklahoma	 	None	 	9,013,000	
 	 	 	 	($15 par value)	
Southwestern Electric Power Company	 	None	 	7,536,640	
 	 	 	 	($18 par value)	

Note On Market Value Of Common Equity Held By Non-Affiliates

American Electric Power Company, Inc. owns, directly or indirectly, all of the common stock of AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (see Item 12 herein).

Documents Incorporated By Reference
 
Description	Part of Form 10-K
Into Which Document Is Incorporated	
 	 	
Portions of Annual Reports of the following companies for
the fiscal year ended December 31, 2006:	Part II	
 AEP Generating Company	 	
 AEP Texas Central Company	 	
 AEP Texas North Company	 	
 American Electric Power Company, Inc.	 	
 Appalachian Power Company	 	
 Columbus Southern Power Company	 	
 Indiana Michigan Power Company	 	
 Kentucky Power Company	 	
 Ohio Power Company	 	
 Public Service Company of Oklahoma	 	
 Southwestern Electric Power Company	 	
 	 	
Portions of Proxy Statement of American Electric Power Company, Inc. for 2007 Annual Meeting of Shareholders	Part III	
 	 	
Portions of Information Statements of the following companies for 2007 Annual Meeting of Shareholders:	Part III	
 Appalachian Power Company	 	
 Ohio Power Company	 	

This combined Form 10-K is separately filed by AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct (which also serves as a code of ethics applicable to Item 10 of this Form 10-K), certain committee charters and Principles of Corporate Governance. The address is www.AEP.com. AEP makes available, free of charge on its website, copies of its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.

 
TABLE OF CONTENTS
Item
Number	 	Page
Number	
 	Glossary of Terms	i	
 	Forward-Looking Information	iii	
PART I	
1	 	Business	 	
 	 	General	1	
 	 	Utility Operations  	8	
 	 	MEMCO Operations  	23	
 	 	Generation and Marketing  	24	
 	 	Other  	24	
1	A	Risk Factors	25	
1	B	Unresolved Staff Comments	37	
2	 	Properties	38	
 	 	Generation Facilities	38	
 	 	Transmission and Distribution Facilities	40	
 	 	Titles	41	
 	 	System Transmission Lines and Facility Siting	41	
 	 	Construction Program	41	
 	 	Potential Uninsured Losses	45	
3	 	Legal Proceedings  	45	
4	 	Submission Of Matters To A Vote Of Security Holders  	45	
 	 	Executive Officers of the Registrant  	45	
PART II	
5	 	Market For Registrant’s Common Equity, Related Stockholder Matters And Issuer Purchases Of Equity Securities	48	
6	 	Selected Financial Data	49	
7	 	Management’s Discussion And Analysis Of Financial Condition And Results Of Operations	49	
7	A	Quantitative And Qualitative Disclosures About Market Risk	49	
8	 	Financial Statements And Supplementary Data	50	
9	 	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure            	50	
9	A	Controls And Procedures	50	
9	B	Other Information	50	
PART III	
10	 	Directors, Executive Officers and Corporate Governance	51	
11	 	Executive Compensation	52	
12	 	Security Ownership Of Certain Beneficial Owners And Management and Related Stockholder Matters	53	
13	 	Certain Relationships And Related Transactions, and Director Independence	54	
14	 	Principal Accounting Fees And Services	55	
PART IV	
15	 	Exhibits, Financial Statement Schedules	57	
 	 	Financial Statements	57	
 	 	Signatures	58	
 	 	Index to Financial Statement Schedules	S-1	
 	 	Report of Independent Registered Public Accounting Firm	S-2	
 	 	Exhibit Index	E-1	

 
GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym	Definition	
AEGCo	AEP Generating Company, an electric utility subsidiary of AEP	
AEP or parent	American Electric Power Company, Inc.	
AEP East companies	APCo, CSPCo, I&M, KPCo and OPCo	
AEP Power Pool	APCo, CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection Agreement	
AEPSC or Service Corporation	American Electric Power Service Corporation, a service company subsidiary of AEP	
AEP System or the System	The American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries	
AEP West companies	PSO, SWEPCo, TCC and TNC	
AEP Utilities	AEP Utilities, Inc., a subsidiary of AEP, formerly, Central and South West Corporation	
AFUDC	Allowance for funds used during construction (the net cost of borrowed funds, and a reasonable rate of return on other funds, used for construction under regulatory accounting)	
ALJ	Administrative law judge	
APCo	Appalachian Power Company, a public utility subsidiary of AEP	
APSC	Arkansas Public Service Commission	
Buckeye	Buckeye Power, Inc., an unaffiliated corporation	
CAA	Clean Air Act	
CAAA	Clean Air Act Amendments of 1990	
Cardinal Station	Generating facility co-owned by Buckeye and OPCo	
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980	
CG&E	The Cincinnati Gas & Electric Company, an unaffiliated utility company	
Cook Plant	The Donald C. Cook Nuclear Plant (2,143 MW), owned by I&M, and located near Bridgman, Michigan	
CSPCo	Columbus Southern Power Company, a public utility subsidiary of AEP	
CSW	Central and South West Corporation, a public utility holding company that merged with AEP in June 2000.	
CSW Operating Agreement	Agreement, dated January 1, 1997, as amended, originally by and among PSO, SWEPCo, TCC and TNC, currently by and between PSO and SWEPCO governing generating capacity allocation. AEPSC acts as the agent for the parties.	
DOE	United States Department of Energy	
Dow	The Dow Chemical Company, and its affiliates collectively, unaffiliated companies	
DP&L	The Dayton Power and Light Company, an unaffiliated utility company	
EMF	Electric and Magnetic Fields	
EPA	United States Environmental Protection Agency	
EPACT	The Energy Policy Act of 2005	
ERCOT	Electric Reliability Council of Texas	
FERC	Federal Energy Regulatory Commission	
Fitch	Fitch Ratings, Inc.	
FPA	Federal Power Act	
I&M	Indiana Michigan Power Company, a public utility subsidiary of AEP	
I&M Power Agreement	Unit Power Agreement Between AEGCo and I&M, dated March 31, 1982	
Interconnection Agreement	Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants	
IURC	Indiana Utility Regulatory Commission	
KPCo	Kentucky Power Company, a public utility subsidiary of AEP	
LLWPA	Low-Level Waste Policy Act of 1980	
LPSC	Louisiana Public Service Commission	
MEMCO	AEP MEMCO LLC	
MISO	Midwest Independent Transmission System Operator	
Moody’s	Moody’s Investors Service, Inc.	
MW	Megawatt	
NOx	Nitrogen oxide	
NPC	National Power Cooperatives, Inc., an unaffiliated corporation	
NRC	Nuclear Regulatory Commission	
OASIS	Open Access Same-time Information System	
OATT	Open Access Transmission Tariff, filed with FERC	
OCC	Corporation Commission of the State of Oklahoma	
Ohio Act	Ohio electric restructuring legislation	
OPCo	Ohio Power Company, a public utility subsidiary of AEP	
OVEC	Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo together own a 43.47% equity interest	
PJM	PJM Interconnection, L.L.C., a regional transmission organization	
PSO	Public Service Company of Oklahoma, a public utility subsidiary of AEP	
PUCO	Public Utilities Commission of Ohio	
PUCT	Public Utility Commission of Texas	
PUHCA	Public Utility Holding Company Act of 1935, as amended (repealed effective February 8, 2006)	
RCRA	Resource Conservation and Recovery Act of 1976, as amended	
REP	Texas retail electricity provider	
Rockport Plant	A generating plant owned and partly leased by AEGCo and I&M (two 1,300 MW, coal-fired) located near Rockport, Indiana	
RTO	Regional Transmission Organization	
SEC	Securities and Exchange Commission	
S&P	Standard & Poor’s Ratings Service	
SO 2	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 CO 2 emissions. See Management’s Financial Discussion and Analysis of Results of Operations under the headings entitled Environmental Matters - Potential Regulation of CO 2 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 SO 2 , 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 CO 2 becomes regulated. See Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters and   Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 2006 Annual Reports, for more information regarding this litigation and environmental expenditures in general.

Historical and Projected Environmental Investments	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2004	 	 	2005	 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	
	 	 	Actual	 	 	Actual	 	 	Actual	 	 	Estimate	 	 	Estimate	 	 	Estimate	 	
(in thousands)	
AEGCo	 	$	6,500	 	$	1,400	 	$	1,400	 	$	1,400	 	$	900	 	$  	1,300	 	
APCo	 	 	159,100	 	 	231,200	 	 	532,800	 	 	305,200	 	 	215,100	 	 	164,200	 	
CSPCo	 	 	23,200	 	 	32,200	 	 	138,900	 	 	112,000	 	 	133,400	 	 	36,200	 	
I&M	 	 	11,800	 	 	62,900	 	 	23,200	 	 	4,800	 	 	18,900	 	 	16,100	 	
KPCo	 	 	2,700	 	 	13,100	 	 	(12,400	)	 	2,600	 	 	14,600	 	 	14,800	 	
OPCo	 	 	133,000	 	 	458,600	 	 	660,800	 	 	498,800	 	 	104,500	 	 	30,300	 	
PSO	 	 	100	 	 	200	 	 	500	 	 	2,500	 	 	12,000	 	 	18,300	 	
SWEPCo	 	 	4,000	 	 	11,900	 	 	21,000	 	 	7,100	 	 	17,300	 	 	16,600	 	
TCC	 	 	0	 	 	0	 	 	0	 	 	0	 	 	0	 	 	0	 	
TNC	 	 	0	 	 	(100	)	 	0	 	 	700	 	 	4,600	 	 	2,800	 	
AEP System	 	$	340,400	 	$	811,400	 	$	1,366,200	 	$	935,100	 	$	521,300	 	$	300,600	 	

Figures set forth in parentheses reflect amounts invested and later expensed as a result of project cancellation or significant delay.

Electric and Magnetic Fields

EMF are found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF are created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances.

A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.

Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from customers.  

UTILITY OPERATIONS

GENERAL

Utility operations constitute most of AEP’s business operations. Utility operations include (i) the generation, transmission and distribution of electric power to retail customers and (ii) the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants. AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.

ELECTRIC GENERATION

Facilities
 
AEP’s public utility subsidiaries own or lease approximately 35,000 MW of domestic generation. See Item 2 — Properties for more information regarding AEP’s generation capacity.

AEP Power Pool and CSW Operating Agreement

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company’s “member-load-ratio.” The Interconnection Agreement has been approved by the FERC.

The member-load-ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all AEP East companies. As of December 31, 2006, the member-load-ratios were as follows:

 	Peak Demand (MW)	Member-Load Ratio (%)	
APCo	6,943	30.2	
CSPCo	4,425	19.3	
I&M	4,650	20.3	
KPCo	1,665	7.3	
OPCo	5,260	22.9	

The Ohio Act was enacted in 2001. To comply with that law CSPCo and OPCo functionally separated their generation business from their remaining operations. They plan to remain functionally separated through at least December 31, 2008 as authorized by their rate stabilization plans approved by the PUCO. CSPCo and OPCo have been involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the rate stabilization plans. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2006 Annual Reports, for more information.

Since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement (Allowance Agreement), which provides, among other things, for the transfer of emission allowances associated with transactions under the Interconnection Agreement.

The following table shows the net (credits) or charges allocated among the parties under the Interconnection Agreement during the years ended December 31, 2004, 2005 and 2006:

 	 	 	2004	 	 	2005	 	 	2006	 	
	 	(in thousands)	
APCo	 	$	239,400	 	$	288,000	 	$	319,500	 	
CSPCo	 	 	284,900	 	 	285,600	 	 	281,700	 	
I&M	 	 	(141,500	)	 	(197,400	)	 	(146,100	)	
KPCo	 	 	31,600	 	 	42,200	 	 	38,800	 	
OPCo	 	 	(414,400	)	 	(418,400	)	 	(493,900	)	

PSO, SWEPCo, and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which has been approved by the FERC. The CSW Operating Agreement requires these public utility subsidiaries to maintain adequate annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other public utility subsidiary parties as capacity commitments. Parties are compensated for energy delivered to the recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids the use of more costly alternatives. Revenues and costs arising from third party sales in their region are generally shared based on the amount of energy each west zone public utility subsidiary contributes that is sold to third parties. The separation of the generation business undertaken by TCC and TNC to comply with the Texas Act has made the business operations of TCC and TNC incompatible with the CSW Operating Agreement. As a result, with FERC approval, these companies are no longer parties to, and no longer supply generating capacity under, the CSW Operating Agreement.

The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2004, 2005 and 2006:

 	 	 	2004	 	 	2005	 	 	2006	 	
 	 	(in thousands)	
PSO	 	$	55,000	 	$	27,600	 	$	(15,300	)	
SWEPCo	 	 	(59,800	)	 	(27,500	)	 	9,900	 	
TCC	 	 	1,100	 	 	0	 	 	0	 	
TNC	 	 	3,700	 	 	(100	)	 	5,400	 	

Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is primarily sold to customers by such public utility subsidiary at rates approved by the public utility commission in the jurisdiction of sale. In Ohio and Virginia, such rates are based on a statutory formula as those jurisdictions continue to transition to the use of market rates for generation. See Regulation — Rates under Item 1, Utility Operations .

Under both the Interconnection Agreement and CSW Operating Agreement, power that is not needed to serve the native load of our public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of those subsidiaries. See Risk Management and Trading , below , for a discussion of the trading and marketing of such power.

AEP’s System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP’s East companies, PSO and SWEPCO. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits for activities within each zone. The separation of the generation business undertaken by TCC and TNC to comply with the Texas Act has also made the business operations of TCC and TNC incompatible with the System Integration Agreement. As a result, with FERC approval, these two companies have been removed from this agreement.

Risk Management and Trading

As agent for AEP’s public utility subsidiaries, AEPSC sells excess power into the market and engages in power, natural gas, coal and emissions allowances risk management and trading activities focused in regions in which AEP traditionally operates. These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under physical forward contracts at fixed and variable prices. These contracts include physical transactions, over-the-counter swaps and exchange-traded futures and options. The majority of physical forward contracts are typically settled by entering into offsetting contracts.   These transactions are executed with numerous counterparties or on exchanges. Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2006, counterparties and exchanges have posted approximately $156 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries had posted approximately $110 million with counterparties and exchanges). Since open trading contracts are valued based on changes in market power prices, exposures change daily.

Fuel Supply

The following table shows the sources of power generated by the AEP System:

 	2004	2005	2006	
Coal and Lignite	83%	83%	85%	
Natural Gas	5%	6%	6%	
Nuclear	12%	10%	9%	
Hydroelectric and other	1%	1%	<1%	

Variations in the generation of nuclear power are primarily related to refueling and maintenance outages in addition to the sale of TCC’s share of a nuclear generating unit in May 2005. Variations in the generation of natural gas power are primarily related to the availability of cheaper alternatives to fulfill certain power requirements and the deactivation or sale of certain gas-fired plants owned by TCC and TNC. Price increases in one or more fuel sources relative to other fuels generally result in increased use of other fuels.

Coal and Lignite : AEP’s public utility subsidiaries procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations, short-term, and spot agreements with various producers and coal trading firms. The price for most solid fuels generally has been increasing. Management has responded to increases in the price of coal by rebalancing the coal used in its generating facilities with products from different coal regions and sources that have different heat and sulfur contents. This rebalancing is an ongoing process that is expected to continue , primarily enabled by the installation of scrubbers at many of our generating facilities. Management believes, but cannot provide assurances, that AEP’s public utility subsidiaries will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units. Through subsidiaries, AEP owns or leases more than 7,000 railcars, 600 barges, 15 towboats and a coal handling terminal with 20 million tons of annual capacity to move and store coal for use in its generating facilities. See MEMCO Operations for a discussion of AEP’s for-profit coal and other dry-bulk commodity transportation operations that are not part of AEP’s Utility Operations segment.

The following table shows the amount of coal and lignite delivered to the AEP System during the past three years and the average delivered price of spot coal purchased by System companies:

 	2004	2005	2006	
Total coal delivered to AEP operated plants (thousands of tons)	71,778	75,063	77,897	
Average price per ton of purchased coal	$28.96	$32.67	$35.37	

The coal supplies at AEP System plants vary from time to time depending on various factors, including customers’ usage of electric power, space limitations, the rate of consumption at particular plants, labor issues and weather conditions which may interrupt deliveries. At December 31, 2006, the System’s coal inventory was approximately 44 days of normal usage. This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently.

In cases of emergency or shortage, system companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the relevant state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agency.

The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to reallocate coal and to require the transportation thereof, for the use at power plants or major fuel-burning installations experiencing fuel shortages.

Natural Gas : Through its public utility subsidiaries, AEP consumed over 104 billion cubic feet of natural gas during 2006 for generating power. A majority of the natural gas-fired power plants are connected to at least two pipelines, which allows greater access to competitive supplies and improves delivery reliability. A portfolio of long-term, monthly, seasonal firm and daily peaking purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant.

Nuclear:   I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago. I&M anticipates that the Cook Plant has sufficient storage capacity for its spent nuclear fuel to permit normal operations through 2013. I&M has initiated a project to study the use of dry cask storage.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranges from $733 million to $1.3 billion in 2006 nondiscounted dollars. At December 31, 2006, the total decommissioning trust fund balance for the Cook Plant was $974 million. The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

·  	Type of decommissioning plan selected;	

·  	Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy);	

·  	Further development of regulatory requirements governing decommissioning;	

·  	Limited availability to date of significant experience in decommissioning such facilities;	

·  	Technology available at the time of decommissioning differing significantly from that assumed in studies;	

·  	Availability of nuclear waste disposal facilities; and	

·  	Availability of a DOE facility for permanent storage of spent nuclear fuel.	

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.

See Note 10 to the consolidated financial statements, entitled Nuclear , included in the 2006 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste : The LLWPA mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan does not currently have a disposal site for such waste available. I&M cannot predict when such a site may be available, but South Carolina and Utah operate low-level radioactive waste disposal sites and currently accept low-level radioactive waste from Michigan. I&M’s access to the South Carolina facility is currently allowed through the end of fiscal year 2008. There is currently no set date limiting I&M’s access to the Utah facility.

Structured Arrangements Involving Capacity, Energy, and Ancillary Services

In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC and called the Mone Plant. OPCo is entitled to 100% of the power generated by the Mone Plant, and is responsible for the fuel and other costs of the facility through May 2007, as extended. Following that, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the Mone Plant, and both parties will generally be responsible for their allocable portion of the fuel and other costs of the facility.

Certain Power Agreements

AEGCo : Since its formation in 1982, AEGCo’s business has consisted of the ownership and financing of its 50% interest in Unit 1 of the Rockport Plant and, since 1989, its 50% leasehold interest in Unit 2 of the Rockport Plant. Substantially all of the operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M and KPCo pursuant to unit power agreements, which have been approved by the FERC.

The I&M Power Agreement provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo, I&M is obligated to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M). When added to amounts received by AEGCo from any other sources, such amounts will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant has expired (currently December 2022) unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo the amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement expires in December 2022.

AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities; (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant; (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements); and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The capital funds agreement will terminate after all AEGCo obligations have been paid in full.

OVEC:   AEP and several unaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%. Until September 1, 2001, OVEC supplied from its generating capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now entitled to receive and obligated to pay for all OVEC capacity (approximately 2,200 MW) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 43.47%. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. The Amended and Restated Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2026. AEP and the other owners have been evaluating the need for environmental investments related to their ownership interests, which are material. In December 2006, OVEC’s Board of Directors authorized interim capital expenditures totaling $366 million in order to complete detailed engineering and begin construction of flue gas desulfurization (sulfur dioxide scrubber) projects and the associated scrubber waste disposal landfills. If approved, the estimated total cost to complete the projects would be slightly in excess of $1 billion, which OVEC would expect to finance through issuing debt.  With the expiration of that provision, Buckeye is entitled to receive and must pay for power up to its proportionate share of the station.

Buckeye: On October 1, 2004, AEP joined PJM, and the Buckeye transmission service over the AEP System was transferred under the PJM Open Access Transmission Tariff (OATT). The Cardinal Station Agreement between OPCO and Buckeye contains a provision that expired in May 2006. Under that provision, Buckeye was entitled to receive, and was obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on July 25, 2005, was recorded at 1,434,807 kilowatts.  With the expiration of that provision, Buckeye is entitled to receive and must pay for power in amounts equal to its proportionate share of the station.

ELECTRIC TRANSMISSION AND DISTRIBUTION

General

AEP’s public utility subsidiaries (other than AEGCo) own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2—Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP’s public utility subsidiaries in their service territories. These sales are made at rates established and approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. See Regulation—Rates . The FERC regulates and approves the rates for wholesale transmission transactions. See Item 1 - Business/Utility Operations - Regulation—FERC . As discussed below, some transmission services also are separately sold to non-affiliated companies.

AEP’s public utility subsidiaries (other than AEGCo) hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Item 1 - Business/Utility Operations - Competition .

AEP Transmission Pool

Transmission Equalization Agreement:   APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the TEA, defining how they share the costs and benefits associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345kV and above) and certain facilities operated at lower voltages (138kV up to 345kV). The TEA has been approved by the FERC. Sharing under the TEA is based upon each company’s “member-load-ratio.” The member-load-ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies.  The respective peak demands and member-load-ratios as of December 31, 2006 are set forth above in the section titled ELECTRIC GENERATION - AEP Power Pool and CSW Operating Agreement.

The following table shows the net (credits) or charges allocated among the parties to the TEA during the years ended December 31, 2004, 2005 and 2006:

 	 	2004	 	2005	 	2006	 	
 	 	(in thousands)  	
APCo	 	$	(500	)	$	8,900	 	$	(16,000	)	
CSPCo	 	 	37,700	 	 	34,600	 	 	46,000	 	
I&M	 	 	(40,800	)	 	(47,000	)	 	(37,000	)	
KPCo	 	 	(6,100	)	 	(3,500	)	 	(2,000	)	
OPCo	 	 	9,700	 	 	7,000	 	 	9,000	 	

Transmission Coordination Agreement:   PSO, SWEPCo, TCC, TNC and AEPSC are parties to the TCA. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with the responsibility of (i) overseeing the coordinated planning of the transmission facilities of the AEP West companies, including the performance of transmission planning studies, (ii) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (iii) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.

Under the TCA, the AEP West companies have delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the AEP OATT on their behalf. Prior to September 2005, the TCA also provided for the allocation among the AEP West companies of revenues collected for transmission and ancillary services provided under the AEP OATT. Since then, these allocations have been determined by the FERC-approved OATT for the SPP (with respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect to TCC and TNC).

The following table shows the net (credits) or charges allocated among the parties to the TCA prior to September 2005, and pursuant to the SPP OATT and ERCOT protocols as described above during the years ended December 31, 2004, 2005 and 2006:

 	 	 	2004	 	 	2005	 	 	2006	 	
	 	(in thousands)	
PSO	 	$	8,100	 	$	3,500	 	$	1,800	 	
SWEPCo	 	 	13,800	 	 	5,200	 	 	(1,900	)	
TCC	 	 	(12,200	)	 	(3,800	)	 	1,100	 	
TNC	 	 	(9,700	)	 	(4,900	)	 	(1,000	)	

Transmission Services for Non-Affiliates:   In addition to providing transmission services in connection with their own power sales, AEP’s public utility subsidiaries through RTOs also provide transmission services for non-affiliated companies. See Item 1 - Business/Utility operations - Regional Transmission Organizations, below . Transmission of electric power by AEP’s public utility subsidiaries is regulated by the FERC.

Coordination of East and West Zone Transmission:   AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East and AEP West companies. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TEA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern:

·  	The allocation of transmission costs and revenues and	
·  	The allocation of third-party transmission costs and revenues and System dispatch costs.	

The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.

Regional Transmission Organizations

On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff that reflects the Commission’s views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an OASIS, which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct that prohibit utilities’ system operators from providing non-public transmission information to the utility’s merchant energy employees. The orders also allow a utility to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission service.

In December 1999, FERC issued Order 2000, which provides for the voluntary formation of RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals. As a condition of FERC’s approval in 2000 of AEP’s merger with CSW, AEP was required to transfer functional control of its transmission facilities to one or more RTOs. The AEP East Companies integrated into PJM (a FERC-approved RTO) on October 1, 2004.

SWEPCo and PSO are members of the SPP. In February 2004, the FERC conditionally approved SPP as an RTO. In October 2004, the FERC issued an order granting RTO status to SPP subject to certain filings. The APSC and LPSC have ordered the utilities in those states, including our utilities, to analyze and submit to them the costs and benefits of RTO options available to the utilities. Certain states in the region have undertaken and released a study investigating the costs and benefits of SPP developing into a RTO that administers energy and associated markets. On August 10, 2006, the APSC issued an order approving, among other things, SWEPCo’s participation in SPP, subject to certain reporting and continuing oversight conditions.

The remaining AEP West companies (TCC and TNC) are members of ERCOT.

See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2006 Annual Reports under the heading entitled RTO Formation/Integration Costs and Transmission Rate Proceedings at the FERC for a discussion of public utility subsidiary participation in RTOs.

REGULATION

General

Except for retail generation sales in Ohio, Virginia and the ERCOT area of Texas, AEP’s public utility subsidiaries’ retail rates and certain other matters are subject to traditional regulation by the state utility commissions. While still regulated, retail sales in Michigan are now made at unbundled rates. See Item 1 - Utility Operations - Electric Restructuring and Customer Choice Legislation and Rates, below. AEP’s subsidiaries are also subject to regulation by the FERC under the FPA. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. AEP and its public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC. EPACT contains key provisions affecting the electric power industry such as giving the FERC “backstop” transmission siting authority as well as increased utility merger oversight. The law also provides incentives and funding for clean coal technologies and initiatives to voluntarily reduce greenhouse gases.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time as part of a transition to customer choice of generation suppliers, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

In many jurisdictions, the rates of AEP’s public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In the ERCOT area of Texas, our utilities have exited the generation business and they currently charge unbundled cost-based rates for transmission and distribution service. In Ohio, rates are transitioning from bundled cost-based rates for electric service to unbundled cost-based rates for transmission and distribution service on the one hand, and market pricing for and/or customer choice of generation on the other. Historically, the state regulatory frameworks in the service area of the AEP System reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. While the historical framework remains in a portion of AEP’s service territory, recovery of increased fuel costs through a fuel adjustment clause is no longer provided for in Ohio.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction.

Indiana : I&M provides retail electric service in Indiana at bundled rates approved by the IURC. While rates are set on a cost-of-service basis, I&M’s base rates are capped through June 30, 2007. Its fuel recovery rate is capped through that time period at a level that automatically increased in January 2006 and January 2007. I&M expects, however, that its actual fuel costs will exceed the capped fuel rates permitted through June 30, 2007.

Ohio : CSPCo and OPCo each operated as a functionally separated utility and provided “default” retail electric service to customers at unbundled rates pursuant to the Ohio Act through December 31, 2006. The PUCO approved the rate stabilization plans filed by CSPCo and OPCo (which, among other things, address default retail generation service rates from January 1, 2006 through December 31, 2008). T he Ohio Supreme Court vacated and remanded the PUCO’s approval of the rate stabilization plans. In response, the PUCO issued an order requiring CSPCo and OPCo to make additional filings and holding that their rate stabilization plans remained in effect. CSPCo and OPCo have submitted proposals with the PUCO addressing the matters identified by the PUCO. Retail generation rates will be determined consistent with the rate stabilization plan until December 31, 2008. CSPCo and OPCo are providing and will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates will be frozen (with certain exceptions, including automatic annual increases in generation rates of 3% and 7% for CSPCo and OPCo, respectively) from their levels as of December 31, 2005 through December 31, 2008. Transmission services will continue to be provided at rates established by the FERC. CSPCo and OPCo have been involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the rate stabilization plans. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2006 Annual Reports, for more information.

Oklahoma : PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is generally adjusted annually and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are returned to or recovered from customers when new annual factors are established. In November 2006, PSO filed a request with the OCC seeking an increase in base rates and other rate relief. The OCC has not yet ruled on this filing. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2006 Annual Reports, for information regarding current rate proceedings.

Texas:   TCC has sold all of its generation assets and TNC has transferred its active generation capacity to a non-utility affiliate pursuant to a 20-year agreement. TCC and TNC serve most of their retail customers in the ERCOT area of Texas through non-affiliated REPs. TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. In November 2006, TCC and TNC filed requests with the PUCT seeking increases in the rates charged to REPs for delivering electricity over their transmission and distribution lines. The PUCT has not ruled on the filings. See Note 4 to the consolidated financial statements, entitled Rate Matters included in the 2006 Annual Reports, for information on current rate proceedings. In August 2006, the PUCT delayed competition in the SPP area of Texas until at least January 1, 2011. As such, SWEPCo’s Texas operations continue to operate and to be regulated as a traditional bundled utility with both base and fuel rates.

Virginia:   APCo provides retail electric service in Virginia at unbundled rates. In February 2007, the Virginia legislature adopted amendments to its previously-enacted electric restructuring law. The amendments would cut two years off of the transition period (from 2010 to 2008) after which rates for retail generation supply would return to a form of cost-based regulation. The Governor of Virginia has not yet signed this legislation. APCo’s unbundled generation, transmission (which reflect FERC-approved transmission rates) and distribution rates, as well as its functional separation plan, were approved by the VSCC in December 2001. APCO’s base rates are capped at their mid-1999 levels until the end of the transition period (now December 31, 2010), or sooner if the VSCC finds that a competitive market for generation exists in Virginia, but APCo is permitted to seek two changes to its capped rates through December 31, 2010. In addition, APCo is entitled to annual rate changes to recover the incremental costs it incurs for transmission and distribution reliability and compliance with state or federal environmental laws or regulations. In May 2006, APCo filed a request with the VSCC seeking an increase in base rates. Hearings on this request were held in December 2006. APCo expects a ruling in 2007.  APCo is entitled to adjustments to fuel rates through 2010 to recover its actual fuel costs, the fuel component of its purchased power costs and certain capacity charges. APCo recovers its generation capacity charges through capped base rates. In November 2006, the VSCC approved APCo’s previous request to recover additional environmental and reliability-related costs. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2006 Annual Reports, for additional information on these matters.

West Virginia : APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC. West Virginia generally allows for timely recovery of fuel costs. In July 2006, the WVPSC approved an increase in the retail rates of APCo and WPCo and the reactivation of their suspended operative fuel clause and other recovery mechanisms. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2006 Annual Reports, for additional information on current rate proceedings.

Other Jurisdictions : The public utility subsidiaries of AEP also provide service at regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.

The following table illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate:

 	 	 	 	 	 	Fuel Clause Rates(6)	 	 	
 	 	 	 	 	 	 	 	Off-System Sales Profits	 	Percentage of AEP
System	
 	 	Status of Base Rates for	 	 	 	Shared with	 	Retail	
Jurisdiction	 	Power Supply	 	Energy Delivery	 	Status	 	Ratepayers	 	Revenues(1)	
 	 	 	 	 	 	 	 	 	 	 	
Ohio	 	See footnote 2	 	Distribution frozen through 2008(2)	 	None	 	Not applicable	 	32%	
 	 	 	 	 	 	 	 	 	 	 	
Oklahoma	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	Yes	 	14%	
 	 	 	 	 	 	 	 	 	 	 	
Texas ERCOT	 	Not applicable (3)	 	Not capped or frozen	 	Not applicable	 	Not applicable	 	7%	
 	 	 	 	 	 	 	 	 	 	 	
Texas SPP	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	Yes	 	5%	
 	 	 	 	 	 	 	 	 	 	 	
Indiana	 	Capped until 6/30/07	 	Capped until 6/30/07	 	Capped until 6/30/07 (4)	 	No	 	10%	
 	 	 	 	 	 	 	 	 	 	 	
Virginia	 	Capped until as late as 12/31/10(5)	 	Capped until as late as 12/31/10(5)	 	Active	 	No	 	9%	
 	 	 	 	 	 	 	 	 	 	 	
West Virginia	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	No	 	9%	
 	 	 	 	 	 	 	 	 	 	 	
Louisiana	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	Yes, above base levels	 	4%	
 	 	 	 	 	 	 	 	 	 	 	
Kentucky	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	Yes, above and below base levels	 	4%	
 	 	 	 	 	 	 	 	 	 	 	
Arkansas	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	Yes, above base levels	 	3%	
 	 	 	 	 	 	 	 	 	 	 	
Michigan	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	Yes, in some areas	 	2%	
 	 	 	 	 	 	 	 	 	 	 	
Tennessee	 	Not capped or frozen	 	Not capped or frozen	 	Active	 	No	 	1%	

(1)	Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2006.	
 	 	
(2)	The PUCO has approved the rate stabilization plan filed by CSPCo and OPCo that began after the market development period and extends through December 31, 2008 during which OPCo’s retail generation rates will increase 7% annually and CSPCo’s retail generation rates will increase 3% annually. Distribution rates are frozen, with certain exceptions, through December 31, 2008. The rate stabilization plans have been the subject of litigation. At the PUCO’s request, CSPCo and OPCo have submitted proposals addressing those matters identified by the commission . See Note 4 to the Consolidated Financial Statements, entitled Rate Matters.	
 	 	
(3)	TCC and TNC are no longer in the retail generation supply business. Retail electric service in the ERCOT area of Texas is provided to most customers through unaffiliated REPs with TCC and TNC providing only regulated delivery services. SWEPCo and an affiliated REP provide retail electric service in the SPP area of Texas. All customers of the affiliated REP were transferred to SWEPCo with the first billing cycle in February 2007.	
 	 	
(4)	Fuel rates capped through June 2007 billing month subject to certain events at the Cook Plant.	
 	 	
(5)	Legislation passed in 2004 capped base rates until December 31, 2010 and expanded the rate change opportunities to one full rate case (including generation, transmission and distribution) between July 1, 2004 and June 30, 2007 (which has been filed) and one additional full rate case between July 1, 2007 and December 31, 2010. The law also permits APCo to recover, on a timely basis, incremental costs incurred on and after July 1, 2004 for transmission and distribution reliability purposes and to comply with state and federal environmental laws and regulations.   In February 2007, the Virginia legislature adopted amendments to its previously-enacted electric restructuring law. The amendments would cut two years off of the transition period (from 2010 to 2008) after which rates for retail generation supply would return to a form of cost-based regulation. The Governor of Virginia has not yet signed this legislation.	
 	 	
(6)	Includes, where applicable, fuel and fuel portion of purchased power.	

FERC

Under the FPA, FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require AEP to provide open access transmission service at FERC-approved rates. FERC also regulates unbundled transmission service to retail customers. FERC also regulates the sale of power for resale in interstate commerce by (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. Except for wholesale power that AEP delivers within its control area of the SPP, AEP has market-rate authority from FERC, under which much of its wholesale marketing activity takes place.

The FERC has jurisdiction over the issuances of securities of our public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets, and mergers with another electric utility or holding company. In addition, both FERC and state regulators are permitted to review the books and records of any company within a holding company system. EPACT gives the FERC “backstop” transmission siting authority as well as increased utility merger oversight.

ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION

Certain states in AEP’s service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas has been delayed by the PUCT until at least 2011. AEP’s public utility subsidiaries operate in both the ERCOT and SPP areas of Texas. See Note 4 to the consolidated financial statements entitled Rate Matters for additional information.

Ohio Restructuring

The Ohio Act requires vertically integrated electric utility companies that are in the business of providing competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which ended December 31, 2005), retail customers receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates are approved by the PUCO and whose transmission rates are based on rates established by the FERC. The PUCO approved CSPCo’s and OPCo’s rate stabilization plans that, among other things, addressed default generation service rates from January 1, 2006 through December 31, 2008. See Item 1 - Utility Operations - Regulation—FERC for a discussion of FERC regulation of transmission rates, Regulation—Rates—Ohio and Note 4 to the consolidated financial statements entitled Rate Matters , included in the 2006 Annual Reports , for a discussion of the impact of restructuring on distribution rates. The PUCO authorized CSPCo and OPCo to remain functionally separated through the end of that three-year period. The Supreme Court of Ohio vacated and remanded the PUCO’s order authorizing the rate stabilization plans. In response, the PUCO issued an order in August 2006 requiring CSPCo and OPCo to make additional filings and holding that the rate stabilization plans remained in effect. CSPCo and OPCo have submitted proposals with the PUCO addressing the matters identified by the PUCO. CSPCo and OPCo have been involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the rate stabilization plans.

Texas Restructuring

Signed into law in June of 1999, the Texas Act substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for customers. Among other things, the Texas Act:

 	·	gave Texas customers the opportunity to choose their REP beginning January 1, 2002 (delayed until at least 2011 in the SPP portion of Texas),	
 	·	required each utility to legally separate into a REP, a power generation company, and a transmission and distribution utility, and	
 	·	required that REPs provide electricity at generally unregulated rates, except that until January 1, 2007 the prices that may be charged to residential and small commercial customers by REPs affiliated with a utility within the affiliated utility’s service area are set by the PUCT, until certain conditions in the Texas Act are met.	

The Texas Act provides each affected utility an opportunity to recover its generation related regulatory assets and stranded costs resulting from the legal separation of the transmission and distribution utility from the generation facilities and the related introduction of retail electric competition. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Stranded costs consist of the positive excess of the net regulated book value of generation assets (as of December 31, 2001) over the market value of those assets, taking specified factors into account, as ultimately determined in a PUCT true-up proceeding.

In May 2005, TCC filed its stranded cost quantification application, or true-up proceeding, with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up items. A final order was issued in April 2006. In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion. Other parties have appealed the PUCT’s final order as unwarranted or too large; TCC has appealed seeking additional recovery consistent with the Texas Act and related rules. In a preliminary ruling filed in February 2007, the Texas state district court adjudicating the appeal of the final order in the true-up proceeding found that the PUCT erred in several respects, including the method used to determine stranded costs and the awarding of certain carrying costs. Following the preliminary ruling, the court granted a rehearing of the issue regarding the method to determine stranded costs. That rehearing is scheduled for late March 2007. TCC intends to appeal any final adverse rulings regarding the PUCT’s order in the true-up proceedings.

After PUCT approval, in October 2006 TCC issued $1.74 billion of securitization bonds, including additional issuance and carrying costs through the date of issuance. The PUCT authorized negative competition transition charges in the amount of $356 million in October 2006. TCC is required to refund this amount to its ratepayers. For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Note 4 to the consolidated financial statements entitled Rate Matters included in the 2006 Annual Reports .  

Michigan Customer Choice

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Rates for retail electric service for I&M’s Michigan customers were unbundled (though they continue to be regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2006, none of I&M’s Michigan customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory.

Virginia Restructuring

In April 2004, the Governor of Virginia signed legislation that extends the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides specified cost recovery opportunities during the capped rate period, including two optional general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004.   In February 2007, the Virginia legislature adopted amendments to its previously-enacted electric restructuring law. The amendments would cut two years off of the transition period (from 2010 to 2008) after which rates for retail generation supply would return to a form of cost-based regulation. The Governor of Virginia has not yet signed this legislation.

COMPETITION

The public utility subsidiaries of AEP, like the electric industry generally, face competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, there are more generators able to participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service.

AEP’s public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.

Significant changes in the global economy in recent years have led to increased price competition for industrial customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power. In addition, industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with the various state commissions. Occasionally, these rates are first negotiated, and then filed with the state commissions. The public utility subsidiaries of AEP believe that they are unlikely to be materially adversely affected by this competition.

SEASONALITY

The sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations and may impact its financial condition. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

MEMCO OPERATIONS

Our MEMCO business segment transports coal and dry bulk commodities primarily on the Ohio, Illinois, and Lower Mississippi rivers. Almost all of our customers are nonaffiliated third parties who obtain the transport coal and dry bulk commodities for various uses. We charge these customers market rates for the purpose of making a profit. Depending on market conditions and other factors, including barge availability, we have also served AEP utility subsidiary affiliates. Our affiliated utility customers procure the transport of coal for use as fuel in their respective generating plants. We charge affiliated customers rates that reflect our costs. The MEMCO operations include approximately 2,038 barges, 37 towboats and 10 harbor boats that we own or lease.

Competition within the barging industry for major commodity contracts is intense, with a number of companies offering transportation services in the waterways we serve. We compete with other carriers primarily on the basis of commodity shipping rates, but also with respect to   customer service, available routes, value-added services (including scheduling convenience and flexibility), information timeliness and equipment. Since 1980, the industry has experienced consolidation. The resulting companies increasingly offer the widespread geographic reach necessary to support major national customers. Demand for barging services can be seasonal, particularly with respect to the movement of harvested agricultural commodities (beginning in the late summer and extending through the fall.) Cold winter weather may also limit our operations when certain of the waterways we serve are closed.
 
Our transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international conventions. Legislation has been proposed that could make our towboats subject to inspection by the U.S. Coast Guard.
 
GENERATION AND MARKETING
 
Our generation and marketing business segment consists of non-utility generating assets and as of January 2007, a competitive power supply and energy trading business. We enter into short and long-term transactions to buy or sell capacity, energy, and ancillary services primarily in the ERCOT market. The assets utilized in this segment include approximately 791 MW of domestic wind power and gas-fired generation facilities (of which AEP ownership is approximately 551 MW) and, since January 2007, 377 MW of coal-fired capacity obtained from TNC’s interest in the Oklaunion power station. TNC has entered into a 20-year power agreement transferring this generating capacity to a non-utility affiliate that we operate in order to comply with the separation requirements of the Texas Act. The power obtained from the Oklaunion power station is to be marketed and sold in ERCOT. We are regulated by the PUCT for transactions inside ERCOT and by the FERC for transactions outside of ERCOT. While peak load in ERCOT typically occurs in the summer, we do not necessarily expect seasonal variation in our operations.
 
OTHER

Gas Operations

In January 2005, we sold a 98% controlling interest in HPL and related assets with the remaining 2% interest being sold to the buyer in November 2005. See Note 8 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments, and Assets Held for Sale , included in the 2006 Annual Reports for more information. As a result, management anticipates that our gas marketing operations will be limited to managing our obligations with respect to the gas transactions entered into before these sales.

Plaquemine Cogeneration Facility

Pursuant to an agreement with Dow, AEP constructed an 880 MW cogeneration facility (“Facility”) at Dow’s chemical facility in Plaquemine, Louisiana that achieved commercial operation status in 2004. Dow used a portion of the energy produced by the Facility and sold the excess power to us. We agreed to sell up to all of the excess 800 MW to Tractebel. That power agreement is currently being litigated. See Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies . In November 2006, we sold our interest in the Facility to Dow. Negotiations for the sale resulted in an after-tax impairment of approximately $136 million. See Note 8 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments and Assets Held for Sale.

For information regarding other non-core investments, see Note 8 to the consolidated financial statements entitled Acquisitions, Dispositions, Discontinued Operations, Impairments and Assets Held for Sale, included in the 2006 Annual Reports.

ITEM 1A.    RISK FACTORS

General Risks of Our Regulated Operations

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.   (Applies to each registrant.)

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction and/or acquisition of additional generation units and transmission facilities, modernizing existing infrastructure as well as other initiatives. Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment. This would cause our financial results to be diminished. While we may seek to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

Our planned capital investment program coincides with a material increase in the price of the fuels used to generate electricity. Many of our jurisdictions have fuel clauses that permit us to recover these increased fuel costs through rates without a general rate case. While prudent capital investment and variable fuel costs each generally warrant recovery, in practical terms our regulators could limit the amount or timing of increased costs that we would recover through higher rates. Any such limitation could cause our financial results to be diminished.

Our request for rate recovery of additional costs may not be approved in Virginia.   (Applies to AEP and APCo.)

APCo filed a request with the VSCC in May 2006 seeking a net increase in base rates of $198 million to recover increasing costs, including a return on equity of 11.5%. APCo also requested to apply its off-system sales margins (currently credited to customers through base rates) to the fuel factor where they can be adjusted annually. APCo also requested to retain a portion of the off-system sales margins. In May 2006, the VSCC issued an order placing the net requested base rate increase into effect as of October 2, 2006, subject to refund. In October 2006, the VSCC staff filed direct testimony recommending a base rate increase of $13 million with a return on equity of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo has filed rebuttal testimony and hearings were held in December 2006. If the VSCC denies the requested rate recovery, it could adversely impact future results of operations and cash flows.

Our request for rate recovery of additional costs may not be approved in Texas.   (Applies to AEP, TCC and TNC.)

TCC and TNC have filed requests with the PUCT to increase their transmission and distribution rates. The rate requests include the amounts charged for the delivery of electricity over TCC´s and TNC´s transmission and distribution lines. TCC is seeking approval of an $81 million increase, which includes the expiration of $20 million in billing credits that the PUCT required in approving the merger of CSW into AEP. The credits have been in place since 2000. TNC is seeking approval of a $25 million increase, which includes the expiration of $6.2 million in billing credits. TCC and TNC are requesting a return on equity of 11.25% with a capital structure of approximately 60% debt/40% equity. If the PUCT denies the requested rate recovery, it could adversely impact future results of operations and cash flows.

Our request for rate recovery of additional costs may not be approved in Oklahoma.   (Applies to AEP and PSO.)

PSO filed a request with the OCC in November, 2006 seeking approval of a $50 million overall increase in base rates, an annually adjusted rate mechanism to recover the expected significant investment PSO will be making in new facilities, several new and restructured tariffs to allow PSO to begin to reduce the relationship between its revenues and its sales volumes, and to implement some demand side management tariffs. PSO´s planned investments over the next five years include new generation facilities ($1.12 billion), new and refurbished transmission substations and lines ($302 million) and new distribution lines and equipment ($582 million). If the OCC denies the requested rate recovery, it could adversely impact future results of operations and cash flows.

We may not be able to recover all of our fuel costs in Indiana. (Applies to AEP and I&M.)

I&M entered into a settlement agreement which the IURC approved in 2005. The approved settlement caps fuel rates through June 2007 at increasing rates during agreed-upon intervals. I&M has experienced a cumulative under-recovery of fuel costs through December 2006. If future fuel costs through June 30, 2007 continue to exceed the agreed-upon caps, future results of operations and cash flows would be adversely affected.

The rates that SWEPCo may charge its customers may be reduced. (Applies to SWEPCo.)

At the time of the CSW merger, SWEPCO agreed to file with the LPSC detailed financial information typically utilized in a revenue requirement filing on a periodic basis in order to demonstrate the lack of adverse impact from the merger. The first such filing was in October 2002 and the second was in April 2004. Both filings indicated SWEPCo’s rates should not be reduced. In April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorized return on equity of 11.1%. In July 2006, consultants to the LPSC staff filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, which included a 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain on-going operations and maintenance expense levels and the recommended base rate reduction does not include the impact of a proposed consolidated federal income tax adjustment, which would increase the proposed rate reduction. SWEPCo filed rebuttal testimony in October 2006 refuting the consultants’ recommendations. In December 2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by $17 million which includes a proposed return on equity of 9.8%. SWEPCo filed testimony in the first quarter of 2007. Hearings are expected to occur in early 2007. A decision is expected in mid-to-late 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction were ultimately ordered, it would adversely impact future results of operations and cash flows.

The amount that PSO seeks to recover for fuel costs is currently being reviewed.   (Applies to PSO.)

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO filed with the OCC offering to collect the under-recovery over 18 months. An intervenor, the staff of the OCC and the Attorney General of Oklahoma have made filings indicating that recovery should be reduced substantially or disallowed altogether. These filings disputed the allocation of AEP System off-system sales margins pursuant to an agreement approved by FERC. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices. The allocation issue was referred to an ALJ. The ALJ recommended that the OCC lacks authority to examine whether PSO deviated from the FERC allocation methodology and that any such complaints should be addressed at the FERC. The OCC conducted a hearing on the jurisdictional matter in January 2005 but has not issued a decision. If the OCC determines, as a result of the review, that a portion of PSO’s fuel and purchased power costs should not be recovered, there could be an adverse effect on PSO’s results of operations, cash flows and possibly financial condition.

The internal allocation of AEP System off-system sales margins has been challenged. (Applies to APCo, CSPCo, I&M, KPCo and OPCo.)

Off-system sales margins are allocated among the AEP System companies pursuant to a FERC-approved agreement among those companies entered into at the time of the merger with CSW. In November 2005, we filed with the FERC a proposed allocation methodology to be used in 2006 and beyond. The original allocations have been challenged in different forums, including PSO’s fuel clause recovery proceeding before the OCC. In general, the challenges assert that AEP West companies, acquired in the merger with CSW, are being allocated a disproportionately small amount of the off-system sales margins. An ALJ in the OCC proceeding and, separately, a federal district court in Texas have each held that the FERC is the only appropriate adjudicator of such challenges. This holding has been affirmed by a federal appellate court. No proceeding questioning the allocation of our off-system sales is currently before the FERC; the OCC, however, has yet to rule on whether it has jurisdiction over this issue. If the FERC or another entity of competent authority were to retroactively allocate additional off-system sales margins to the AEP West companies, the AEP East companies may be required to pay money to the AEP West companies. Any such payments could have an adverse effect on the results of operations, cash flows and possibly financial condition of the AEP East companies.

The base rates that certain of our utilities charge are currently capped or frozen. (Applies to AEP, CSPCo, I&M and OPCo.)

Base rates charged to customers in Michigan and Ohio are currently either frozen or capped. To the extent our costs in these states exceed the applicable cap or frozen rate, those costs are not recoverable from customers.

Certain of our revenues and results of operations are subject to risks that are beyond our control. (Applies to each registrant.)

Unless mitigated by timely and adequate regulatory recovery, the cost of repairing damage to our utility facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of insurance coverage, when applicable, may adversely impact our revenues, operating and capital expenses and results of operations. Such events may also create additional risks related to the supply and/or cost of equipment and materials.

We are exposed to nuclear generation risk. (Applies to AEP and I&M.)

Through I&M, we own the Cook Plant. It consists of two nuclear generating units for a rated capacity of 2,143 MW, or 6% of our generation capacity. We are, therefore, subject to the risks of nuclear generation, which include the following:

·  	the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel;	
·  	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations;	
·  	uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the losses of others); and,	
·  	uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.	

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if and when these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could harm our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Moreover, a major incident at a nuclear facility in the U.S. could require us to make material contributory payments.

The different regional power markets in which we compete or will compete in the future have changing transmission regulatory structures, which could affect our performance in these regions. (Applies to each registrant.)

Our results are likely to be affected by differences in the market and transmission regulatory structures in various regional power markets. Problems or delays that may arise in the operation of new regional transmission organization (RTO) power markets, may restrict our ability to sell power produced by our generating capacity to certain markets if there is insufficient transmission capacity available to fully support market operation. The rules governing the various regional power markets may also change from time to time which could affect our costs or revenues. Because it remains unclear which companies will be participating in the various regional power markets, or the manner in which RTOs will evolve or the regions they will cover, we are unable to assess fully the impact that these power markets may have on our business.

AEP East companies joined PJM on October 1, 2004. SWEPCo and PSO are members of SPP. In February 2004, FERC granted RTO status to SPP, subject to fulfilling specified requirements. In October 2004, the FERC issued an order granting final RTO status to SPP subject to certain filings.

The LPSC has ordered the utilities subject to its jurisdiction, including SWEPCo, to analyze and submit to them the costs and benefits of RTO options available to the utilities. Certain states in the region have undertaken and released a study investigating the costs and benefits of SPP developing into a RTO that administers energy and associated markets.

To the extent we are faced with conflicting state and Federal requirements as to our participation in RTOs, it could adversely affect our ability to operate and recover transmission costs from retail customers. Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, our transmission operations or future results of operations and cash flows.

The amount we charged third parties for using our transmission facilities has been reduced, is subject to refund and may not be completely restored in the future.   (Applies to AEP and AEP East companies .)

In July 2003, the FERC issued an order directing PJM and the MISO to make compliance filings for their respective tariffs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within those RTOs. The elimination of the T&O rates reduces the transmission service revenues collected by the RTOs and thereby reduces the revenues received by transmission owners under the RTOs’ revenue distribution protocols. To mitigate the impact of lost T&O revenues, the FERC approved temporary replacement seams elimination cost allocation (SECA) transition rates beginning in December 2004 and extending through March 2006. Intervenors objected to this decision; therefore the SECA fees we collected ( $220 million) are subject to refund. Approximately $19 million of the SECA revenues that we billed were never collected. The AEP East zone public utilities filed a motion with the FERC to force payment of these SECA billings.

A hearing was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates were not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory, and that new compliance filings and refunds should be made. The ALJ also found that unpaid SECA rates must be paid in the recommended reduced amount. The FERC has not ruled on the matter. If the FERC upholds the decision of the ALJ, up to $126 million of collected SECA rates could be refunded by the AEP East zone public utilities. We have recorded provisions in the aggregate amount of $37 million related to the potential refund of SECA rates pending settlement negotiations with various intervenors.

SECA transition rates expired at the end of March 2006 and did not fully compensate AEP for ongoing lost T&O revenues . As a result of rate relief in certain jurisdictions, however, approximately 85% of the ongoing lost T&O revenues are now being recovered from native load customers of AEP East companies in those jurisdictions . The portion attributable to Virginia is being collected subject to refund.  

In addition to seeking retail rate recovery from native load customers in the applicable states, AEP and another member of PJM have filed an application with the FERC seeking compensation from other unaffiliated members of PJM for the costs associated with those members’ use of our respective transmission assets. A majority of PJM members have filed in opposition to the proposal. Hearings were held in April 2006. An ALJ recommended a rate design that would result in greater recovery for AEP than the proposal AEP had submitted. The ALJ also recommended, however, that the design be phased-in, which could limit the amount of recovery for AEP. The FERC has not yet ruled on this matter. Management cannot at this time estimate the outcome of these proceedings.

Rate regulation may delay or deny full recovery of costs.   (Applies to each registrant.)

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year. Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time. Additionally, there may also be a delay between the timing of when these costs are incurred and when these costs are recovered. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.

We operate in a non-uniform and fluid regulatory environment. (Applies to each registrant.)

In addition to the multiple levels of state regulation at the states in which we operate, our business is subject to extensive federal regulation. There can be no assurance that (1) the federal legislative and regulatory initiatives (which have occurred over the past few years and which have generally facilitated competition in the energy sector) will continue or will not be reversed or (2) state regulation will not become significantly more restrictive. Further alteration of the regulatory landscape in which we operate will impact the effectiveness of our business plan and may, because of the continued uncertainty, harm our financial condition and results of operations.

At times, demand for power could exceed our supply capacity . (Applies to each registrant other than TCC and TNC.)

We are currently obligated to supply power in parts of eleven states. From time to time, because of unforeseen circumstances, the demand for power required to meet these obligations could exceed our available generation capacity. If this occurs, we would have to buy power from the market. We may not always have the ability to pass these costs on to our customers because some of the states we operate in do not allow us to increase our rates in response to increased fuel cost charges. Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high. Even if a supply shortage were brief, we could suffer substantial losses that could reduce our results of operations.

Risks Related to Market, Economic or Financial Volatility

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses. (Applies to each registrant other than AEGCo.)

Following the bankruptcy of Enron, the credit ratings agencies initiated a thorough review of the capital structure and the quality and stability of earnings of energy companies, including us. The agencies revised ratings at that time. Further negative ratings actions could constrain the capital available to our industry and could limit our access to funding for our operations. Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition could be harmed and future results of operations could be adversely affected.

If Moody’s or S&P were to downgrade the long-term rating of any of the registrants , particularly below investment grade, the borrowing costs of that registrant would increase, which would diminish its financial results. In addition, the registrant’s potential pool of investors and funding sources could decrease.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt. Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions. If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

AEP has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries. (Applies to AEP.)

AEP is a holding company and has no operations of its own. Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP. Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments. Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations. In addition, any payment of dividends, distributions or advances by the utility subsidiaries to AEP would be subject to regulatory or contractual restrictions.

Our operating results may fluctuate on a seasonal and quarterly basis . (Applies to each registrant.)

Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the terms of power sale contracts that we enter into. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish our results of operations and harm our financial condition. Conversely, unusually extreme weather conditions could increase AEP’s results of operations in a manner that would not likely be sustainable.

Parties we have engaged to provide construction materials or services may fail to perform their obligations, which could harm our results of operations. (Applies to each registrant.)

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades, construction of additional generation units and transmission facilities as well as other initiatives. We are exposed to the risk of substantial price increases in the costs of materials used in construction. We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and almost certainly cause delays in that and related projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This would cause our financial results to be diminished, and we might incur losses or delays in completing construction.

Changes in commodity prices may increase our cost of producing power or decrease the amount we receive from selling power, harming our financial performance . (Applies to each registrant.)

We are heavily exposed to changes in the price and availability of coal because most of our generating capacity is coal-fired. We have contracts of varying durations for the supply of coal for most of our existing generation capacity, but as these contracts end or otherwise are not honored, we may not be able to purchase coal on terms as favorable as the current contracts. Similarly, we are heavily exposed to changes in the price and availability of emission allowances. We use emission allowances based on the amount of coal we use as fuel and the reductions achieved through emission controls and other measures. According to our estimates we have procured sufficient emission allowances to cover our projected needs for the next two years and for much of the projected needs for periods beyond that. At some point, however, we may have to obtain additional allowances and those purchases may not be on as favorable terms as those currently obtained.

We also own natural gas-fired facilities, which increases our exposure to market prices of natural gas.  Natural gas prices tend to be more volatile than prices for other fuel sources.

The price trends for coal, natural gas and emission allowances have shown material increases in the recent past. Changes in the cost of coal, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power will affect our financial results. Since the prices we obtain for power may not change at the same rate as the change in coal, emission allowances or natural gas costs, we may be unable to pass on the changes in costs to our customers. In addition, the prices we can charge our retail customers in some jurisdictions are capped.

In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value our trading and marketing transactions, and those differences may be material. As a result, our financial results may be diminished in the future as those transactions are marked to market.

In certain jurisdictions, we have limited ability to pass on our fuel costs to our customers. (Applies to AEP, CSPCo, I&M and OPCo.)

We are exposed to risk from changes in the market prices of coal, natural gas, and emissions allowances used to generate power where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The prices of coal, natural gas and emissions allowances have increased materially in the recent past. The protection afforded by retail fuel clause recovery mechanisms has been eliminated by the implementation of customer choice in Ohio, which represents approximately 20% of our fuel costs. Because the risk of generating costs cannot be passed through to customers as a matter of right in Ohio, we retain these risks. We also have a fuel cap in Indiana that may not allow us to fully recover our fuel costs there. If we cannot recover an amount sufficient to cover our actual fuel costs, our results of operations and cash flows would be adversely affected.

We are exposed to losses resulting from the bankruptcy of Enron Corp. (Applies to AEP.)

On June 1, 2001, we purchased Houston Pipe Line Company (“HPL”) from Enron Corp. (“Enron”). Later that year, Enron and its subsidiaries filed bankruptcy proceedings in the U.S. Bankruptcy Court for the Southern District of New York. Various HPL related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy. In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 BCF of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (“BOA”) and certain other banks (together with BOA, “BOA Syndicate”) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Additionally, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. We purchased 10 BCF of gas from Enron and are currently litigating the rights to the remaining 55 BCF of cushion gas.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas use agreement and other incidental agreements. We have objected to Enron’s attempted rejection of these agreements. In 2005 we sold HPL, including the Bammel gas storage facility. We indemnified the purchaser for damages, if any, arising from the litigation with BOA. The case in federal court in Texas is set for trial beginning April 2007. Management is unable to predict the final resolution of these disputes, however the impact on results of operations, cash flows and financial condition could be material.

Risks Relating To State Restructuring

In Ohio, our costs may not be recovered and rates may be reduced. (Applies to AEP, OPCo and CSPCo)

In January 2005, the PUCO approved rate stabilization plans (“RSPs”) for CSPCo and OPCo. The RSPs provide, among other things, for CSPCo and OPCo to raise their generation rates on an annual basis through 2008 by 3% and 7%, respectively. The RSPs also provide for possible additional annual generation rate increases of up to an average of 4% per year for specified costs. The RSPs also provide that CSPCo and OPCo can recover certain environmental carrying costs, PJM-related administrative costs and certain congestion costs. In 2006, CSPCo and OPCo collected an additional estimated $244 million in gross margin as a result of the RSPs. This amount is expected to increase in 2007 and 2008.

In 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the validity of the RSPs under Ohio’s electricity restructuring law. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP orders for CSPCo and OPCo and remanded the case to the PUCO for further proceedings.

In August 2006, the PUCO directed CSPCo and OPCo to file a plan providing an option for customer participation in the electric market through competitive bids or other reasonable means. The PUCO also held that the RSPs shall remain effective. Accordingly, the Ohio companies continued collecting RSP revenues. In September 2006, CSPCo and OPCo submitted their proposals to provide additional options for customer participation in the electric market. If the PUCO were to reverse or limit the RSPs, our results of operations and cash flows could be adversely affected.
 
Some laws and regulations governing restructuring in Virginia have not yet been interpreted or adopted and could harm our business, operating results and financial condition. (Applies to AEP and APCo.)

Virginia restructuring legislation was enacted in 1999 providing for retail choice of generation suppliers to be phased in over two years beginning January 1, 2002. It required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan with the VSCC and, following VSCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later VSCC consideration. While the electric restructuring law in Virginia established the general framework governing the retail electric market, it required the VSCC to issue rules and determinations implementing the law. Some of the regulations governing the retail electric market have not yet been adopted by the VSCC. When the regulations are developed and adopted, compliance with them may harm our business, results of operations and financial condition.   In February 2007, the Virginia legislature adopted amendments to its electric restructuring law. The amendments would cut two years off of the transition period (from 2010 to 2008) after which rates for retail generation supply would return to a form of cost-based regulation. The Governor of Virginia has not yet signed this legislation.

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas. (Applies to AEP and TCC.)

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs. We elected to use the sale of assets method to determine the market value of the generation assets of TCC for stranded cost purposes. In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost quantification application with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up items. A final order was issued in April 2006. In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion. We have appealed the PUCT’s final order seeking additional recovery consistent with the Texas Act and related rules, other parties have appealed the PUCT’s final order as unwarranted or too large. In a preliminary ruling filed in February 2007, the Texas state district court adjudicating the appeal of the final order in the true-up proceeding found that the PUCT erred in several respects, including the method used to determine stranded costs and the awarding of certain carrying costs. Following the preliminary ruling, the court granted a rehearing of the issue regarding the method to determine stranded costs. That rehearing is scheduled for late March 2007. TCC intends to appeal any final adverse rulings regarding the PUCT’s order in the true-up proceeding. If the district court judge’s preliminary determination that TCC used an improper method to value its stranded costs is ultimately upheld on appeal, it could substantially reduce TCC’s stranded costs. We cannot estimate the amount of any potential impact at this time, but it could exceed TCC’s common shareholder’s equity at December 31, 2006. Any reduction of the recovery authorized in the PUCT’s order could have a material adverse effect on results of operations, cash flows and possibly financial condition.

Collection of our revenues in Texas is concentrated in a limited number of REPs.   (Applies to AEP, TCC and TNC.)

Our revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distribute to their customers. Currently, we do business with approximately sixty REPs. The two largest customers of TCC accounted for 29% of its operating revenues in 2006; the three largest customers of TNC accounted for 50% of its operating revenues in 2006. Adverse economic conditions, structural problems in the new Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs for timely remittance of payments. Any delay or default in payment could adversely affect the timing and receipt of our cash flows and thereby have an adverse effect on our liquidity.

Risks Related to Owning and Operating Generation Assets and Selling Power

Our costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws could harm our cash flow and profitability. (Applies to each registrant other than TCC and TNC.)

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities. These expenditures have been significant in the past, and we expect that they will increase in the future. Costs of compliance with environmental regulations could adversely affect our results of operations and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including timing of implementation, required levels of reductions, allocation requirements of the new rules, and our selected compliance alternatives. As a result, we cannot estimate our compliance costs with certainty. The actual costs to comply could differ significantly from the estimates. All of the costs are incremental to our current investment base and operating cost structure.

If Federal and/or State requirements are imposed on electric utility companies mandating further emission reductions, including limitations on CO 2 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 CO 2 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 CO 2 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 e mission 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 765 kV transmission line that was placed in -service on June 20, 2006.

PROPOSED GENERATION FACILITIES

IGCC Projects

In conjunction with an environmental impact study issued in August 2004, we announced plans to construct a synthesis-gas-fired plant or plants of approximately 1,200 MW of capacity in the next five to six years utilizing integrated gasification combined cycle (IGCC) technology. We originally estimated construction and other direct costs would equal approximately $1.2 billion for each nominal 629 MW facility. We currently expect these estimates to be exceeded in amounts that are not yet determinable and that may be material. We are currently completing front-end engineering and design on the facilities pursuant to an agreement with General Electric and Bechtel Power Corporation and are working with state regulators and legislators to establish a framework for expedient recovery of this significant investment in new clean coal technology.

 The plans are contingent upon receiving adequate cost recovery through rates approved by the applicable commission prior to beginning construction.   In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity to construct a 600 MW IGCC plant adjacent to APCo’s existing Mountaineer generating station in Mason County, WV. In January 2007, the WVPSC issued an order setting a deadline of December 3, 2007 for it to rule on APCo’s filing.

 In March 2005, OPCo and CSPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposed for cost recovery associated with the IGCC plant in three phases. In April 2006, the PUCO issued an order authorizing OPCo and CSPCo to implement Phase 1 of their cost recovery proposal. In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs. In its June order, the PUCO indicated that if the Ohio companies have not commenced continuous construction of the IGCC plant within five years of the order, all charges collected for pre-construction costs must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. No date for a further hearing has been set.

SWEPCo Projects

In December 2005, SWEPCo sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, SWEPCo announced plans to construct new generation. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas. SWEPCo also will build a 480 MW combined-cycle natural gas fired plant at its existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also plans to build a new 600 MW base load coal plant, of which its investment will be 73%, in Hempstead County, Arkansas by 2011. Preliminary cost estimates for the new facilities are approximately $1.4 billion. These new facilities are subject to regulatory approvals from SWEPCo’s three state commissions—APSC, LPSC and the PUCT. The peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions. Construction of all of these units is expected to begin in 2007.

PSO Projects

In September 2005, PSO sought proposals for new peaking generation to be online in 2008. In December 2005, PSO sought proposals for base load generation to be online in 2011. PSO received and evaluated proposals with oversight from a neutral third party. In March 2006, PSO announced plans to add 170 MW of peaking generation to its Riverside Station plant in Jenks, Oklahoma. PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines at the Jenks facility. In March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma. PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines at that facility. Combined preliminary cost estimates for these additions are approximately $120 million. In July 2006, PSO announced plans to enter a joint venture with Oklahoma Gas and Electric Company (“OG&E”) and Oklahoma Municipal Power Authority. OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the new unit. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion. The unit is expected to be online no later than the first half of 2012. These new facilities are subject to regulatory approval from the OCC. Construction of all of these units is expected to begin in 2007.

Other

Our significant planned environmental investments in emission control installations at existing coal-fired plants and our commitment to IGCC technology reinforce our belief that coal will be a lower-emission domestic energy source of the future and further signals our commitment to invest in clean, environmentally safe technology. For additional information regarding anticipated environmental expenditures, see Management’s Financial Discussion and Analysis of Results of Operations under the heading entitled Environmental Matters .

CONSTRUCTION EXPENDITURES

The following table shows construction expenditures (including environmental expenditures) during 2004, 2005 and 2006 and current estimates of 2007, 2008 and 2009 construction expenditures, in each case excluding AFUDC, capitalized interest and assets acquired under leases.
 
 	2004
Actual	2005
Actual	2006
Actual	2007
Estimate	2008
Estimate	2009
Estimate	
 	(in thousands)	
AEP Systems (a)	$1,536,400	 (b)	$2,501,600	 (c)	$3,522,100	 (d)	$3,440,300	 (e)	$3,026,300	$2,974,100	
AEGCo	15,700	 	15,200	 	10,000	 	18,000	 	28,300	34,100	
APCo	435,900	 	634,000	 	922,700	 	663,600	 	531,200	460,900	
CSPCo	148,200	 	171,600	 	315,100	 	337,200	 	354,300	232,600	
I&M	173,400	 	317,100	 	306,900	 	252,000	 	264,300	293,800	
KPCo	38,000	 	60,300	 	57,400	 	70,500	 	114,500	100,100	
OPCo	339,200	 	733,400	 	968,700	 	832,000	 	367,800	389,200	
PSO	90,800	 	139,700	 	245,200	 	318,600	 	329,600	465,900	
SWEPCo	95,300	 	151,200	 	330,300	 	537,300	 	605,200	539,700	
TCC	109,400	 	186,300	 	273,200	 	240,600	 	213,700	273,100	
TNC	35,700	 	64,800	 	67,900	 	142,600	 	187,900	148,900	
 
(a)  	Includes expenditures of other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies. Excludes discontinued operations.	
(b)  	Excludes Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC Debt Equals $1,636,200)	
(c)  	Excludes $293 million for the purchase of two generating plants and Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC Debt Equals $2,403,800)	
(d)  	Excludes Cash Flow Statement Adjustments (Statement of Cash Flow Including AFUDC Debt Equals $3,528,000)	
(e)  	Excludes $427 million for the purchase of two generating plants.	

The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System’s construction program.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to our generating plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could have a material adverse effect on results of operations and the financial condition of AEP and other AEP System companies. For risks related to owning a nuclear generating unit, see Note 10 to the consolidated financial statements entitled Nuclear for information with respect to nuclear incident liability insurance.

ITEM 3.      LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies , incorporated by reference in Item 8.
 
ITEM 4.      SUBMISSION OF MATTERS TO A VOTE
        OF SECURITY HOLDERS

AEP, APCo, OPCo and SWEPCo . None.

AEGCo, CSPCo, I&M, KPCo, PSO, TCC and TNC. Omitted pursuant to Instruction I(2)(c).

EXECUTIVE OFFICERS OF THE REGISTRANTS

AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of February 1, 2007.

Name	 	Age	 	Office (a)	
Michael G. Morris	 	60	 	Chairman of the Board, President and Chief Executive Officer of AEP and of AEPSC	
Nicholas K. Akins	 	46	 	Executive Vice President of AEP and Executive Vice President-Generation of AEPSC	
Carl L. English	 	60	 	President-AEP Utilities of AEP and of AEPSC	
Thomas M. Hagan	 	62	 	Executive Vice President of AEP and Executive Vice President-AEP Utilities-West of AEPSC	
John B. Keane	 	60	 	Senior Vice President, General Counsel, Chief Compliance Officer and Secretary of AEP and Senior Vice President and General Counsel of AEPSC	
Holly K. Koeppel	 	48	 	Executive Vice President and Chief Financial Officer of AEP and of AEPSC	
Robert P. Powers	 	52	 	Executive Vice President of AEP and Executive Vice President-AEP Utilities-East of AEPSC	
Susan Tomasky	 	53	 	Executive Vice President of AEP and Executive Vice President-Shared Services of AEPSC	

(a)  	Before joining AEPSC in his current position in January 2004, Mr. Morris was Chairman of the Board, President and Chief Executive Officer of Northeast Utilities (1997-2003). Messrs. Akins, Hagan, and Powers and Ms. Tomasky and Ms. Koeppel have been employed by AEPSC or System companies in various capacities (AEP, as such, has no employees) for the past five years. Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became executive officers of AEP effective with their promotions to Executive Vice President on September 9, 2002, October 24, 2001, November 18, 2002 and January 26, 2000, respectively. As a result of AEP’s realignment of its executive management team in July 2004, Mr. Keane became an executive officer of AEP. Before joining AEPSC in his current position in July 2004, Mr. Keane was President of Bainbridge Crossing Advisors. Before that, he was Vice President-Administration for Northeast Utilities (1998-2002). Mr. English joined AEP as President-Utility Group and became an executive officer of AEP on August 1, 2004. Before joining AEPSC in his current position in August 2004, Mr. English was President and Chief Executive Officer of Consumers Energy gas division (1999-2004). As a result of AEP’s realignment of management in August 2006, Mr. Akins became an executive officer of AEP. All of the above officers are appointed annually for a one-year term by the board of directors of AEP, the board of directors of AEPSC, or both, as the case may be.	

APCo, OPCo and SWEPCo . The names of the executive officers of APCo, OPCo and SWEPCo, the positions they hold with these companies, their ages as of February 1, 2007, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, OPCo and SWEPCo are elected annually to serve a one-year term.

Name	 	Age	 	Position	 	Period	
Michael G. Morris (a)(b)	 	60	 	Chairman of the Board, President, Chief Executive Officer and Director of AEP and AEPSC	 	2004-Present	
 	 	 	 	Chairman of the Board, Chief Executive Officer and Director of APCo, OPCo and SWEPCo	 	2004-Present	
 	 	 	 	Chairman of the Board, President and Chief Executive Officer of Northeast Utilities	 	1997-2003	
Nicholas K. Akins (a)	 	46	 	Executive Vice President of AEP	 	2006-Present	
 	 	 	 	Executive Vice President-Generation and Director of AEPSC	 	2006-Present	
 	 	 	 	Vice President and Director of APCo and OPCo	 	2006-Present	
 	 	 	 	Director of SWEPCo	 	2006-Present	
 	 	 	 	President and Chief Operating Officer of SWEPCo	 	2004-2006	
 	 	 	 	Vice President-Energy Market Services of AEPSC	 	2002-2004	
 	 	 	 	Vice President-Energy Delivery Business Development of AEPSC	 	2001-2002	
Carl L. English (c)	 	60	 	President-AEP Utilities of AEP	 	2004-Present	
 	 	 	 	President-AEP Utilities and Director of AEPSC	 	2004-Present	
 	 	 	 	Director and Vice President of APCo, OPCo and SWEPCo	 	2004-Present	
 	 	 	 	President and Chief Executive Officer of Consumers Energy gas division	 	1999-2004	
Thomas M. Hagan (d)	 	62	 	Executive Vice President of AEP	 	2006-Present	
 	 	 	 	Executive Vice President-AEP Utilities-West	 	2004-Present	
 	 	 	 	Director of AEPSC	 	2002-Present	
 	 	 	 	Vice Chairman of the Board of SWEPCo	 	2004-Present	
 	 	 	 	Vice President and Director of SWEPCo	 	2002-Present	
 	 	 	 	Vice President and Director of APCo and OPCo	 	2002-2004	
 	 	 	 	Executive Vice President of AEP	 	2004	
 	 	 	 	Executive Vice President-Shared Services of AEPSC	 	2002-2004	
 	 	 	 	Senior Vice President-Governmental Affairs of AEPSC	 	2000-2002	
John B. Keane (e)	 	60	 	Senior Vice President, General Counsel, Chief Compliance Officer and Secretary of AEP	 	2004-Present	
 	 	 	 	Senior Vice President, General Counsel and Director of AEPSC	 	2004-Present	
 	 	 	 	Director of APCo, OPCo and SWEPCo	 	2004-Present	
 	 	 	 	President of Bainbridge Crossing Advisors	 	2003-2004	
 	 	 	 	Vice President-Administration-Northeast Utilities	 	1998-2002	
Holly K. Koeppel (a)	 	48	 	Executive Vice President and Chief Financial Officer of AEP and AEPSC	 	2006-Present	
 	 	 	 	Director of AEPSC	 	2003-Present	
 	 	 	 	Executive Vice President-AEP Utilities-East of AEPSC	 	2004-Present	
 	 	 	 	Vice President of APCo and OPCo	 	2003-Present	
 	 	 	 	Director of APCo and OPCo	 	2004-Present	
 	 	 	 	Chief Financial Officer of APCo, OPCo and SWEPCo	 	2006-Present	
 	 	 	 	Vice President and Director of SWEPCO	 	2006-Present	
 	 	 	 	Executive Vice President of AEP	 	2004	
 	 	 	 	Executive Vice President-Commercial Operations of AEPSC	 	2002-2004	
 	 	 	 	Senior Vice President-Corporate Development of AEPSC	 	2002	
Robert P. Powers (f)	 	52	 	Executive Vice President of AEP	 	2004-Present	
 	 	 	 	Executive Vice President-AEP Utilities East of AEPSC	 	2006-Present	
 	 	 	 	Director of AEPSC	 	2001-Present	
 	 	 	 	Executive Vice President-Generation of AEPSC	 	2003-2006	
 	 	 	 	Director and Vice President of APCo and OPCo	 	2001-Present	
 	 	 	 	Director and Vice President of SWEPCo	 	2001-2006	
 	 	 	 	Executive Vice President-Nuclear Generation and Technical Services of AEPSC	 	2001-2003	
Susan Tomasky (c)	 	53	 	Executive Vice President of AEP	 	2004-Present	
 	 	 	 	Executive Vice President-Shared Services of AEPSC	 	2006-Present	
 	 	 	 	Chief Financial Officer and Vice President of AEP	 	2001-2006	
 	 	 	 	Executive Vice President-Chief Financial Officer of AEPSC	 	2004-2006	
 	 	 	 	Director of AEPSC	 	1998-Present	
 	 	 	 	Vice President and Director of APCo, OPCo and SWEPCo	 	2000-Present	
 	 	 	 	Executive Vice President-Policy, Finance and Strategic Planning of AEPSC	 	2001-2004	

(a)	Messrs. Morris and Akins and Ms. Koeppel are directors of AEGCo, CSPCo, I&M, KPCo, PSO, TCC and TNC.	
 	 	
(b)	Mr. Morris is a director of Cincinnati Bell, Inc. and The Hartford Financial Services Group, Inc.	
 	 	
(c)	Mr. English and Ms. Tomasky are directors of CSPCo, I&M, KPCo, PSO, TCC and TNC.	
 	 	
(d)	Mr. Hagan is a director of PSO, TCC and TNC.	
 	 	
(e)	Mr. Keane is a director of AEGCo, CSPCo, KPCo, PSO, TCC and TNC.	
 	 	
(f)	Mr. Powers is a director of AEGCo, CSPCo, I&M, KPCo, PSO, TCC and TNC.	

APCo:
Name	 	Age	 	Position	 	Period	
Dana E. Waldo	 	55	 	President and Chief Operating Officer of APCo and Kingsport Power Company	 	2004-Present	
 	 	 	 	President of Wheeling Power Company	 	2005-Present	
 	 	 	 	President and Chief Executive Officer of West Virginia Roundtable	 	1999-2004	

OPCo:
Name	 	Age	 	Position	 	Period	
Kevin E. Walker	 	43	 	President and Chief Operating Officer of CSPCo and OPCo	 	2004-Present	
 	 	 	 	President of WPCo	 	2004-2005	
 	 	 	 	Vice President of Consolidated Edison (New York)	 	2001-2004	

SWEPCo:
Name	 	Age	 	Position	 	Period	
Venita McCellon-Allen	 	47	 	President and Chief Operating Officer of SWEPCo	 	2006-Present	
 	 	 	 	Director and Senior Vice President-Shared Services of AEPSC	 	2004-2006	
 	 	 	 	Director of APCo, I&M, OPCo, SWEPCo and TCC	 	2004-2006	
 	 	 	 	Senior Vice President-Human Resources for Baylor Health Care Systems	 	2000-2004	

PART II

ITEM 5.    MARKET FOR REGISTRANTS’ COMMON EQUITY,
RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP . The information required by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend Information in the 2006 Annual Report.

AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. The common stock of these companies is held solely by AEP. The amounts of cash dividends on common stock paid by these companies to AEP during 2006, 2005 and 2004 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) in the 2006 Annual Reports.

The following table provides information about purchases by AEP (or its publicly-traded subsidiaries) during the quarter ended December 31, 2006 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	 	Total Number
of Shares
Purchased	 	Average Price
Paid per Share	 	Total Number Of Shares Purchased as Part of Publicly Announced Plans or Programs	 	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs	 	
10/01/06 - 10/31/06 (a)(b)	 	 	177	 	$	68.08	 	 	-	 	$	-	 	
11/01/06 - 11/30/06 (c)	 	 	17	 	 	83.50	 	 	-	 	 	-	 	
12/01/06 - 12/31/06	 	 	-	 	 	-	 	 	-	 	 	-	 	
Total	 	 	194	 	$	69.43	 	 	-	 	$	-	 	

(a)	OPCo repurchased 2 shares of its 4.50% cumulative preferred stock, in privately-negotiated transactions outside of an announced program	
(b)	TCC repurchased 175 shares of its 4.20% cumulative preferred stock, in privately-negotiated transactions outside of an announced program.	
(c)	SWEPCo repurchased 17 shares of its 5.00% cumulative preferred stock, in privately-negotiated transactions outside of an announced program.	
 
ITEM 6.    SELECTED FINANCIAL DATA

AEGCo , CSPCo, I&M, KPCo, PSO, TCC and TNC. Omitted pursuant to Instruction I(2)(a).

AEP, APCo, OPCo and SWEPCo . The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2006 Annual Reports.

ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION
AND RESULTS OF OPERATION

AEGCo, CSPCo, I&M, KPCo, PSO, TCC and TNC . Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis   of Results of Operations in the 2006 Annual Reports.

AEP, APCo, OPCo and SWEPCo . The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis of Results of Operations in the 2006 Annual Reports .

ITEM 7A.   QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK

AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC . The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis of Results of Operations in the 2006 Annual Reports.

ITEM 8.   FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA

AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.   None.

ITEM 9A.   CONTROLS AND PROCEDURES

During 2006, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc. (“AEP”), AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (each, together with AEP, a “Registrant” and collectively, together with AEP, the “Registrants”) evaluated each respective Registrant’s disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2006, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2006 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal controls over financial reporting.

Additional information required by this item of AEP, as a large accelerated filer, is incorporated by reference to Management’s Report on Internal Control over Financial Reporting , included in the 2006 Annual Report.

ITEM 9B.    OTHER INFORMATION

None.

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE

AEGCo , CSPCo, I&M, KPCo, PSO, TCC and TNC. Omitted pursuant to Instruction I(2)(c).

AEP:

Directors, Director Nomination Process and Audit Committee. The information required by this item concerning directors and nominees for election as directors at AEP’s annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)) and the audit committee (Item 407(d)(4) and (d)(5)) is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

Executive Officers. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I, Item 4 of this report.

Code of Ethics. AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Principles of Business Conduct is available on AEP’s website at www.aep.com . The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.
 
If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com , or in a report on Form 8-K.  

Beneficial Ownership Reporting Compliance. The information required by this item is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

APCo and OPCo:

Directors and Executive Officers. The information required by this item is incorporated herein by reference to the information in the definitive information statement of each company for the 2007 annual meeting of stockholders. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I, Item 4 of this report.

Audit Committee. Each of APCo and OPCo is a controlled subsidiary of AEP and does not have a separate audit committee.

Code of Ethics. AEP’s Principles of Business Conduct is the code of ethics that applies to the Chief Executive Officer, Chief Financial Officer and principal accounting officer of APCo and OPCo. The discussion of AEP’s Principles of Business Conduct above is incorporated herein by reference. If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to the Chief Executive Officer, Chief Financial Officer or principal accounting officer of APCo or OPCo, as applicable, that company will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com , or in a report on Form 8-K.

SWEPCo:

Directors and Executive Officers. The names of the directors and executive officers of SWEPCo, the positions they hold with SWEPCo, their ages as of February 1, 2007, and a brief account of their business experience during the past five years appear below or under the caption Executive Officers of the Registrants in Part I, Item 4 of this report.

Name	 	 Age	 	Position	 	Period	
Stephen P. Smith (a)	 	45	 	Senior Vice President and Treasurer of AEP	 	2004-Present	
 	 	 	 	Vice President and Director of APCo, OPCo and SWEPCo	 	2004-Present	
 	 	 	 	Director of AEPSC	 	2004-Present	
 	 	 	 	Senior Vice President and Treasurer of AEPSC	 	2003-Present	
 	 	 	 	Treasurer of AEPSC, APCo, OPCo and SWEPCo	 	2003-Present	
 	 	 	 	President and Chief Operating Officer-Corporate Services for NiSource	 	1999-2003	
Dennis E. Welch (b)	 	55	 	Senior Vice President of AEP	 	2005-Present	
 	 	 	 	Director of APCo, OPCo and SWEPCo	 	2005-Present	
 	 	 	 	Senior Vice President-Environment and Safety and Director of AEPSC	 	2005-Present	
 	 	 	 	President of Yankee Gas Services Company	 	2001-2005	

(a)   Mr. Smith is a director of AEGCo, CSPCo, KPCo, PSO, TCC and TNC.
(b)   Mr. Welch is a director of CSPCo, KPCo, PSO, TCC and TNC.

Audit Committee. SWEPCo is a controlled subsidiary of AEP and does not have a separate audit committee.

Code of Ethics. AEP’s Principles of Business Conduct is the code of ethics that applies to the Chief Executive Officer, Chief Financial Officer and principal accounting officer of SWEPCo. The discussion of AEP’s Principles of Business Conduct above is incorporated herein by reference. If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, SWEPCo will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com , or in a report on Form 8-K.

ITEM 11.   EXECUTIVE COMPENSATION

AEGCo , CSPCo, I&M, KPCo, PSO, TCC and TNC.   Omitted pursuant to Instruction I(2)(c).

AEP . The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

APCo and OPCo . The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of each company for the 2007 annual meeting of stockholders.

SWEPCo . The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

AEGCo , CSPCo, I&M, KPCo, PSO, TCC and TNC.   Omitted pursuant to Instruction I(2)(c).

AEP . The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

APCo and OPCo . The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of each company for the 2007 annual meeting of stockholders.

SWEPCo. All 7,536,640 outstanding shares of Common Stock, $18 par value, of SWEPCo are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of SWEPCo generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares.

The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 2006, by each director and nominee of SWEPCo and each of the executive officers of SWEPCo named in the summary compensation table, and by all directors and executive officers of SWEPCo as a group. It is based on information provided to SWEPCo by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of SWEPCo. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his or her name. Fractions of shares and units have been rounded to the nearest whole number.

Name	 	Shares (a)	 	Stock Units (b)	 	Total	
Nicholas K. Akins	 	15,900	 	 	1,574	 	17,474	
Carl L. English	 	13,610	 	 	12,351	 	25,961	
Thomas M. Hagan	 	166,708	 	 	28,971	 	195,679	
John B. Keane	 	6,804	 	 	6,174	 	12,978	
Holly K. Koeppel	 	36,967	 	 	33,617	 	70,584	
Venita McCellon-Allen	 	4,536	 	 	4,066	 	8,602	
Michael G. Morris	 	438,498	(c)	 	161,008	 	599,506	
Stephen P. Smith	 	19,000	 	 	9,814	 	28,814	
Susan Tomasky	 	208,572	 	 	41,144	 	249,716	
Dennis E. Welch	 	3,333	 	 	10,398	 	13,731	
All Directors and
Executive Officers	 	913,928	(d)	 	309,117	 	1,223,045	

 	AEP Retirement  Savings Plan	
Name	(Share Equivalents)	
Nicholas K. Akins	—	
Carl L. English	—	
Thomas M. Hagan	5,715	
John B. Keane	—	
Holly K. Koeppel	267	
Venita McCellon-Allen	—	
Michael G. Morris	—	
Stephen P. Smith	—	
Susan Tomasky	4,238	
Dennis E. Welch	—	
All Directors and Executive Officers	10,220	

With respect to the share equivalents held in the AEP Retirement Savings Plan, such persons have sole voting power, but the investment/disposition power is subject to the terms of the Plan. Also, includes the following numbers of shares attributable to options exercisable within 60 days: Mr. Akins, 15,900; Mr. Hagan, 150,500; Ms. Koeppel, 36,700; Mr. Morris, 149,000; Mr. Smith, 16,500; Ms. Tomasky, 204,334; and Mr. Welch, 3,333.

(a)   Includes share equivalents held in the AEP Retirement Savings Plan in the amounts listed.
(b)   This column includes amounts deferred in stock units and held under AEP’s various director and officer benefit plans.
(c)   Represents less than 1% of the total number of shares outstanding.
(d)   Includes restricted shares with different vesting schedules and accrued dividends.

EQUITY COMPENSATION PLAN INFORMATION

Information regarding the equity compensation plan is incorporated by reference from the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

AEGCo , CSPCo, I&M, KPCo, PSO, TCC and TNC. Omitted pursuant to Instruction I(2)(c).

AEP . The information required by this item is incorporated herein by reference to the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

APCo , OPCo and SWEPCo:   Certain Relationships and Related Transactions. None. Director Independence . None of the directors of APCo, OPCo or SWEPCo is independent because each director is either (i) an officer of the company in which each serves as director, or (ii) an officer of AEP.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP . The following table presents fees for professional audit services rendered by Deloitte & Touche LLP for the audit of AEP’s annual financial statements for the years ended December 31, 2006 and December 31, 2005, and fees billed for other services rendered by Deloitte & Touche LLP during those periods.

 	 	 	2006	 	 	2005	 	
Audit Fees (1)	 	 	 	 	 	 	 	
 Financial Statements	 	$	8,564,000	 	$	8,469,000	 	
 Internal Control over financial reporting	 	 	4,080,000	 	 	4,210,000	 	
  Total Audit Fees	 	 	12,644,000	 	 	12,679,000	 	
Audit-Related Fees (2)	 	 	822,000	 	 	581,000	 	
Tax Fees (3)	 	 	703,000	 	 	1,116,000	 	
  TOTAL	 	$	14,169,000	 	$	14,376,000	 	
 
(1)	Audit fees in 2005 and 2006 consisted primarily of fees related to the audit of the Company’s annual consolidated financial statements, including each registrant subsidiary. Audit fees also included auditing procedures performed in accordance with Sarbanes-Oxley Act Section 404 and the related Public Company Accounting Oversight Board Auditing Standard Number 2 regarding the Company’s internal control over financial reporting.  This category also includes work generally only the independent registered public accounting firm can reasonably be expected to provide.	
 	 	
(2)	Audit related fees consisted principally of regulatory and statutory audits and audit-related work in connection with acquisitions and dispositions.	
 	 	
(3)	Tax fees consisted principally of tax compliance services. Tax compliance services are services rendered based upon facts already in existence or transactions that have already occurred to document, compute, and obtain government approval for amounts to be included in tax filings.	
 
APCo and OPCo . The information required by this item is incorporated herein by reference to the definitive information statement of each company for the 2007 annual meeting of stockholders.

AEGCo , CSPCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC.

Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2007 annual meeting of shareholders. The following table presents directly billed fees for professional services rendered by Deloitte & Touche LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2005 and 2006, and fees directly billed for other services rendered by Deloitte & Touche LLP during those periods. Deloitte & Touche LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the definitive proxy statement of AEP for the 2007 annual meeting of shareholders.

 	 	AEGCo	 	CSPCo	 	I&M	 	
 	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
Audit Fees	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Financial Statement Audits	 	$	162,474	 	$	165,550	 	$	786,264	 	$	672,646	 	$	841,074	 	  $	755,644	 	
Sarbanes-Oxley 404	 	 	97,512	 	 	100,619	 	 	451,248	 	 	465,626	 	 	426,768	 	 	440,366	 	
Audit Fees - Other	 	 	57,739	 	 	29,628	 	 	179,792	 	 	145,287	 	 	276,523	 	 	139,603	 	
Audit Fees Subtotal	 	 	317,725	 	 	295,797	 	 	1,417,304	 	 	1,283,559	 	 	1,544,365	 	 	1,335,613	 	
Audit-Related Fees	 	 	5,513	 	 	0	 	 	31,755	 	 	55,500	 	 	248,233	 	 	5,500	 	
Tax Fees	 	 	1,350	 	 	2,250	 	 	22,913	 	 	23,100	 	 	26,216	 	 	30,350	 	
TOTAL	 	$	324,588	 	$	298,047	 	$	1,471,972	 	$	1,362,159	 	$	1,818,814	 	$	1,371,463	 	

 	 	KPCo	 	PSO	 	SWEPCo	 	
 	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
Audit Fees	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Financial Statement Audits	 	$	488,070	 	$	446,615	 	$	293,625	 	$	416,418	 	$	336,039	 	$	483,761	 	
Sarbanes-Oxley 404	 	 	247,656	 	 	255,547	 	 	238,272	 	 	245,864	 	 	276,216	 	 	285,438	 	
Audit Fees - Other	 	 	107,136	 	 	71,972	 	 	111,144	 	 	89,098	 	 	133,580	 	 	99,190	 	
Audit Fees Subtotal	 	 	842,862	 	 	774,134	 	 	643,041	 	 	751,380	 	 	745,835	 	 	868,389	 	
Audit-Related Fees	 	 	15,638	 	 	0	 	 	16,772	 	 	5,500	 	 	87,657	 	 	5,500	 	
Tax Fees	 	 	8,945	 	 	10,550	 	 	18,804	 	 	21,400	 	 	22,134	 	 	20,400	 	
TOTAL	 	$	867,445	 	$	784,684	 	$	678,617	 	$	778,280	 	$	855,626	 	$	894,289	 	

 	 	TCC	 	TNC	 	
 	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
Audit Fees	 	 	 	 	 	 	 	 	 	 	 	 	 	
Financial Statement Audits	 	$	332,124	 	$	512,496	 	$	122,019	 	$	175,723	 	
Sarbanes-Oxley 404	 	 	310,896	 	 	320,802	 	 	163,608	 	 	168,821	 	
Audit Fees - Other	 	 	242,977	 	 	170,027	 	 	42,018	 	 	48,337	 	
Audit Fees Subtotal	 	 	885,997	 	 	1,003,325	 	 	327,645	 	 	392,881	 	
Audit-Related Fees	 	 	60,113	 	 	0	 	 	6,029	 	 	0	 	
Tax Fees	 	 	23,079	 	 	28,900	 	 	9,795	 	 	15,250	 	
TOTAL	 	$	969,189	 	  $	1,032,225	 	$	343,469	 	$	408,131	 	

PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this report:

 	 Page	
1.   Financial Statements:	 	
The following financial statements have been incorporated herein by reference pursuant to Item 8.	 	
AEGCo:	 	
Statements of Income for the years ended December 31, 2006, 2005 and 2004; Statements of Retained Earnings for the years ended December 31, 2006, 2005 and 2004; Balance Sheets as of December 31, 2006 and 2005; Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.	 	
AEP and Subsidiary Companies:	 	
Reports of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004; Consolidated Balance Sheets as of December 31, 2006 and 2005; Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004; Consolidated Statements of Changes in Common Shareholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004; Notes to Consolidated Financial Statements.	 	
APCo, CSPCo, I&M, OPCo, SWEPCo, TNC and TCC:	 	
Consolidated Statements of Income (or Statements of Operations) for the years ended December 31, 2006, 2005 and 2004; Consolidated Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004; Consolidated Balance Sheets as of December 31, 2006 and 2005; Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.	 	
KPCo and PSO:	 	
Statements of Income for the years ended December 31, 2006, 2005 and 2004; Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004; Balance Sheets as of December 31, 2006 and 2005; Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.	 	
2.   Financial Statement Schedules:	 	
Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Report of Independent Registered Public Accounting Firm	S-1	
3.   Exhibits:	 	
Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference	E-1	

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 	American Electric Power Company, Inc.	
 	By:	/s/ Holly K. Koeppel	
 	 	(Holly K. Koeppel, Executive Vice President	
 	 	and Chief Financial Officer)	
Date: February 28, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	 	Title	 	Date	
 	 	 	 	 	
(i)   Principal Executive Officer:	 	 	 	 	
 	 	 	 	 	
/ s / Michael G. Morris	 	Chairman of the Board, President,	 	February 28, 2007	
(Michael G. Morris)	 	Chief Executive Officer	 	 	
 	 	And Director	 	 	
 	 	 	 	 	
(ii)   Principal Financial Officer:	 	 	 	 	
 	 	 	 	 	
/s/ Holly K. Koeppel	 	Executive Vice President and	 	February 28, 2007	
(Holly K. Koeppel)	 	Chief Financial Officer	 	 	
 	 	 	 	 	
(iii)   Principal Accounting Officer:	 	 	 	 	
 	 	 	 	 	
/s/ Joseph M. Buonaiuto	 	Senior Vice President, Controller and	 	February 28, 2007	
(Joseph M. Buonaiuto)	 	Chief Accounting Officer	 	 	
 	 	 	 	 	
(iv)   A Majority of the Directors:	 	 	 	 	
 	 	 	 	 	
* E. R. Brooks	 	 	 	 	
* Donald M. Carlton	 	 	 	 	
*Ralph D. Crosby, Jr.	 	 	 	 	
* John P. DesBarres	 	 	 	 	
* Robert W. Fri	 	 	 	 	
* Linda A. Goodspeed	 	 	 	 	
* William R. Howell	 	 	 	 	
* Lester A. Hudson, Jr.	 	 	 	 	
*Lionel L. Nowell, III	 	 	 	 	
*Richard L. Sandor	 	 	 	 	
* Donald G. Smith	 	 	 	 	
* Kathryn D. Sullivan	 	 	 	 	
 	 	 	 	 	 	
*By:	 /s/ Holly K. Koeppel	 	 	 	February 28, 2007	
 	(Holly K. Koeppel, Attorney-in-Fact)	 	 	 	 	

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
 	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 the   Companies listed in Item 15.  These financial statement schedules are the responsibility of the Companies’ management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
 
/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

 	 	  	 	  	 	  	 	  	 	  	 	
Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	30,553	 	$	29,831	 	$	1,001	 	$	31,557	 	$	29,828	 	
   Year Ended December 31, 2005	 	 	77,175	 	 	27,384	 	 	24	 	 	74,030	 	 	30,553	 	
   Year Ended December 31, 2004	 	 	123,685	 	 	39,766	 	 	7,989	 	 	94,265	 	 	77,175	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	143	 	$	(29	) (c)		$	-	 	$	65	 	$	49	 	
   Year Ended December 31, 2005	 	 	3,493	 	 	29	 	 	 	-	 	 	3,379	 	 	143	 	
   Year Ended December 31, 2004	 	 	1,710	 	 	3,493	 	 	 	-	 	 	1,710	 	 	3,493	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   (c) Includes a credit of $29 thousand from a true-up adjustment as a result of changes to the System Integration Agreement and the CSW
        Operating Agreement.	 	

  AEP TEXAS NORTH COMPANY AND SUBSIDIARY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	18	 	$	(9	) (c)	 	$	-	 	$	-	 	$	9	 	
   Year Ended December 31, 2005	 	 	787	 	 	14	 	 	 	-	 	 	783	 	 	18	 	
   Year Ended December 31, 2004	 	 	175	 	 	787	 	 	 	-	 	 	175	 	 	787	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   (c) Includes a credit of $14 thousand from a true-up adjustment as a result of changes to the System Integration Agreement and the CSW
        Operating Agreement.	 	

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	1,805	 	$	4,012		$	999	 	$	2,482	 	$	4,334	 	
   Year Ended December 31, 2005	 	 	5,561	 	 	3,304	 	 	21	 	 	7,081	 	 	1,805	 	
   Year Ended December 31, 2004	 	 	2,085	 	 	3,059	 	 	4,201	 	 	3,784	 	 	5,561	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	1,082	 	$	189		$	-	 	$	725	 	$	546	 	
   Year Ended December 31, 2005	 	 	674	 	 	408	 	 	-	 	 	-	 	 	1,082	 	
   Year Ended December 31, 2004	 	 	531	 	 	577	 	 	187	 	 	621	 	 	674	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	898	 	$	208		$	-	 	$	505	 	$	601	 	
   Year Ended December 31, 2005	 	 	187	 	 	819	 	 	-	 	 	108	 	 	898	 	
   Year Ended December 31, 2004	 	 	531	 	 	195	 	 	90	 	 	629	 	 	187	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

KENTUCKY POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	147	 	$	80		$	-	 	$	-	 	$	227	 	
   Year Ended December 31, 2005	 	 	34	 	 	146	 	 	-	 	 	33	 	 	147	 	
   Year Ended December 31, 2004	 	 	736	 	 	43	 	 	27	 	 	772	 	 	34	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

  OHIO POWER COMPANY CONSOLIDATED
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	1,517	 	$	243		$	-	 	$	936	 	$	824	 	
   Year Ended December 31, 2005	 	 	93	 	 	1,425	 	 	-	 	 	1	 	 	1,517	 	
   Year Ended December 31, 2004	 	 	789	 	 	122	 	 	89	 	 	907	 	 	93	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

PUBLIC SERVICE COMPANY OF OKLAHOMA
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	240	 	$	(81	) (c)	 	$	-	 	$	154	 	$	5	 	
   Year Ended December 31, 2005	 	 	76	 	 	164	 	 	 	-	 	 	-	 	 	240	 	
   Year Ended December 31, 2004	 	 	37	 	 	21	 	 	 	55	 	 	37	 	 	76	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   (c) Includes a credit of $81 thousand from a true-up adjustment as a result of changes to the System Integration Agreement and the CSW
        Operating Agreement.	 	

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Column A	 	Column B	 	Column C	 	Column D	 	Column E	 	
 	 	  	 	Additions	 	  	 	  	 	
Description	 	Balance at Beginning of Period	 	Charged to Costs and Expenses	 	 	Charged to Other Accounts (a)	 	Deductions (b)	 	Balance at End of Period	 	
 	 	(in thousands)	 	
Deducted from Assets:	 	  	 	  	 	 	  	 	  	 	  	 	
Accumulated Provision for	 	  	 	  	 	 	  	 	  	 	  	 	
   Uncollectible Accounts:	 	  	 	  	 	 	  	 	  	 	  	 	
   Year Ended December 31, 2006	 	$	548	 	$	(37	) (c)	 	$	-	 	$	381	 	$	130	 	
   Year Ended December 31, 2005	 	 	45	 	 	534	 	 	 	-	 	 	31	 	 	548	 	
   Year Ended December 31, 2004	 	 	2,093	 	 	(2,079	)	 	 	134	 	 	103	 	 	45	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Recoveries on accounts previously written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(b) Uncollectible accounts written off.	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   (c) Includes a credit of $95 thousand from a true-up adjustment as a result of changes to the System Integration Agreement and the CSW
        Operating Agreement.	 	

 
EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof. Exhibits (“Ex”) not identified as previously filed are filed herewith. Exhibits, designated with a dagger (†), are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form pursuant to Item 14(c) of this report.

Exhibit
Designation	 	Nature of Exhibit	 	Previously Filed as Exhibit to:	
REGISTRANT:   AEGCo   File No. 0-18135	 	 	
3(a)	 	Articles of Incorporation of AEGCo.	 	Registration Statement on Form 10 for the Common Shares of AEGCo, Ex 3(a).	
3(b)	 	Copy of the Code of Regulations of AEGCo, amended as of June 15, 2000.	 	2000 Form 10-K, Ex 3(b).	
10(a)	 	Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP.	 	Registration Statement No. 33-32752, Ex 28(a).	
10(b)(1)	 	Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.	 	Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B).	
10(b)(2)	 	Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KPCo.	 	Registration Statement No. 33-32752, Ex 28(b)(2).	
10(c)	 	Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust Company, as amended.	 	Registration Statement No. 33-32752, Ex 28(c)(1-6)(C);
1993 Form 10-K, Ex 10(c)(1-6)(B).	
*13	 	Copy of those portions of the AEGCo 2006 Annual Report, which are incorporated by reference in this filing.	 	 	
*24	 	Power of Attorney.	 	 	
*31(a)	 	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	 	 	
*31(b)	 	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	 	 	
*32(a)	 	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.	 	 	
*32(b)	 	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.	 	 	
REGISTRANT:   AEP‡     File No. 1-3525	 	 	
3(a)	 	Composite of the Restated Certificate of Incorporation of AEP, dated January 13, 1999.	 	1998 Form 10-K, Ex 3(c).	
3(b)	 	By-Laws of AEP, as amended through December 15, 2003	 	2003 Form 10-K, Ex 3(d).	
4(a)	 	Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.	 	Registration Statement No. 333-86050, Ex 4(a)(b)(c);
Registration Statement No. 333-105532, Ex 4(d)(e)(f).	
4(b)	 	Purchase Agreement dated as of March 8, 2005, between AEP and Merrill Lynch International	 	Form 10-Q, Ex. 4(a), March 31, 2005	
10(a)	 	Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and with AEPSC, as amended.	 	Registration Statement No. 2-52910, Ex 5(a);
Registration Statement No. 2-61009, Ex 5(b);
1990 Form 10-K, Ex 10(a)(3).	
10(b)	 	Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006,.	 	2002 Form 10-K; Ex 10(b)
Form 10-Q, Ex 10(b), March 31, 2006.	
10(c)	 	Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.	 	1985 Form 10-K; Ex 10(b)
1988 Form 10-K, Ex 10(b)(2).	
10(d)	 	Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.	 	2002 Form 10-K; Ex 10(d).	
10(e)(1)	 	Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.	 	2004 Form 10-K, Ex 10(e)(1)	
10(e)(2)	 	PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area.	 	2004 Form 10-K, Ex 10(e)(2)	
10(e)(3)	 	Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.	 	2004 Form 10-K, Ex 10(e)(3)	
10(f)	 	Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended.	 	Registration Statement No. 33-32752, Ex 28(c)(1-6)(C);
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C);
AEGCO 1993 Form 10-K, Ex 10(c)(1-6)(B);
I&M 1993 Form 10-K, Ex 10(e)(1-6)(B).	
10(g)	 	Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested)	 	OPCo 1994 Form 10-K, Ex 10(l)(2).	
10(h)	 	Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.	 	1996 Form 10-K, Ex 10(l)	
†10(i)	 	AEP Accident Coverage Insurance Plan for directors.	 	1985 Form 10-K, Ex 10(g)	
*†10(j)(1)	 	AEP Retainer Deferral Plan for Non-Employee Directors, effective January 1, 2005, as amended February 9, 2007.	 	Form 10-Q, Ex. 10(b), March 31, 2005	
†10(j)(2)	 	AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended.	 	2003 Form 10-K, Ex 10(k)(2).	
*†10(j)(2)(A)	 	First Amendment to AEP Stock Unit Accumulation Plan for Non-Employee Directors dated as of February 9, 2007	 	 	
†10(k)(1)(A)	 	AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001.	 	2000 Form 10-K, Ex 10(j)(1)(A)	
†10(k)(1)(B)	 	Guaranty by AEP of AEPSC Excess Benefits Plan.	 	1990 Form 10-K, Ex 10(h)(1)(B)	
†10(k)(1)(C)	 	First Amendment to AEP System Excess Benefit Plan, dated as of March 5, 2003.	 	2002 Form 10-K; Ex 10(1)(1)(c)	
*†10(k)(2)	 	AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2005 (Non-Qualified), as amended December 28, 2006.	 	 	
†10(k)(3)	 	Service Corporation Umbrella Trust for Executives.	 	1993 Form 10-K, Ex 10(g)(3).	
†10(l)(1)	 	Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.	 	2003 Form 10-K, Ex 10(m)(1).	
†10(l)(2)	 	Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001.	 	2000 Form 10-K, Ex 10(s)	
†10(l)(3)	 	Letter Agreement dated June 23, 2000 between AEPSC and Holly K. Koeppel.	 	2002 Form 10-K; Ex 10(m)(3)(A)	
†10(l)(4)	 	Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.	 	2002 Form 10-K; Ex 10(m)(4)	
†10(l)(5)	 	Letter Agreements dated June 4, 2004 and June 9, 2004 between AEPSC and Carl English	 	Form 10-Q, Ex 10(b), September 30, 2004	
*†10(l)(6)	 	Letter Agreements dated June 14, 2004 and June 17, 2004 between AEPSC and John B. Keane	 	 	
†10(m)	 	AEP System Senior Officer Annual Incentive Compensation Plan.	 	1996 Form 10-K, Ex 10(i)(1)	
†10(n)(1)	 	AEP System Survivor Benefit Plan, effective January 27, 1998.	 	Form 10-Q, Ex 10, September 30, 1998	
†10(n)(2)	 	First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000.	 	2002 Form 10-K; Ex 10(o)(2)	
*†10(o)	 	AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2005, as amended December 28, 2006.	 	 	
†10(p)	 	AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.	 	2002 Form 10-K, Ex 10(r)	
†10(q)	 	Nuclear Key Contributor Retention Plan dated May 1, 2000.	 	2002 Form 10-K; Ex 10(s)	
†10(r)	 	AEP Change In Control Agreement, effective January 1, 2006.	 	Form 8-K, Ex 1, dated January 3, 2006	
†10(s)(1)	 	Amended and Restated AEP System Long-Term Incentive Plan	 	Form 8-K, Item 1.01, dated April 26, 2005.	
†10(s)(2)	 	Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended	 	Form 10-Q, Ex. 10(c), September 30, 2004	
†10(s)(3)	 	Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.	 	Form 10-Q, Ex 10(a), March 31, 2005	
*†10(s)(4)	 	AEP System Stock Ownership Requirement Plan, (as Amended and Restated Effective January 1, 2005), as amended December 28, 2006	 	 	
†10(t)(1)	 	Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997.	 	CSW 1998 Form 10-K, Ex 18, File No. 1-1443	
†10(t)(2)	 	Certified Board Resolutions of AEP Utilities, Inc. (formerly CSW) of July 16, 1996.	 	2003 Form 10-K, Ex 10(v)(3).	
†10(t)(3)	 	Central and South West Corporation Executive Deferred Savings Plan as amended and restated effective as of January 1, 1997.	 	CSW 1998 Form 10-K, Ex 24, File No. 1-1443.	
*12	 	Statement re: Computation of Ratios.	 	 	
*13	 	Copy of those portions of the AEP 2006 Annual Report (for the fiscal year ended December 31, 2006) which are incorporated by reference in this filing.	 	 	
*21	 	List of subsidiaries of AEP.	 	 	
*23	 	Consent of Deloitte & Touche LLP.	 	 	
*24	 	Power of Attorney.	 	 	
*31(a)	 	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	 	 	
*31(b)	 	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	 	 	
*32(a)	 	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.	 	 	
*32(b)	 	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.	 	 	
REGISTRANT:   APCo‡   File No. 1-3457	 	 	
3(a)	 	Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997.	 	1996 Form 10-K, Ex 3(d).	
3(b)	 	By-Laws of APCo, amended as of October 24, 2001.	 	2001 Form 10-K, Ex 3(e).	
4(a)	 	Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.	 	Registration Statement No. 333-45927, Ex 4(a)(b);
Registration Statement No. 333-49071, Ex 4(b);
Registration Statement No. 333-84061, Ex 4(b)(c);
Registration Statement No. 333-100451, Ex 4(b)(c)(d);
Registration Statement No. 333-116284, Ex 4(b)(c);
Registration Statement No. 333-123348, Ex 4(b)(c).
Registration Statement No. 333-136432, Ex 4(b)(c)(d)	
10(a)(1)	 	Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.	 	Registration Statement No. 2-60015, Ex 5(a);
Registration Statement No. 2-63234, Ex 5(a)(1)(B); Registration Statement No 2-66301, Ex 5(a)(1)(C); Registration Statement No. 2-67728, Ex 5(a)(1)(D);
1989 Form 10-K, Ex 10(a)(1)(F);
1992 Form 10-K, Ex 10(a)(1)(B)].	
10(a)(2)	 	Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006.	 	Registration Statement No. 2-60015, Ex 5(c);
Registration Statement No. 2-67728, Ex 5(a)(3)(B);
1992 Form 10-K, Ex 10(a)(2)(B);
2005 Form 10-K, Ex 10(a)(2).	
10(a)(3)	 	Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.	 	Registration Statement No. 2-60015, Ex 5(e).	
10(b)	 	Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and with AEPSC, as amended.	 	Registration Statement No. 2-52910, Ex 5(a);
Registration Statement No. 2-61009, Ex 5(b);
AEP 1990 Form 10-K, Ex 10(a)(3), File No. 1-3525.	
10(c)	 	Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.	 	AEP 1985 Form 10-K, Ex 10(b);
AEP 1988 Form 10-K, Ex 10(b)(2).	
10(d)(1)	 	Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.	 	2004 Form 10-K, Ex 10(d)(1)	
10(d)(2)	 	PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area.	 	2004 Form 10-K, Ex 10(d)(2)	
10(d)(3)	 	Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.	 	2004 Form 10-K, Ex 10(d)(3)	
10(e)	 	Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.	 	AEP 1996 Form 10-K, Ex 10(l), File No. 1-3525.	
†10(f)	 	AEP 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.

  
EXHIBIT 12

PUBLIC SERVICE COMPANY OF OKLAHOMA
Computation of Ratios of Earnings to Fixed Charges
(in thousands except ratio data)  
 	 	Year Ended December 31,          	 	
 	 	2002  	 	2003  	 	2004	 	2005  	 	2006  	 	
EARNINGS	 	    	 	    	 	    	 	    	 	    	 	
Income Before Income Taxes	 	$	63,443	 	$	91,728	 	$	45,351	 	$	88,378	 	$	52,847	 	
Fixed Charges (as below)	 	 	42,377	 	 	46,787	 	 	39,475	 	 	36,762	 	 	44,769	 	
Total Earnings	 	$	105,820	 	$	138,515	 	$	84,826	 	$	125,140	 	$	97,616	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
FIXED CHARGES	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest Expense	 	$	40,422	 	$	44,784	 	$	37,957	 	$	34,094	 	$	40,778	 	
Credit for Allowance for Borrowed Funds Used
   During Construction	 	 	673	 	 	451	 	 	280	 	 	668	 	 	1,491	 	
Trust Dividends	 	 	(186	) 	 	(93	)	 	(62	)	 	-	 	 	-	 	
Estimated Interest Element in Lease Rentals	 	 	1,468	 	 	1,645	 	 	1,300	 	 	2,000	 	 	2,500	 	
Total Fixed Charges	 	$	42,377	 	$	46,787	 	$	39,475	 	$	36,762	 	$	44,769	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ratio of Earnings to Fixed Charges	 	 	2.49	 	 	2.96	 	 	2.14	 	 	3.40	 	 	2.18	 	

 

 

 

 

 

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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	 	 
M eaning	

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.	
NO x	 	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.	
SO 2	 	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.

 

 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
 	 	(in millions)	 	
STATEMENTS OF OPERATIONS DATA	 	  	 	  	 	  	 	  	 	  	 	
Total Revenues	 	$	12,622	 	$	12,111	 	$	14,245	 	$	14,833	 	$	13,641	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	1,966	 	$	1,927	 	$	1,983	 	$	1,743	 	$	1,930	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Discontinued Operations,  Extraordinary
  Loss and Cumulative Effect of Accounting Changes	 	$	992	 	$	1,029	 	$	1,127	 	$	522	 	$	485	 	
Discontinued Operations, Net of Tax	 	 	10	 	 	27	 	 	83	 	 	(605	)	 	(654	)	
Extraordinary Loss, Net of Tax	 	 	-	 	 	(225	)	 	(121	)	 	-	 	 	-	 	
Cumulative Effect of Accounting Changes, Net of Tax	 	 	-	 	 	(17	)	 	-	 	 	193	 	 	(350	)	
Net Income (Loss)	 	$	1,002	 	$	814	 	$	1,089	 	$	110	 	$	(519	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	(in millions)	
Property, Plant and Equipment	 	$	42,021	 	$	39,121	 	$	37,294	 	$	36,031	 	$	34,132	 	
Accumulated Depreciation and Amortization	 	 	15,240	 	 	14,837	 	 	14,493	 	 	14,014	 	 	13,544	 	
Net Property, Plant and Equipment	 	$	26,781	 	$	24,284	 	$	22,801	 	$	22,017	 	$	20,588	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	37,987	 	$	36,172	 	$	34,636	 	$	36,736	 	$	36,003	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholders’ Equity	 	$	9,412	 	$	9,088	 	$	8,515	 	$	7,874	 	$	7,064	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stocks of Subsidiaries	 	$	61	 	$	61	 	$	127	 	$	137	 	$	145	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trust Preferred Securities (a)	 	$	-	 	$	-	 	$	-	 	$	-	 	$	321	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (b)	 	$	13,698	 	$	12,226	 	$	12,287	 	$	14,101	 	$	10,190	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (b)	 	$	291	 	$	251	 	$	243	 	$	182	 	$	228	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMMON STOCK DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic Earnings (Loss) per Common Share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Discontinued Operations, Extraordinary
   Loss and Cumulative Effect of Accounting Changes	 	$	2.52	 	$	2.64	 	$	2.85	 	$	1.35	 	$	1.46	 	
Discontinued Operations, Net of Tax	 	 	0.02	 	 	0.07	 	 	0.21	 	 	(1.57	)	 	(1.97	)	
Extraordinary Loss, Net of Tax	 	 	-	 	 	(0.58	)	 	(0.31	)	 	-	 	 	-	 	
Cumulative Effect of Accounting Changes, Net of Tax	 	 	-	 	 	(0.04	)	 	-	 	 	0.51	 	 	(1.06	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic Earnings (Loss) Per Share	 	$	2.54	 	$	2.09	 	$	2.75	 	$	0.29	 	$	(1.57	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted Average Number of Basic Shares Outstanding (in millions)	 	 	394	 	 	390	 	 	396	 	 	385	 	 	332	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Market Price Range:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
High	 	$	43.13	 	$	40.80	 	$	35.53	 	$	31.51	 	$	48.80	 	
Low	 	$	32.27	 	$	32.25	 	$	28.50	 	$	19.01	 	$	15.10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year-end Market Price	 	$	42.58	 	$	37.09	 	$	34.34	 	$	30.51	 	$	27.33	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Dividends Paid per Common Share	 	$	1.50	 	$	1.42	 	$	1.40	 	$	1.65	 	$	2.40	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dividend Payout Ratio	 	 	59.1	%	 	67.9	%	 	50.9	%	 	569.0	%	 	(152.9	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Book Value per Share	 	$	23.73	 	$	23.08	 	$	21.51	 	$	19.93	 	$	20.85	 	

(a)	See “Trust Preferred Securities” section of Note 15.	
(b)	Including portion due within one year.	

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

American Electric Power Company, Inc. (AEP) is one of the largest investor-owned electric public utility holding companies in the United States. Our electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

We operate an extensive portfolio of assets including:

·	Almost 36,000 megawatts of generating capacity as of December 31, 2006, one of the largest complements of generation in the U.S., the majority of which provides a significant cost advantage in many of our market areas.	
·	Approximately 39,000 miles of transmission lines, including 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.	
·	207,632 miles of distribution lines that deliver electricity to customers.	
·	Substantial coal transportation assets (more than 8,300 railcars, 2,600 barges, 51 towboats and one active coal handling terminal with 20 million tons of annual capacity).	

EXECUTIVE OVERVIEW

BUSINESS STRATEGY

Our mission is to bring comfort to our customers, support business and commerce and build strong communities. We invest in our core utility business operations to execute our mission. Our objective is to be an economical, reliable and safe provider of electric energy to the markets that we serve. We plan to buy or build additional generation to meet franchise service obligations. Our plan entails designing, building, improving and operating reasonably priced, environmentally-compliant, efficient sources of power and maximizing the amount of power delivered from these facilities. We intend to maintain and enhance our position as a safe and reliable provider of electric energy by making significant investments in environmental and reliability upgrades. We will seek to recover the cost of our new utility investments in a manner that results in reasonable rates for our customers while providing a fair return for our shareholders through a stable stream of cash flows, enabling us to pay dependable, competitive dividends. We operate our generating assets to maximize our productivity and profitability after meeting our native load requirements.

In summary, our business strategy is to:

·	Respect our employees and give them the opportunity to be as successful as they can be.	
·	Meet the energy needs of our customers in ways that improve their quality of life and protect the environment today and for generations to come.	
·	Improve the environmental and safety performance of our generating fleet, and grow that fleet.	
·	Set the standards for safety, efficiency and reliability in our electric transmission and distribution systems.	
·	Nurture strong and productive relationships with public officials and regulators.	
·	Provide leadership, integrity and compassion as a corporate citizen to every community we serve.	

OUTLOOK FOR 2007

We remain focused on the fundamental earning power of our utilities and committed to maintaining our credit quality. To achieve our goals we plan to:

·	Obtain permits and continue to pursue federal tax credits for our proposed IGCC plants in Ohio and West Virginia and move forward with the engineering and design of these plants.	
·	Begin construction of over 2,000 MW of new generation in Arkansas, Louisiana and Oklahoma with commercial operation dates ranging from 2007 through 2012.	
·	Purchase 1,576 MW of additional gas-fired generating unit capacity.	
·	Invest in transmission projects such as the AEP Interstate Project, the Electric Transmission Texas Project, a joint venture with MidAmerican Energy Holdings Company (MidAmerican), and others to ensure competitive energy prices for electric consumers in and around congested areas.	
·	Maintain our strong financial condition and credit ratings.	
·	Control our operating and maintenance costs.	
·	Obtain favorable resolutions to our numerous rate proceedings.	
·	Continue developing strong regulatory relationships through operating company interaction with the various regulatory bodies.	

There are, nevertheless, certain risks and challenges including:

·	Regulatory activity in Virginia, Texas, Oklahoma, Ohio and with the FERC.	
·	Legislative activity in Ohio and Virginia regarding future regulatory operating environment.	
·	Fuel cost volatility and fuel cost recovery, including related transportation issues.	
·	Wholesale market volatility.	
·	Plant availability.	
·	Weather.	

Regulatory Activity

In 2007, our significant regulatory activities will include:

·	Pursuit of favorable resolutions of our pending base rate cases in Virginia, Texas and Oklahoma.	
·	Influence of key legislative outcomes regarding Ohio and Virginia’s future regulatory operating environment.	
·	Legal proceedings regarding appeals related to Texas stranded cost recoveries.	
·	Continued regulatory proceedings before the FERC seeking:	
 	·	proper regional transmission rates in our eastern transmission zone,	
 	·	approval of SECA rates collected subject to refund through March 31, 2006 and	
 	·	approval and incentives to construct a 550-mile 765 kV transmission line project in the PJM footprint.	
·	Our request before the PUCT regarding new transmission rates and designation as a utility for Electric Transmission Texas LLC, our joint venture with MidAmerican.	

Fuel Costs

During 2006, spot market prices for coal and natural gas declined. In contrast, market prices for fuel oil increased and continue to be volatile. We still experienced an eight percent increase in coal costs during 2006 and expect a seven to nine percent increase in 2007 even considering softening fuel markets and favorable transportation effects during the year. The increase is primarily due to expiring lower priced contracts being replaced with new higher priced contracts. We have price risk related to these commodity prices. We do not have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs. In Indiana, our fuel recovery mechanism is temporarily capped, subject to preestablished escalators, at a fixed rate through June 2007. As a consequence of the cap, we incurred under-recoveries of $26 million for 2006 and expect additional under-recoveries through June 2007.

Our Ohio companies increased their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans. These increased rates, along with the reinstated fuel cost adjustment rate clause for over- or under-recovery of fuel, off-system sales margins, certain transmission items and related costs effective July 1, 2006 in West Virginia, will help offset future negative impacts of fuel price increases on our gross margins.

Capital Expenditures

Our current projections call for capital expenditures of approximately $9.9 billion from 2007-2009. For 2007, we forecast approximately $3.5 billion in construction expenditures, excluding allowances for funds used during construction. We also forecast purchases of additional gas-fired generating units for a total of $427 million. Our current projections are as follows:
 
 	 	(in millions)	 	
Generation	 	$	996	 	
Distribution	 	 	848	 	
Environmental	 	 	935	 	
Transmission	 	 	496	 	
Corporate	 	 	165	 	
Total Construction Expenditures	 	 	3,440	 	
Purchase of Gas-Fired Units	 	 	427	 	
Total Capital Expenditures	 	$	3,867	 	

Off-System Sales

In 2007, we expect a decline in off-system sales revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power. This decline is primarily due to expected increases in sales to municipal and energy cooperative customers and demand for electricity from our native load retail customers including Ormet, which reduces the amount of power available for off-system sales. In addition, lower expected generating plant availability due to environmental retrofit outages likely will result in lower off-system sales.

Corporate Sustainability Reporting

Our first Corporate Responsibility report will be published and available in 2007. In 2004 a subcommittee of the Policy Committee of our Board of Directors prepared a report entitled, “An Assessment of AEP’s Actions to Mitigate the Economic Impacts of Emissions Policies.” While the 2004 report was quite well received, it primarily addressed environmental issues we face. The scope of our 2007 report will reach beyond environmental issues and address other matters that create risk to our sustainability into the future. The report will be developed using the sustainability reporting guidelines issued by the Global Reporting Initiative and will address issues such as leadership, strategy and management, workforce issues including safety and health, climate change and energy security, reliability and growth.

2006 RESULTS

We had a year of continued improvement and many accomplishments in 2006. Our total shareholder return was 18.8% and we increased our quarterly dividend 5.4% to $0.39 per share.

We continued receiving favorable outcomes in various regulatory activities resulting in increased revenues. We continued securing new power supply contracts with municipal and cooperative customers and our barging subsidiary produced strong results. Some of these positive factors were offset in part by mild weather and an impairment loss from the sale of the Plaquemine Cogeneration Facility to Dow Chemical Company.

We announced plans for new generation in Oklahoma, Louisiana and Arkansas; continued work on engineering and design on new clean-coal plants in Ohio and West Virginia; announced a proposal to build a 550-mile, 765-kilovolt transmission line from West Virginia to New Jersey to address west-east power flow and congestion issues in PJM; announced a joint venture with MidAmerican to build much needed transmission capacity in Texas and we agreed to purchase additional gas-fired generating plants in 2007 to address capacity concerns in the east.

Our regulatory accomplishments include the implementation of new base rates in Ohio, Kentucky, West Virginia and Virginia (subject to refund) and we have taken a step forward in resolving the rate design issues related to our FERC transmission rates. Although various legal issues remain to be decided, we received a final order in our Texas True-up Proceeding and in October 2006 we received proceeds of $1.7 billion related to the securitization of our Texas regulatory assets. We received approval for our request to increase rates for recovery of incremental environmental and reliability costs in Virginia.
 
RESULTS OF OPERATIONS

Segments

Our primary business strategy and the core of our business focus on our electric utility operations. Within our Utility Operations segment, we centrally dispatch all generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Generation/supply in Ohio and Virginia continue to have commission-determined transition rates. Virginia is currently considering returning to regulation for generation. While our Utility Operations segment remains our primary business segment, the emergence of other areas of our business prompted us to identify two new business segments in 2006. One of these new segments is our MEMCO Operations segment, which reflects our significant ongoing barging activities. We also identified our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities in the ERCOT market area. We no longer consider Investments - Gas Operations and Investments - UK Operations as reportable segments because we have sold substantially all of those assets.

Starting in the fourth quarter of 2006, our new segments and their related business activities are as follows:

Utility Operations
·	Generation of electricity for sale to U.S. retail and wholesale customers.	
·	Electricity transmission and distribution in the U.S.	

MEMCO Operations
·	Bulk commodity barging operations.	

Generation and Marketing
·	IPPs, wind farms and marketing and risk management activities in ERCOT.	

The table below presents our consolidated Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change for the years ended December 31, 2006, 2005 and 2004 (Earnings and Weighted Average Number of Basic Shares Outstanding in millions). We reclassified prior year amounts to conform to the current year’s presentation.

 	 	2006	 	2005	 	2004	 	
 	 	Earnings	 	EPS (b)	 	Earnings	 	EPS (b)	 	Earnings	 	EPS (b)	 	
Utility Operations	 	$	1,028	 	$	2.61	 	$	1,018	 	$	2.61	 	$	1,175	 	$	2.97	 	
MEMCO Operations	 	 	80	 	 	0.20	 	 	21	 	 	0.05	 	 	12	 	 	0.03	 	
Generation and Marketing	 	 	12	 	 	0.03	 	 	16	 	 	0.04	 	 	73	 	 	0.18	 	
All Other (a)	 	 	(128	)	 	(0.32	)	 	(26	)	 	(0.06	)	 	(133	)	 	(0.33	)	
Income Before Discontinued Operations, 
  Extraordinary  Loss and Cumulative Effect of 
  Accounting Change	 	$	992	 	$	2.52	 	$	1,029	 	$	2.64	 	$	1,127	 	$	2.85	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted Average Number of Basic 
  Shares Outstanding	 	 	 	 	 	394	 	 	 	 	 	390	 	 	 	 	 	396	 	

(a)	All Other includes:	
 	·	Parent company’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.	
 	·	Our UK operations, which were sold in 2004.	
 	·	Our gas pipeline and storage operations, which were sold in 2004 and 2005.	
 	·	Other energy supply related businesses, including the Plaquemine Cogeneration Facility.	
(b)	The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in AEP’s assets and liabilities as a whole.	

2006 Compared to 2005

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change in 2006 decreased $37 million compared to 2005 primarily due to a $136 million after-tax impairment recorded in the third quarter of 2006 related to the sale of the Plaquemine Cogeneration Facility offset by a $59 million increase in MEMCO Operations earnings. Utility Operations earnings increased $10 million due to new retail rates implemented in Ohio, Kentucky, Oklahoma, Virginia and West Virginia mostly offset by unfavorable weather, decreases in transmission revenues from the loss of SECA rates and increases in regulatory amortization and operating expenses.

Average basic shares outstanding increased to 394 million in 2006 from 390 million in 2005 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 397 million as of December 31, 2006.

2005 Compared to 2004

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change in 2005 decreased $98 million compared to 2004 primarily due to gains on sales of equity investments in 2004 and a decrease in recorded stranded generation carrying costs income in 2005, as a result of the PUCT decisions related to TCC’s True-up Proceeding.

Average basic shares outstanding decreased to 390 million in 2005 from 396 million in 2004 primarily due to the common stock share repurchase program executed in 2005.  Actual shares outstanding were 394 million as of December 31, 2005. 

Our results of operations are discussed below according to our operating segments.

Utility Operations

Our Utility Operations include primarily regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations. We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment. Gross margin represents utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power.

 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Revenues	 	$	12,011	 	$	11,389	 	$	10,764	 	
Fuel and Purchased Power	 	 	4,669	 	 	4,288	 	 	3,704	 	
Gross Margin	 	 	7,342	 	 	7,101	 	 	7,060	 	
Depreciation and Amortization	 	 	1,435	 	 	1,315	 	 	1,281	 	
Other Operating Expenses	 	 	3,843	 	 	3,801	 	 	3,749	 	
Operating Income	 	 	2,064	 	 	1,985	 	 	2,030	 	
Other Income, Net	 	 	177	 	 	103	 	 	330	 	
Interest Charges and Preferred Stock Dividend Requirements	 	 	670	 	 	595	 	 	627	 	
Income Tax Expense	 	 	543	 	 	475	 	 	558	 	
Income Before Discontinued Operations, Extraordinary   Loss
  and Cumulative Effect of  Accounting Change	 	$	1,028	 	$	1,018	 	$	1,175	 	

Summary of Selected Sales and Weather Data
For Utility Operations
For the Years Ended December 31, 2006, 2005 and 2004

 	 	  2006	 	2005	 	2004	 	
Energy Summary	 	  (in millions of KWH)	 	
Retail:	 	  	 	 	 	 	 	
Residential	 	 	47,222	 	 	48,720	 	 	45,770	 	
Commercial	 	 	38,579	 	 	38,605	 	 	37,203	 	
Industrial	 	 	53,914	 	 	53,217	 	 	51,484	 	
Miscellaneous	 	 	2,653	 	 	2,745	 	 	3,252	 	
Total Retail (a)	 	 	142,368	 	 	143,287	 	 	137,709	 	
 	 	 	 	 	 	 	 	 	 	 	
Wholesale	 	 	44,564	 	 	47,785	 	 	57,409	 	
 	 	 	 	 	 	 	 	 	 	 	
Texas Wires Delivery	 	 	26,382	 	 	26,525	 	 	25,581	 	
Total KWHs	 	 	213,314	 	 	217,597	 	 	220,699	 	
 
( a )	Does not include retail sales to Texas Commercial and Industrial (Texas C&I) customers, which are included in the Generation and Marketing segment. Sales by Texas C&I were formerly included in the Utility Operations segment. Total KWHs sold to Texas C&I customers were 296 million, 470 million and 911 million for 2006, 2005 and 2004, respectively.	

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on results of operations. In general, degree day changes in our eastern region have a larger effect on results of operations than changes in our western region due to the relative size of the two regions and the associated number of customers within each. Cooling degree days and heating degree days in our service territory for the years ended December 31, 2006, 2005 and 2004 were as follows:

 	 	  2006	 	2005	 	2004	 	
Weather Summary	 	  (in degree days)	 	
Eastern Region	 	  	 	 	 	 	 	
Actual - Heating (a)	 	 	2,477	 	 	3,130	 	 	2,992	 	
Normal - Heating (b)	 	 	3,078	 	 	3,088	 	 	3,086	 	
 	 	 	 	 	 	 	 	 	 	 	
Actual - Cooling (c)	 	 	923	 	 	1,153	 	 	877	 	
Normal - Cooling (b)	 	 	985	 	 	969	 	 	974	 	
 	 	 	 	 	 	 	 	 	 	 	
Western Region (d)	 	 	 	 	 	 	 	 	 	 	
Actual - Heating (a)	 	 	1,172	 	 	1,377	 	 	1,382	 	
Normal - Heating (b)	 	 	1,605	 	 	1,615	 	 	1,624	 	
 	 	 	 	 	 	 	 	 	 	 	
Actual - Cooling (c)	 	 	2,430	 	 	2,386	 	 	2,006	 	
Normal - Cooling (b)	 	 	2,175	 	 	2,150	 	 	2,149	 	

(a)	Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.	
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.	
(c)	Eastern Region and Western Region cooling degree days are calculated on a 65 degree temperature base.	
(d)	Western Region statistics represent PSO/SWEPCo customer base only.	

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income from Utility Operations Before Discontinued Operations, Extraordinary Loss and
Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	1,018	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	352	 	 	 	 	
Off-system Sales	 	 	(18	)	 	 	 	
Transmission Revenues	 	 	(140	)	 	 	 	
Other Revenues	 	 	47	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	241	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(39	)	 	 	 	
Asset Impairments and Other Related Charges	 	 	39	 	 	 	 	
Gain on Dispositions of Assets, Net	 	 	(50	)	 	 	 	
Depreciation and Amortization	 	 	(120	)	 	 	 	
Taxes Other Than Income Taxes	 	 	8	 	 	 	 	
Carrying Costs Income	 	 	59	 	 	 	 	
Other Income, Net	 	 	15	 	 	 	 	
Interest and Other Charges	 	 	(75	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(163	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(68	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	1,028	 	

Income from Utility Operations Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change increased $10 million to $1,028 million in 2006. The key driver of the increase was a $241 million increase in Gross Margin offset by a $163 million increase in Operating Expenses and Other and a $68 million increase in Income Tax Expense.

The major components of the net increase in Gross Margin were as follows:

·	Retail Margins increased $352 million primarily due to the following:	
·	A $244 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs, a $67 million increase related to new rates implemented in other East jurisdictions of Kentucky, West Virginia and Virginia (subject to refund) and a $13 million increase related to new rates implemented in Oklahoma in June 2005.	
·	A $123 million increase related to increased usage and customer growth of which $63 million relates to the purchase of the Ohio service territory of Monongahela Power in December 2005.	
·	A $70 million increase related to increased sales to municipal, cooperative and other customers primarily as a result of new power supply contracts.	
·	A $55 million increase related to decreased sharing of off-system sales margins with retail customers due to lower off-system sales and changes in the SIA.	
These increases were partially offset by:	
·	A $148 million increase in delivered fuel cost, which relates to the AEP East companies with inactive, capped or frozen fuel clauses.	
·	A $95 million decrease in usage related to mild weather. As compared to the prior year, our eastern region and western region experienced 21% and 15% declines, respectively, in heating degree days. Also compared to the prior year, our eastern region experienced a 20% decrease in cooling degree days.
 	
·	Margins from Off-system Sales decreased $18 million primarily due to lower generation availability in the west due to the sale of STP in May 2005, a reversal of a Texas regulatory provision in 2005 and lower margins from trading activities mostly offset by higher margins in the east.	
·	Transmission Revenues decreased $140 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $34 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. We have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 4.	
·	Other Revenues increased $47 million primarily due to the sale of emission allowances and increased securitization revenues.	

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $39 million primarily due to increases in generation expenses related to base operations and maintenance, distribution expenses related to vegetation management and service reliability, expenses at the Plaquemine Cogeneration Facility and favorable insurance adjustments which reduced expenses in 2005. These increases were partially offset by favorable variances related to expenses from the January 2005 ice storm in Ohio and Indiana and the recovery of the ice storm expenses in Ohio in 2006 and a decrease in severance costs related to the 2005 staffing and budget review.	
·	Asset Impairments and Other Related Charges were $39 million in 2005 due to our retirement of two units at our Conesville Plant.	
·	Gain on Disposition of Assets, Net decreased $50 million primarily resulting from revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase-and-sale agreement from the sale of our REPs in 2002. In 2005, we reached a settlement with Centrica and received $112 million related to two years of earnings sharing whereas in 2006 we received $70 million related to one year of earnings sharing.	
·	Depreciation and Amortization expense increased $120 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases, increased Texas amortization of the securitized transition assets and higher depreciable property balances.	
·	Carrying Costs Income increased $59 million primarily due to negative adjustments in 2005 related to the Texas True-up Proceeding orders received from the PUCT and an increase related to the Virginia environmental and reliability deferred costs.	
·	Interest and Other Charges increased $75 million primarily due to additional debt issued in late 2005 and in 2006 and increasing interest rates, partially offset by an increase in allowance for borrowed funds used during construction.	
·	Income Tax Expense increased $68 million due to an increase in pretax income, state income taxes, changes in certain book/tax differences accounted for on a flow-through basis and the recording of tax reserve adjustments. See “AEP System Income Taxes” section below for further discussion of fluctuations related to income taxes.	

2005 Compared to 2004

Reconciliation of Year Ended December 31, 2004 to Year Ended December 31, 2005
Income from Utility Operations Before Discontinued Operations, Extraordinary Loss and
Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2004	 	 	 	 	$	1,175	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	67	 	 	 	 	
Off-system Sales	 	 	17	 	 	 	 	
Transmission Revenues	 	 	(57	)	 	 	 	
Other Revenues	 	 	14	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	41	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(92	)	 	 	 	
Asset Impairments and Other Related Charges	 	 	(39	)	 	 	 	
Gain on Dispositions of Assets, Net	 	 	116	 	 	 	 	
Depreciation and Amortization	 	 	(34	)	 	 	 	
Taxes Other Than Income Taxes	 	 	(37	)	 	 	 	
Other Income, Net	 	 	(227	)	 	 	 	
Interest and Other Charges	 	 	32	 	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(281	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	83	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2005	 	 	 	 	$	1,018	 	

Income from Utility Operations Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change decreased $157 million to $1,018 million in 2005. Key driver of the decrease included a $281 million increase in Operating Expenses and Other, offset in part by a $41 million increase in Gross Margin and an $83 million decrease in Income Tax Expense.

The major components of the net increase in Gross Margin were as follows:

·	The increase in Retail Margins from our utility segment over the prior year was due to increased demand in both the East and the West as a consequence of higher usage in most classes and customer growth in the residential and commercial classes. The higher usage was primarily weather-related as cooling degree days increased 31% and 19% for the East and West, respectively. This load growth was partially offset by higher delivered fuel costs of approximately $129 million, of which the majority relates to our East companies with inactive fuel clauses.	
·	Margins from Off-system Sales for 2005 were $17 million higher than in 2004 due to favorable price margins partially offset by a decrease in gross margin principally due to the sale of almost all of our Texas generation assets to support Texas stranded cost recovery.	
·	Transmission Revenues decreased $57 million primarily due to the loss of through-and-out rates as mandated by the FERC.	

Utility Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $92 million due to an $87 million increase in generation expense related to strong retail and wholesale sales and capacity requirements, increased plant maintenance in 2005 and PJM expenses of $30 million. Additionally, distribution maintenance expense increased $91 million from tree trimming and reliability work. These increases were partially offset by reduced administrative and general expenses of $90 million.	
·	Asset Impairments and Other Related Charges for 2005 included a $39 million impairment related to the retirement of two units at CSPCo’s Conesville Plant.	
·	Gain on Dispositions of Assets, Net increased $116 million resulting from the receipt of net revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase-and-sale agreement from the sale of our REPs in 2002. We reached an agreement with Centrica in March 2005 resolving disputes back to 2002 on how such amounts were calculated.	
·	Depreciation and Amortization expense increased $34 million primarily due to a higher depreciable asset base.	
·	Taxes Other Than Income Taxes increased $37 million due to increased property tax values and assessments and higher state excise taxes due to the increase in taxable KWH sales.	
·	Other Income, Net decreased $227 million primarily due to the following:	
 	·	A $321 million decrease related to carrying costs recorded by TCC on its net stranded generation costs and its capacity auction true-up asset. In 2004, TCC booked $302 million of carrying costs income related to 2002 through 2004. Upon receipt of the final order in February 2006 in TCC’s True-up Proceeding, we determined that adjustments to those carrying costs were required, resulting in carrying costs expense of $19 million in 2005 for TCC.	
This decrease was offset by:	
 	·	A $56 million increase related to the establishment of regulatory assets for carrying costs on environmental capital expenditures and RTO expenses by our Ohio companies related to the Rate Stabilization Plans.	
 	·	A $20 million increase related to increased interest income and increased AFUDC due to extensive construction activities occurring in 2005.	
 	·	A $14 million increase related to the establishment of regulatory assets for carrying costs on environmental and reliability deferred costs for APCo.	
·	Interest and Other Charges decreased $32 million from the prior period primarily due to refinancings of higher coupon debt at lower interest rates and the retirement of debt in 2004 and 2005.	
·	Income Tax Expense decreased $83 million due to the decrease in pretax income and tax return adjustments. See “AEP System Income Taxes” section below for further discussion of fluctuations related to income taxes.	

MEMCO Operations

2006 Compared to 2005

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change from our MEMCO Operations segment increased from $21 million in 2005 to $80 million in 2006. The increase was primarily related to strong demand and a tight supply of barges resulting in increased barge freight rates and utilization. Additionally, 2006 operating conditions for our barging operations improved from 2005 when hurricanes, severe ice and flooding caused increased operating costs.

2005 Compared to 2004

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change from our MEMCO Operations segment increased from $12 million in 2004 to $21 million in 2005. The increase was primarily related to favorable barging activity due to strong demand and a tight supply of barges, resulting in a 45% increase in freight rates between 2004 and 2005.

Generation and Marketing

2006 Compared to 2005

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change from our Generation and Marketing segment in 2006 was essentially flat when compared to 2005.

2005 Compared to 2004

Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change from our Generation and Marketing segment decreased from $73 million in 2004 to $16 million in 2005. The decrease was primarily due to a $64 million after-tax gain on the sale of our equity investments in the Colorado and Florida independent power producers in 2004.

All Other

2006 Compared to 2005

Loss Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change from All Other increased from a $26 million loss in 2005 to a $128 million loss in 2006. The increase primarily relates to the $136 million after-tax impairment recorded in the third quarter of 2006 related to the sale of the Plaquemine Cogeneration Facility, partially offset by lower interest expense and associated buyback costs related to the redemption of $550 million of senior unsecured notes in April 2005.

2005 Compared to 2004

Loss Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change decreased from a $133 million loss in 2004 to a $26 million loss in 2005. The 2005 results include only one-month of HPL’s operations compared to a full year of HPL operations in 2004 due to the sale of HPL in January of 2005. We also resolved a portion of our outstanding Enron litigation in 2005 resulting in a net of tax settlement cost of approximately $28 million.

AEP System Income Taxes

Income Tax Expense increased $55 million between 2005 and 2006 primarily due to an increase in pretax book income, state income taxes and changes in certain book/tax differences accounted for on a flow-through basis and the recording of tax reserve adjustments.

Income Tax Expense decreased $142 million between 2004 and 2005 primarily due to a decrease in pretax book income, state income taxes and changes in certain book/tax differences accounted for on a flow-through basis, offset in part by the recording of the tax return adjustments.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows. During 2006, we maintained our strong financial condition as reflected by the following actions and events:

·	We maintained stable credit ratings across the AEP System including our rated subsidiaries;	
·	We issued $1.74 billion of securitization bonds for Texas stranded costs; and	
·	Standard and Poor’s improved our business risk profile rating from six to five.	

Debt and Equity Capitalization ($ in millions)
 	 	December 31, 2006	 	December 31, 2005	 	
Long-term Debt, including amounts due within one year	 	$	13,698	 	 	59.1	%	$	12,226	 	 	57.2	%	
Short-term Debt	 	 	18	 	 	0.0	 	 	10	 	 	0.0	 	
Total Debt	 	 	13,716	 	 	59.1	 	 	12,236	 	 	57.2	 	
Common Equity	 	 	9,412	 	 	40.6	 	 	9,088	 	 	42.5	 	
Preferred Stock	 	 	61	 	 	0.3	 	 	61	 	 	0.3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Debt and Equity Capitalization	 	$	23,189	 	 	100.0	%	$	21,385	 	 	100.0	%	

As a consequence of the capital changes during 2006, primarily the issuance of the securitization bonds and the adoption of SFAS 158, our ratio of debt to total capital increased from 57.2% to 59.1%.

In September 2006, the FASB issued SFAS 158 related to phase one of its pension and postretirement benefit accounting project. The new standard requires the recognition of a liability for pension and postretirement benefit plans, thereby eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net actuarial gains and losses. The adoption during the fourth quarter of 2006 resulted in a negative impact on our common equity at December 31, 2006 due to the recognition of a $235 million net of tax accumulated other comprehensive income reduction to common equity for those jurisdictions where we could not record a regulatory asset.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability. We are committed to maintaining adequate liquidity.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At December 31, 2006, our available liquidity was approximately $3.3 billion as illustrated in the table below:

 	 	Amount	 	Maturity	 	
 	 	(in millions)	 	 	 	
Commercial Paper Backup:	 	  	 	 	 	
Revolving Credit Facility	 	$	1,500	 	 	March 2010	 	
Revolving Credit Facility	 	 	1,500	 	 	April 2011	 	
Total	 	 	3,000	 	 	 	 	
Cash and Cash Equivalents	 	 	301	 	 	 	 	
Total Liquidity Sources	 	 	3,301	 	 	 	 	
Less: Letters of Credit Drawn	 	 	26	 	 	 	 	
 	 	 	 	 	 	 	 	
Net Available Liquidity	 	$	3,275	 	 	 	 	

In 2006, we amended the terms and increased the size of our credit facilities from $2.7 billion to $3 billion on terms more economically favorable than the previous agreements. The amended facilities are structured as two $1.5 billion credit facilities, each with an option to issue up to $200 million as letters of credit.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At December 31, 2006, this contractually-defined percentage was 54.0%. Nonperformance of these covenants could result in an event of default under these credit agreements. At December 31, 2006, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

The two revolving credit facilities do not contain a material adverse change clause in the event of a draw on either facility.

Under a regulatory order, our utility subsidiaries, other than TCC, cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% of its capital. In addition, this order restricts those utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. At December 31, 2006, all applicable utility subsidiaries complied with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At December 31, 2006, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910, representing 387 consecutive quarters. The Board of Directors increased the quarterly dividend from $0.37 to $0.39 per share in October 2006. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.

Credit Ratings

Our current credit ratings are as follows:

 	 	  Moody’s	 	  S&P	 	  Fitch	 	
 	 	  	 	  	 	  	 	
AEP Short Term Debt	 	 	P-2	 	 	A-2	 	 	F-2	 	
AEP Senior Unsecured Debt	 	 	Baa2	 	 	BBB	 	 	BBB	 	

If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease. If we receive a downgrade in our credit ratings by one of the rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Managing our cash flows is a major factor in maintaining our liquidity strength.

 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Cash and Cash Equivalents at Beginning of Period	 	$	401	 	$	320	 	$	778	 	
Net Cash Flows From Operating Activities	 	 	2,732	 	 	1,877	 	 	2,711	 	
Net Cash Flows Used For Investing Activities	 	 	(3,743	)	 	(1,005	)	 	(329	)	
Net Cash Flows From (Used For) Financing Activities	 	 	911	 	 	(791	)	 	(2,840	)	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	(100	)	 	81	 	 	(458	)	
Cash and Cash Equivalents at End of Period	 	$	301	 	$	401	 	$	320	 	

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2006, we had credit facilities totaling $3 billion to support our commercial paper program. The maximum amount of commercial paper outstanding during 2006 was $325 million. The weighted-average interest rate of our commercial paper during 2006 was 4.96%. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements. Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders. See the discussion below for further detail related to the components of our cash flows.

Operating Activities
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Net Income	 	$	1,002	 	$	814	 	$	1,089	 	
Less: Discontinued Operations, Net of Tax	 	 	(10	)	 	(27	)	 	(83	)	
Income Before Discontinued Operations	 	 	992	 	 	787	 	 	1,006	 	
Noncash Items Included in Earnings	 	 	1,535	 	 	1,494	 	 	1,315	 	
Changes in Assets and Liabilities	 	 	205	 	 	(404	)	 	390	 	
Net Cash Flows From Operating Activities	 	$	2,732	 	$	1,877	 	$	2,711	 	

Net Cash Flows From Operating Activities increased in 2006 because we did not make a pension contribution in 2006 compared with a $626 million contribution in 2005 and increased recovery of deferred fuel. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of increased fuel costs.

Net Cash Flows From Operating Activities were approximately $2.7 billion in 2006 consisting primarily of Income Before Discontinued Operations of $992 million. Income Before Discontinued Operations included noncash expense items primarily for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. Under-recovered fuel costs decreased due to recoveries under proceedings we initiated in Oklahoma, Texas, Virginia and Arkansas during 2005. Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant is a $232 million decrease in cash related to customer deposits held for trading activities generally due to lower gas and power market prices.

Net Cash Flows From Operating Activities were approximately $1.9 billion in 2005. We produced Income Before Discontinued Operations of $787 million. Income Before Discontinued Operations included noncash expense items primarily for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. We made contributions of $626 million to our pension trusts. Under-recovered fuel costs increased due to the higher cost of fuel, especially natural gas. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs. Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $140 million cash increase from Accounts Payable due to higher fuel and allowance acquisition costs not paid at December 31, 2005 and an increase in Customer Deposits held for trading activities of $157 million related to market prices.

Net Cash Flows From Operating Activities were $2.7 billion in 2004 consisting of our Income Before Discontinued Operations of $1 billion and noncash charges of $1.6 billion for depreciation, amortization and deferred taxes. We recorded $302 million in noncash income for carrying costs on Texas stranded cost recovery and recognized an after-tax, noncash Extraordinary Loss of $121 million to provide for probable disallowances to TCC’s stranded generation costs. We realized gains of $157 million on sales of assets, primarily the IPPs and our South Coast equity investment. We made $231 million of contributions to our pension trusts. Changes in Assets and Liabilities represent those items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Changes in working capital items resulted in cash from operations of $430 million predominantly due to increased accrued income taxes. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since our consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments.

Investing Activities
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Construction Expenditures	 	$	(3,528	)	$	(2,404	)	$	(1,637	)	
Change in Other Temporary Cash Investments, Net	 	 	(33	)	 	76	 	 	32	 	
Investment in Discontinued Operations, Net	 	 	-	 	 	-	 	 	(59	)	
Purchases/Sales of Investment Securities, Net	 	 	(279	)	 	98	 	 	46	 	
Acquisitions of Assets	 	 	-	 	 	(360	)	 	-	 	
Proceeds from Sales of Assets	 	 	186	 	 	1,606	 	 	1,357	 	
Other	 	 	(89	)	 	(21	)	 	(68	)	
Net Cash Flows Used for Investing Activities	 	$	(3,743	)	$	(1,005	)	$	(329	)	

Net Cash Flows Used For Investing Activities were $3.7 billion in 2006 primarily due to Construction Expenditures for our environmental investment plan. In our normal course of business, we purchase investment securities including auction rate securities and variable rate demand notes with cash available for short-term investments. These amounts also include purchases and sales of securities within our nuclear trusts.

Net Cash Flows Used For Investing Activities were $1.0 billion in 2005 primarily due to Construction Expenditures being partially offset by the proceeds from the sales of HPL and STP. The sales were part of an announced plan to divest noncore investments and assets and a requirement of collecting stranded costs in Texas. Construction Expenditures increased due to our environmental investment plan.
 
Net Cash Flows Used For Investing Activities were $329 million in 2004. We funded our construction expenditures primarily with cash generated by operations. Our construction expenditures of $1.6 billion were distributed across our system, of which the most significant expenditures were investments for environmental improvements of $350 million and for a high voltage transmission line of $75 million. During 2004, we sold our U.K. generation, Jefferson Island Storage, LIG and certain IPP and TCC generation assets and used the proceeds from the sales of these assets to reduce debt.

We forecast approximately $3.5 billion of construction expenditures for 2007 plus $427 million for announced purchases of gas-fired generating units. 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, weather, legal reviews and the ability to access capital. These construction expenditures will be funded through results of operations and financing activities.

Financing Activities
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Issuance of Common Stock	 	$	99	 	$	402	 	$	17	 	
Repurchase of Common Stock	 	 	-	 	 	(427	)	 	-	 	
Issuance/Retirement of Debt, Net	 	 	1,420	 	 	(91	)	 	(2,238	)	
Dividends Paid on Common Stock	 	 	(591	)	 	(553	)	 	(555	)	
Other	 	 	(17	)	 	(122	)	 	(64	)	
Net Cash Flows From (Used for) Financing Activities	 	$	911	 	$	(791	)	$	(2,840	)	

Net Cash Flows From Financing Activities were $911 million in 2006 primarily due to issuance of the Texas Securitization Bonds. We paid common stock dividends of $591 million and issued and retired debt securities. See Note 15.

In 2005, we used $791 million of cash to pay dividends, buy back stock, retire preferred stock and reduce debt.

In 2004, we used $2.8 billion of cash to reduce debt and pay common stock dividends. We achieved our goal of reducing debt below 60% of total capitalization by December 31, 2004. The debt reductions were primarily funded with proceeds from our various divestitures during 2004.

The following financing activities occurred during 2006:

Common Stock:

·	During 2006, we issued 2,955,898 shares of common stock under our incentive compensation and dividend reinvestment plans and received net proceeds of $99 million.	

Debt:

·	During 2006, we issued approximately $3.4 billion of long-term debt, including approximately $264 million of pollution control revenue bonds, $1.4 billion of senior notes and $1.7 billion of securitization bonds for Texas stranded costs. The proceeds from these issuances were used to fund long-term debt maturities and optional redemptions and construction programs.	
·	During 2006, we entered into $898 million of interest rate derivatives and settled $1.2 billion of such transactions. The settlements resulted in a net cash expenditure of $8 million. As of December 31, 2006, we had in place interest rate derivatives designated as cash flow hedges with a notional amount of $200 million in order to hedge a portion of anticipated 2007 issuances.	
·	At December 31, 2006, we had credit facilities totaling $3 billion to support our commercial paper program. As of December 31, 2006, we had no commercial paper outstanding related to the corporate borrowing program. For the corporate borrowing program, the maximum amount of commercial paper outstanding during the year was $325 million in March 2006 and the weighted average interest rate of commercial paper outstanding during the year was 4.96%.	

Our capital investment plans for 2007 will require additional funding from the capital markets.

Off-balance Sheet Arrangements

Under a limited set of circumstances, we enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business. The following identifies significant off-balance sheet arrangements:

AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires from affiliated utility subsidiaries to the commercial paper conduits and banks and receives cash. We have no ownership interest in the commercial paper conduits and, in accordance with GAAP, are not required to consolidate these entities. We continue to service the receivables. This off-balance sheet transaction was entered to allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables, and accelerate AEP Credit’s cash collections.

AEP Credit’s sale of receivables agreement expires August 24, 2007. We intend to extend or replace the sale of receivables agreement. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2006, $536 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent receivables purchased by AEP Credit from certain Registrant Subsidiaries. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts.

Rockport Plant Unit 2

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each company are $1.2 billion as of December 31, 2006.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. Our subsidiaries account for the lease as an operating lease with the future payment obligations included in Note 14. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. We, as well as our subsidiaries, have no ownership interest in the Owner Trustee and do not guarantee its debt.

Railcars

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years. At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years; (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value; or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. We intend to renew the lease for the full twenty years. This operating lease agreement allows us to avoid a large initial capital expenditure and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the current lease term from approximately 86% to 77% of the projected fair market value of the equipment. At December 31, 2006, the maximum potential loss was approximately $31 million ($20 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. We have other railcar lease arrangements that do not utilize this type of financing structure.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in our footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payments Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than 1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Short-term Debt (a)	 	$	18	 	$	-	 	$	-	 	$	-	 	$	18	 	
Interest on Fixed Rate Portion of Long-term  Debt (b)	 	 	619	 	 	1,144	 	 	981	 	 	5,244	 	 	7,988	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	1,126	 	 	1,050	 	 	1,823	 	 	8,162	 	 	12,161	 	
Variable Rate Portion of Long-term Debt (d)	 	 	143	 	 	85	 	 	88	 	 	1,277	 	 	1,593	 	
Capital Lease Obligations (e)	 	 	90	 	 	117	 	 	43	 	 	126	 	 	376	 	
Noncancelable Operating Leases (e)	 	 	331	 	 	599	 	 	490	 	 	1,893	 	 	3,313	 	
Fuel Purchase Contracts (f)	 	 	2,499	 	 	3,892	 	 	3,090	 	 	8,299	 	 	17,780	 	
Energy and Capacity Purchase Contracts (g)	 	 	199	 	 	352	 	 	306	 	 	408	 	 	1,265	 	
Construction Contracts for Capital Assets (h)	 	 	1,728	 	 	645	 	 	29	 	 	945	 	 	3,347	 	
Total	 	$	6,753	 	$	7,884	 	$	6,850	 	$	26,354	 	$	47,841	 	

(a)	Represents principal only excluding interest.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancing, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.50% and 6.35% at December 31, 2006.	
(e)	See Note 14.	
(f)	Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.	
(g)	Represents contractual cash flows of energy and capacity purchase contracts.	
(h)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9 to the consolidated financial statements, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trusts.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds and other commitments. At December 31, 2006, our commitments outstanding under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period
(in millions)

Other Commercial Commitments	 	Less Than 1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Standby Letters of Credit (a) (b)	 	$	26	 	$	-	 	$	-	 	$	-	 	$	26	 	
Guarantees of the Performance of Outside  Parties (b)	 	 	-	 	 	-	 	 	-	 	 	85	 	 	85	 	
Guarantees of Our Performance (c)	 	 	1,943	 	 	1,376	 	 	7	 	 	20	 	 	3,346	 	
Transmission Facilities for Third Parties (d)	 	 	21	 	 	12	 	 	-	 	 	-	 	 	33	 	
Total Commercial Commitments	 	$	1,990	 	$	1,388	 	$	7	 	$	105	 	$	3,490	 	

(a)	We issue standby letters of credit to third parties. These letters of credit, issued in our ordinary course of business, cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. The maximum future payments of these letters of credit are $26 million with maturities ranging from March 2007 to November 2007. As the parent of all of these subsidiaries, AEP holds all assets of the subsidiaries as collateral. There is no recourse to third parties if these letters of credit are drawn.	
(b)	See “Guarantees of Third-party Obligations” section of Note 6.	
(c)	We issued performance guarantees and indemnifications for energy trading, International Marine Terminal Pollution Control Bonds and various sale agreements.	
(d)	As construction agent for third party owners of transmission facilities, we committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.	

Other

Cook Plant

In 2006, during a regular refueling outage, Cook Plant Unit 1 completed the planned replacement of major components, including the reactor vessel head, at a cost of $119 million. These improvements and replacement of major components should increase efficiency as well as adding 40 MW of capacity in the winter. We refueled Cook Plant Unit 2 during March and April 2006 and plan to replace its vessel head during its next refueling outage scheduled for the fall of 2007.

Texas REPs

As part of the purchase-and-sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities. In 2005, upon resolution of various contractual matters with Centrica, we received payments from our share in earnings of $45 million and $70 million for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in 2005. In 2006, we received a $70 million payment for our share in earnings of 2005. The 2006 payment is contingent on Centrica’s operating results, contractually capped at $20 million, and, to the extent earned, we expect to receive the 2006 payment in March 2007.

SIGNIFICANT FACTORS

Electric Transmission Texas LLC Joint Venture

In January 2007, we signed a participation agreement with MidAmerican Energy Holdings Company (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 and to establish a wholesale transmission tariff for ETT. ETT also requested approval from PUCT of initial rates based on an 11.25% return on equity.

Upon receipt of all required regulatory approvals, AEP Utilities, Inc., a subsidiary of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each will acquire a 50 percent equity ownership in ETT. AEP and MidAmerican plan for ETT to invest in additional transmission projects in ERCOT. The joint venture partners anticipate in excess of $1 billion in projects could be made by ETT during the next several years.

TCC also made a regulatory filing at the FERC in February 2007 regarding the transfer of certain 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 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.

We believe Texas can provide a high degree of regulatory certainty for transmission investment due to the predetermination of ERCOT’s need based on reliability needs and significant Texas economic growth as well as public policy that supports “green generation” initiatives, which require transmission access. In addition, a streamlined annual interim transmission cost of service review process is available in ERCOT, which should help reduce regulatory lag. The use of a joint venture structure will allow us to share the capital requirements for this type of significant investment while allowing us to participate in more transmission projects than previously anticipated.

AEP Interstate Project

In January 2006, we filed a proposal with the FERC and PJM to build a new 765 kV 550-mile transmission line from West Virginia to New Jersey. The 765 kV line is designed to reduce PJM congestion costs by substantially improving west-east transfer capability by approximately 5,000 MW during peak loading conditions and reducing transmission line losses by up to 280 MW. The project would also enhance reliability of the Eastern transmission grid. A new subsidiary, AEP Transmission Co., LLC, will own the line and undertake construction of the project. The projected cost for the project is approximately $3 billion, of which ownership may ultimately be shared with third party affected participants. The project is subject to PJM, state and FERC approvals of appropriate incentive cost recovery mechanisms. The projected in-service date assumes eight years for siting and construction. Due to delays in approval by the PJM stakeholder process, the projected in-service date is now 2015. This assumes approval by PJM in mid-2007, followed by approval by FERC on initial rates by the end of 2007.

We were the first entity to file with the Department of Energy (DOE) seeking to have the route of a proposed transmission project designated as a National Interest Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005 provides for NIETC designation for areas 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 Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation. This finding should help us obtain early NIETC Designation as promulgated by the Energy Policy Act of 2005. In October 2006, we filed comments with the DOE encouraging corridor designation that is consistent with the proposed line.

In July 2006, pursuant to our request, 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 conditionally approved incentives include (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the timely recovery of the cost of capital during the construction period; and (c) the ability to defer 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 a future FERC rate filing.

Texas Restructuring

Texas Restructuring Legislation established customer choice on January 1, 2002 and allowed electric utility companies to file for recovery of securitizable stranded generation plant costs, generation related regulatory assets and non-securitizable other restructuring true-up items. These recoverable and refundable items were recorded as true-up regulatory assets and liabilities.

TCC will recover its PUCT approved net true-up regulatory asset under the Texas Restructuring Legislation using two mechanisms: (a) by issuing securitization bonds in the amount of its net stranded generation costs and implementing a transition charge (TC) rate rider to collect the bond interest and principal over the term of the bonds and (b) by implementing a credit competition transition charge (CTC) rate rider to refund its net regulatory liability for other true-up items.

In February 2006, the PUCT issued an order in TCC’s True-up Proceeding, which determined that TCC’s recoverable net true-up regulatory asset, for both securitizable net stranded generation cost regulatory assets and net other true-up items regulatory liabilities, was $1.475 billion as of September 30, 2005. The order disallowed specific items which included, among other things, a significant portion of TCC’s wholesale capacity auction true-up revenues and a portion of TCC’s stranded costs determined from the sale of the ERCOT generating units.

TCC appealed the PUCT true-up orders seeking relief in both state and federal court on the grounds that the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. The significant items appealed by TCC are:

·	The PUCT ruling that TCC did not comply with the statute and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues,	
·	The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled out of the money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant cost, and	
·	The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation. See “TCC and TNC Deferred Fuel” and “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections of Note 4.	

Municipal customers and other intervenors appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. On February 1, 2007 the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final True-up order with two significant exceptions. The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) method to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. However, the District Court did not rule that the carrying cost rate was inappropriate. He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future revenues.

In response to a request by TCC, the District Court judge will hear additional argument on March 22, 2007 regarding use of the ECOM method to value TCC’s nuclear plant stranded cost. TCC anticipates that the final judgment will be entered after that hearing. TCC intends to appeal any final adverse rulings of the District Court regarding these two matters along with certain of the judge’s other preliminary determinations that affirm the PUCT’s decisions. It is possible that the PUCT could also appeal any final adverse rulings regarding these two matters.

Although management cannot predict the ultimate outcome of these preliminary District Court determinations, any future remanded PUCT proceedings or any future court appeals, management has concluded that it is probable that the District Court’s preliminary ruling regarding the use of an ECOM method in lieu of a sales method to determine securitizable stranded cost will not be upheld on appeal. The judge has also determined in his letter ruling that if the sales method is permitted for valuing the nuclear plant, the PUCT improperly reduced stranded costs in connection with the sales process, which could have a materially favorable effect on TCC.

Management also concluded if the District Court’s preliminary carrying cost rate ruling is ultimately remanded to the PUCT for reconsideration, the PUCT could either confirm the existing carrying cost rate or redetermine the rate. If the PUCT changes the rate, it could result in a material adverse change to TCC’s recoverable carrying costs. However, management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

If the District Court judge’s original 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 at this time, but the amount could exceed TCC’s Common Shareholder’s Equity at December 31, 2006. If it were finally concluded that the ECOM method must be used to value TCC’s nuclear plant stranded cost, and/or that the PUCT’s rule on carrying costs was invalid, it could, after the PUCT remand decisions, have a substantial adverse impact on future results of operations, cash flows and financial condition.

If TCC ultimately succeeds in its appeals on other than the above two matters, it could have a favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, including their appeals of the two matters discussed above, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

SECA Revenue Subject to Refund

We eliminated through-and-out transmission service (T&O) revenues in accordance with FERC orders and implemented SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. 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 was 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.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund. The AEP East companies have reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. The AEP East companies have provided a reserve for $37 million in net refunds.

We, together with Exelon and the Dayton Power and Light Company, filed an extensive post hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. We believe that the FERC should reject the initial decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, we believe the ALJ’s findings on key issues are largely without merit. However, the initial decision is adversely impacting settlement negotiations. Although we believe we have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.

Virginia Restructuring
 
In February 2007, the Virginia legislature adopted amendments to its electric restructuring law. The amendments would shorten the transition period by two years (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. We are in the process of evaluating the impact of the legislation if it is signed into law.

New Generation

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 629 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases. In Phase 1, the Ohio companies would recover approximately $24 million in pre-construction costs during 2006. In Phase 2, the Ohio companies would recover construction-financing costs through regulatory authorization until the plant is placed in service. The proposed recoveries in Phases 1 and 2 will be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008, under their RSPs. In Phase 3, which begins when the plant enters commercial operation and runs through the operating life of the plant, the Ohio companies would recover or refund in distribution rates any difference between the Ohio companies’ market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power costs. Through December 31, 2006, the Ohio companies deferred $20 million of pre-construction IGCC costs, of which they have recovered $12 million. The PUCO indicated that if the Ohio companies have not commenced continuous construction of the IGCC plant by 2010, all charges collected for pre-construction costs, which are assignable to other jurisdictions, must be refunded to Ohio ratepayers with interest.

In January 2006, APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer generating station in Mason County, West Virginia. In January 2007, the WVPSC issued an order granting APCo’s motion to delay the Commission’s statutory deadline for issuing an order on the certificate for the construction of the proposed IGCC plant. The WVPSC approved a deadline of December 3, 2007. Through December 31, 2006, APCo deferred pre-construction IGCC costs totaling $10 million.

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 to satisfy the demands of its customers. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and 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 SWEPCo’s investment will be 73%, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of its customers. Preliminary cost estimates for SWEPCo’s share of the new facilities are approximately $1.4 billion (this total excludes the related transmission investment and AFUDC). These new facilities are subject to regulatory approvals from SWEPCo’s three state commissions. The peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions and Units 3 and 4 are projected to be online in July 2007 and the remaining two units by 2008. Construction is expected to begin in 2007 on the intermediate and base load facilities upon approval from the state regulatory commissions. Expenditures related to construction of these facilities are expected to total $349 million in 2007.

In September 2005, PSO sought proposals for new peaking generation to be online in 2008, and in December 2005 PSO sought proposals for base load generation to be online in 2011. PSO received proposals and evaluated those proposals meeting the Request for Proposal criteria 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 where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma where they will construct and operate two 85 MW simple-cycle natural gas combustion turbines. 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 (OMPA) where 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. PSO, OG&E and OMPA signed an agreement in February 2007 with Red Rock Power Partners to begin the first phase of the project. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion, and 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 additions is expected to begin in 2007. Expenditures related to construction of these facilities are expected to total $125 million in 2007.

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the first half of 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the second quarter of 2007. The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW.

Pension and Postretirement Benefit Plans

We maintain qualified, defined benefit pension plans (Qualified Plans), which cover a substantial majority of nonunion and certain union employees, and unfunded, nonqualified supplemental plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans, collectively the Pension Plans. Additionally, we entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits as a part of the nonqualified, supplemental plans. We also sponsor other postretirement benefit plans to provide medical and life insurance benefits for retired employees (Postretirement Plans). The Qualified Plans and Postretirement Plans are collectively the Plans.

The following table shows the net periodic cost for the Pension Plans and Postretirement Plans:

 	 	 	2006  	 	 	2005  	 	 	2004 	 	
Net Periodic Benefit Cost	 	 (in millions)	 	
Pension Plans	 	$	71	 	$	61	 	$	40	 	
Postretirement Plans	 	 	96	 	 	109	 	 	141	 	
Assumed Rate of Return	 	 	 	 	 	 	 	 	 	 	
Pension Plans	 	 	8.50	%	 	8.75	%	 	8.75	%	
Postretirement Plans	 	 	8.00	%	 	8.37	%	 	8.35	%	

The net periodic cost is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Plans’ assets. In developing the expected long-term rate of return assumption, we evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. We also considered historical returns of the investment markets as well as our ten-year average return, for the period ended December 2006, of approximately 9.43%. We anticipate that the investment managers we employ for the Plans will generate long-term returns averaging 8.50%.

The expected long-term rate of return on the Plans’ assets is based on our targeted asset allocation and our expected investment returns for each investment category. Our assumptions are summarized in the following table:

 	 	  Pension	 	Other Postretirement
Benefit Plans	 	 	 	
 	 	  2006
Actual Asset Allocation	 	2007
Target Asset
Allocation	 	2006
Actual Asset
Allocation	 	2007
Target Asset
Allocation	 	Assumed/
Expected
Long-term
Rate of Return	 	
 	 	  	 	 	 	 	 	 	 	 	 	
Equity	 	 	63	%	 	65	%	 	66	%	 	65	%	 	10.00	%	
Real Estate	 	 	6	%	 	5	%	 	-	%	 	-	%	 	8.25	%	
Fixed Income	 	 	26	%	 	28	%	 	32	%	 	33	%	 	5.25	%	
Cash and Cash Equivalents	 	 	5	%	 	2	%	 	2	%	 	2	%	 	4.25	%	
Total	 	 	100	%	 	100	%	 	100	%	 	100	%	 	 	 	

 	Pension	 	Other Postretirement
Benefit Plans	
Overall Expected Return  (weighted average)	 
8.50%	 	 
8.00%	

We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation. We believe that 8.50% and 8.00% for the Pension Plans and Postretirement Plans, respectively, are reasonable long-term rates of return on the Plans’ assets despite the recent market volatility. The Plans’ assets had an actual gain of 12.78% and 7.76% for the twelve-months ended December 31, 2006 and 2005, respectively. We will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

We base our determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2006, we had cumulative gains of approximately $187 million that remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial gains will result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with SFAS No. 87, “Employers’ Accounting for Pensions.”

The method used to determine the discount rate that we utilize for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s AA bond index was constructed but with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2006 under this method was 5.75% for the Pension Plans and 5.85% for the Postretirement Plans. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 8.50%, a discount rate of 5.75% and various other assumptions, we estimate that the pension costs for all pension plans will approximate $40 million, $14 million and $5 million in 2007, 2008 and 2009, respectively. Based on an expected rate of return on the OPEB plans’ assets of 8.00%, a discount rate of 5.85% and various other assumptions, we estimate Postretirement Plan costs will approximate $85 million, $81 million and $78 million in 2007, 2008 and 2009, respectively. Future actual cost will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 50 basis point change to selective actuarial assumptions are included in “Pension and Other Postretirement Benefits” within the “Critical Accounting Estimates” section of this Management’s Financial Discussion and Analysis of Results of Operations.

The value of the Pension Plans’ assets increased to $4.3 billion at December 31, 2006 from $4.1 billion at December 31, 2005 primarily due to investment returns on the assets. The Qualified Plans paid $267 million in benefits to plan participants during 2006 (nonqualified plans paid $9 million in benefits). The value of our Postretirement Plans’ assets increased to $1.3 billion at December 31, 2006 from $1.2 billion at December 31, 2005. The Postretirement Plans paid $112 million in benefits to plan participants during 2006.

Our nonqualified pension plans are unfunded, and are therefore considered underfunded for accounting purposes. For the nonqualified pension plans, the accumulated benefit obligation in excess of plan assets was $78 million and $81 million at December 31, 2006 and 2005, respectively. We made a contribution of $626 million in 2005 to meet our goal of fully funding all Qualified Plans by the end of 2005. Our Qualified Plans remained fully funded as of December 31, 2006.

Certain pension plans we sponsor and maintain contain a cash balance benefit feature. In recent years, cash balance benefit features have become a focus of scrutiny, as government regulators and courts consider how the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended, and other relevant federal employment laws apply to plans with such a cash balance plan feature. We believe that our defined benefit pension plans comply with the applicable requirements of such laws.

The Pension Protection Act of 2006 did not materially impact our plans.

Litigation

In the ordinary course of business, we, along with our subsidiaries, are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what their eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations.

See discussion of the Environmental Litigation within the “Environmental Matters” section of “Significant Factors.”

Environmental Matters

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

·	Requirements under the Clean Air Act (CAA) to reduce emissions of sulfur dioxide (SO 2 ), nitrogen oxide (NO x ), particulate matter (PM) and mercury from fossil fuel-fired power plants; and	
·	Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain of our power plants.	

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units. We are also monitoring possible future requirements to reduce carbon dioxide (CO 2 ) emissions to address concerns about global climate change. All of these matters are discussed below.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality, and control mobile and stationary sources of air emissions. The major CAA programs affecting our power plants are described below. The states in which we operate, implement and administer many of these programs and could impose additional or more stringent requirements.

National Ambient Air Quality Standards: The CAA requires the Federal EPA to periodically review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin. These concentration levels are known as “national ambient air quality standards” or NAAQS.

Each state identifies those areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. In addition, as the Federal EPA reviews the NAAQS, the attainment status of areas can change, and states may be required to develop new SIPs. The Federal EPA recently proposed a new PM NAAQS and is conducting periodic reviews for additional criteria pollutants.

In 1997, the Federal EPA established new NAAQS that required further reductions in SO 2 and NO x emissions. In 2005, the Federal EPA issued a final model federal rule, the Clean Air Interstate Rule (CAIR), that assists states developing new SIPs to meet the new NAAQS. CAIR reduces regional emissions of SO 2 and NO x from power plants in the Eastern U.S. (29 states and the District of Columbia). CAIR requires power plants within these states to reduce emissions of SO 2 by 50 percent by 2010, and by 65 percent by 2015. NO x emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015. Reduction of both SO 2 and NO x would be achieved through a cap-and-trade program. The Federal EPA affirmed certain aspects of the final CAIR after reconsideration. The rule has been challenged in the courts. States were required to develop and submit SIPs to implement CAIR by November 2006. Nearly all of the states in which our power plants are located will be covered by CAIR. Oklahoma is not affected, while Texas and Arkansas will be covered only by certain parts of CAIR. A SIP that complies with CAIR will also establish compliance with other CAA requirements, including certain visibility goals.

Hazardous Air Pollutants: As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the Federal EPA issued a final Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants. The Federal EPA issued a model federal rule based on a cap-and-trade program for mercury emissions from existing coal-fired power plants that would reduce mercury emissions to 38 tons per year from all existing plants in 2010, and to 15 tons per year in 2018. The national cap of 38 tons per year in 2010 is intended to reflect the level of reduction in mercury emissions that will be achieved as a result of installing controls to reduce SO 2 and NO x emissions in order to comply with CAIR. The Federal EPA affirmed certain aspects of the final CAMR after reconsideration, and the rule has been challenged in the courts. States were required to develop and submit their SIPs to implement CAMR by November 2006.

The Acid Rain Program: The 1990 Amendments to the CAA include a cap-and-trade emission reduction program for SO 2 emissions from power plants, implemented in two phases. By 2000, the program established a nationwide cap on power plant SO 2 emissions of 8.9 million tons per year. The 1990 Amendments also contain requirements for power plants to reduce NOx emissions through the use of available combustion controls.

The success of the SO 2 cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs, including CAIR and CAMR. We continue to meet our obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. CAIR uses the SO 2 allowances originally allocated through the Acid Rain Program as the basis for its SO 2 cap-and-trade system.

Regional Haze : The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (the “Regional Haze” program). In 2005, the Federal EPA issued its final Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology (BART) requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. The final rule contains a demonstration that CAIR will result in more visibility improvements than BART for power plants subject to it. Thus, states are allowed to substitute CAIR requirements in their Regional Haze SIPs for controls that would otherwise be required by BART. For BART-eligible facilities located in states not subject to CAIR requirements for SO 2 and NO x , some additional controls will be required. The courts upheld the final rule.

Estimated Air Quality Environmental Investments

The CAIR and CAMR programs described above require us to make significant additional investments, some of which are estimable. However, many of the rules described above have been challenged in the courts and are not incorporated into SIPs. As a result, these rules may be further modified. Our estimates are subject to significant uncertainties, and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: the timing of implementation; required levels of reductions; methods for allocation of allowances; and our selected compliance alternatives. In short, we cannot estimate our compliance costs with certainty and the actual costs to comply could differ significantly from the estimates discussed below.

We installed a total of 9,700 MW of selective catalytic reduction (SCR) technology to control NO x emissions at our eastern power plants over the past several years to comply with NO x requirements in various SIPs. We comply with Acid Rain Program SO 2 requirements by installing scrubbers, using alternate fuels and using SO 2 allowances. We receive allowances through Acid Rain Program allocations and purchase them at the annual Federal EPA auction or in the market. Decreasing allowance allocations, our diminishing SO 2 allowance bank and increasing allowance costs will require us to install additional controls on our power plants. In addition under CAIR and CAMR, we will be required to install additional controls by 2010. We plan to install additional scrubbers on 7,300 MW for SO 2 control and additional SCRs on 1,900 MW for NO x control to comply with current CAIR and CAMR requirements. In January 2007, the scrubber on Unit 2 of Mitchell Plant went into service leaving 6,500 MW of scrubbers to be completed. From 2007 to 2011, we estimate total environmental investment of $2.2 billion including investment in scrubbers and other SO 2 equipment of approximately $1.4 billion. We will also incur additional operation and maintenance expenses in future years due to the costs associated with the maintenance of additional controls, disposal of byproducts and purchase of reagents.

Assuming that the CAIR and CAMR programs are implemented consistent with the provisions of the final federal rules, we expect to incur additional costs for pollution control technology retrofits between 2012 and 2020 of approximately $2.6 billion. However, this estimate is highly uncertain due to the variability associated with: (1) the states’ implementation of these regulatory programs, including the potential for SIPs that impose standards more stringent than CAIR or CAMR; (2) the actual performance of the pollution control technologies installed on our units; (3) changes in costs for new pollution controls; (4) new generating technology developments; and (5) other factors. Associated operational and maintenance expenses will also increase during those years. We cannot estimate these additional operational and maintenance costs due to the uncertainties described above, but they are expected to be significant.

We will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through our regulated rates (in regulated jurisdictions). We should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, those costs could adversely affect future results of operations, cash flows and possibly financial condition.

Clean Water Act Regulations

In 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water. The standards vary based on the water bodies from which the plants draw their cooling water. These rules will result in additional capital and operating expenses, which the Federal EPA estimated could be $193 million for our plants. Any capital costs incurred to meet these standards had been expected to be incurred between 2008 and 2010. We undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates. In addition, a recent court decision introduced additional uncertainty to these costs and their timing.

The rule was challenged in the courts by states, advocacy organizations and industry. On January 25, 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA. Among other things, the restoration option, the cost-benefit and other tests and certain alternative technology options in the 2004 rule have been remanded. We cannot predict how or when the Federal EPA will respond to the remand, or what effect the remand may have on similar requirements adopted by the states. We may seek further review or relief from the schedules included in the final rule and our permits, in order to allow time for the Federal EPA’s response to the remand.

Potential Regulation of CO 2 Emissions

At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in 1997, more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly CO 2 , which many scientists believe are contributing to global climate change. The U.S. signed the Kyoto Protocol in 1998, but the treaty was not submitted to the Senate for its advice and consent. In 2001, President Bush announced his opposition to the treaty. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries in February 2005. Members of Congress introduced several bills seeking regulation of greenhouse gas emissions, including CO 2 emissions from power plants, but none have passed. We participate in a number of voluntary programs to monitor, mitigate, and reduce greenhouse gas emissions.

The Federal EPA stated that it does not have authority under the CAA to regulate greenhouse gas emissions that may affect global climate trends. This decision was upheld by an appellate court. The U.S. Supreme Court reviewed the appellate decision and is expected to issue its decision in 2007.

We will seek recovery of expenditures for potential regulation of CO 2 emissions from customers through our regulated rates (in regulated jurisdictions). We should be able to recover these expenditures through market prices in deregulated jurisdictions.

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. A separate lawsuit, initiated by certain special interest groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and thereafter against nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at our power plants occurred over a twenty-year period. A bench trial on the liability issues was held during 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions. Similarly, courts that considered whether the activities at issue increased emissions from the power plants reached different results. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. The Federal EPA also proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues to be determined by the court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Other Environmental Concerns

We perform environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. In addition to the matters discussed above, we manage other environmental concerns that we do not believe are material or potentially material at this time. If they become significant or if any new matters arise that we believe could be material, they could have a material adverse effect on future results of operations, cash flows and possibly financial condition.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:

·	It requires assumptions to be made that were uncertain at the time the estimate was made; and	
·	Changes in the estimate or different estimates that could have been selected could have a material effect on our consolidated results of operations or financial condition.	

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosure relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates.

The sections that follow present information about our most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required: Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

We recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation. Specifically, we match the timing of our expense recognition with the recovery of such expense in regulated revenues. Likewise, we match income with the regulated revenues from our customers in the same accounting period. We also record regulatory liabilities for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used: When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We review the probability of recovery whenever new events occur, for example, changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates. If recovery of a regulatory asset is no longer probable, we write-off that regulatory asset as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations. Refer to Note 5 of the Notes to Consolidated Financial Statements for further detail related to regulatory assets and liabilities.

Revenue Recognition - Unbilled Revenues

Nature of Estimates Required : We record revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which we performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded. In the Arkansas, Louisiana, Oklahoma and Texas jurisdictions, we do not record the fuel portion of unbilled revenue in accordance with the applicable state commission regulatory treatment. This estimate is reversed in the following month and actual revenue is recorded based on meter readings.

Incremental unbilled electric utility revenues included in Revenue on our Consolidated Statements of Income were $(19) million, $28 million and $22 million for the years ended December 31, 2006, 2005 and 2004, respectively. Accrued unbilled revenues for the Utility Operations segment were $329 million and $348 million as of December 31, 2006 and 2005, respectively.

Assumptions and Approach Used: The operating company calculates the monthly estimate for unbilled revenues as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to the occurrence of problems in meter readings, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWH to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWH. The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

Effect if Different Assumptions Used : Significant fluctuations in energy demand for the unbilled period, weather impact, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the Accrued Unbilled Revenues on the Balance Sheets.

Revenue Recognition - Accounting for Derivative Instruments

Nature of Estimates Required: Management considers fair value techniques, valuation adjustments related to credit and liquidity, and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used: We measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based on exchange prices and broker quotes. If a quoted market price is not available, we estimate the fair value based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data, and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

We reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. We calculate liquidity adjustments by utilizing future bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. We base credit adjustments on estimated defaults by counterparties that are calculated using historical default probabilities for companies with similar credit ratings. We evaluate the probability of the occurrence of the forecasted transaction within the specified time period as provided in the original documentation related to hedge accounting.

Effect if Different Assumptions Used: There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

The probability that hedged forecasted transactions will occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding accounting for derivative instruments, see sections labeled Credit Risk and VaR Associated with Risk Management Contracts within “Quantitative and Qualitative Disclosures About Risk Management Activities.”

Long-Lived Assets

Nature of Estimates Required: In accordance with the requirements of SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable or the assets meet the held for sale criteria under SFAS 144. The evaluations of long-lived held and used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses. If the carrying amount is not recoverable, we record an impairment to the extent that the fair value of the asset is less than its book value. For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery is probable. For nonregulated assets, any impairment charge is recorded against earnings.

Assumptions and Approach Use : The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, we estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used : In connection with the evaluation of long-lived assets in accordance with the requirements of SFAS 144, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment as described in Note 8 of the Notes to Consolidated Financial Statements, we made our best estimate of fair value using valuation methods based on the most current information at that time. We divested certain noncore assets and their sales values can vary from the recorded fair value as described in Note 8 of the Notes to Consolidated Financial Statements. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

Nature of Estimates Required: We sponsor pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. We account for these benefits under SFAS 87, “Employers’ Accounting For Pensions”, SFAS 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” and SFAS 158. See Note 9 of the Notes to Consolidated Financial Statements for more information regarding costs and assumptions for employee retirement and postretirement benefits. The measurement of our pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.

Assumptions and Approach Used: The critical assumptions used in developing the required estimates include the following key factors:

·	Discount rate	
·	Expected return on plan assets	
·	Health care cost trend rate	
·	Rate of compensation increase	
·	Cash balance crediting rate	

Other assumptions, such as retirement, mortality, and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used: The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants. If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:
 	 	Pension Plans	 	Other Postretirement Benefits Plans	 	
 	 	+0.5%	 	-0.5%	 	+0.5%	 	-0.5%	 	
 	 	(in millions)	 	
 	 	  	 	  	 	  	 	  	 	
Effect on December 31, 2006 Benefit Obligations:	 	  	 	  	 	  	 	  	 	
Discount Rate	 	$	(178.2	)	$	192.7	 	$	(114.1	)	$	121.4	 	
Compensation Increase Rate	 	 	27.2	 	 	(25.5	)	 	3.3	 	 	(3.2	)	
Cash Balance Crediting Rate	 	 	13.4	 	 	16.7	 	 	N/A	 	 	N/A	 	
Health Care Cost Trend Rate	 	 	N/A	 	 	N/A	 	 	91.7	 	 	(83.7	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect on 2006 Periodic Cost:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount Rate	 	 	(13.0	)	 	13.6	 	 	(10.4	)	 	10.6	 	
Compensation Increase Rate	 	 	5.9	 	 	(5.6	)	 	0.6	 	 	(0.6	)	
Cash Balance Crediting Rate	 	 	6.7	 	 	(1.9	)	 	N/A	 	 	N/A	 	
Health Care Cost Trend Rate	 	 	N/A	 	 	N/A	 	 	15.2	 	 	(14.7	)	
Expected Return on Plan Assets	 	 	(19.7	)	 	19.7	 	 	(5.6	)	 	5.7	 	

N/A = Not Applicable	

Adoption of New Accounting Pronouncements

Beginning in 2006, we adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, did not materially affect our quarter-over-quarter and year-to-date net income and earnings per share. We have not granted options as part of our regular stock-based compensation program since 2003. However, we have used options in limited circumstances totaling 149,000 options in 2004, 10,000 options in 2005 and none during 2006. As of December 31, 2006, we have $90 million of total unrecognized compensation cost related to unvested share-based compensation arrangements. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.64 years. See Note 2 in our Notes to Consolidated Financial Statements for further discussion.

New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption. SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. We expect that the adoption of this standard will impact MTM valuations of certain contracts, but are unable to quantify the effect at this time. Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. We will adopt SFAS 157 effective January 1, 2008.

In July 2006, the FASB issued FIN 48. It clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. FIN 48 is effective for fiscal years beginning after December 15, 2006. We estimate the effect of this interpretation on our financial statements to be an unfavorable adjustment to retained earnings of less than $15 million.

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. In the event we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted. The statement is applied prospectively upon adoption. We will adopt SFAS 159 effective January 1, 2008.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

As a major power producer and marketer of wholesale electricity, coal and emission allowances, our Utility Operations segment is exposed to certain market risks. These risks include commodity price risk, interest rate risk and credit risk. In addition, we may be exposed to foreign currency exchange risk because occasionally we procure various services and materials used in our energy business from foreign suppliers. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

All Other includes gas operations which holds forward gas contracts that were not sold with the gas pipeline and storage assets. These contracts are primarily financial derivatives, along with physical contracts, which will gradually liquidate and completely expire in 2011. Our risk objective is to keep these positions generally risk neutral through maturity.

In 2006, our Generation and Marketing segment holds power sale contracts to commercial and industrial customers in ERCOT. In 2007, the Generation and Marketing segment will also own wholesale power trading and marketing contracts within ERCOT. The wholesale ERCOT trading and marketing activity was previously reflected in AEP’s Utility Operations segment.

We employ risk management contracts including physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps and other derivative contracts to offset price risk where appropriate. We engage in risk management of electricity, gas, coal, and emissions and to a lesser degree other commodities associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy and monitored by the Chief Risk Officer and risk management staff. When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.

We have policies and procedures that allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies have been reviewed with our Board of Directors and approved by our Risk Executive Committee. Our Chief Risk Officer administers our risk policies and procedures. The Risk Executive Committee establishes risk limits, approves risk policies, and assigns responsibilities regarding the oversight and management of risk and monitors risk levels. Members of this committee receive various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, senior executives, and other senior financial and operating managers.

We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts. The CCRO is composed predominantly of chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and embrace the disclosure standards applicable to our business activities. The following tables provide information on our risk management activities.
 
Mark-to-Market Risk Management Contract Net Assets (Liabilities)

The following two tables summarize the various mark-to-market (MTM) positions included on our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value included on our balance sheet as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheet
December 31, 2006
(in millions)
 	 	  Utility Operations	 	 Generation and
Marketing	 	 All Other	 	 Sub-Total MTM Risk Management Contracts	 	 PLUS: MTM of Cash Flow and Fair Value Hedges	 	 Total	 	
Current Assets	 	$	553	 	$	1	 	$	94	 	$	648	 	$	32	 	$	680	 	
Noncurrent Assets	 	 	260	 	 	1	 	 	115	 	 	376	 	 	2	 	 	378	 	
Total Assets	 	 	813	 	 	2	 	 	209	 	 	1,024	 	 	34	 	 	1,058	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(440	)	 	-	 	 	(92	)	 	(532	)	 	(9	)	 	(541	)	
Noncurrent Liabilities	 	 	(137	)	 	-	 	 	(122	)	 	(259	)	 	(1	)	 	(260	)	
Total Liabilities	 	 	(577	)	 	-	 	 	(214	)	 	(791	)	 	(10	)	 	(801	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total MTM   Derivative  Contract Net Assets  (Liabilities)	 	$	236	 	$	2	 	$	(5	)	$	233	 	$	24	 	$	257	 	

MTM Risk Management Contract Net Assets (Liabilities)
Year Ended December 31, 2006
(in millions)
 	 	Utility Operations	 	Generation
and
Marketing	 	All Other	 	Total	 	
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2005	 	$	215	 	$	-	 	$	(19	)	$	196	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in
  a Prior Period	 	 	(19	)	 	-	 	 	13	 	 	(6	)	
Fair Value of New Contracts at Inception When Entered  During the Period (a)	 	 	2	 	 	1	 	 	-	 	 	3	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option
  Contracts Entered  During The Period	 	 	(2	)	 	-	 	 	-	 	 	(2	)	
Changes in Fair Value Due to Valuation Methodology  Changes on Forward
  Contracts	 	 	1	 	 	-	 	 	-	 	 	1	 	
Changes in Fair Value due to Market Fluctuations During  the Period (b)	 	 	24	 	 	1	 	 	1	 	 	26	 	
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	 	 	15	 	 	-	 	 	-	 	 	15	 	
Total MTM Risk Management Contract Net Assets (Liabilities) at
  December 31, 2006	 	$	236	 	$	2	 	$	(5	)	 	233	 	
Net Cash Flow and Fair Value Hedge   Contracts	 	 	 	 	 	 	 	 	 	 	 	24	 	
Ending Net Risk Management Assets at December 31, 2006	 	 	 	 	 	 	 	 	 	 	$	257	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.	
(c)	“Change in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions. Approximately $7 million of the regulatory deferred change is due to the change in the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of December 31, 2006
(in millions)
 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Utility Operations:	 	  	 	  	 	  	 	  	 	  	 	  	 	  	 	
Prices Actively Quoted - Exchange   Traded Contracts	 	$	(22	)	$	16	 	$	2	 	$	-	 	$	-	 	$	-	 	$	(4	)	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	142	 	 	26	 	 	24	 	 	-	 	 	-	 	 	-	 	 	192	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	(7	)	 	2	 	 	15	 	 	29	 	 	4	 	 	5	 	 	48	 	
Total	 	$	113	 	$	44	 	$	41	 	$	29	 	$	4	 	$	5	 	$	236	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Generation and Marketing:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Prices Actively Quoted - Exchange Traded Contracts	 	$	-	 	$	-	 	$	-	 	$	-	 	$	-	 	$	-	 	$	-	 	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	1	 	 	1	 	 	-	 	 	-	 	 	-	 	 	-	 	 	2	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Total	 	$	1	 	$	1	 	$	-	 	$	-	 	$	-	 	$	-	 	$	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
All Other:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Prices Actively Quoted - Exchange Traded Contracts	 	$	4	 	$	-	 	$	-	 	$	-	 	$	-	 	$	-	 	$	4	 	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	(2	)	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	(2	)	
Prices Based on Models and Other  Valuation Methods (b)	 	 	-	 	 	(1	)	 	(4	)	 	(3	)	 	1	 	 	-	 	 	(7	)	
Total	 	$	2	 	$	(1	)	$	(4	)	$	(3	)	$	1	 	$	-	 	$	(5	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Prices Actively Quoted - Exchange  Traded Contracts	 	$	(18	)	$	16	 	$	2	 	$	-	 	$	-	 	$	-	 	$	-	 	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	141	 	 	27	 	 	24	 	 	-	 	 	-	 	 	-	 	 	192	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	(7	)	 	1	 	 	11	 	 	26	 	 	5	 	 	5	 	 	41	 	
Total	 	$	116	 	$	44	 	$	37	 	$	26	 	$	5	 	$	5	 	$	233	 	

(a)	Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.	
(b)	Prices Based on Models and Other Valuation Methods is in the absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity is limited, such valuations are classified as modeled.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

The determination of the point at which a market is no longer liquid for placing it in the modeled category in the preceding table varies by market. The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of December 31, 2006

Commodity	 	Transaction Class	 	Market/Region	 	Tenor	
 	 	 	 	 	 	(in Months)	
Natural Gas	 	Futures	 	NYMEX / Henry Hub	 	60	
 	 	Physical Forwards	 	Gulf Coast, Texas	 	22	
 	 	Swaps	 	Northeast, Mid-Continent, Gulf Coast, Texas	 	22	
 	 	Exchange Option Volatility	 	NYMEX / Henry Hub	 	12	
Power	 	Futures	 	AEP East - PJM	 	36	
 	 	Physical Forwards	 	AEP East	 	36	
 	 	Physical Forwards	 	AEP West	 	36	
 	 	Physical Forwards	 	West Coast	 	36	
 	 	Peak Power Volatility (Options)	AEP East - Cinergy, PJM	 	12	
Emissions	 	Credits	 	SO 2 , NO x	 	36	
Coal	 	Physical Forwards	 	PRB, NYMEX, CSX	 	36	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheets

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

We use forward contracts and collars as cash flow hedges to lock-in prices on certain transactions denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2005 to December 31, 2006. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12-months. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2006
(in millions)
 	 	  Power	 	  Interest Rate and
Foreign Currency	 	  Total	 	
Beginning Balance in AOCI, December 31, 2005	 	$	(6	)	$	(21	)	$	(27	)	
Changes in Fair Value	 	 	17	 	 	(4	)	 	13	 	
Reclassifications from AOCI to Net Income for  Cash Flow Hedges Settled	 	 	6	 	 	2	 	 	8	 	
Ending Balance in AOCI, December 31, 2006	 	$	17	 	$	(23	)	$	(6	)	
 	 	 	 	 	 	 	 	 	 	 	
After Tax Portion Expected to be Reclassified to Earnings During
  Next 12-Months	 	$	17	 	$	(2	)	$	15	 	

Credit Risk

We limit credit risk in our marketing and trading activities by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Only after an entity meets our internal credit rating criteria will we extend unsecured credit. We use Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. We use our analysis, in conjunction with the rating agencies’ information, to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of December 31, 2006, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 3.02%, expressed in terms of net MTM assets and net receivables. As of December 31, 2006, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality	 	Exposure Before Credit Collateral	 	Credit Collateral	 	Net Exposure	 	Number of Counterparties >10%	 	Net Exposure of Counterparties >10%	 	
Investment Grade	 	$	851	 	$	116	 	$	735	 	 	1	 	$	99	 	
Split Rating	 	 	39	 	 	14	 	 	25	 	 	1	 	 	25	 	
Noninvestment Grade	 	 	17	 	 	12	 	 	5	 	 	2	 	 	4	 	
No External Ratings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Internal Investment Grade	 	 	56	 	 	5	 	 	51	 	 	2	 	 	22	 	
Internal Noninvestment Grade	 	 	35	 	 	14	 	 	21	 	 	3	 	 	19	 	
Total as of December 31, 2006	 	$	998	 	$	161	 	$	837	 	 	9	 	$	169	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total as of December 31, 2005	 	$	1,366	 	$	484	 	$	882	 	 	10	 	$	322	 	

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2009. This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
December 31, 2006

 	 	2007	 	2008	 	2009	 	
Estimated Plant Output Hedged	 	 	91	%	 	88	%	 	89	%	

VaR Associated with Risk Management Contracts

Commodity Price Risk

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

VaR Model

December 31, 2006	 	 	 	 	December 31, 2005	
(in millions)	 	 	 	 	(in millions)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$3	 	$10	 	$3	 	$1	 	 	 	 	$3	 	$5	 	$3	 	$1	

The High VaR for 2006 occurred in mid-August during a period of high gas and power volatility. The following day, positions were flattened and the VaR was significantly reduced.

Interest Rate Risk

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $624 million at December 31, 2006 and $615 million at December 31, 2005. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of American Electric Power Company, Inc.:
 
We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006. As discussed in Note 17 to the consolidated financial statements, the Company adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations,” effective December 31, 2005. As discussed in Note 9 to the consolidated financial statements, the Company adopted FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of American Electric Power Company, Inc.:

We have audited management's assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting , that American Electric Power Company, Inc. and subsidiary companies (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006 of the Company and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph concerning the Company’s adoption of new accounting pronouncements in 2004, 2005 and 2006.

/s/Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and subsidiary companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. AEP’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

AEP management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework . Based on our assessment, the Company’s internal control over financial reporting was effective as of December 31, 2006.

AEP’s independent registered public accounting firm has issued an attestation report on our assessment of the Company’s internal control over financial reporting. The Report of Independent Registered Public Accounting Firm appears on the previous page.

 

 

 

 

 

 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in millions, except per-share and share amounts)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Utility Operations	 	$	12,066	 	$	11,157	 	$	10,620	 	
Gas Operations	 	 	(85	)	 	463	 	 	3,068	 	
Other	 	 	641	 	 	491	 	 	557	 	
TOTAL	 	 	12,622	 	 	12,111	 	 	14,245	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	3,817	 	 	3,592	 	 	3,059	 	
Purchased Energy for Resale	 	 	856	 	 	687	 	 	670	 	
Purchased Gas for Resale	 	 	-	 	 	256	 	 	2,807	 	
Other Operation and Maintenance	 	 	3,639	 	 	3,619	 	 	3,676	 	
Asset Impairments and Other Related Charges	 	 	209	 	 	39	 	 	-	 	
(Gain) Loss on Disposition of Assets, Net	 	 	(69	)	 	(120	)	 	(4	)	
Depreciation and Amortization	 	 	1,467	 	 	1,348	 	 	1,324	 	
Taxes Other Than Income Taxes	 	 	737	 	 	763	 	 	730	 	
TOTAL	 	 	10,656	 	 	10,184	 	 	12,262	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	1,966	 	 	1,927	 	 	1,983	 	
 	 	 	 	 	 	 	 	 	 	 	
Interest and Investment Income	 	 	99	 	 	105	 	 	33	 	
Carrying Costs Income	 	 	114	 	 	55	 	 	302	 	
Allowance For Equity Funds Used During Construction	 	 	30	 	 	21	 	 	15	 	
Investment Value Losses	 	 	-	 	 	(7	)	 	(15	)	
Gain on Disposition of Equity Investments, Net	 	 	3	 	 	56	 	 	153	 	
 	 	 	 	 	 	 	 	 	 	 	
INTEREST AND OTHER CHARGES	 	 	 	 	 	 	 	 	 	 	
Interest Expense	 	 	732	 	 	697	 	 	781	 	
Preferred Stock Dividend Requirements of Subsidiaries	 	 	3	 	 	7	 	 	6	 	
TOTAL	 	 	735	 	 	704	 	 	787	 	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAX EXPENSE, MINORITY INTEREST EXPENSE AND EQUITY EARNINGS	 	 	1,477	 	 	1,453	 	 	1,684	 	
Income Tax Expense	 	 	485	 	 	430	 	 	572	 	
Minority Interest Expense	 	 	3	 	 	4	 	 	3	 	
Equity Earnings of Unconsolidated Subsidiaries	 	 	3	 	 	10	 	 	18	 	
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY LOSS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE	 	 	992	 	 	1,029	 	 	1,127	 	
 	 	 	 	 	 	 	 	 	 	 	
DISCONTINUED OPERATIONS, NET OF TAX	 	 	10	 	 	27	 	 	83	 	
 	 	 	 	 	 	 	 	 	 	 	
EXTRAORDINARY LOSS, NET OF TAX	 	 	-	 	 	(225	)	 	(121	)	
 	 	 	 	 	 	 	 	 	 	 	
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX	 	 	-	 	 	(17	)	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	$	1,002	 	$	814	 	$	1,089	 	
 	 	 	 	 	 	 	 	 	 	 	
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING	 	 	394,219,523	 	 	389,969,636	 	 	395,622,137	 	
 	 	 	 	 	 	 	 	 	 	 	
BASIC EARNINGS (LOSS) PER SHARE	 	 	 	 	 	 	 	 	 	 	
Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect   of Accounting Change	 	$	2.52	 	$	2.64	 	$	2.85	 	
Discontinued Operations, Net of Tax	 	 	0.02	 	 	0.07	 	 	0.21	 	
Extraordinary Loss, Net of Tax	 	 	-	 	 	(0.58	)	 	(0.31	)	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	(0.04	)	 	-	 	
TOTAL BASIC EARNINGS PER SHARE	 	$	2.54	 	$	2.09	 	$	2.75	 	
 	 	 	 	 	 	 	 	 	 	 	
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING	 	 	396,483,464	 	 	391,423,842	 	 	396,590,407	 	
 	 	 	 	 	 	 	 	 	 	 	
DILUTED EARNINGS (LOSS) PER SHARE	 	 	 	 	 	 	 	 	 	 	
Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of   Accounting Change	 	$	2.50	 	$	2.63	 	$	2.85	 	
Discontinued Operations, Net of Tax	 	 	0.03	 	 	0.07	 	 	0.21	 	
Extraordinary Loss, Net of Tax	 	 	-	 	 	(0.58	)	 	(0.31	)	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	(0.04	)	 	-	 	
TOTAL DILUTED EARNINGS PER SHARE	 	$	2.53	 	$	2.08	 	$	2.75	 	
 	 	 	 	 	 	 	 	 	 	 	
CASH DIVIDENDS PAID PER SHARE	 	$	1.50	 	$	1.42	 	$	1.40	 	

See Notes to Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in millions)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	301	 	$	401	 	
Other Temporary Cash Investments	 	 	425	 	 	127	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	676	 	 	826	 	
Accrued Unbilled Revenues	 	 	350	 	 	374	 	
Miscellaneous	 	 	44	 	 	51	 	
Allowance for Uncollectible Accounts	 	 	(30	)	 	(31	)	
   Total Accounts Receivable	 	 	1,040	 	 	1,220	 	
Fuel, Materials and Supplies	 	 	913	 	 	726	 	
Risk Management Assets	 	 	680	 	 	926	 	
Regulatory Asset for Under-Recovered Fuel Costs	 	 	38	 	 	197	 	
Margin Deposits	 	 	120	 	 	221	 	
Prepayments and Other	 	 	71	 	 	127	 	
TOTAL	 	 	3,588	 	 	3,945	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	16,787	 	 	16,506	 	
Transmission	 	 	7,018	 	 	6,433	 	
Distribution	 	 	11,338	 	 	10,702	 	
Other (including coal mining and nuclear fuel)	 	 	3,405	 	 	3,263	 	
Construction Work in Progress	 	 	3,473	 	 	2,217	 	
Total	 	 	42,021	 	 	39,121	 	
Accumulated Depreciation and Amortization	 	 	15,240	 	 	14,837	 	
TOTAL - NET	 	 	26,781	 	 	24,284	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	2,477	 	 	3,262	 	
Securitized Transition Assets	 	 	2,158	 	 	593	 	
Spent Nuclear Fuel and Decommissioning Trusts	 	 	1,248	 	 	1,134	 	
Goodwill	 	 	76	 	 	76	 	
Long-term Risk Management Assets	 	 	378	 	 	886	 	
Employee Benefits and Pension Assets	 	 	327	 	 	1,105	 	
Deferred Charges and Other	 	 	910	 	 	843	 	
TOTAL	 	 	7,574	 	 	7,899	 	
 	 	 	 	 	 	 	 	
Assets Held for Sale	 	 	44	 	 	44	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	37,987	 	$	36,172	 	

See Notes to Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	 	 	 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in millions)	 	
Accounts Payable	$	1,360	 	$	1,144	 	
Short-term Debt	 	18	 	 	10	 	
Long-term Debt Due Within One Year	 	1,269	 	 	1,153	 	
Risk Management Liabilities	 	541	 	 	906	 	
Customer Deposits	 	339	 	 	571	 	
Accrued Taxes	 	781	 	 	651	 	
Accrued Interest	 	186	 	 	183	 	
Other	 	962	 	 	842	 	
TOTAL	 	5,456	 	 	5,460	 	
 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	
Long-term Debt	 	12,429	 	 	11,073	 	
Long-term Risk Management Liabilities	 	260	 	 	723	 	
Deferred Income Taxes	 	4,690	 	 	4,810	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	2,910	 	 	2,747	 	
Asset Retirement Obligations	 	1,023	 	 	936	 	
Employee Benefits and Pension Obligations	 	823	 	 	355	 	
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2	 	148	 	 	157	 	
Deferred Credits and Other	 	775	 	 	762	 	
TOTAL	 	23,058	 	 	21,563	 	
 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	28,514	 	 	27,023	 	
 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	61	 	 	61	 	
 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	
 	 	 	 	 	 	 	
COMMON SHAREHOLDERS’ EQUITY	 	 	 	 	 	 	
Common Stock Par Value $6.50:	 	 	 	 	 	 	
 	 	 	2006	 	 	2005	 	 	 	 	 	 	 	
Shares Authorized	 	 	600,000,000	 	 	600,000,000	 	 	 	 	 	 	 	
Shares Issued	 	 	418,174,728	 	 	415,218,830	 	 	 	 	 	 	 	
(21,499,992 shares were held in treasury at December 31, 2006 and 2005, respectively)	 	2,718	 	 	2,699	 	
Paid-in Capital	 	4,221	 	 	4,131	 	
Retained Earnings	 	2,696	 	 	2,285	 	
Accumulated Other Comprehensive Income (Loss)	 	(223	)	 	(27	)	
TOTAL	 	9,412	 	 	9,088	 	
 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	37,987	 	$	36,172	 	

See Notes to Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in millions)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	1,002	 	$	814	 	$	1,089	 	
Less: Discontinued Operations, Net of Tax	 	 	(10	)	 	(27	)	 	(83	)	
Income Before Discontinued Operations	 	 	992	 	 	787	 	 	1,006	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	1,467	 	 	1,348	 	 	1,324	 	
Deferred Income Taxes	 	 	24	 	 	65	 	 	291	 	
Deferred Investment Tax Credits	 	 	(29	)	 	(32	)	 	(29	)	
Cumulative Effect of Accounting Changes, Net	 	 	-	 	 	17	 	 	-	 	
Extraordinary Loss	 	 	-	 	 	225	 	 	121	 	
Asset Impairments, Investment Value Losses and Other Related Charges	 	 	209	 	 	46	 	 	15	 	
Carrying Costs Income	 	 	(114	)	 	(55	)	 	(302	)	
Gain on Sales of Assets and Equity Investments, Net	 	 	(72	)	 	(176	)	 	(157	)	
Amortization of Nuclear Fuel	 	 	50	 	 	56	 	 	52	 	
Mark-to-Market of Risk Management Contracts	 	 	(37	)	 	84	 	 	14	 	
Pension Contributions to Qualified Plan Trusts	 	 	- 	 	 	(626	) 	 	(231	) 	
Fuel Over/Under-Recovery, Net	 	 	182	 	 	(239	)	 	96	 	
Deferred Property Taxes	 	 	(14	)	 	(17	)	 	(3	)	
Change in Other Noncurrent Assets	 	 	(15	)	 	(115	)	 	(176	)	
Change in Other Noncurrent Liabilities	 	 	28	 	 	67	 	 	260	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	177	 	 	(7	)	 	280	 	
Fuel, Materials and Supplies	 	 	(187	)	 	(20	)	 	33	 	
Margin Deposits	 	 	101	 	 	(108	)	 	6	 	
Accounts Payable	 	 	56	 	 	140	 	 	(306	)	
Accrued Taxes	 	 	128	 	 	48	 	 	427	 	
Customer Deposits	 	 	(232	)	 	157	 	 	35	 	
Other Current Assets	 	 	17	 	 	52	 	 	(53	)	
Other Current Liabilities	 	 	1	 	 	180	 	 	8	 	
Net Cash Flows From Operating Activities	 	 	2,732	 	 	1,877	 	 	2,711	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(3,528	)	 	(2,404	)	 	(1,637	)	
Change in Other Temporary Cash Investments, Net	 	 	(33	)	 	76	 	 	32	 	
Investment in Discontinued Operations, Net	 	 	-	 	 	-	 	 	(59	)	
Purchases of Investment Securities	 	 	(18,359	)	 	(8,836	)	 	(1,574	)	
Sales of Investment Securities	 	 	18,080	 	 	8,934	 	 	1,620	 	
Acquisitions of Assets	 	 	-	 	 	(360	)	 	-	 	
Proceeds from Sales of Assets	 	 	186	 	 	1,606	 	 	1,357	 	
Other	 	 	(89	)	 	(21	)	 	(68	)	
Net Cash Flows Used For Investing Activities	 	 	(3,743	)	 	(1,005	)	 	(329	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Common Stock	 	 	99	 	 	402	 	 	17	 	
Repurchase of Common Stock	 	 	-	 	 	(427	)	 	-	 	
Change in Short-term Debt, Net	 	 	7	 	 	(13	)	 	(409	)	
Issuance of Long-term Debt	 	 	3,359	 	 	2,651	 	 	682	 	
Retirement of Long-term Debt	 	 	(1,946	)	 	(2,729	)	 	(2,511	)	
Dividends Paid on Common Stock	 	 	(591	)	 	(553	)	 	(555	)	
Other	 	 	(17	)	 	(122	)	 	(64	)	
Net Cash Flows From (Used For) Financing Activities	 	 	911	 	 	(791	)	 	(2,840	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	(100	)	 	81	 	 	(458	)	
Cash and Cash Equivalents at Beginning of Period	 	 	401	 	 	320	 	 	778	 	
Cash and Cash Equivalents at End of Period	 	$	301	 	$	401	 	$	320	 	
 	 	 	 	 	 	 	 	 	 	 	
CASH FLOWS FROM DISCONTINUED OPERATIONS	 	 	 	 	 	 	 	 	 	 	
Operating Activities	 	$	-	 	$	-	 	$	(3	)	
Investing Activities	 	 	-	 	 	-	 	 	(10	)	
Financing Activities	 	 	-	 	 	-	 	 	-	 	
Net Decrease in Cash and Cash Equivalents from Discontinued Operations	 	 	-	 	 	-	 	 	(13	)	
Cash and Cash Equivalents from Discontinued Operations - Beginning of
   Period	 	 	-	 	 	-	 	 	13	 	
Cash and Cash Equivalents from Discontinued Operations - End of Period	 	$	-	 	$	-	 	$	-	 	

See Notes to Consolidated Financial Statements.	

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005, and 2004
(in millions)

 	 	Common Stock  	 	 	 	 	 	 Accumulated	 	 		
 	 	Shares	 	Amount	 	Paid-in Capital	 	Retained Earnings	 	Other Comprehensive Income (Loss)	 	  Total		
DECEMBER 31, 2003	 	 	404	 	$	2,626	 	$	4,184	 	$	1,490	 	$	(426	)	$	7,874	 	
Issuance of Common Stock	 	 	1	 	 	6	 	 	11	 	 	 	 	 	 	 	 	17	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	 	 	 	(555	)	 	 	 	 	(555	) 	
Other	 	 	 	 	 	 	 	 	8	 	 	 	 	 	 	 	 	8	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	7,344	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign Currency Translation Adjustments,  Net of
  Tax of $0	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(104	)	 	(104	) 	
Cash Flow Hedges, Net of Tax of $51	 	 	 	 	 	 	 	 	 	 	 	 	 	 	94	 	 	94	 	
Minimum Pension Liability, Net of Tax of $52	 	 	 	 	 	 	 	 	 	 	 	 	 	 	92	 	 	92	 	
NET INCOME	 	 	 	 	 	 	 	 	 	 	 	1,089	 	 	 	 	 	1,089	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,171	 	
DECEMBER 31, 2004	 	 	405	 	 	2,632	 	 	4,203	 	 	2,024	 	 	(344	)	 	8,515	 	
Issuance of Common Stock	 	 	10	 	 	67	 	 	335	 	 	 	 	 	 	 	 	402	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	 	 	 	(553	)	 	 	 	 	(553	) 	
Repurchase of Common Stock	 	 	 	 	 	 	 	 	(427	)	 	 	 	 	 	 	 	(427	) 	
Other	 	 	 	 	 	 	 	 	20	 	 	 	 	 	 	 	 	20	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	7,957	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign Currency Translation Adjustments,  Net of
  Tax of $0	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(6	)	 	(6	) 	
Cash Flow Hedges, Net of Tax of $15	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(27	)	 	(27	) 	
Securities Available for Sale, Net of Tax of $11	 	 	 	 	 	 	 	 	 	 	 	 	 	 	20	 	 	20	 	
Minimum Pension Liability, Net of Tax of $175	 	 	 	 	 	 	 	 	 	 	 	 	 	 	330	 	 	330	 	
NET INCOME	 	 	 	 	 	 	 	 	 	 	 	814	 	 	 	 	 	814	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,131	 	
DECEMBER 31, 2005	 	 	415	 	 	2,699	 	 	4,131	 	 	2,285	 	 	(27	)	 	9,088	 	
Issuance of Common Stock	 	 	3	 	 	19	 	 	80	 	 	 	 	 	 	 	 	99	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	 	 	 	(591	)	 	 	 	 	(591	) 	
Other	 	 	 	 	 	 	 	 	10	 	 	 	 	 	 	 	 	10	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	8,606	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $11	 	 	 	 	 	 	 	 	 	 	 	 	 	 	21	 	 	21	 	
Securities Available for Sale, Net of Tax of $0	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(1	)	 	(1	) 	
Minimum Pension Liability, Net of Tax of $1	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2	 	 	2	 	
NET INCOME	 	 	 	 	 	 	 	 	 	 	 	1,002	 	 	 	 	 	1,002	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,024	 	
Minimum Pension Liability Elimination, Net of  Tax
  of $9	 	 	 	 	 	 	 	 	 	 	 	 	 	 	17	 	 	17	 	
SFAS 158 Adoption, Net of Tax of $126	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(235	)	 	(235	) 	
DECEMBER 31, 2006	 	 	418	 	$	2,718	 	$	4,221	 	$	2,696	 	$	(223	)	$	9,412	 	

   See Notes to Consolidated Financial Statements.

 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 1.	 	Organization and Summary of Significant Accounting Policies	
 2.	 	New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	
 3.	 	Goodwill and Other Intangible Assets	
 4.	 	Rate Matters	
 5.	 	Effects of Regulation	
 6.	 	Commitments, Guarantees and Contingencies	
 7.	 	Company-wide Staffing and Budget Review	
8.	 	Acquisitions, Dispositions, Discontinued Operations, Impairments and Assets Held for Sale	
9.	 	Benefit Plans	
10.	 	Nuclear	
11.	 	Business Segments	
12.	 	Derivatives, Hedging and Financial Instruments	
13.	 	Income Taxes	
14.	 	Leases	
15.	 	Financing Activities	
16.	 	Stock-Based Compensation	
17.	 	Property, Plant and Equipment	
18.	 	Unaudited Quarterly Financial Information	

 

 

 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

         1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by nine of our electric utility operating companies is the generation, transmission and distribution of electric power. TCC and TNC are completing the final stage of exiting the generation business. WPCo and KGPCo provide only transmission and distribution services. AEGCo is a regulated electricity generation business whose function is to provide power to our regulated electric utility operating companies. These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005. These companies maintain accounts in accordance with FERC and other regulatory guidelines. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States. In addition, our operations include nonregulated independent power and cogeneration facilities, coal mining and barging operations and we provide various energy-related services.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP, AEPSC and its other subsidiaries are regulated by the FERC under the 2005 Public Utility Holding Company Act (2005 PUHCA). AEP’s public utility subsidiaries are regulated by the FERC and state regulatory commissions in our eleven state operating territories. The state regulatory commissions with jurisdiction approve the rates charged and regulate the services and operations of the utility subsidiaries for the generation and supply of power, a majority of transmission energy delivery services and distribution services. The FERC also regulates certain, mostly affiliated, transactions under the 2005 PUHCA.
 
The FERC regulates wholesale power markets and wholesale power transactions. Our wholesale power transactions are generally market-based and are not cost-based regulated unless we negotiate and file a cost-based contract with the FERC or the FERC determines that we have “market power” in the region in which the transaction is taking place. We have wholesale power supply contracts with various municipalities and cooperatives that are FERC regulated, cost-based contracts and our wholesale power transactions in the SPP region are all cost-based due to our having market power in the SPP region as determined by the FERC. As of December 31, 2006, only SWEPCo, PSO and TNC operate in the SPP region.

The FERC also regulates, on a cost basis, our wholesale transmission service and rates except in Texas. The FERC has claimed jurisdiction over retail transmission rates when the retail rates are unbundled in connection with restructuring. In Ohio, CSPCo’s and OPCo’s rates are unbundled, therefore our retail transmission rates are based on FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based. Although our retail rates are unbundled in Virginia and Texas, retail transmission rates are still regulated, on a cost basis, by the state regulatory commissions.

In addition, FERC regulates our East and West Power Pools, East Transmission Equalization Agreement, System Interim Allowance Agreement, and SIA, all of which allocate shared system costs and revenues to the utility subsidiaries that are parties to the agreements.

The state regulatory commissions regulate all of our retail public utility operations (generation, transmission and distribution operations) and rates except in states that have enacted restructuring legislation where only transmission and distribution rates are regulated on a cost-basis and unbundled by function. Our retail generation/power supply operations and rates are cost-based regulated by the state regulatory commissions except for CSPCo and OPCo in Ohio and APCo in Virginia, which are in transition to market pricing under state restructuring legislation.  However, Virginia legislature adopted amendments to its electric restructuring law.  If approved, Virginia would return to a form of cost-based regulation.  AEP has no Texas jurisdictional retail generation/power supply operations in Texas other than a minor generational supply operation through a commercial and industrial customer REP. See Note 4 for further details of such legislation and its effects on AEP in Ohio, Texas, Virginia and Michigan.

In 2004 and 2005, we were subject to regulation by the SEC under the Public Utility Holding Company Act of 1935 (1935 PUHCA). The Energy Policy Act of 2005 repealed the 1935 PUHCA effective February 8, 2006 and replaced it with the 2005 PUHCA. With the repeal of the 1935 PUHCA, the SEC no longer has jurisdiction over the activities of registered holding companies, their respective service corporations and their intercompany transactions, which it regulated predominantly at cost. Jurisdiction over holding company-related activities has been transferred to the FERC. Regulation and required reporting under the 2005 PUHCA have been reduced compared to the 1935 PUHCA. However, the FERC has jurisdiction over the issuances and acquisitions of securities of our public utility subsidiaries, the acquisition or sale of certain utility assets, mergers with another electric utility or holding company, intercompany transactions, accounting and AEPSC intercompany service billings which are generally at cost. The intercompany sale of non-power goods and non-AEPSC services to affiliates cannot exceed market under the 2005 PUHCA. The state regulatory commissions in Virginia and West Virginia also regulate certain intercompany transactions under their affiliates statutes.

Both FERC and state regulatory commissions are permitted to review and audit the books and records of any company within a public utility holding company system.

Principles of Consolidation

Our consolidated financial statements include AEP and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned subsidiaries or substantially-controlled variable interest entities (VIE). Intercompany items are eliminated in consolidation. Equity investments not substantially-controlled that are 50% or less owned are accounted for using the equity method of accounting; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on our Consolidated Statements of Income. We also consolidate VIEs in accordance with FASB Interpretation Number (FIN) 46 (revised December 2003) “Consolidation of Variable Interest Entities” (FIN 46R) (see “Guarantees of Third-Party Obligations” section of Note 6). We also have generating units that are jointly-owned with nonaffiliated companies. Our proportionate share of the operating costs associated with such facilities is included on our Consolidated Statements of Income and our proportionate share of the assets and liabilities are reflected on our Consolidated Balance Sheets.

Accounting for the Effects of Cost-Based Regulation

As the owner of cost-based rate-regulated electric public utility companies, our consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues. Due to the commencement of legislatively required transitions to customer choice and market-based rates, we discontinued the application of SFAS 71, regulatory accounting, for the generation portion of our business: in Ohio for OPCo and CSPCo in September 2000, in Virginia for APCo in June 2000 and in Texas for TCC, TNC and the Texas portion of SWEPCo in September 1999. SFAS 101, “Regulated Enterprises - Accounting for the Discontinuance of Application of FASB Statement No. 71” requires the recognition of an impairment of stranded regulatory assets and stranded plant costs if they are not recoverable in regulated rates. Such impairments arising from the discontinuance of SFAS 71 are classified as an extraordinary item. TCC recorded extraordinary impairment losses related to its regulatory assets and plant costs in 2004 and 2005 resulting from the discontinuance of cost-based regulation of their generation business without full recovery of the resultant stranded costs.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of nonregulated operations and other investments are stated at fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are charged to accumulated depreciation. For nonregulated operations, retirements from the plant accounts, net of salvage, are charged to accumulated depreciation and removal costs are charged to expense. The costs of labor, materials and overhead incurred to operate and maintain our plants are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Equity investments are required to be tested for impairment when it is determined there may be an other than temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. For nonregulated operations including domestic generating assets in Ohio, Texas and Virginia, effective with the discontinuance of SFAS 71 regulatory accounting, interest is capitalized during construction in accordance with SFAS 34, “Capitalization of Interest Costs.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three-months or less.

Other Temporary Cash Investments

Other Temporary Cash Investments include marketable securities that we intend to hold for less than one year and funds held by trustees primarily for the payment of debt.

We classify our investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). We do not have any investments classified as trading.

Available-for-sale securities reflected in Other Temporary Cash Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive income. Held-to-maturity securities reflected in Other Temporary Cash Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. The fair value of most investment securities is determined by currently available market prices. Where quoted market prices are not available, we use the market price of similar types of securities that are traded in the market to estimate fair value.

The following is a summary of Other Temporary Cash Investments at December 31:

 	 	2006	 	2005	 	
Other Temporary Cash Investments	 	Cost	 	Gross Unrealized Gains	 	Gross Unrealized Losses	 	  Estimated
Fair
Value	 	Cost	 	Gross Unrealized Gains	 	Gross Unrealized Losses	 	Estimated
Fair
Value	 	
 	 	(in millions)	 	
Cash (a)	 	$	138	 	$	-	 	$	-	 	$	138	 	$	96	 	$	-	 	$	-	 	$	96	 	
Government   Debt   Securities	 	 	258	 	 	-	 	 	-	 	 	258	 	 	-	 	 	-	 	 	-	 	 	-	 	
Corporate   Equity  Securities	 	 	1	 	 	28	 	 	-	 	 	29	 	 	2	 	 	29	 	 	-	 	 	31	 	
Total Other   Temporary   Cash  
   Investments	 	$	397	 	$	28	 	$	-	 	$	425	 	$	98	 	$	29	 	$	-	 	$	127	 	

(a)	Primarily represents amounts held for the payment of debt.	

Proceeds from sales of current available-for-sale securities were $17,449 million, $8,228 million and $670 million in 2006, 2005 and 2004, respectively. Purchases of current available-for-sale securities were $17,667 million, $8,075 million and $573 million in 2006, 2005 and 2004, respectively. Gross realized gains from the sale of current available-for-sale securities were $39 million and $47 million in 2006 and 2005, respectively, and were not material in 2004. Gross realized losses from the sale of current available-for-sale securities were not material in 2006, 2005 or 2004.

The fair value of debt securities, summarized by contractual maturities, at December 31, 2006 is as follows:

 	 	Fair Value	 	
Maturity	 	(in millions)	 	
2007	 	$	-	 	
2008 - 2011	 	 	-	 	
2012 - 2016	 	 	4	 	
After 2016	 	 	254	 	
Total	 	$	258	 	

Inventory

Fossil fuel inventories are carried at average cost for AEGCo, APCo, I&M, KPCo and SWEPCo. OPCo and CSPCo value fossil fuel inventories at the lower of average cost or market. PSO carries fossil fuel inventories utilizing a LIFO method. TNC carries fossil fuel inventories at the lower of cost or market using a LIFO method. Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.

We recognize revenue from electric power and gas sales when we deliver power or gas to our customers. To the extent that deliveries have occurred but a bill has not been issued, we accrue and recognize, as Accrued Unbilled Revenues on our Consolidated Balance Sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable for certain subsidiaries, including CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” allowing the receivables to be removed from the company’s balance sheet (see “Sale of Receivables - AEP Credit” section of Note 15).

Foreign Currency Translation

The financial statements of subsidiaries outside the U.S. that are included in our consolidated financial statements and investments outside the U.S. that are accounted for under the equity method are measured using the local currency as the functional currency and translated into U.S. dollars in accordance with SFAS 52, “Foreign Currency Translation.” In 2006, we completed the disposal of our various non-U.S. equity method investments. Revenues and expenses are translated at monthly average foreign currency exchange rates throughout the year, unless a specific rate can be identified through an event. Assets and liabilities are translated into U.S. dollars at year-end foreign currency exchange rates. Accordingly, our consolidated common shareholders’ equity will fluctuate depending on the relative strengthening or weakening of the U.S. dollar versus relevant foreign currencies. Currency translation gain and loss adjustments are recorded in shareholders’ equity as Accumulated Other Comprehensive Income (Loss). The foreign currency translation balance of Accumulated Other Comprehensive Income (Loss) as of December 31, 2006 and 2005 was $58 thousand and $53 thousand, respectively, and was reduced primarily due to the disposition of our U.K. assets in 2004, which is reflected in Discontinued Operations on our Consolidated Statements of Income.

Deferred Fuel Costs  

The cost of fuel and related chemical and emission allowance consumables are charged to Fuel and Other Consumables Used for Electric Generation Expense when the fuel is burned or the consumable is utilized. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. These deferrals are amortized when refunded or when billed to customers in later months with the regulator’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of regulators. On a routine basis, state regulatory commissions audit our fuel cost calculations. When a fuel cost disallowance becomes probable, we adjust our deferrals and record provisions for estimated refunds to recognize these probable outcomes (see Note 4). Fuel cost over-recovery and under-recovery balances are classified as noncurrent when the fuel clauses have been suspended or terminated as in West Virginia (prior to July 2006) and Texas-ERCOT, respectively.

In general, changes in fuel costs in Kentucky for KPCo, Michigan for I&M, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO, Virginia and West Virginia (beginning July 1, 2006) for APCo are reflected in rates in a timely manner through the fuel cost adjustment clauses in place in those states. All or a portion of profits from off-system sales are shared with customers through fuel clauses in Texas (SPP area only), Oklahoma, Louisiana, Arkansas, Kentucky, West Virginia (beginning July 1, 2006) and in some areas of Michigan. Where fuel clauses have been eliminated due to the transition to market pricing (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002), changes in fuel costs impact earnings unless recovered in the sales price for electricity. In other state jurisdictions, (Indiana and prior to July 1, 2006 in West Virginia), where fuel clauses have been capped, frozen or suspended for a period of years, fuel costs impact earnings. The Indiana fuel clause suspension ends June 30, 2007. In West Virginia, deferred fuel accounting for over- or under-recovery began July 1, 2006. Changes in fuel costs also impact earnings for certain of our IPP generating units that do not have long-term contracts for their fuel supply or have not hedged fuel costs.

Revenue Recognition

Regulatory Accounting

Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers in cost-based regulated rates. Regulatory liabilities or regulatory assets are also recorded for unrealized MTM gains or losses that occur due to changes in the fair value of physical and financial contracts that are derivatives and that are subject to the regulated ratemaking process when realized.

When regulatory assets are probable of recovery through regulated rates, we record them as assets on our Consolidated Balance Sheets. We test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against earnings. A write-off of regulatory assets also reduces future cash flows since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities  

Revenues are recognized from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. We recognize the revenues on our Consolidated Statements of Income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. In general, we record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase-and-sale contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio, Virginia and the ERCOT portion of Texas. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

For power purchased under derivative contracts in our west zone where we are short capacity, prior to settlement, we recognize as Revenues the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period. If the contract results in the physical delivery of power, we reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts gross as Purchased Energy for Resale. If the contract does not physically deliver, we reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts as Revenues on our Consolidated Statements of Income on a net basis (see “Derivatives and Hedging” section of Note 12).

Domestic Gas Pipeline and Storage Activities

As a result of the sale of HPL in 2005, our domestic gas pipeline and storage activities ceased. Prior to the sale of HPL, we recognized revenues from domestic gas pipeline and storage services when gas was delivered to contractual meter points or when services were provided, with the exception of certain physical forward gas purchase-and-sale contracts that were derivatives and accounted for using MTM accounting (resale gas contracts). The unrealized and realized gains and losses on resale gas contracts for the sale of natural gas are presented as Revenues on our Consolidated Statements of Income. The unrealized and realized gains and losses on physically-settled resale gas contracts for the purchase of natural gas are presented as Purchased Gas for Resale on our Consolidated Statements of Income (see “Fair Value Hedging Strategies” section of Note 12).

Energy Marketing and Risk Management Activities

We engage in wholesale electricity, natural gas, coal and emission allowances marketing and risk management activities focused on wholesale markets where we own assets. Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts, which include exchange traded futures and options and over-the-counter options and swaps.

We recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity. We use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow or fair value hedge relationship, or as a normal purchase or sale. We include the unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in Revenues on our Consolidated Statements of Income on a net basis. In jurisdictions subject to cost-based regulation, we defer the unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains). We include unrealized MTM gains and losses resulting from derivative contracts on our Consolidated Balance Sheets as Risk Management Assets or Liabilities as appropriate.

Certain wholesale marketing and risk management transactions are designated as hedges of future cash flows as a result of forecasted transactions (cash flow hedge) or as hedges of a recognized asset, liability or firm commitment (fair value hedge). We recognize the gains or losses on derivatives designated as fair value hedges in Revenues on our Consolidated Statements of Income in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged. For derivatives designated as cash flow hedges, we initially record the effective portion of the derivative’s gain or loss as a component of Accumulated Other Comprehensive Income (Loss) and, depending upon the specific nature of the risk being hedged, subsequently reclassify into Revenues or fuel expenses on our Consolidated Statements of Income when the forecasted transaction is realized and affects earnings. We recognize the ineffective portion of the gain or loss in Revenues on our Consolidated Statements of Income immediately, except in those jurisdictions subject to cost-based regulation. In those regulated jurisdictions we defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains) (see “Fair Value Hedging Strategies” and “Cash Flow Hedging Strategies” sections of Note 12).

Barging Activities

MEMCO Operations revenue is recognized based on percentage of completion. The proportion of freight transportation revenue to be recognized is determined by applying a percentage to the contractual charges for such services. The percentage is determined by dividing the number of miles from the loading point to the position of the barge as of the end of the accounting period by the total miles to the destination specified in the customer’s freight contract. The position of the barge at accounting period end is determined by MEMCO’s computerized barge tracking system. The recognition of revenue based upon the percentage of voyage completion results in a better matching of revenue and expenses.

Construction Projects for Outside Parties

We engage in construction projects for outside parties and account for the projects on the percentage-of-completion method of revenue recognition. This method recognizes revenue, including the related margin, as we incur and bill project costs to the outside party.

Maintenance

We expense maintenance costs as incurred. If it becomes probable that we will recover specifically-incurred costs through future rates, we establish a regulatory asset to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. We defer maintenance costs during refueling outages at the Cook Plant and amortize the costs over the period between outages in accordance with rate orders in Indiana and Michigan.

Income Taxes and Investment Tax Credits

We use the liability method of accounting for income taxes. Under the liability method, we provide deferred income taxes for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), we record deferred income taxes and establish related regulatory assets and liabilities to match the regulated revenues and tax expense.

We account for investment tax credits under the flow-through method except where regulatory commissions reflect investment tax credits in the rate-making process on a deferral basis. We amortize deferred investment tax credits over the life of the plant investment.

Excise Taxes

We act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customers. We do not recognize these taxes as revenue or expense.

Debt and Preferred Stock

We defer gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plants and amortize the deferral over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If we refinance the reacquired debt associated with the regulated business, the reacquisition costs attributable to the portions of the business subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Some jurisdictions require that these costs be expensed upon reacquisition. We report gains and losses on the reacquisition of debt for operations not subject to cost-based rate regulation in Interest Expense on our Consolidated Statements of Income.

We defer debt discount or premium and debt issuance expenses and amortize generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. We include the amortization expense in Interest Expense on our Consolidated Statements of Income.

Where reflected in rates, we include redemption premiums paid to reacquire preferred stock of certain domestic utility subsidiaries in paid-in capital and amortize the premiums to retained earnings commensurate with recovery in rates. We credit the excess of par value over costs of preferred stock reacquired to paid-in capital and reclassify the excess to retained earnings upon the redemption of the entire preferred stock series. We credit the excess of par value over the costs of reacquired preferred stock for nonregulated subsidiaries to retained earnings upon reacquisition.

Goodwill and Intangible Assets  

When we acquire businesses, we record the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, we record goodwill. We do not amortize purchased goodwill and intangible assets with indefinite lives. We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. We test goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, we estimate fair value using various internal and external valuation methods. We amortize intangible assets with finite lives over their respective estimated lives, currently ranging from 5 to 10 years, to their estimated residual values. We also review the lives of the amortizable intangibles with finite lives on an annual basis.

Emission Allowances

We record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. We follow the inventory model for all allowances. We record allowances expected to be consumed within one year in Fuel, Materials and Supplies and allowances with expected consumption beyond one year in Other Noncurrent Assets-Other on our Consolidated Balance Sheets. We record the consumption of allowances in the production of energy in Fuel and Other Consumables Used for Electric Generation on our Consolidated Statements of Income at an average cost. We record allowances held for speculation in Other Current Assets on our Consolidated Balance Sheets. We report the purchases and sales of allowances in the Operating Activities section of the Statements of Cash Flows. We record the net margin on sales of emission allowances in Utility Operations Revenue on our Consolidated Statements of Income because of its integral nature to the production process of energy and our revenue optimization strategy for our utility operations.

Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

·	acceptable investments (rated investment grade or above);	
·	maximum percentage invested in a specific type of investment;	
·	prohibition of investment in obligations of the applicable company or its affiliates; and	
·	withdrawals permitted only for payment of decommissioning costs and trust expenses.	

We maintain trust funds for each regulatory jurisdiction, which are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification, and other prudent investment objectives.

We record securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel in Spent Nuclear Fuel and Decommissioning Trusts on our Consolidated Balance Sheets. We record these securities at market value. We classify securities in the trust funds as available-for-sale due to their long-term purpose. Upon the issuance of FSP 115-1 and 124-1 “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” we consider all nuclear decommissioning trust fund and spent nuclear fuel trust fund investments in unrealized loss positions to be other-than-temporary impairments as we do not make specific investment decisions regarding assets held in trusts. Thus, effective in 2006, the other-than-temporary impairments are considered realized losses and will reduce the cost basis of the securities which will affect any future unrealized gain or realized gains or losses. Amounts prior to 2006 were not restated as the other-than-temporary impairments do not affect earnings or AOCI. We record unrealized gains and losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. See Note 10 for additional discussion of nuclear matters.

Comprehensive Income   (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the Consolidated Balance Sheets in the common shareholders’ equity section. The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss):
 
 	 	December 31,	 	
 	 	2006	 	2005	 	
Components	 	(in millions)	 	
Securities Available for Sale, Net of Tax	 	$	18	 	$	19	 	
Cash Flow Hedges, Net of Tax	 	 	(6	)	 	(27	)	
Minimum Pension Liability, Net of Tax (a)	 	 	-	 	 	(19	)	
SFAS 158 Adoption, Net of Tax (a)	 	 	(235	)	 	-	 	
Total	 	$	(223	)	$	(27	)	

(a)	See “SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” section of Note 2.	

At December 31, 2006, we expect to reclassify approximately $15 million of net gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve-months at the time the hedged transactions affect Net Income. The actual amounts that are reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ as a result of market fluctuations.

At December 31, 2006, forty-two- months is the maximum length of time that our exposure to variability in future cash flows is hedged with contracts designated as cash flow hedges.

Stock-Based Compensation Plans  

As of December 31, 2006, we had stock options, performance units, restricted shares and restricted stock units outstanding to employees under The Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP). This plan was originally approved by shareholder vote in 2000 and the Amended and Restated version was subsequently approved in 2005.

We maintain career share accounts under the Stock Ownership Requirement Plan to facilitate executives in meeting minimum stock ownership requirements assigned to executives by the HR Committee of the Board of Directors. Career shares are derived from vested performance units granted to employees under the LTIP. Career shares are equal in value to shares of AEP common stock and do not become payable to executives until after their service ends.

We also compensate our non-employee directors, in part, with stock units under The Stock Unit Accumulation Plan for Non-Employee Directors. These stock units also do not become payable in cash to Directors until after their service to the company ends.

In addition, we maintain a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP stock.

On January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123R) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including stock options and employee stock purchases based on estimated fair values. See the SFAS 123 (revised 2004) “Share-Based Payment (SFAS 123R)” section of Note 2 for additional discussion.

In conjunction with the adoption of SFAS 123R, we changed our method of attributing the value of stock-based compensation to expense for awards with service only conditions from the accelerated multiple-option approach to the straight-line single-option method. We recognize compensation expense for all share-based payment awards granted prior to January 1, 2006 using the accelerated multiple-option approach while we recognize compensation expense for all share-based payment awards with service only condition granted on or after January 1, 2006 using the straight-line single-option method. In 2006, we granted an award with performance conditions which continue to be expensed on the accelerated multiple-option approach. As stock-based compensation expense recognized on our Consolidated Statements of Income for the year ended December 31, 2006 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In our pro forma information presented in Note 16 as required under SFAS 123 for the periods prior to 2006, we accounted for forfeitures as they occurred.

For the years ended December 31, 2005 and 2004, no stock option expense was reflected in Net Income as we accounted for stock options using the intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, “Accounting For Stock Issued to Employees.” Under the intrinsic value method, no stock option expense is recognized when the exercise price of the stock options granted equals the fair value of the underlying stock at the date of grant. For the years ended December 31, 2006, 2005 and 2004, compensation cost is included in Net Income for the performance share units, phantom stock units, restricted shares, restricted stock units and the Director’s stock units. See Note 16 for additional discussion.
 
Pro Forma Information Under SFAS 123, “Accounting for Stock-Based Compensation,” for Periods Presented Prior to January 1, 2006

The following table shows the effect on our Net Income and Earnings Per Share as if we had applied fair value measurement and recognition provisions of SFAS 123   to stock-based employee and director compensation awards for the years ended December 31, 2005 and 2004:
 	 	2005	 	2004	 	
 	 	(in millions, except per share data)	 	
Net Income, as reported	 	$	814	 	$	1,089	 	
Add: Stock-based compensation expense included in reported Net Income, net of related tax effects	 	 	22	 	 	15	 	
Deduct: Stock-based compensation expense determined under fair value based method for all awards,
  net of related tax effects	 	 	(22	)	 	(18	)	
Pro Forma Net Income	 	$	814	 	$	1,086	 	
 	 	 	 	 	 	 	 	
Earnings Per Share:	 	 	 	 	 	 	 	
Basic - as Reported	 	$	2.09	 	$	2.75	 	
Basic - Pro Forma (a)	 	$	2.09	 	$	2.74	 	
 	 	 	 	 	 	 	 	
Diluted - as Reported	 	$	2.08	 	$	2.75	 	
Diluted - Pro Forma (a)	 	$	2.08	 	$	2.74	 	

(a)	The pro forma amounts are not representative of the effects on reported net income for future years.	

Earnings Per Share (EPS)

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

The following table presents our basic and diluted EPS calculations included on our Consolidated Statements of Income:
 
 	 	 2006	 	  2005	 	  2004	 	
 	 	(in millions, except per share data)	 	
 	 	 	 	 	 	$/share 	 	 	 	 	 	$/share 	 	 	 	 	 	$/share  	 	
Earnings Applicable to Common Stock	 	$	1,002	 	 	 	 	$	814	 	 	 	 	$	1,089	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Number of Basic Shares Outstanding	 	 	394.2	 	$	2.54	 	 	390.0	 	$	2.09	 	 	395.6	 	$	2.75	 	
Average Dilutive Effect of:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Performance Share Units	 	 	1.8	 	 	0.01	 	 	1.0	 	 	0.01	 	 	0.6	 	 	-	 	
Stock Options	 	 	0.3	 	 	-	 	 	0.3	 	 	-	 	 	0.3	 	 	-	 	
Restricted Stock Units	 	 	0.1	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Restricted Shares	 	 	0.1	 	 	-	 	 	0.1	 	 	-	 	 	0.1	 	 	-	 	
Average Number of Diluted Shares Outstanding	 	 	396.5	 	$	2.53	 	 	391.4	 	$	2.08	 	 	396.6	 	$	2.75	 	

The assumed conversion of stock options does not affect net earnings (loss) for purposes of calculating diluted earnings per share.

Options to purchase 0.4 million, 0.5 million and 5.2 million shares of common stock were outstanding at December 31, 2006, 2005 and 2004, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the year-end market price of the common shares and, therefore, the effect would be antidilutive.

Supplementary Information
 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Related Party Transactions	 	(in millions)	 	
AEP Consolidated Purchased Energy:	 	 	 	 	 	 	 	 	 	 	
Ohio Valley Electric Corporation (43.47% Owned)	 	$	223	 	$	196	 	$	161	 	
Sweeny Cogeneration Limited Partnership (50% Owned)	 	 	121	 	 	141	 	 	-	 	
AEP Consolidated Other Revenues - Barging and Other Transportation Services -
   Ohio Valley Electric  Corporation (43.47% Owned)	 	 	28	 	 	20	 	 	14	 	
AEP Consolidated Revenues - Utility Operations:	 	 	 	 	 	 	 	 	 	 	
Power Pool Purchases - Ohio Valley Electric Corporation (43.47% Owned)	 	 	(37	)	 	-	 	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Information	 	 	 	 	 	 	 	 	 	 	
Cash paid (received) for:	 	 	 	 	 	 	 	 	 	 	
Interest, Net of Capitalized Amounts	 	 	664	 	 	637	 	 	755	 	
Income Taxes, Net of Refunds	 	 	358	 	 	439	 	 	(107	)	
Noncash Investing and Financing Activities:	 	 	 	 	 	 	 	 	 	 	
Acquisitions Under Capital Leases	 	 	106	 	 	63	 	 	123	 	
Disposition of Liabilities Related to Acquisitions/Divestitures, Net	 	 	-	 	 	(18	)	 	(67	)	
Noncash Construction Expenditures Included in Accounts Payable at December 31	 	 	404	 	 	253	 	 	116	 	
Noncash Acquisition of Nuclear Fuel in Accounts Payable at December 31	 	 	-	 	 	24	 	 	-	 	

Power Projects

We own a 50% interest in Sweeny, a domestic unregulated power plant with a capacity of 480 MW located in Texas. In 2006, we sold our 50% interest in an international power plant totaling 600 MW located in Mexico (see “Dispositions” section of Note 8).

We account for investments in power projects that are 50% or less owned using the equity method and report them as Deferred Charges and Other on our Consolidated Balance Sheets. At December 31, 2006 and 2005, the 50% owned domestic power project and international power investment are accounted for under the equity method and have unrelated third-party partners. The domestic project is a combined cycle gas turbine that provides steam to a host commercial customer and is considered a Qualifying Facility (QF) under PURPA. The international power investment was classified as a Foreign Utility Company (FUCO) under the Energy Policies Act of 1992.

The domestic power project has project-level financing, which is nonrecourse to AEP.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.

On our Consolidated Balance Sheets, we reclassified $147 million of mining equipment as of December 31, 2005 from Production to Other within Property, Plant and Equipment.

On our Consolidated Statements of Income, we reclassified regulatory credits related to regulatory asset cost deferral on ARO from Depreciation and Amortization to Other Operation and Maintenance to offset the ARO accretion expense. These reclassifications totaled $30 million and $24 million for 2005 and 2004, respectively.

In our segment information, we reclassified two subsidiary companies, AEP Texas Commercial & Industrial Retail GP, LLC and AEP Texas Commercial & Industrial Retail LP, from the Utility Operations segment to the Generation and Marketing segment as discussed in Note 11. Combined revenues for these companies totaled $36 million and $44 million for 2005 and 2004, respectively. As a result, on our Consolidated Statements of Income we reclassified these revenues from Utility Operations to Other.

These revisions had no impact on our previously reported results of operations, cash flows or changes in shareholders’ equity.

         2.   NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of final pronouncements that we have determined relate to our operations.

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

The FASB issued SFAS 123R, requiring entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting.

In 2005, the SEC issued Staff Accounting Bulletin No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued FASB Staff Positions (FSP) that provided additional implementation guidance. We applied the principles of SAB 107 and the applicable FSPs in conjunction with our adoption of SFAS 123R in 2006. We adopted SFAS 123R using the modified prospective method without materially affecting our results of operations, cash flows or financial condition.
 
SFAS 154 “Accounting Changes and Error Corrections” (SFAS 154)

In 2005, the FASB issued SFAS 154. The statement applies to all voluntary changes in accounting principle and changes resulting from adoption of a new accounting pronouncement that do not specify transition requirements. It requires retrospective application to prior periods’ financial statements for changes in accounting principle unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. It also requires that retrospective application of a change in accounting principle should be recognized in the period of the accounting change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 was effective for accounting changes and corrections of errors after January 1, 2006 and is applied as necessary.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. We expect that the adoption of this standard will impact MTM valuations of certain contracts, but we are unable to quantify the effect. Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. We will adopt SFAS 157 effective January 1, 2008.

SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

In September 2006, the FASB issued SFAS 158, amending previous standards. It requires employers to fully recognize the obligations associated with defined benefit pension plans and other postretirement employee benefit (OPEB) plans, which include retiree healthcare, in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to previous standards. It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit pension or OPEB plan affects net periodic benefit costs for the next fiscal year.

The effect of SFAS 158 is to adjust pretax AOCI at the end of each year, for both underfunded deferred benefit and overfunded pension and OPEB plans, to an amount equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition. The year-end AOCI measure can be volatile based on fluctuating investment returns and discount rates. Favorable changes include higher returns that increase plan assets and higher discount rates that reduce the discounted benefit obligation.

We adopted SFAS 158 as of December 31, 2006. We recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of our regulated operations that for ratemaking purposes will be deferred for future recovery. The following table shows the incremental effect of this standard on our financial statements versus prior accounting requirements including the additional minimum pension liability provisions of SFAS 87, “Employers’ Accounting for Pensions,” which were replaced by SFAS 158 as follows:

 	 	Before Application
of SFAS 158	 	Incremental
Effect	 	After
Application
of SFAS 158	 	
 	 	(in millions)	 	
Prepaid Benefit Costs	 	$	1,038	 	$	(718	)	$	320	 	
Current Accrued Benefit Liability	 	 	-	 	 	(13	)	 	(13	)	
Noncurrent Accrued Benefit Liability	 	 	(80	)	 	(505	)	 	(585	)	
Regulatory Assets	 	 	-	 	 	875	 	 	875	 	
Deferred Income Taxes	 	 	9	 	 	117	 	 	126	 	
Additional Minimum Liability	 	 	(32	)	 	32	 	 	N/A	 	
Intangible Asset	 	 	6	 	 	(6	)	 	N/A	 	
Net of Tax AOCI Equity Reduction	 	 	17	 	 	218	 	 	235	 	
Total	 	$	958	 	$	-	 	$	958	 	

N/A = Not Applicable	

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.

SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. In the event we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted. The statement is applied prospectively upon adoption. We will adopt SFAS 159 effective January 1, 2008.

FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48)

In July 2006, the FASB issued FIN 48. It clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. FIN 48 is effective for fiscal years beginning after December 15, 2006. Although we are in the process of evaluating the impact of FIN 48, we estimate the effect of this interpretation on our financial statements to be an unfavorable adjustment to retained earnings of less than $15 million.

EITF Issue 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”

This issue focuses on two inventory exchange issues. Purchases or sales of inventory transactions with the same counterparty should be combined under APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” if they were entered in contemplation of one another. Nonmonetary exchanges of inventory within the same line of business should be valued at fair value if an entity exchanges finished goods for raw materials or work in progress within the same line of business and if fair value can be determined and the transaction has commercial substance. All other nonmonetary exchanges within the same line of business should be valued at the carrying amount of the inventory transferred. We implemented this issue beginning April 1, 2006 without a material impact on our financial statements.

EITF Issue 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF 06-3)

In June 2006, the EITF reached a consensus on the income statement presentation of various types of taxes. The scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes. The presentation of taxes within the scope of this issue on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed. The EITF’s decision on gross/net presentation requires that any such taxes reported on a gross basis be disclosed on an aggregate basis in interim and annual financial statements, for each period for which an income statement is presented, if those amounts are significant.

As disclosed in Note 1, we act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customers. Our policy is to present these taxes on a net basis. We do not recognize these taxes as revenues or expenses. Therefore, this issue did not impact our financial statements.

SAB No. 108 “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements” (SAB 108)

In September 2006, the SEC staff issued SAB 108 addressing diversity in practice when quantifying the effect of an error on financial statements. It provides guidance on the consideration of the effects of prior year misstatements in quantifying misstatements in current year financial statements. Our adoption of SAB 108, effective December 31, 2006, did not have a material impact on our financial statements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including business combinations, revenue recognition, liabilities and equity, derivatives disclosures, earnings per share calculations, leases, insurance, subsequent events and related tax impacts. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position.

EXTRAORDINARY ITEMS

Results for 2005 reflect net adjustments made by TCC to its net true-up regulatory asset for the PUCT’s final order in its True-up Proceeding issued in February 2006. Based on the final order, TCC’s net true-up regulatory asset was reduced by $384 million. Of the $384 million, $345 million ($225 million, net of tax) was recorded as an extraordinary item in accordance with SFAS 101 “Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71” (SFAS 101) and is reflected in Extraordinary Loss, Net of Tax on our 2005 Consolidated Statement of Income (see “ TCC Texas Restructuring” section of Note 4).

In 2004, as part of its True-up Proceeding, TCC made net adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset related to its transition to retail competition. We recorded this adjustment as an extraordinary item in accordance with SFAS 101. The adjustment is included in Extraordinary Loss, Net of Tax on our 2004 Consolidated Statement of Income.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE

Asset Retirement Obligations

In 2005, we recorded a $26 million ($17 million, net of tax) cumulative effect of accounting change for ARO in accordance with FIN 47 in the Utility Operations segment. This adjustment is included in Cumulative Effect of Accounting Change, Net on our 2005 Consolidated Statement of Income.

         3.   GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in our carrying amount of goodwill for the years ended December 31, 2006 and 2005 by operating segment are as follows:
 	 	Utility Operations	 	MEMCO
Operations	 	AEP
Consolidated	 	
 	 	 (in millions)	 	
Balance at January 1, 2005	 	$	37.1	 	$	38.8	 	$	75.9	 	
 	 	 	 	 	 	 	 	 	 	 	
Impairment Losses	 	 	-	 	 	-	 	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2005	 	 	37.1	 	 	38.8	 	 	75.9	 	
 	 	 	 	 	 	 	 	 	 	 	
Impairment Losses	 	 	-	 	 	-	 	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2006	 	$	37.1	 	$	38.8	 	$	75.9	 	

In the fourth quarters of 2005 and 2006, we performed our annual impairment tests. The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses required.

Other Intangible Assets

Acquired intangible assets subject to amortization were $19.4 million at December 31, 2006 and $23.9 million at December 31, 2005, net of accumulated amortization and are included in Deferred Charges and Other on our Consolidated Balance Sheets. The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows:
 	 	 	 	December 31, 2006	 	December 31, 2005	 	
 	 	Amortization Life	 	Gross Carrying Amount	 	Accumulated Amortization	 	Gross Carrying Amount	 	Accumulated Amortization	 	
 	 	(in years)	 	(in millions)	 	(in millions)	 	
Patent	 	 	5	 	$	0.1	 	$	0.1	 	$	0.1	 	$	0.1	 	
Easements	 	 	10	 	 	2.2	 	 	1.1	 	 	2.2	 	 	0.7	 	
Purchased Technology	 	 	10	 	 	10.9	 	 	5.4	 	 	10.9	 	 	4.3	 	
Advanced Royalties	 	 	10	 	 	29.4	 	 	16.6	 	 	29.4	 	 	13.6	 	
Total	 	 	 	 	$	42.6	 	$	23.2	 	$	42.6	 	$	18.7	 	

Amortization of intangible assets was $5 million, $4 million and $4 million for 2006, 2005 and 2004, respectively. Our estimated total amortization is $5 million for 2007, $4 million per year for 2008 through 2010 and $2 million in 2011, when all assets will be fully amortized with no residual value.

Other than goodwill, we have no intangible assets that are not subject to amortization.
 
        4.   RATE MATTERS  

Our subsidiaries are involved in rate and regulatory proceedings at the FERC and state commissions. This note is a discussion of pending rate matters, including industry restructuring and customer choice related proceedings, that could materially impact results of operations and cash flows.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans

Ohio restructuring legislation provided for a transition to market pricing for power supply beginning on January 1, 2006. Open access to power suppliers began in Ohio on January 1, 2001 with a five-year transition to market pricing. Under a 2000 PUCO-approved settlement agreement, CSPCo and OPCo (the Ohio companies) froze their rates through December 31, 2005. In accordance with the approved settlement agreement, CSPCo and OPCo amortize their stranded generation-related transition regulatory assets commensurate with recovery through their frozen rates and starting January 1, 2006 through rate riders that expire in 2008 and 2007, respectively. To date, CSPCo and OPCo have lost very few customers to competing suppliers.

In 2005, the PUCO approved Rate Stabilization Plans (RSPs) for the Ohio companies effective January 1, 2006 and ending December 31, 2008, which allow the Ohio companies to increase their generation rates over three years. The approved three-year RSPs provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7% a year, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year to recover governmentally-mandated costs. During 2006 through 2008, the RSPs also allow the Ohio companies to recover regulatory assets for 2004 and 2005 environmental carrying costs and PJM-related administrative costs and congestion costs, net of financial transmission rights (FTR) revenues, related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program.

Pretax earnings increased by $110 million for the Ohio companies in 2006 from the RSP rate increases, net of the amortization of RSP regulatory assets. This increase includes the recovery of unrecognized equity carrying costs for 2004 and 2005. At December 31, 2006, unrecognized equity costs total $29 million. As of December 31, 2006, the unamortized RSP regulatory assets to be recovered through December 31, 2008 were $38 million.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court challenging the RSPs and also arguing that there is no POLR obligation the Ohio companies are entitled to recover. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for the Ohio companies and remanded the case to the PUCO for further proceedings. In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continue collecting RSP revenues, amortizing the RSP costs and realizing and recognizing related equity carrying costs.

In September 2006, the Ohio companies submitted their proposal to the PUCO to provide additional options for customer participation in the electric market. The proposal provides for the recovery of the cost of providing the additional options. In January 2007, the PUCO set a schedule for interested persons to file comments concerning the proposal.

The Ohio Supreme Court did not address any other issues raised on appeal, stating its decision did not preclude the Ohio Consumers’ Counsel from raising those issues in a future appeal. Management believes that the RSP regulatory assets remain probable of recovery and that the Ohio companies will continue to collect RSP revenues.

In January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of their RSPs to increase their annual generation rates for 2007 by $24 million and $8 million, respectively, to recover governmentally-mandated costs.

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. At this time, management is unable to predict whether the Ohio companies will transition to market pricing, whether the RSP will be extended with or without modification, or whether cost-based regulation will be reinstated on January 1, 2009 when the RSP period ends.

Customer Choice Deferrals

As provided in the restructuring settlement agreement approved by the PUCO in 2000, the Ohio companies established regulatory assets for customer choice implementation costs and related carrying costs in excess of $40 million in total for recovery in the next general rate filing to change distribution rates after December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo was further deferred until the next distribution rate filing to change rates after the end of the RSP period dated December 31, 2008. Through December 31, 2006, we incurred $99 million of such costs and established regulatory assets of $49 million for such costs. We have not recognized $10 million of equity carrying costs, which are not recognizable until collected. We believe that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates.

IGCC Plant

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology. The application proposed three phases of cost recovery associated with the IGCC plant: Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery, or refund, in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power costs. The proposed recoveries in Phases 1 and 2 would be applied against the 4% limit on additional generation rate increases the Ohio companies could request under their RSPs.

In April 2006, the PUCO issued an order authorizing the Ohio companies to implement Phase 1 of the cost recovery proposal. In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over no more than a twelve-month period effective July 1, 2006. Through December 31, 2006, the Ohio companies recorded pre-construction IGCC regulatory assets of $20 million and recovered $12 million of those costs. We are currently recovering the remaining amounts through June 30, 2007. 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, which are assignable to other jurisdictions, 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.

In August 2006, The Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio companies believe that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. Management, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, the Ohio companies could be required to refund Phase I cost-related recoveries.

Transmission Rate Filing

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders for the Ohio companies. The transmission cost recovery riders are subject to an annual true-up process. In May 2006, the PUCO issued an order approving a two-step increase in the transmission cost recovery riders effective April 1, 2006. The Ohio companies implemented the new tariffs in June 2006. They reflect the Ohio companies’ share of the loss of SECA revenues in step one. The step two increase, effective August 1, 2006, reflects the change in the AEP East Zone transmission rate approved by the FERC related to completion of the new Wyoming-Jacksons Ferry 765 kV line.

In October 2006, the Ohio companies filed for initial true-ups under the transmission cost recovery riders. The filings reflect the refund of a regulatory liability, as of September 30, 2006, of $12 million and $16 million for CSPCo and OPCo, respectively, including carrying charges. These refunds were reflected as part of new transmission cost recovery riders, which became effective for 2007. The net effect of the new transmission cost recovery riders is to increase cost recoveries in 2006 over 2005 levels for CSPCo and OPCo by $27 million and $36 million, respectively. We anticipate a favorable net effect in 2007 over 2005 levels of $15 million and $18 million, respectively.

Distribution Service Reliability and Restoration Costs

In December 2003, the Ohio companies entered into a stipulation agreement regarding distribution service reliability. The stipulation agreement covered the years 2004 and 2005 and, among other features, established certain distribution service reliability measures for the Ohio companies to meet. In July 2006, based on a staff report on service reliability and responses filed by the Ohio companies, the PUCO directed the Ohio companies to earmark $10 million for future measures to improve service reliability without recovery. The PUCO further indicated that it will determine where and how to expend the $10 million.

The Ohio companies implemented storm cost recovery riders effective with September 2006 billings, to recover a portion of previously expensed incremental costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. The riders will continue until they have collected the authorized amounts or one year, whichever is shorter.

As a result, at December 31, 2006 the Ohio companies have regulatory assets of $7 million for these costs.

Distribution Reliability Plan

In January 2006, the Ohio companies initiated a proceeding at the PUCO seeking a new distribution rate rider to fund enhanced distribution reliability programs. In the fourth quarter of 2006, as directed by the PUCO, the Ohio companies filed a proposed enhanced reliability plan. The plan contemplates recovering approximately $71 million in additional distribution revenue during an eighteen-month period beginning July 2007. A hearing is scheduled for April 2007. The OCC filed testimony, which argues that the Ohio companies should be required to improve their distribution service reliability with funds from their existing rates. Management is unable to predict the outcome of this proceeding.

Ormet

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load. The settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties was approved by the PUCO in November 2006. The settlement agreement provides for the recovery in 2007 and 2008 by the Ohio companies of the difference between $43 per MWH to be paid by Ormet for power and a market price, if higher. The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient, an increase in RSP generation rates under the additional 4% provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation services is above the industrial RSP generation tariff but below current market prices. In December 2006, the Ohio companies submitted a market price of $47.69 per MWH, which is pending PUCO approval.

Texas Rate Matters

TCC TEXAS RESTRUCTURING

TCC’s True-up Proceedings and 2002 Securitization

Texas Restructuring Legislation established customer choice on January 1, 2002 and allowed electric utility companies to file for recovery of securitizable stranded generation plant costs, generation-related regulatory assets and non-securitizable other restructuring true-up items. These recoverable and refundable items were recorded as true-up regulatory assets and liabilities.

In 2002, TCC securitized $797 million to recover most of its stranded generation related regulatory assets. TCC sold its generating units to establish its stranded costs and recorded an impairment loss, which resulted in an additional net true-up regulatory asset recoverable under the Texas Restructuring Legislation. Beginning in 2002, TCC also recorded wholesale capacity auction true-up revenues and debt-related carrying costs on its net true-up regulatory asset, as additional true-up regulatory assets. Unrecognized equity carrying costs of $224 million included in the net stranded generation cost to be securitized will be recognized, as collected through transition charge securitization revenues, over the fourteen-year term of the securitization bonds.

In December 2004, predominately based on a PUCT disallowance of a specific stranded cost item in other true-up proceedings, TCC reduced its true-up regulatory assets.

In February 2006, the PUCT issued an order in TCC’s True-up Proceeding, which determined that TCC’s recoverable net true-up regulatory asset, for both securitizable net stranded generation cost regulatory assets and net other true-up items regulatory liabilities, was $1.475 billion as of September 30, 2005. The order disallowed specific items which included, among other things, a significant portion of TCC’s wholesale capacity auction true-up revenues and a portion of TCC’s stranded costs determined from the sale of the ERCOT generating units. B ased on the PUCT’s order in December 2005, TCC reduced its true-up regulatory asset. The order also identified a reduction in the net recoverable amount, which represented the present value benefit of ADITC and EDFIT related to the plants sold. See “TCC’s 2006 CTC Proceeding” section below.

TCC will recover its PUCT-approved net true-up regulatory asset under the Texas Restructuring Legislation using two mechanisms: (a) by issuing securitization bonds in the amount of its net stranded generation costs and implementing a transition charge (TC) rate rider to collect the bond interest and principal over the term of the bonds and (b) by implementing a competition transition charge (CTC) rate rider credit to refund its net regulatory liability for other true-up items.  

TCC’s 2006 Securitization Proceeding

TCC filed an application in March 2006 requesting recovery through the issuance of securitization bonds of $1.804 billion of PUCT-approved securitizable net stranded generation costs plus subsequent carrying costs through August 31, 2006 and issuance costs. The securitization request excluded TCC’s net regulatory liability for other true-up items, which will be refunded to customers using a CTC rate rider. See the “TCC’s 2006 CTC Proceeding” section of this note. The PUCT approved a settlement in June 2006, which reduced the securitizable amount by $77 million and settled several issues and authorized the issuance of securitization bonds of $1.72 billion as of August 31, 2006. TCC issued securitization bonds on October 11, 2006 for $1.74 billion, which included additional issuance and carrying costs through October 11, 2006.

The securitization order provides for TCC to recover the securitization bond principal and related interest expense from customers over the fourteen-year term of the securitization bonds. Beginning in October 2006, the Securitized Transition Asset is amortized based on the ratio of annual transition revenues to total revenues over the fourteen-year TC collection period.

The June 2006 securitization order reduced the amount to be securitized and recovered by the present value of the ADITC and EDFIT benefit identified above in the April 2006 final true-up order. The securitization order also identified the present value cost-of-money benefit generated through the final year the securitization bonds will be outstanding (fourteen years) as an additional reduction. The present value cost-of-money benefit of $315 million resulted from the ADFIT related to the generation assets. However, rather than reducing the amount to be securitized, the PUCT ordered TCC to refund the ADFIT benefit through the CTC rate rider credit. See the “TCC’s 2006 CTC Proceeding” section below for further details.

TCC’s 2006 CTC Proceeding

In June 2006, TCC filed to refund, through a CTC rate rider credit, its net other true-up items and the ADFIT cost-of-money benefit less the present value benefit of ADITC and EDFIT, discussed above. An interim order required that the CTC refund begin in October 2006 pending a final CTC decision. The PUCT issued a final order in December 2006, which required that TCC refund $356 million of other true-up items and $19 million in estimated interest through the CTC over twenty-one months starting in October 2006. The ADFIT cost-of-money benefit of $315 million has a retrospective portion of $75 million which has been expensed and a prospective portion of $240 million which will be amortized to expense over the fourteen-year securitization bond term consistent with the period over which the cost-of-money benefit is generated and computed in the securitization order. The difference between the amount being refunded and the net other true-up regulatory liability of $219 million ($155 million at December 31, 2006) is predominantly due to the inclusion in the CTC refund of the $240 million unrecorded prospective portion of the ADFIT cost-of-money benefit less the $61 million present value benefit of ADITC and EDFIT applied to reduce the amount securitized above plus $42 million of interest through the date of securitization. The $103 million will be deferred pending a final determination of whether a normalization violation would occur. See “Other Texas Restructuring Matters” section below for further details.

TCC will accrue interest expense until its net CTC refund is completed. The interest expense on the net CTC amount is $22 million for the year ended December 31, 2006 and is included in Interest Expense on TCC’s 2006 Consolidated Statement of Income.

Impairment Assessment of Net True-up Regulatory Assets

TCC performed a probability of recovery impairment test on TCC’s recorded net true-up regulatory asset as of September 30, 2006, after receipt of the final securitization order, and again as of December 31, 2006 after receipt of the final CTC order. At both dates, TCC determined that the projected net cash flows from the securitization less the proposed CTC refund would provide more than sufficient net positive cash flows to recover TCC’s recorded net true-up regulatory asset. Accordingly, no impairment was recorded at either date.

At December 31, 2006, TCC’s Consolidated Balance Sheet reflects a securitization bond liability of $2.335 billion of which $595 million is from the initial 2002 securitization, a securitization transition asset of $2.158 billion of which $542 million is from the initial 2002 securitization, and a net true-up regulatory liability for other true-up items of $155 million as a result of the True-up Proceeding.

Texas District Court Appeal Proceedings

TCC appealed the PUCT orders seeking relief in both state and federal court on the grounds that the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. The significant items appealed by TCC are:

·	The PUCT ruling that TCC did not comply with the statute and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues,	
·	The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled out of the money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant cost, and	
·	The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation. See “ TCC and TNC Deferred Fuel” and “ TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections below.	

Municipal customers and other intervenors appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final true-up order with two significant exceptions. The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) method to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. However, the District Court did not rule that the carrying cost rate was inappropriate. He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future revenues.

In response to a request by TCC, the District Court judge will hear additional argument on March 22, 2007 regarding use of the ECOM method to value TCC’s nuclear plant stranded cost. TCC anticipates that the final judgment will be entered after that hearing. TCC intends to appeal any final adverse rulings of the District Court regarding these two matters along with certain of the judge’s other preliminary determinations that affirm the PUCT’s decisions. It is possible that the PUCT could also appeal any final adverse rulings regarding these two matters.

Although management cannot predict the ultimate outcome of these preliminary District Court determinations, any future remanded PUCT proceedings or any future court appeals, management concluded it is probable that the District Court’s preliminary ruling regarding the use of an ECOM method in lieu of a sales method to determine securitizable stranded cost will not be upheld on appeal. The judge has also determined in his letter ruling that if the sales method is permitted for valuing the nuclear plant, the PUCT improperly reduced stranded costs in connection with the sales process, which could have a materially favorable effect on TCC.

Management also concluded if the District Court’s preliminary carrying cost rate ruling is ultimately remanded to the PUCT for reconsideration, the PUCT could either confirm the existing carrying cost rate or redetermine the rate. If the PUCT changes the rate, it could result in a material adverse change to TCC’s recoverable carrying costs. However, management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

If the District Court judge’s original 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 at this time, but the amount could exceed TCC’s Common Shareholder’s Equity at December 31, 2006. If it were finally concluded that the ECOM method must be used to value TCC’s nuclear plant stranded cost, and/or that the PUCT’s rule on carrying costs was invalid, it could, after the PUCT remand decisions, have a substantial adverse impact on future results of operations, cash flows and financial condition.

If TCC ultimately succeeds in its appeals on other than the above two matters, it could have a favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, including their appeals of the two matters discussed above, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

OTHER TEXAS RESTRUCTURING MATTERS

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s true-up and securitization orders, the PUCT reduced net regulatory assets and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generation assets for a total reduction of $61 million.
 
TCC filed a request for a private letter ruling with the IRS in June 2005 regarding the permissibility under the IRS rules and regulations of the ADITC and EDFIT reduction proposed by the PUCT. The IRS issued its private letter ruling in May 2006, which stated that the PUCT’s flow-through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. To address the matter, the PUCT agreed to allow TCC to defer an amount of the CTC refund totaling $103 million ($61 million in present value of ADITC and EDFIT associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of the normalization issue.   It is anticipated that if the normalization issue is resolved consistent with the PUCT’s treatment, TCC will then refund $103 million plus additional carrying costs. If such refund is ultimately determined to cause a normalization violation, TCC anticipates it will be permitted to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impacting future results of operations.
 
If a normalization violation occurs, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, which approximates $104 million as of December 31, 2006, and a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows.
 
TCC and TNC Deferred Fuel

The TCC deferred fuel over-recovery regulatory liability is a component of the other true-up items net regulatory liability refunded through the CTC discussed above. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances. In its final fuel reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation of additional AEP System off-system sales margins under a FERC-approved SIA. Both TCC and TNC appealed the PUCT’s rulings regarding a number of issues in the fuel orders in state court and challenged the jurisdiction of the PUCT over the allocation of off-system sales margin allocations in the federal court. Intervenors also appealed the PUCT’s rulings in state court.
 
In 2006, the Federal District Court issued orders precluding the PUCT from enforcing the off-system sales allocation portion of its ruling in the final TNC and TCC fuel reconciliation proceedings. The Federal court ruled, in both cases, that the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed both Federal District Court decisions to the United States Court of Appeals. In TNC’s case, the Court of Appeals affirmed the District Court’s decision. We await a ruling in TCC’s appeal. If the PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of $16 million and $8 million, respectively, related to the reversal of the regulatory liabilities.

If the PUCT is unsuccessful in the federal court system, it or another interested party may file a complaint at the FERC to address the allocation issue. If a complaint at the FERC results in the PUCT’s decisions being adopted by the FERC, there could be an adverse effect on results of operations and cash flows. An unfavorable FERC ruling may result in a retroactive reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits. Although management cannot predict the ultimate outcome of this federal litigation, management believes that its allocations were in accordance with the then existing FERC-approved SIA.

In January 2007, TCC began refunding as part of the CTC rate rider credit described above, $149 million of its $165 million over-recovered deferred fuel regulatory liability. The remaining $16 million refund relating to the favorable Federal District Court order may be subject to being refunded only upon a successful appeal by the PUCT. See “TNC’s True-up Proceeding” section below for status of TNC’s over-recovered fuel refund.

Excess Earnings

In 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. To date, TCC refunded $55 million of excess earnings, including interest, of which $30 million went to the affiliated REP. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. If the Court of Appeals decision is upheld and the refund mechanism is found to be unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered by the PUCT to refund the excess earnings to ultimate customers and (b) whether it will be able to recover the amounts previously refunded to the REPs including the REP TCC sold to Centrica. Management is unable to predict the ultimate outcome of this litigation and its effect on future results of operations and cash flows.

TNC’s True-up Proceeding

TNC filed with the PUCT in August 2005 to establish a credit rider to refund its $21 million net true-up regulatory liability. In December 2005, that proceeding was suspended, pending a final ruling from TNC’s appeal to the federal court regarding the fuel proceeding (described above). In August 2006, the suspension was lifted and the proceeding resumed. The PUCT approved a settlement that recommended implementing a $13 million interim refund over six-months beginning in September 2006 of the net true-up regulatory liability, exclusive of the $8 million federal court fuel issue. TNC is accruing interest expense on the unrefunded balance and will continue to do so until the balance is fully refunded. TNC anticipates a final PUCT decision regarding this proceeding in 2007. The appeals to the state and federal courts are ongoing.

Texas Restructuring - SPP

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo’s and approximately 3% of TNC’s businesses were in SPP. We filed a petition in May 2006, requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) customers and TNC’s facilities and certificated service territory located in the SPP area to SWEPCo. In January 2007, we received our final regulatory approval for the transfers. The transfers were   effective February 2007. As required by the Arkansas Public Service Commission, SWEPCo will amend its fuel recovery tariff so that Arkansas customers do not pay the incremental cost of serving the additional load.

OTHER TEXAS RATE MATTERS

ERCOT PTB Fuel Factor Appeal

Several parties including the Office of Public Utility Counsel and the cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s respective former affiliated REPs). In 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued in 2005, the Texas Court of Appeals reversed the District Court. The cities appealed the decision to the Supreme Court of Texas, which ordered full briefing. In February 2007, the Supreme Court of Texas denied review. No motions for rehearing have been filed and management believes the matter is now final.

TCC and TNC Energy Delivery Base Rate Filings

TCC and TNC each filed a rate case for recovery of the cost of transmission and distribution energy delivery services (wires) in Texas. TCC and TNC requested $81 million and $25 million in annual increases, respectively. Both requests include a return on common equity of 11.25% and the impact of the expiration of the CSW merger savings rate credits. We expect the new base wires rates to become effective, subject to refund, in the second quarter of 2007 with a decision from the PUCT expected in the third quarter of 2007.

SWEPCo PUCT Staff Review of Earnings

In October 2005, the staff of the PUCT reported the results of its review of SWEPCo’s year end 2004 earnings. Based on the staff’s adjustments to the information submitted by SWEPCo, the report indicates that SWEPCo is receiving excess revenues of approximately $15 million. The staff engaged SWEPCo in discussions to reconcile the earnings calculation and to consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo in April 2006 that they would not pursue the matter further.  

SWEPCo Fuel Reconciliation - Texas

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations. SWEPCo sought, in the proceedings, to include underrecoveries related to the reconciliation period of $50 million. In January 2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced. The intervenor recommendations ranged from a $10 million to $28 million reduction. In February 2007, the PUCT staff filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million. SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed rebuttal testimony in February 2007. Management is unable to predict the outcome of this proceeding or its effect on future results of operations and cash flows.

Virginia Rate Matters  

Virginia Restructuring
 
In April 2004, the Governor of Virginia signed legislation that extended 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 bundled 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. Under the restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting. Also, under the restructuring law, APCo is deferring incremental environmental generation costs and incremental reliability costs for future recovery and is amortizing a portion of such deferrals commensurate with recovery. See the “APCo Virginia Environmental and Reliability Costs” section below for further details.
 
In February 2007, the Virginia legislature adopted amendments to its electric restructuring law. The amendments would shorten the transition period by two years (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. We are in the process of evaluating the impact of the legislation if it is signed into law.
 
APCo Virginia Environmental and Reliability Costs

The amended Virginia Electric Restructuring Act includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred on and after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 1, 2004 through September 30, 2005.

In November 2006, the Virginia SCC issued a final order that rejected the staff’s and the Hearing Examiner’s interpretation of the law, which would have resulted in the inability to record a regulatory asset and would have ultimately prevented APCo from recovering its full incremental E&R costs incurred since July 1, 2004. The order approved an increase in APCo’s rates to recover $21 million of incremental E&R costs previously incurred from July 1, 2004 through September 30, 2005 by means of a surcharge, effective December 1, 2006 through November 30, 2007. As a result, in the fourth quarter of 2006, APCo commenced recovery of the approved E&R rate rider and deferred as a regulatory asset, $60 million of incremental E&R costs incurred from July 1, 2004 through September 30, 2006 based on the Virginia SCC’s order and reversed $11 million of related AFUDC and capitalized interest, thereby increasing pre-tax earnings by $49 million. In addition, APCo has identified but not recognized $10 million of equity carrying costs on incremental E&R capital expenditures, which are not recognizable until collected. The order requires APCo to keep track, for true-up purposes, of base rate and surcharge recoveries of incremental E&R costs on a continuing basis to avoid any double recovery. During 2007 we will file for recovery of incremental E&R costs incurred from October 1, 2005 through September 30, 2006. The Virginia base rate case increase implemented October 2, 2006, subject to refund, is currently recovering an ongoing level of incremental E&R costs incurred since September 30, 2006 and as a result, we ceased deferring such costs incurred after that date.

APCo Virginia Base Rate Case

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%. In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to the fuel factor where they can be trued-up to actual. APCo also proposed to share the off-system sales margins with customers with 40% going to reduce rates and 60% being retained by APCo. This proposed off-system sales fuel rate credit, which is estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in base rate revenues of $198 million. The major components of the $225 million base rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity.

In May 2006, the Virginia SCC issued an order, consistent with Virginia law, placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund. The $198 million base rate increase being collected, subject to refund, includes recovery of incremental E&R costs projected to be incurred during the rate year beginning October 2006. These incremental E&R costs can be deferred and recovery sought through the E&R surcharge mechanism previously discussed if not recovered through base rates. In October 2006, the Virginia SCC staff filed their 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. Management reserved a portion of the revenue subject to refund that in its opinion is not probable of recovery. APCo filed rebuttal testimony in November 2006. Hearings were held in December 2006. APCo expects a ruling during 2007.  We are unable to predict the ultimate effect of this filing on future revenues, cash flows and financial condition.

West Virginia Rate Matters

APCo and WPCo West Virginia Rate Case

In July 2006, the WVPSC approved a settlement agreement reached by APCo and WPCo and the WVPSC staff and intervenors in connection with a West Virginia rate case filed in 2005. The settlement agreement provided for an initial overall increase in rates of $44 million effective July 28, 2006 comprised of:

·	A $56 million increase in Expanded Net Energy Cost (ENEC) for fuel, purchased power expenses, off- system sales credits and other energy-related costs (the ENEC is an expanded form of a fuel clause mechanism which includes all energy-related costs);	
·	A $23 million special construction surcharge providing recovery of the costs of scrubbers and the new Wyoming-Jacksons Ferry 765 kV line to date;	
·	An $18 million general base rate reduction resulting predominantly from a reduction in the return on equity to 10.5% and a $9 million reduction in depreciation expense which affects cash flows but not earnings; and	
·	A $17 million credit to refund a portion of deferred prior over-recoveries of ENEC of $51 million, recorded in regulatory liabilities on the Consolidated Balance Sheets, which will impact cash flows but not earnings.	

In addition, the agreement provided a mechanism that allows APCo and WPCo to adjust their special construction surcharges annually for the timely recovery in each of the next three years of the incremental cost of ongoing environmental investments in scrubbers at APCo’s Mountaineer and John Amos power plants and the costs of the new Wyoming-Jacksons Ferry 765 kV line. APCo and WPCo plan to file in March 2007 with the WVPSC for the first adjustment to their special construction surcharge, providing an incremental annual increase of $29 million to be effective July 1, 2007. APCo estimates annual increases in revenues of $14 million effective July 1, 2008 and $18 million effective July 1, 2009, subject to review by the WVPSC.

Under the settlement, the ENEC mechanism was reinstated effective July 1, 2006 with over/under recovery deferral accounting and annual ENEC proceedings to affect annual rate adjustments for changes in fuel, purchased power costs, off-system sales margins and other energy-related costs beginning in 2007. The settlement provides for the return to customers of the remaining $34 million of the prior ENEC regulatory liability plus interest at a LIBOR rate (London Interbank Offered Rate) on the unrefunded balance in future ENEC proceedings.

APCo IGCC

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer generating station in Mason County, WV. In January 2007, the WVPSC issued an order delaying the Commission’s deadline for issuing an order on the certificate to December 3, 2007. The order also cancels a previously-approved procedural schedule. Through December 31, 2006, APCo deferred pre-construction IGCC costs totaling $10 million.
 
Indiana Rate Matters

I&M Depreciation Study Filing

In December 2005, I&M filed a petition with the IURC seeking authorization to revise its book depreciation rates applicable to its electric utility plant in service effective January 1, 2006. An order issued by the IURC in October 2006 did not dispute our revised depreciation accounting rates but, nevertheless, denied I&M’s request to revise its book depreciation rates between base rate cases. In November 2006, I&M filed with the IURC a petition for reconsideration of the October order as well as a notice of appeal to the Indiana Court of Appeals. In January 2007, the IURC denied I&M’s petition for reconsideration.
 
In February 2007, I&M withdrew its appeal of the IURC order and filed a new request with the IURC for approval of the revised book depreciation rates effective January 1, 2007. The filing included a settlement agreement entered into with the Indiana Office of the Utility Consumer Counselor that would provide direct benefits to I&M's customers if new depreciation rates are approved by the IURC. The direct benefits would include a $5 million credit in fuel costs, an approximate $8 million smart metering pilot program. In addition, if the agreement is approved, I&M would initiate a general rate proceeding on or before July 1, 2007 and initiate two studies, one to investigate a general smart metering program and the other to study the market viability of demand side management programs.  Based on the depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. As proposed the book depreciation reduction would increase earnings but would not impact cash flows until rates are revised. I&M requested expeditious review and approval of its filing, but management cannot predict the outcome of the request.  

Kentucky Rate Matters

KPCo Rate Filing

In March 2006, the KPSC approved a settlement agreement in KPCo’s 2005 base rate case. The approved agreement provided for a $41 million annual increase in revenues effective March 30, 2006 and the retention of the existing environmental surcharge tariff. No return on equity was specified by the settlement terms except to note that KPCo will use a 10.5% return on equity to calculate the environmental surcharge tariff and AFUDC.

KPCo Environmental Surcharge Filing

In July 2006, KPCo filed for approval of an amended environmental compliance plan and revised tariff to implement an adjusted environmental surcharge. KPCo requested recovery of approximately $2 million of additional revenue in 2007 and an additional $6 million in 2008 for a total of $8 million of additional revenue. In January 2007, the KPSC issued an order approving KPCo’s proposed plan and surcharge.

In November 2006, the Kentucky attorney general and the Kentucky Industrial Utility Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental Surcharge order. In its order, the KPSC approved KPCo’s recovery of its environmental costs at its Big Sandy Plant and its share of environmental costs it incurs as a result of the AEP Power Pool capacity settlement. The KPSC allowed KPCo to recover these FERC-approved allocated costs, via the environmental surcharge, since the KPSC’s first order in the environmental surcharge case in 1997. KPCo presently recovers $7 million a year in environmental surcharge revenues. At this time, management is unable to predict the outcome of this proceeding and its effect on KPCo’s current environmental surcharge revenues or on the January 2007 KPSC order increasing KPCo’s environmental rates.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP West companies

In 2002, PSO under-recovered $44 million 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 proposed collection of those reallocated costs over eighteen months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with their proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from their recommendation.
 
In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. The United States District Court for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling. The United States Court of Appeals for the Fifth Circuit, issued a decision in December 2006 regarding the TNC fuel proceeding that affirmed the United States District Court ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals other than the staff’s original recommendation that PSO be allowed to recover the $42 million over three years and will defend its position. We believe that if the position taken by the federal courts in the Texas proceeding is applied to PSO’s case, then the OCC should be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party could file a complaint at the FERC alleging the allocation of off-system sales margins adopted by PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies.

In June 2005, the OCC issued an order directing its staff to conduct a prudence review of PSO’s fuel and purchased power practices for the year 2003. The OCC staff filed testimony finding no disallowances in the test year data. The Attorney General of Oklahoma filed testimony stating that they could not determine if PSO’s gas procurement activities were prudent, but did not include a recommended disallowance. However, an intervenor filed testimony in June 2006 proposing the disallowance of $22 million in fuel costs based on a historical review of potential hedging opportunities that he alleges existed during the year. A hearing was held in August 2006 and we expect a recommendation from the ALJ in 2007.  

In February 2006, a law was enacted requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served. PSO is subject to the required biennial reviews. In compliance with an OCC order, PSO is required to file its testimony by June 15, 2007. This proceeding will cover the year 2005.

Management cannot predict the outcome of the pending fuel and purchase power reviews or planned future reviews, but believes that PSO’s fuel and purchased power procurement practices and costs are prudent and properly incurred. If the OCC disagrees and disallows fuel or purchased power costs including the unrecovered 2002 reallocation of such costs incurred by PSO, it would have an adverse effect on future results of operations and cash flows.

PSO Rate Filing

In November 2006, PSO filed a request to increase base rates $50 million for Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007. PSO sought a return on equity of 11.75%. PSO also proposed a formula rate plan that, if approved as filed, will permit PSO to defer any unrecovered costs as a result of a revenue deficiency that exceeds 50 basis points of the allowed return on equity for recovery within twelve-months beginning six months after the test year. The formula would enable PSO to recover on a timely basis the cost of its new generation, transmission and distribution construction (including carrying costs during construction), provide the opportunity to achieve the approved return on equity and avoid recording a large amount of AFUDC that would have been recorded during the construction time period. Hearings are scheduled to begin in May, 2007.

Louisiana Rate Matters

SWEPCo Louisiana Fuel Inquiry

In March 2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into SWEPCo’s fuel and purchased power procurement activities during the period January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s report, which concluded that SWEPCo’s activities were appropriate and did not identify any disallowances or areas for improvement.

SWEPCo Louisiana Compliance Filing

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed updated 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, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, based on a proposed 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain ongoing operations and maintenance expense levels. SWEPCo filed rebuttal testimony in October 2006 strongly 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 will file testimony in the first quarter of 2007. Hearings are expected to occur in early 2007. A decision is not expected until mid or late 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ultimately ordered, it would adversely impact future results of operations and cash flows.

Michigan Rate Matters

Michigan Restructuring

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Effective on that date, the rates on I&M’s Michigan customers’ bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M’s total base rates in Michigan remain unchanged and reflect cost of service. As of December 31, 2006, none of I&M’s customers elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory. As a result, management concluded that as of December 31, 2006, the requirements to apply SFAS 71 continue to be met since I&M’s rates for generation in Michigan continue to be cost-based regulated.

FERC Rate Matters

RTO Formation/Integration Costs

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. As of December 31, 2006 and 2005, the AEP East companies deferred $29 million and $31 million, respectively, of unamortized RTO and PJM formation/integration costs.

In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs and related carrying costs not billed by PJM in monthly charges from November 1, 2005 through May 31, 2020. The rate, the result of a settlement, will be adjusted each year to collect $2 million on an annualized basis for 175 months. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is approximately 85% of the transmission load in the AEP zone. As a result, the AEP East companies will need to recover the 85% through their retail rates.

In May 2006, the FERC approved a settlement that provides for recovery over a ten-year period of the deferred PJM-billed integration costs, including related carrying charges, of AEP, Commonwealth Edison Company (ComEd) and the Dayton Power and Light Company from all present zones of the PJM region, except the Virginia Electric & Power Company (VEPCo) zone. The net result of the settlement is that the AEP East companies will recover approximately 50% of the deferred PJM-billed integration costs from third parties, and will need to recover the remaining 50% through retail rates.

As a result of recently approved rate increases, CSPCo, OPCo, KPCo and APCo recover the amortization of RTO formation/integration costs billed to the AEP East companies in Ohio, Kentucky, Virginia (subject to refund) and West Virginia. In Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded from recovering its share of the deferred RTO costs until that date or until it can file for a rate increase in Indiana. I&M has not yet filed for recovery in Michigan.

If the Virginia, Indiana or Michigan commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs, it could result in a write-off of up to 25% of the total remaining deferred balance, adversely impacting future results of operations and cash flows. In the event of a disallowance, we would appeal that decision to the appropriate state or federal courts.

Transmission Rate Proceedings at the FERC

SECA Revenue Subject to Refund

We eliminated through-and-out transmission service (T&O) revenues in accordance with FERC orders, and collected SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, we would also receive refunds related to the SECA rates we paid to third parties. The AEP East companies recognized gross SECA revenues as follows:
 	 	Gross SECA Revenues Recognized	 	
 	 	(in millions)	 	
Year Ended December 31, 2006 (a)	 	$	43	 	
Year Ended December 31, 2005	 	 	163	 	
Year Ended December 31, 2004	 	 	14	 	

(a)	Represents revenues through March 31, 2006, when SECA rates expired, and excludes all provisions for refund .	

Approximately $19 million of these recorded SECA revenues billed by PJM were never collected. The AEP East companies filed a motion with the FERC to force payment of these SECA billings.

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 was 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 the unpaid SECA rates must be paid in the recommended reduced amount.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund. The AEP East companies reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. It would also provide insignificant refunds of SECA rates paid by the AEP East companies. Based on the completed settlements and before the issuance of the ALJ’s initial decision, the AEP East companies initially provided a reserve for $22 million in net refunds.

We, together with Exelon and DP&L, filed an extensive post-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. We believe that the FERC should reject the initial decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, we believe the ALJ’s findings on key issues are largely without merit. However, the initial decision is adversely impacting settlement negotiations. As a consequence we recorded an additional $15 million reserve in December 2006 . Although we believe we have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.

The FERC PJM Regional Transmission Rate Proceeding

At our urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway.

Parties to the regional rate proceeding proposed the following rate regimes:

·	AEP/AP proposed a Highway/Byway rate design in which:	
 	·	The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.	
 	·	The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.	
·	Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues for AEP than the AEP/AP proposal.	
·	In a competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues for AEP than the AEP/AP proposal.	
·	In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues for AEP than the AEP/AP proposal.	

All of these proposals were challenged by a majority of other transmission owners in the PJM region, who favor continuation of the existing PJM rate design. Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006. The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced. The ALJ found that the Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp rate proposed by the FERC staff to be just and reasonable alternatives and recommended that the FERC staff’s Postage Stamp rate proposal be adopted. The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination. Because the Postage Stamp rate was found to produce greater cost shifts than other proposals, the judge also recommended that the design be phased-in. Without a phase-in, the Postage Stamp method would produce more revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates would delay the full impact of that result until about 2012.

We filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. We argued that a phase-in should not be required. Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and a phase-in plan, the revenue collections curtailed by the phase-in should be deferred and paid later with interest. A FERC decision is likely before mid-2007.

To recover these lost T&O and SECA rates, we sought to increase our retail rates in most of our states. The status of such state retail rate proceedings is as follows:

·	In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.	
·	In Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.	
·	In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.	
·	In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.	
·	In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.	
·	In Michigan, I&M has not filed to seek recovery of the lost transmission revenues.	

We presently recover from retail customers approximately 85% of the reduction in transmission revenues of $128 million a year.

Once approved by the FERC, the favorable impacts of the new regional PJM rate design will flow directly to wholesale customers and to retail customers in West Virginia through the ENEC and to retail customers in Ohio upon PUCO approval of a filing we would make to reflect the new rates in the Transmission Cost Recovery Rider. In Kentucky, Indiana, Virginia and Michigan, the additional transmission revenues can be expected to reduce retail rates in future base rate proceedings.

Management is unable to predict whether the FERC will approve either the ALJ’s decision or another regional rate design. We believe that the AEP/AP proposal or the Postage Stamp proposal combined with the retail rate recovery discussed above would be an effective replacement for the eliminated T&O and SECA rates. Future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues. The resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates on a timely basis especially in Indiana, where there is a rate freeze until June 30, 2007, and Michigan.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement which allowed increases in our wholesale transmission OATT rates in three steps: first, beginning retroactively on November 1, 2005, second, beginning on April 1, 2006 when the SECA revenues were eliminated and third, beginning on August 1, 2006 when the new Wyoming-Jacksons Ferry 765 kV line went into service. Wholesale transmission revenues increased approximately $23 million in 2006 due to this rate increase. We estimate that this rate increase will increase wholesale transmission revenues by $35 million in 2007.

Calpine Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From SPP

In April 2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate schedule to charge SPP for reactive power from Calpine’s generating facility. The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCo and, until February 2007, a small portion of TNC operated in SPP. In September 2006, the FERC issued an order reversing an ALJ initial decision, granting Calpine’s request and requiring Calpine to make a compliance filing within 30 days. Our share of this SPP expense could be approximately 90% of the total amount billed by Calpine. Based on this information, in 2006 we recorded a provision, including interest, of $9 million for the retroactive reactive power liability. We requested rehearing at the FERC.

Calpine issued invoices to AEP for service and interest charges from June 2003 through December 2006 totaling $10 million. We objected to these invoices, in part, on the basis that Calpine seeks to collect its entire revenue requirement from us, leaving us with the risk of collecting the portion that may be owed by other service providers in the AEP zone of SPP. Meanwhile, in December 2006, SPP filed a new rate schedule. If the new rate schedule is approved, it will be generally applicable throughout SPP for reactive power service. If the FERC accepts the new rate, on a going forward basis from March 2007, we will owe an immaterial amount to Calpine for its reactive power production capability. The new tariff compensates generators for the reactive service they actually provide rather than the capability they possess.

Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved our proposed methodology effective April 1, 2006 and beyond. The approved allocation methodology for the AEP East companies and AEP West companies is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies, which effectively allowed the AEP West companies to share in PJM and MISO regional margins in the East. In February 2006, we filed with the FERC to remove TCC and TNC from the SIA and CSW Operating Agreement because they are in the final stages of exiting the generation business and have already ceased serving retail load. The FERC approved the removal of TCC and TNC from the SIA effective April 1, 2006 and CSW Operating Agreement effective May 1, 2006.

Our total trading and marketing margins are unaffected by the allocation methodology. The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of expanded net energy fuel clause recovery mechanisms and related off-system sales sharing mechanisms by state. However, the new allocation method is expected to increase the net system sales margins allocated to the AEP East companies, who flow considerably less of these margins through expanded fuel clause mechanisms and more in base rates than do the AEP West companies. As a result, the change in allocation methods should tend to increase future results of operations and cash flows.

5      5.   EFFECTS OF REGULATION  

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:
 	 	December 31,	 	 	 	
 	 	2006	 	2005	 	Notes	 	
 	 	(in millions)	 	 	 	
Regulatory Assets:	 	  	 	  	 	 	 	
 	 	  	 	  	 	 	 	
Current Regulatory Asset -  Under-recovered Fuel Costs	 	$	38	 	$	197	 	 	(c) (j)	 	
 	 	 	 	 	 	 	 	 	 	 	
SFAS 158 Regulatory Asset (Notes 2 and 9)	 	$	875	 	$	-	 	 	(a)	 	
SFAS 109 Regulatory Asset, Net (Note 13)	 	 	771	 	 	785	 	 	(c) (i)	 	
Transition Regulatory Assets - Ohio and Virginia (Note 4)	 	 	185	 	 	306	 	 	(a) (k)	 	
Designated for Securitization - Texas	 	 	-	 	 	1,436	 	 	(d)	 	
Unamortized Loss on Reacquired Debt	 	 	105	 	 	110	 	 	(b) (l)	 	
Unrealized Loss on Forward Commitments	 	 	89	 	 	92	 	 	(a) (i)	 	
Texas Wholesale Capacity Auction True-up (Note 4)	 	 	-	 	 	77	 	 	(e)	 	
Refunded Excess Earnings (Note 4)	 	 	56	 	 	55	 	 	(n)	 	
Cook Nuclear Plant Refueling Outage Levelization	 	 	47	 	 	23	 	 	(a) (f)	 	
Other	 	 	349	 	 	378	 	 	(c) (i)	 	
Total Noncurrent Regulatory Assets	 	$	2,477	 	$	3,262	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
Current Regulatory Liability -  Over-recovered Fuel Costs (o)	 	$	37	 	$	3	 	 	(c) (j)	 	
 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities and Deferred Investment Tax Credits:	 	 	 	 	 	 	 	 	 	 	
Asset Removal Costs	 	$	1,610	 	$	1,437	 	 	(g)	 	
Deferred Investment Tax Credits	 	 	332	 	 	361	 	 	(c) (m)	 	
Excess ARO for Nuclear Decommissioning Liability (Note 10)	 	 	323	 	 	271	 	 	(h)	 	
Unrealized Gain on Forward Commitments	 	 	181	 	 	168	 	 	(a) (i)	 	
TCC CTC Refund	 	 	155	 	 	238	 	 	(e)	 	
Other	 	 	309	 	 	272	 	 	(c) (i)	 	
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	 	$	2,910	 	$	2,747	 	 	 	 	

(a)	Does not earn a return.	
(b)	Amount effectively earns a return.	
(c)	Includes items both earning and not earning a return.	
(d)	Amount includes a carrying cost and was included in TCC’s True-up Proceeding and securitized in October 2006. The cost of the securitization bonds will be recovered over a 14 year period. Amount is included within Securitized Transition Assets on the Consolidated Balance Sheet for 2006. See “TCC Texas Restructuring” section of Note 4.	
(e)	Net amounts were ordered to be refunded through the CTC. TCC’s net refund began on an interim basis in October 2006. In a final order issued December 2006, the PUCT set the final net refund to be completed by June 2008. CTC refunds for TCC accrue interest until the refunds are completed. See “TCC’s 2006 CTC Proceeding” section of Note 4.	
(f)	Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.	
(g)	The liability for removal costs, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.	
(h)	This is the cumulative difference in the amount provided through rates and the amount as measured by applying SFAS 143. This amount earns a return, accrues monthly, and will be paid when the nuclear plant is decommissioned.	
(i)	Recovery/refund period - various periods.	
(j)	Recovery/refund period - 1 year.	
(k)	Recovery/refund period - up to 4 years.	
(l)	Recovery/refund period - up to 37 years.	
(m)	Recovery/refund period - up to 56 years.	
(n)	Recovery method and timing to be determined in future proceeding.	
(o)	Current Regulatory Liability - Over-recovered Fuel Costs are recorded in Other on our Consolidated Balance Sheets.	

Merger with CSW

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. The following table summarizes significant merger-related agreements:

Summary of key provisions of Merger Rate Agreements beginning in the third quarter of 2000:

State/Company	 	Ratemaking Provisions	
Texas - SWEPCo, TCC, TNC	 	Rate reduction of $221 million over 6 years. In 2006, TCC and TNC requested to have these rate reductions eliminated. See “TCC and TNC Energy Delivery Base Rate Filings” section of Note 4.	
Indiana - I&M	 	Rate reduction of $67 million over 8 years.	
Michigan - I&M	 	Customer billing credits of approximately $14 million over 8 years.	
Kentucky - KPCo	 	Rate reductions of approximately $28 million over 8 years.	
Louisiana - SWEPCo	 	Rate reductions to share merger savings estimated to be $18 million over 8 years.	

         6.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements.

Insurance and Potential Losses

We maintain insurance coverage normal and customary for an integrated electric utility, subject to various deductibles. Our insurance includes coverage for all risks of physical loss or damage to our nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. Our insurance programs also generally provide coverage against loss arising from third parties and are in excess of retentions absorbed by us. Coverage is generally provided by a combination of a South Carolina domiciled protected-cell captive insurance company together with and/or in addition to various industry mutual and commercial insurance carriers and various Lloyds of London syndicates.

See Note 10 for a discussion of nuclear exposures and related insurance.

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, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on our results of operations, cash flows and financial condition.

COMMITMENTS

The AEP System has substantial construction commitments to support its operations and environmental investments. Aggregate construction expenditures for 2007 for consolidated operations are estimated at   approximately $3.5 billion plus $427 million of announced purchases of gas-fired generating units. 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, weather, legal reviews and the ability to access capital.

Our subsidiaries enter into long-term contracts to acquire fuel for electric generation. The longest contract extends to the year 2029. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain conditions.

Our subsidiaries purchase materials, supplies, services and property, plant and equipment under contract as part of their normal course of business. Certain supply contracts contain penalty provisions for early termination. We do not expect to incur penalty payments under these provisions that would materially affect our results of operations, cash flows or financial condition.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters Of Credit

We enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. As the parent company, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries. At December 31, 2006, the maximum future payments for all the LOCs are approximately $26 million with maturities ranging from March 2007 to November 2007.

Guarantees Of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of December 31, 2006, SWEPCo has collected approximately $29 million through a rider for final mine closure costs, of which approximately $12 million is recorded in Deferred Credits and Other and approximately $17 million is recorded in Asset Retirement Obligations on our Consolidated Balance Sheets.

SWEPCo is the only customer of Sabine and Sabine charges SWEPCo all its costs which are included in the cost of fuel and passed through SWEPCo’s fuel clause.

Indemnifications And Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. The status of certain sales agreements is discussed in the “Dispositions” section of Note 8. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $2.2 billion (approximately $1 billion relates to the BOA litigation, see “Enron Bankruptcy” section of this note). There are no material liabilities recorded for any indemnifications.

Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2006, the maximum potential loss for these lease agreements was approximately $56 million ($36 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

See Note 14 for disclosure of other lease residual value guarantees.

CONTINGENCIES

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states allege that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The alleged modifications occurred at our generating units over a twenty-year period. A bench trial on the liability issues was held during July 2005. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to routine maintenance, replacement of degraded equipment or failed component or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

Cases are pending that could affect CSPCo’s share of jointly-owned units at Beckjord, Zimmer, and Stuart Stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. The Federal EPA also proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded from NSR.

We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices of electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect our future results of operations, cash flows and possibly financial condition.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a response to the complaint in May 2005. A trial in this matter is scheduled for the second quarter of 2007.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit.

We are unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on our results of operations, cash flows or financial condition.

Carbon Dioxide (CO 2 ) Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO 2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The defendants’ motion to dismiss the lawsuits was granted in September 2005. The dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded. We believe the actions are without merit and intend to defend against the claims.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials. We currently incur costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances at disposal sites. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. At December 31, 2006, our subsidiaries are named by the Federal EPA as a Potentially Responsible Party (PRP) for five sites. There are nine additional sites for which our subsidiaries have received information requests which could lead to PRP designation. Our subsidiaries have also been named potentially liable at two sites under state law. In those instances where we have been named a PRP or defendant, our disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on results of operations.

We evaluated the potential liability for each Superfund site separately, but several general statements can be made regarding our potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. If significant cleanup costs were attributed to our subsidiaries in the future under Superfund, our results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be included in our electricity prices.

Plaquemine Cogeneration Facility

Juniper Capital L.P. (Juniper) constructed and financed our ownership interest in the Plaquemine Cogeneration Facility (the Facility) near Plaquemine, Louisiana and leased the Facility to us. We subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

In August 2006, we reached an agreement with Dow to sell the Facility to them and recorded a pretax impairment of $209 million (see “Dispositions” section of Note 8). The sale closed in November 2006. Upon closing, we repaid our recorded $525 million lease financing obligation, which was included in Long-term Debt on our Consolidated Balance Sheets at December 31, 2005.

Prior to the sale, Dow used a portion of the energy produced by the Facility and sold the excess energy. OPCo agreed to purchase up to approximately 800 MW of such excess energy from Dow for a twenty-year term. OPCo sold the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market until the sale of the Facility. With the sale of the Facility, OPCo terminated its purchase agreement with Dow.

TEM Litigation

OPCo agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA). Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We alleged that TEM breached the PPA, and we sought a determination of our rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of AEP’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In August 2005, a federal judge ruled that TEM had breached the contract and awarded us damages of $123 million plus prejudgment interest. Any eventual proceeds will be recorded as a gain when received.

In September 2005, TEM posted a $142 million letter of credit as security pending appeal of the judgment. Both parties filed Notices of Appeal with the United States Court of Appeals for the Second Circuit, which heard oral argument on the appeals in December 2006. We cannot predict the ultimate outcome of this proceeding.

Enron Bankruptcy

In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain of our subsidiaries had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - Right to use of cushion gas agreements - 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 billion cubic feet (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 (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, 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, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. In 2002, the BOA Syndicate filed a lawsuit against HPL in Texas state court seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage facility. In 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In August 2006, the Court of Appeals for the First District of Texas vacated the trial court’s judgment and dismissed the BOA Syndicate’s case. The BOA Syndicate did not seek review of this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL’s motion to have the case assigned to the judge who heard the case originally was granted. HPL intends to defend against any renewed claims by BOA.

In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage facility to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel facility and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA objected to the Magistrate Judge’s decision. In April 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York. HPL and BOA filed motions for summary judgment in the case pending in the Southern District of New York. The case in federal court in Texas is set for trial beginning April 2007.
 
In February 2007, the Judge in the New York action, after hearing oral argument on the motions for summary judgment, made a series of oral “informal findings” and submitted a written memorandum to the parties’ counsel. In the memorandum to counsel, the Judge stated that he was denying several of AEP’s motions for partial summary judgment, granting several of BOA motions for summary judgment and denying others. The substantive matters left open for further proceedings include the issue of the nature of the gas subject to BOA security interest and the value of that interest. The Judge stated that the memorandum to counsel is not an opinion or an order, and that no opinion or order will be issued until all motions pending before the Court have been decided. At this time we are unable to predict how the Judge will rule on the pending motions due to the complexity of those issues and the parties’ disagreement over each issue. If the Judge issues a judgment directing AEP to pay an amount in excess of the gain on the sale of HPL described below and if AEP is unsuccessful in having the judgment reversed or modified, the judgment could have a material adverse effect on the results of operations and cash flow.
 
In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. We objected to Enron’s attempted rejection of these agreements and filed an adversary proceeding contesting Enron’s right to reject these agreements.

In 2005, we sold our interest in HPL. We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price. The determination of the gain on sale and the recognition of the gain are dependent on the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter.

Enron Bankruptcy - Commodity trading settlement disputes - In 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas-related trading transactions. We asserted our right to offset trading payables owed to various Enron entities against trading receivables due to several of our subsidiaries. In 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim sought to unwind the effects of the transaction. In 2005, the parties reached a settlement resulting in a pretax cost of approximately $46 million.

Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy was based on an analysis of contracts where AEP and Enron entities were counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities, the settlement agreement and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, there is a dispute regarding the cushion gas agreement. Although management is unable to predict the outcome of the remaining lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.

Shareholder Lawsuits

In 2002 and 2003, three putative class action lawsuits were filed against AEP, certain executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions were pending in federal District Court, Columbus, Ohio. In these actions, the plaintiffs sought recovery of an unstated amount of compensatory damages, attorney fees and costs. In July 2006, the Court entered judgment denying plaintiff’s motion for class certification and dismissing all claims without prejudice. In August 2006, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Sixth Circuit. Briefing of this appeal was completed in December 2006 and the parties await the scheduling of oral argument. We intend to continue to defend against these claims.

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were filed in California. In addition, a number of other cases were filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. In some of these cases, AEP (or a subsidiary) is among the companies named as defendants. These cases are at various pre-trial stages. Several of these cases were transferred to the United States District Court for the District of Nevada but subsequently were remanded to California state court. In 2005, the judge in Nevada dismissed three of the remaining cases (AEP was a defendant in one of these cases), on the basis of the filed rate doctrine. Plaintiffs in these cases appealed the decisions. We will continue to defend each case where an AEP company is a defendant.

Cornerstone Lawsuit

In 2003, Cornerstone Propane Partners filed an action in the United States District Court for the Southern District of New York against forty companies, including AEP and AEPES, seeking class certification and alleging unspecified damages from claimed price manipulation of natural gas futures and options on the NYMEX from January 2000 through December 2002. Thereafter, two similar actions were filed against a number of companies, including AEP and AEPES, making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. These cases were consolidated. In December 2006, we agreed to settle all claims with the plaintiffs without material impact on our results of operations or financial condition.

Energy Market Investigation

AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission (CFTC), the U.S. Department of Justice and the California attorney general during 2002. In 2003, the CFTC filed a complaint against AEP and AEPES in federal District Court. The CFTC alleged that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. In January 2005, we reached settlement agreements totaling $81 million with the CFTC, the U.S. Department of Justice and the FERC regarding investigations of past gas price reporting and gas storage activities. Our settlements did not admit nor should they be construed as an admission of violation of any applicable regulation or law. We made settlement payments to the agencies in 2005 in accordance with the respective contractual terms. The agencies’ investigations and the CFTC litigation ended. During 2004, we provided for the settlements payment in the amount of $36 million (nondeductible for federal income tax purposes). There was no impact on 2006 or 2005 results of operations as a result of the settlements.

FERC Long-term Contracts

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that we sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered as the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the complaint, held that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required that changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. In December 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows. We have asserted claims against certain companies that sold power to us, which we resold to the Nevada utilities, seeking to recover a portion of any amounts we may owe to the Nevada utilities.

        7.   COMPANY-WIDE STAFFING AND BUDGET REVIEW

As a result of a 2005 company-wide staffing and budget review, we identified approximately 500 positions for elimination. We recorded pretax severance benefits expense of $28 million, which is primarily reflected in Other Operation and Maintenance on our 2005 Consolidated Statement of Income. Approximately 95% of the expense was within the Utility Operations segment. The following table shows the total 2005 expense recorded and the activity during 2005 and 2006, which eliminated the accrual as of June 30, 2006:

 	 	Amount
(in millions)	 	
Total Expense	 	$	28	 	
Less: Total Payments	 	 	16	 	
Accrual at December 31, 2005	 	 	12	 	
Less: Total Payments	 	 	8	 	
Less: Accrual Adjustments	 	 	4	 	
Accrual at December 31, 2006	 	$	-	 	

The December 31, 2005 accrual was primarily reflected in Current Liabilities - Other on our Consolidated Balance Sheets. The favorable accrual adjustments were recorded primarily in Other Operation and Maintenance on our Consolidated Statements of Income.
 
        8.   ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS, IMPAIRMENTS AND ASSETS HELD FOR SALE

ACQUISITIONS

Acquisitions Anticipated Being Completed During the First Half of 2007

Darby Electric Generating Station (Utility Operations segment)

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the first half of 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.
 
Lawrenceburg Generating Station (Utility Operations segment)

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the second quarter of 2007. The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW.

2006

None

2005

Waterford Plant (Utility Operations segment)

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC, a subsidiary of PSEG, for the purchase of the Waterford Plant in Waterford, Ohio. The Waterford Plant is a natural gas, combined cycle power plant with a generating capacity of 821 MW. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million.

Monongahela Power Company (Utility Operations segment)

In June 2005, the PUCO ordered CSPCo to explore the purchase of the Ohio service territory of Monongahela Power Company (Monongahela Power), which includes approximately 29,000 customers. In August 2005, we agreed to terms of a transaction, which included the transfer of Monongahela Power’s Ohio customer base and the assets, at net book value, that serve those customers to CSPCo. This transaction was completed in December 2005 for approximately $46 million and the assumption of liabilities of approximately $2 million. In addition, CSPCo paid $10 million to compensate Monongahela Power for its termination of certain litigation in Ohio. Therefore, beginning January 1, 2006, CSPCo began serving customers in this additional portion of its service territory. CSPCo’s $10 million payment was recorded as a regulatory asset and will be recovered with a carrying cost from all of CSPCo’s customers over approximately 5 years. Also included in the transaction was a power purchase agreement under which Allegheny Power, Monongahela Power’s parent company, will provide the power requirements of the acquired customers through May 31, 2007.

Ceredo Generating Station (Utility Operations segment)

In August 2005, APCo signed a purchase and sale agreement with Reliant Energy for the purchase of the Ceredo Generating Station located near Ceredo, West Virginia. The Ceredo Generating Station is a natural gas, simple cycle power plant with a generating capacity of 505 MW. This transaction was completed in December 2005 for $100 million.

2004

None

DISPOSITIONS

2006

Compresion Bajio S de R.L. de C.V. (All Other)

In January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. de C.V. (Bajio), a 600 MW power plant in Mexico. We received an indicative offer for Bajio in September 2005, which resulted in a pretax other-than-temporary impairment charge of approximately $7 million. The impairment amount is classified in Investment Value Losses on our 2005 Consolidated Statement of Income. We completed the sale in February 2006 for approximately $29 million with no effect on our 2006 results of operations.

Plaquemine Cogeneration Facility (All Other)

In August 2006, we reached an agreement to sell our Plaquemine Cogeneration Facility (the Facility) to Dow Chemical Company (Dow) for $64 million. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on the terms of the agreement to sell the Facility to Dow. We recorded the impairment in Asset Impairments and Other Related Charges on our 2006 Consolidated Statement of Income. The Facility does not meet the criteria for discontinued operations reporting.

We completed the sale in the fourth quarter of 2006. Excluding the 2006 impairment of $209 million discussed above, the effect of the sale on our 2006 results of operations was not significant. In addition to the cash proceeds, the sale agreement allows us to participate in gross margin sharing on the Facility for five years. As a result of the sale, Dow reduced an existing below-current-market long-term power supply contract with us in Texas by 50 MW and we retained the right to any judgment paid by TEM for breaching the original Power Purchase and Sale Agreement. See “TEM Litigation” section of Note 6.

Intercontinental Exchange, Inc. (ICE) Initial Public Offering (All Other)

See the following 2005 disclosure “Intercontinental Exchange, Inc. (ICE) Initial Public Offering” for information regarding sales in 2006.

2005

Intercontinental Exchange, Inc. (ICE) Initial Public Offering (All Other)

In November 2000, we made our initial investment in ICE. An initial public offering (IPO) occurred on November 15, 2005. We sold approximately 2.1 million shares (71% of our investment in ICE) in the fourth quarter of 2005 and recognized a $47 million pretax gain ($30 million, net of tax). During 2006, we sold approximately 0.6 million shares and recognized a $39 million pretax gain ($25 million, net of tax). We recorded the gains in Interest and Investment Income on our Consolidated Statements of Income. Our remaining investment of 0.3 million shares is recorded in Other Temporary Cash Investments on our Consolidated Balance Sheets.

Houston Pipe Line Company LP (HPL) (All Other)

During 2005, we sold our interest in HPL, 30 billion cubic feet (BCF) of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. Although the assets were legally transferred, it is not possible to determine all costs associated with the transfer until the Bank of America (BOA) litigation is resolved. Accordingly, we recorded the excess of the sales price over the carrying cost of the net assets transferred as a deferred gain of $380 million and $379 million as of December 31, 2006 and 2005, respectively, which are reflected in Deferred Credits and Other on our Consolidated Balance Sheets. We provided an indemnity to the purchaser in an amount up to the purchase price for damages, if any, arising from litigation with BOA and a potential resulting inability to use the cushion gas (see “Enron Bankruptcy” section of Note 6). The HPL operations do not meet the criteria to be shown as discontinued operations due to continuing involvement associated with various contractual obligations. Significant continuing involvement includes cash flows from long-term gas contracts with the buyer through 2008 and the cushion gas arrangement. In addition, we hold forward gas contracts, with expirations through 2010, not sold with the gas pipeline and storage assets. We manage the commodity price risk associated with these forward gas contracts to limit our price risk exposure principally by entering into equal and offsetting contracts. For the year ended December 31, 2006, the change in the mark-to-market value of these contracts was less than $100,000.

Pacific Hydro Limited (All Other)

In March 2005, we signed an agreement with Acciona, S.A. for the sale of our equity investment in Pacific Hydro Limited for approximately $88 million. The sale was contingent on Acciona obtaining a controlling interest in Pacific Hydro Limited. The sale was consummated in July 2005 and we recognized a pretax gain of $56 million. This gain is classified in Gain on Disposition of Equity Investments, Net on our 2005 Consolidated Statement of Income.

Texas REPs (Utility Operations segment)

In December 2002, we sold two of our Texas REPs to Centrica, a UK-based provider of retail energy. The sales price was $146 million plus certain other payments including an earnings-sharing mechanism (ESM) for Centrica and us to share in the earnings of the sold business for the years 2003 through 2006. The method of calculating the annual earnings-sharing amount was included in the Purchase and Sales Agreement and was amended through a series of agreements that we and Centrica entered in March 2005. Also in March 2005, we received payments related to the ESM of $45 million and $70 million for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in 2005. In March 2006, we received a payment of $70 million related to the ESM for 2005. The ESM payment for 2006 is contingent on Centrica’s operating results and is contractually capped at $20 million. The payments are reflected in (Gain) Loss on Disposition of Assets, Net on our Consolidated Statements of Income.

Texas Plants - South Texas Project (Utility Operations segment)

In February 2004, we signed an agreement to sell TCC’s 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, we received notice from co-owners of their decisions to exercise their rights of first refusal with terms similar to the original agreement. In September 2004, we entered into sales agreements with two of our nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. The sale was completed for approximately $314 million and the assumption of liabilities of $22 million in May 2005 and did not have a significant effect on our results of operations. The plant did not meet the “component-of-an-entity” criteria because it did not have cash flows that could be clearly distinguished operationally. The plant also did not meet the “component-of-an-entity” criteria for financial reporting purposes because it did not operate individually, but rather as a part of the AEP System which included all of the generation facilities owned by our Registrant Subsidiaries.

2004

Pushan Power Plant (All Other)

In 2002, we began active negotiations to sell our interest in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest partner. The sale was completed in March 2004 for $61 million. The effect of the sale on our 2004 results of operations was not significant. Results of operations of Pushan are classified in Discontinued Operations on our 2004 Consolidated Statement of Income. See “Discontinued Operations” section of this note for additional information.

LIG Pipeline Company and its Subsidiaries (All Other)

As a result of our 2003 decision to exit our noncore businesses, we actively marketed LIG Pipeline Company, which had approximately 2,000 miles of natural gas gathering and transmission pipelines in Louisiana, and five gas processing facilities that straddle the system. In January 2004, a decision was made to sell LIG’s pipeline and processing assets separate from LIG’s gas storage assets. (See “Jefferson Island Storage & Hub, LLC” section of this note for further information.) In February 2004, we signed a definitive agreement to sell LIG Pipeline Company, which owned all of the pipeline and processing assets of LIG. The sale of LIG Pipeline Company and its assets for $76 million was completed in April 2004 and the impact on results of operations in 2004 was not significant. The results of operations are classified in Discontinued Operations on our 2004 Consolidated Statement of Income. See “Discontinued Operations” section of this note for additional information.

Jefferson Island Storage & Hub, LLC (All Other)

In August 2004, a definitive agreement was signed to sell the gas storage assets of Jefferson Island Storage & Hub, LLC (JISH). The sale of JISH and its assets for $90 million was completed in October 2004. The sale resulted in a pretax loss of $12 million ($2 million, net of tax). The results of operations and loss on sale of JISH are classified in Discontinued Operations on our 2004 Consolidated Statement of Income. See “Discontinued Operations” section of this note for additional information.

AEP Coal, Inc. (All Other)

In October 2001, we acquired out of bankruptcy certain assets and assumed certain liabilities of nineteen coal mine companies formerly known as “Quaker Coal” and renamed “AEP Coal, Inc.” During 2002, the coal operations suffered from a decline in prices and adverse mining factors resulting in significantly reduced mine productivity and revenue. Based on an extensive review of economically accessible reserves and other factors, future mine productivity and production was expected to continue below historical levels.

In 2003, as a result of management’s decision to exit our noncore businesses, we retained an advisor to facilitate the sale of AEP Coal, Inc. In March 2004, an agreement was reached to sell assets, exclusive of certain reserves and related liabilities, of the mining operations of AEP Coal, Inc. We received approximately $9 million cash and the buyer assumed an additional $11 million in future reclamation liabilities. We retained an estimated $37 million in future reclamation liabilities which has since been reduced to approximately $14 million. The sale closed in April 2004 and the effect of the sale on our 2004 results of operations was not significant.

Independent Power Producers (Generation and Marketing segment)

During the third quarter of 2003, we initiated an effort to sell four domestic Independent Power Producer (IPP) investments accounted for under the equity method (two located in Colorado and two located in Florida). In March 2004, we entered into an agreement to sell the four domestic IPP investments for a total sales price of $156 million, subject to closing adjustments. A pretax impairment of $2 million was recorded in June 2004 (recorded to Investment Value Losses) to decrease the carrying value of the Colorado plant investments to their estimated sales price, less selling expenses. We closed on the sale of all four investments in 2004. The sale resulted in a pretax gain of $105 million ($64 million, net of tax) generated primarily from the sale of the two Florida IPPs which were not originally impaired. The gain was recorded in Gain on Disposition of Equity Investments, Net on our 2004 Consolidated Statement of Income.

U.K. Generation (All Other)

In December 2001, we acquired two coal-fired generation plants in the U.K. for a cash payment of $942 million and assumption of certain liabilities. Subsequently and continuing through 2002, wholesale U.K. electric power prices declined sharply as a result of domestic over-capacity and static demand. External industry forecasts and our own projections made during the fourth quarter of 2002 indicated that this situation may extend many years into the future.

In the fourth quarter of 2003, the U.K. generation plants were determined to be noncore assets and management engaged an investment advisor to assist in determining the best methodology to exit the U.K. business. In July 2004, we completed the sale of substantially all operations and assets within the U.K. The sale included our two coal-fired generation plants (Fiddler’s Ferry and Ferrybridge), related coal assets, and a number of related commodities contracts for approximately $456 million. The sale resulted in a pretax gain of $266 million ($128 million, net of tax). As a result of the sale, the buyer assumed an additional $46 million in future reclamation liabilities and $10 million in pension liabilities. The remaining assets and liabilities include certain physical power and capacity positions and financial coal and freight swaps. Substantially all of these positions matured or were settled with the applicable counterparties during 2005. The results of operations and gain on sale are included in Discontinued Operations, Net of Tax on our Consolidated Statements of Income for the year ended December 31, 2004. See “Discontinued Operations” section of this note for additional information.

Texas Plants - TCC Generation Assets (Utility Operations segment)

In relation to the implementation of the Texas Restructuring Legislation, we signed an agreement in March 2004 to sell eight natural gas plants, one coal-fired plant and one hydro plant to a nonrelated joint venture. The sale was completed in July 2004 for approximately $428 million, net of adjustments. The sale did not have a significant effect on our 2004 results of operations.

South Coast Power Limited (All Other)

South Coast Power Limited (SCPL) is a 50% owned venture that was formed in 1996 to build, own and operate Shoreham Power Station, a 400 MW, combined-cycle, gas turbine power station located in Shoreham, England. In 2003, management determined that our U.K. operations were no longer part of our core business and as a result, a decision was made to exit the U.K. market. In September 2004, we completed the sale of our 50% ownership in SCPL for $47 million, resulting in a pretax gain of $48 million ($31 million, net of tax). This gain was recorded in Gain on Disposition of Equity Investments, Net on our 2004 Consolidated Statement of Income.

Excess Real Estate (Utility Operations segment)

In June 2004, we entered into negotiations to sell an under-utilized building in Dallas, Texas obtained through our merger with CSW in 2000. A pretax impairment of $3 million was recorded in Other Operation and Maintenance on our Consolidated Statements of Income during the second quarter of 2004 to write down the value of the office building to the current estimated sales price, less estimated selling expenses. In October 2004, we completed the sale of the Dallas office building for $8 million. The sale did not have a significant effect on our results of operations.

Numanco LLC (All Other)

In November 2004, we completed the sale of Numanco LLC for a sale price of $25 million. Numanco was a provider of staffing services to the utility industry. The sale did not have a significant effect on our 2004 results of operations.

DISCONTINUED OPERATIONS

Management periodically assesses our overall business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified in Assets Held for Sale and Liabilities Held for Sale until the time that they are sold.

Certain of our operations were determined to be discontinued operations and are classified as such in 2006, 2005 and 2004. Results of operations of these businesses are classified as shown in the following table:

 	 	SEE-
BOARD (a)	 	Pushan
Power Plant	 	LIG (b)	 	U.K. Generation   (c)	 	Total	 	
 	 	(in millions)	 	
2006 Revenue	 	$	-	 	$	-	 	$	-	 	$	-	 	$	-	 	
2006 Pretax Income	 	 	-	 	 	-	 	 	-	 	 	9	 	 	9	 	
2006 Earnings, Net of Tax	 	 	5	 	 	-	 	 	-	 	 	5	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2005 Revenue (Expense)	 	$	13	 	$	-	 	$	-	 	$	(7	)	$	6	 	
2005 Pretax Income (Loss)	 	 	10	 	 	-	 	 	-	 	 	(13	)	 	(3	)	
2005 Earnings (Loss), Net of Tax	 	 	24	 	 	-	 	 	5	 	 	(2	)	 	27	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2004 Revenue	 	$	-	 	$	10	 	$	165	 	$	125	 	$	300	 	
2004 Pretax Income (Loss)	 	 	(3	)	 	9	 	 	(12	)	 	164	 	 	158	 	
2004 Earnings (Loss), Net of Tax	 	 	(2	)	 	6	 	 	(12	)	 	91	 	 	83	 	

(a)	Relates to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD.	
(b)	Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub LLC. The 2005 amounts relate to purchase price true-up adjustments and tax adjustments from the sale.	
(c)	The 2006 amounts relate to a release of accrued liabilities for the London office lease and tax adjustments from the sale. The 2005 amounts relate to purchase price true-up adjustments and tax adjustments from the sale.	

ASSET IMPAIRMENTS, INVESTMENT VALUE LOSSES AND OTHER RELATED CHARGES

2006

We recorded a pretax impairment of assets totaling $209 million as a result of the terms of our agreement to sell the Plaquemine Cogeneration Facility to Dow. See “Plaquemine Cogeneration Facility” section of this note for additional information regarding this sale.

2005

We recorded pretax impairments of assets totaling $46 million ($39 million related to asset impairments and $7 million related to an equity investment impairment) that reflected our decision to retire two generation units and our decision to exit noncore businesses and other factors as follows:

Conesville Units 1 and 2 (Utility Operations segment)

In the third quarter of 2005, following management’s extensive review of the commercial viability of our generation fleet, management committed to a plan to retire CSPCo’s Conesville Units 1 and 2 before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were considered retired as of the third quarter of 2005.

We recognized a pretax charge of approximately $39 million in 2005 related to our decision to retire the units. The impairment amount is classified in Asset Impairments and Other Related Charges on our 2005 Consolidated Statement of Income.

Compresion Bajio S de R.L. de C.V. (All Other)

In January 2002, we acquired Bajio. A pretax other-than-temporary impairment charge of $13 million was recognized in December 2004 based on an indicative bid, which did not result in a sale.

In September 2005, a pretax other-than-temporary impairment charge of approximately $7 million was recognized based on an indicative offer received in September 2005. Both the 2005 and 2004 impairment amounts are classified as Investment Value Losses on our Consolidated Statements of Income. The sale was completed in February 2006 without significant effect on our 2006 results of operations.

2004

We recorded pretax impairments of assets (including goodwill) and investments totaling $18 million ($15 million related to equity investments recorded in Investment Value Losses and $3 million related to charges recorded for excess real estate in Other Operation and Maintenance on our Consolidated Statement of Income) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, our decision to exit noncore businesses and other factors.

The categories of impairments and gains on dispositions include:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Asset Impairments and Other Related Charges (Pretax)	 	  	 	  	 	  	 	
Plaquemine Cogeneration Facility	 	$	209	 	$	-	 	$	-	 	
Conesville Units 1 and 2	 	 	-	 	 	39	 	 	-	 	
Total	 	$	209	 	$	39	 	$	-	 	
 	 	 	 	 	 	 	 	 	 	 	
(Gain) Loss on Disposition of Assets, Net (Pretax)	 	 	 	 	 	 	 	 	 	 	
Texas REPs	 	$	(70	)	$	(112	)	$	-	 	
Miscellaneous Property, Plant and Equipment	 	 	1	 	 	(8	)	 	(4	)	
Total	 	$	(69	)	$	(120	)	$	(4	)	
 	 	 	 	 	 	 	 	 	 	 	
Investment Value Losses (Pretax)	 	 	 	 	 	 	 	 	 	 	
Independent Power Producers	 	$	-	 	$	-	 	$	(2	)	
Bajio	 	 	-	 	 	(7	)	 	(13	)	
Total	 	$	-	 	$	(7	)	$	(15	)	
 	 	 	 	 	 	 	 	 	 	 	
Gain on Disposition of Equity Investments, Net (Pretax)	 	 	 	 	 	 	 	 	 	 	
Independent Power Producers	 	$	-	 	$	-	 	$	105	 	
South Coast Power Limited	 	 	-	 	 	-	 	 	48	 	
Pacific Hydro Limited	 	 	-	 	 	56	 	 	-	 	
Other	 	 	3	 	 	-	 	 	-	 	
Total	 	$	3	 	$	56	 	$	153	 	

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In January 2004, we signed an agreement to sell TCC’s 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004, we received notice from the nonaffiliated co-owners announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, we entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. Golden Spread challenged these agreements in State District Court in Dallas County. Golden Spread alleges that the Public Utilities Board of the City of Brownsville exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the nonaffiliated co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread in October 2005. TCC and the nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth District at Dallas.

In May 2006, the Court of Appeals for the Fifth District at Dallas reversed the trial court’s judgment in favor of Golden Spread and held that the City of Brownsville properly exercised its right of first refusal to acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the matter, which was denied. Golden Spread then appealed to the Supreme Court of Texas and on December 15, 2006, its Petition for review was denied. Various contract claims, between the parties, that were severed from the appeal on the right of first refusal are pending in the District Court of Dallas County.

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville. The sale did not have a significant effect on our results of operations nor do we expect the remaining litigation to have a significant effect on our results of operations.

TCC’s assets related to the Oklaunion Power Station are classified in Assets Held for Sale on our Consolidated Balance Sheets at December 31, 2006 and 2005. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by our Registrant Subsidiaries.

The Assets Held for Sale at December 31, 2006 and 2005 are as follows:

 	 	December 31,	 	
Texas Plants	 	2006	 	2005	 	
Assets:	 	(in millions)	 	
Other Current Assets	 	$                            11	 	$                            1 1	 	
Property, Plant and Equipment, Net	 	 	43	 	 	43	 	
Total Assets Held for Sale	 	$	44	 	$	44	 	

9.   BENEFIT PLANS  

We sponsor two qualified pension plans and two nonqualified pension plans. A substantial majority of our employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. We sponsor other postretirement benefit plans to provide medical and life insurance benefits for retired employees. We implemented FASB Staff Position FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” in 2004. The Medicare subsidy reduced our SFAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service by $202 million contributing to an actuarial gain in 2004. As a result, the tax-free subsidy reduced 2004’s net periodic postretirement benefit cost by a total of $29 million, including $12 million of amortization of the actuarial gain, $4 million of reduced service cost, and $13 million of reduced interest cost on the APBO.

In December 2006, we implemented SFAS 158. The effect of this standard on our financial statements was a pretax AOCI adjustment of $1,236 million that was offset by a SFAS 71 regulatory asset of $875 million and a deferred income tax asset of $126 million resulting in a net of tax AOCI equity reduction of $235 million. See Note 2.

The following tables provide a reconciliation of the changes in the plans’ projected benefit obligations and fair value of assets over the two-year period ending at the plan’s measurement date of December 31, 2006, and their funded status as of December 31 of each year:

Projected Pension Obligations, Plan Assets, Funded Status as of December 31, 2006 and 2005

 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
 	 	2006	 	2005	 	2006	 	2005	 	
 	 	(in millions)	 	
Change in Projected Benefit Obligation	 	  	 	  	 	  	 	  	 	
Projected Obligation at January 1	 	$	4,347	 	$	4,108	 	$	1,831	 	$	2,100	 	
Service Cost	 	 	97	 	 	93	 	 	39	 	 	42	 	
Interest Cost	 	 	231	 	 	228	 	 	102	 	 	107	 	
Participant Contributions	 	 	-	 	 	-	 	 	21	 	 	20	 	
Actuarial (Gain) Loss	 	 	(293	)	 	191	 	 	(55	)	 	(320	)	
Plan Amendments	 	 	2	 	 	-	 	 	-	 	 	-	 	
Benefit Payments	 	 	(276	)	 	(273	)	 	(112	)	 	(118	)	
Medicare Subsidy Accrued	 	 	-	 	 	-	 	 	(8	)	 	-	 	
Projected Obligation at December 31	 	$	4,108	 	$	4,347	 	$	1,818	 	$	1,831	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in Fair Value of Plan Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair Value of Plan Assets at January 1	 	$	4,143	 	$	3,555	 	$	1,172	 	$	1,093	 	
Actual Return on Plan Assets	 	 	470	 	 	224	 	 	127	 	 	70	 	
Company Contributions	 	 	9	 	 	637	 	 	94	 	 	107	 	
Participant Contributions	 	 	-	 	 	-	 	 	21	 	 	20	 	
Benefit Payments	 	 	(276	)	 	(273	)	 	(112	)	 	(118	)	
Fair Value of Plan Assets at December 31	 	$	4,346	 	$	4,143	 	$	1,302	 	$	1,172	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded Status	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded Status at December 31	 	$	238	 	$	(204	)	$	(516	)	$	(659	)	
Unrecognized Net Transition Obligation	 	 	-	 	 	-	 	 	-	 	 	152	 	
Unrecognized Prior Service Cost (Benefit)	 	 	-	 	 	(9	)	 	-	 	 	5	 	
Unrecognized Net Actuarial Loss	 	 	-	 	 	1,266	 	 	-	 	 	471	 	
Net Asset (Liability) Recognized	 	$	238	 	$	1,053	 	$	(516	)	$	(31	)	

Amounts Recognized on the Balance Sheets as of December 31, 2006 and 2005
 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
 	 	2006	 	2005	 	2006	 	2005	 	
 	 	(in millions)	 	
Employee Benefits and Pension Assets - Prepaid Benefit Costs	 	$	320	 	$	1,099	 	$	-	 	$	-	 	
Other Current Liabilities - Accrued Short-term Benefit Liability	 	 	(8	)	 	-	 	 	(5	)	 	-	 	
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability	 	 	(74	)	 	(46	)	 	(511	)	 	(31	)	
Funded Status	 	 	238	 	 	 	 	 	(516	)	 	 	 	
Regulatory Assets	 	 	582	 	 	N/A	 	 	293	 	 	N/A	 	
Deferred Income Taxes	 	 	60	 	 	10	 	 	66	 	 	N/A	 	
Additional Minimum Liability	 	 	N/A	 	 	(35	)	 	N/A	 	 	N/A	 	
Intangible Asset	 	 	N/A	 	 	6	 	 	N/A	 	 	N/A	 	
Accumulated Other Comprehensive Income (Loss), Net of Tax	 	 	112	 	 	19	 	 	123	 	 	N/A	 	
Total	 	$	992	 	$	1,053	 	$	(34	)	$	(31	)	

N/A = Not Applicable
 
SFAS 158 Amounts Recognized in Accumulated Other Comprehensive Income (AOCI) as of December 31, 2006
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	(in millions)	 	
Components	 	  	 	  	 	
Net Actuarial Loss	 	$	759	 	$	354	 	
Prior Service Cost (Credit)	 	 	(5	)	 	4	 	
Transition Obligation	 	 	-	 	 	124	 	
Pretax AOCI	 	$	754	 	$	482	 	
 	 	 	 	 	 	 	 	
Recorded as	 	 	 	 	 	 	 	
Regulatory Assets	 	$	582	 	$	293	 	
Deferred Income Taxes	 	 	60	 	 	66	 	
Net of tax AOCI	 	 	112	 	 	123	 	
Pretax AOCI	 	$	754	 	$	482	 	

We recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of our regulated operations that for ratemaking purposes will be deferred for future recovery.
 
Pension and Other Postretirement Plans’ Assets

The asset allocations for our pension plans at the end of 2006 and 2005, and the target allocation for 2007, by asset category, are as follows:
 
 	 	Target Allocation	 	Percentage of Plan Assets at Year End	 	
 	 	2007	 	2006	 	2005	 	
Asset Category	 	(in percentage)	 	
Equity Securities	 	 	65	 	 	63	 	 	62	 	
Real Estate	 	 	5	 	 	6	 	 	4	 	
Debt Securities	 	 	28	 	 	26	 	 	25	 	
Cash and Cash Equivalents	 	 	2	 	 	5	 	 	9	 	
Total	 	 	100	 	 	100	 	 	100	 	

The asset allocations for our other postretirement benefit plans at the end of 2006 and 2005, and target allocation for 2007, by asset category, are as follows:
 
 	 	Target Allocation	 	Percentage of Plan Assets at Year End	 	
 	 	2007	 	2006	 	2005	 	
Asset Category	 	(in percentage)	 	
Equity Securities	 	 	65	 	 	66	 	 	68	 	
Debt Securities	 	 	33	 	 	32	 	 	30	 	
Other	 	 	2	 	 	2	 	 	2	 	
Total	 	 	100	 	 	100	 	 	100	 	

Our investment strategy for our employee benefit trust funds is to use a diversified portfolio of investments to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. To minimize risk, our employee benefit trust funds are broadly diversified among classes of assets, investment strategies and investment managers. We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation when considered appropriate. Our investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. Our investment policies prohibit investment in AEP securities, with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies. Because of the $320 million contribution at the end of 2005 the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2006.

The value of our pension plans’ assets increased to $4.3 billion at December 31, 2006 from $4.1 billion at December 31, 2005. The qualified plans paid $267 million in benefits to plan participants during 2006 (nonqualified plans paid $9 million in benefits). The value of AEP’s Postretirement Plans’ assets increased to $1.3 billion in December 31, 2006 from $1.2 billion at December 31, 2005. The Postretirement Plans paid $112 million in benefits to plan participants during 2006.

We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.

Accumulated Benefit Obligation
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Qualified Pension Plans	 	$	3,861	 	$	4,053	 	
Nonqualified Pension Plans	 	 	78	 	 	81	 	
Total	 	$	3,939	 	$	4,134	 	

For our underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets of these plans at December 31, 2006 and 2005 were as follows:
 
 	 	Underfunded Pension Plans	 	
 	 	As of December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Projected Benefit Obligation	 	$	82	 	$	84	 	
 	 	 	 	 	 	 	 	
Accumulated Benefit Obligation	 	$	78	 	$	81	 	
Fair Value of Plan Assets	 	 	-	 	 	-	 	
Accumulated Benefit Obligation Exceeds the Fair Value of
  Plan Assets	 	$	
78	 	$	81	 	

We made a contribution of $626 million in 2005 to meet our goal of fully funding all qualified pension plans by the end of 2005.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31, used in the measurement of our benefit obligations are shown in the following tables:
 
 	 	 	Pension Plans  	 	 	Other Postretirement
Benefit Plans  	 	
 	 	 	2006 	 	 	2005 	 	 	2006 	 	 	2005  	 	
 	 	  (in percentages)	 	
Discount Rate	 	 	5.75	 	 	5.50	 	 	5.85	 	 	5.65	 	
Rate of Compensation Increase	 	 	5.90	(a	) 	5.90	(a	)	N/A	 	 	N/A	 	

(a)	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.	
 	 	
N/A	= Not Applicable	

To determine a discount rate, we use a duration-based method by constructing a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s AA bond index with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2006, the rate of compensation increase assumed varies with the age of the employee, ranging from 5.0% per year to 11.5% per year, with an average increase of 5.90%.

Estimated Future Benefit Payments and Contributions

Information about the 2007 expected cash flows for the pension (qualified and nonqualified) and other postretirement benefit plans is as follows:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
Employer Contribution	 	(in millions)	 	
Required Contributions (a)	 	$	8	 	 	N/A	 	
Additional Discretionary Contributions	 	 	-	 	$	82	 	

(a)	Contribution required to meet minimum funding requirement per the U.S. Department of Labor and to fund nonqualified benefit payments.	
 	 	
N/A	= Not Applicable	

The contribution to the pension plans is based on the minimum amount required by the U.S. Department of Labor and the amount to fund nonqualified benefit payments, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ periodic benefit cost for accounting purposes and is provided for in agreements with state regulatory authorities.

The table below reflects the total benefits expected to be paid from the plan or from our assets, including both our share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan. Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates, and variances in actuarial results. The estimated payments for pension benefits and other postretirement benefits are as follows:
 
 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
 	 	Pension Payments	 	Benefit
Payments	 	Medicare Subsidy Receipts	 	
 	 	(in millions)	 	
2007	 	$	345	 	$	113	 	$	(9	)	
2008	 	 	354	 	 	121	 	 	(10	)	
2009	 	 	361	 	 	130	 	 	(11	)	
2010	 	 	366	 	 	139	 	 	(11	)	
2011	 	 	367	 	 	149	 	 	(12	)	
Years 2012 to 2016, in Total	 	 	1,821	 	 	839	 	 	(77	)	

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the plans for fiscal years 2006, 2005 and 2004:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	2006	 	2005	 	2004	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Service Cost	 	$	97	 	$	93	 	$	86	 	$	39	 	$	42	 	$	41	 	
Interest Cost	 	 	231	 	 	228	 	 	228	 	 	102	 	 	107	 	 	117	 	
Expected Return on Plan Assets	 	 	(335	)	 	(314	)	 	(292	)	 	(94	)	 	(92	)	 	(81	)	
Amortization of Transition Obligation	 	 	-	 	 	-	 	 	2	 	 	27	 	 	27	 	 	28	 	
Amortization of Prior Service Cost (Credit)	 	 	(1	)	 	(1	)	 	(1	)	 	-	 	 	-	 	 	-	 	
Amortization of Net Actuarial Loss	 	 	79	 	 	55	 	 	17	 	 	22	 	 	25	 	 	36	 	
Net Periodic Benefit Cost	 	 	71	 	 	61	 	 	40	 	 	96	 	 	109	 	 	141	 	
Capitalized Portion	 	 	(21	)	 	(17	)	 	(10	)	 	(27	)	 	(33	)	 	(46	)	
Net Periodic Benefit Cost Recognized as   Expense	 	$	50	 	$	44	 	$	30	 	$	69	 	$	76	 	$	95	 	

Estimated amounts expected to be amortized to net periodic benefit costs from pretax accumulated other comprehensive income during 2007 are shown in the following table:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	(in millions)	 	
Net Actuarial Loss	 	$	52	 	$	15	 	
Prior Service Cost (Credit)	 	 	(1	)	 	-	 	
Transition Obligation	 	 	-	 	 	27	 	
Total Estimated 2007 Pretax AOCI Amortization	 	$	51	 	$	42	 	

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1, used in the measurement of our benefit costs are shown in the following tables:

 	 	Pension Plans	 	  Other Postretirement
Benefit Plans	 	
 	 	2006	 	  2005	 	  2004	 	  2006	 	  2005	 	  2004	 	
 	 	(in percentages)	 	
Discount Rate	 	 	5.50	 	 	5.50	 	 	6.25	 	 	5.65	 	 	5.80	 	 	6.25	 	
Expected Return on Plan Assets	 	 	8.50	 	 	8.75	 	 	8.75	 	 	8.00	 	 	8.37	 	 	8.35	 	
Rate of Compensation Increase	 	 	5.90	 	 	3.70	 	 	3.70	 	 	N/A	 	 	N/A	 	 	N/A	 	
 	
N/A = Not Applicable	

The expected return on plan assets for 2006 was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, and current prospects for economic growth.

The health care trend rate assumptions as of January 1, used for other postretirement benefit plans measurement purposes are shown below:

Health Care Trend Rates:	 	2006	 	2005	 	
Initial	 	 	8.0	%	 	9.0	%	
Ultimate	 	 	5.0	%	 	5.0	%	
Year Ultimate Reached	 	 	2009	 	 	2009	 	

Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit health care plans. A 1% change in assumed health care cost trend rates would have the following effects:

 	 	1% Increase	 	1% Decrease	 	
 	 	(in millions)	 	
Effect on Total Service and Interest Cost  Components of Net
  Periodic  Postretirement Health  Care Benefit Cost	 	$	19	 	$	(16	)	
 	 	 	 	 	 	 	 	
Effect on the Health Care Component of the  Accumulated
  Postretirement  Benefit Obligation	 	 	193	 	 	(161	)	

AEP Savings Plans

We sponsor various defined contribution retirement savings plans for substantially all employees who are not members of the United Mine Workers of America (UMWA). These plans offer participants an opportunity to contribute a portion of their pay, include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. Our matching contributions to the plan are 75% of the first 6% of eligible compensation contributed by the employee. The cost for contributions to these plans totaled $62 million in 2006, $57 million in 2005 and $55 million in 2004.

UMWA Benefits

We provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.

The health and welfare benefits are administered by us and benefits are paid from our general assets. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2006, 2005 and 2004.

10.   NUCLEAR  

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. A significant future financial commitment to safely dispose of SNF and to decommission and decontaminate the plant results from its ownership. Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. By agreement, I&M is partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S.

Decommissioning and Low Level Waste Accumulation Disposal

The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. 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. The wide range is caused by variables in assumptions. I&M recovers estimated Cook Plant decommissioning costs in its rates. The amount recovered in rates for decommissioning the Cook Plant was $30 million in 2006 and $27 million in 2005 and 2004. Decommissioning costs recovered from customers are deposited in external trusts.

I&M deposited an additional $4 million in 2006, 2005 and 2004 in its decommissioning trust for Cook Plant under funding provisions approved by regulatory commissions. At December 31, 2006, the total decommissioning trust fund balance for the Cook Plant was $974 million. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. Decommissioning costs for the Cook Plant including interest, unrealized gains and losses and expenses of the trust funds increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

SNF Disposal

Federal law provides for government responsibility for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. At December 31, 2006, fees and related interest of $247 million for fuel consumed prior to April 7, 1983 at the Cook Plant have been recorded as Long-term Debt and funds collected from customers towards payment of the pre-April 1983 fee and related earnings of $274 million are recorded as part of Spent Nuclear Fuel and Decommissioning Trust on our Consolidated Balance Sheets. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

Trust Assets for Decommissioning and SNF Disposal

We record securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel at market value. We classify securities in the trust funds as available-for-sale due to their long-term purpose. As discussed in the “Nuclear Trust Funds” section of Note 1, we record unrealized gains and losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. The gains, losses or other-than-temporary impairments shown below did not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdictions’ liabilities. Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments at December 31 :

 	 	2006	 	2005	 	
 	 	Estimated
Fair
Value	 	Gross
Unrealized
Gains	 	Other-Than-
Temporary
Impairments	 	Estimated
Fair
Value	 	Gross
Unrealized
Gains	 	Gross
Unrealized
Losses	 	
 	 	(in millions)	 	
Cash	 	$	24	 	$	-	 	$	-	 	$	21	 	$	-	 	$	-	 	
Debt Securities	 	 	750	 	 	18	 	 	(8	)	 	691	 	 	7	 	 	(7	)	
Equity Securities	 	 	474	 	 	192	 	 	(4	)	 	422	 	 	148	 	 	(3	)	
Spent Nuclear Fuel
   Decommissioning Trusts	 	$	1,248	 	$	210	 	$	(12	)	$	1,134	 	$	155	 	$	(10	)	
 
Proceeds from sales of nuclear trust fund investments were $631 million, $706 million and $950 million in 2006, 2005 and 2004, respectively. Purchases of nuclear trust fund investments were $692 million, $761 million and $1,001 million in 2006, 2005 and 2004, respectively.

Gross realized gains from the sales of nuclear trust fund investments were $7 million, $13 million and $13 million in 2006, 2005 and 2004, respectively. Gross realized losses including other-than-temporary impairments in 2006 from the sales of nuclear trust fund investments were $7 million, $17 million and $18 million in 2006, 2005 and 2004, respectively.

The fair value of debt securities, summarized by contractual maturities, at December 31, 2006 is as follows:

 	 	Fair Value	 	
 	 	(in millions)	 	
Within 1 year	 	$	50	 	
1 year - 5 years	 	 	188	 	
5 years - 10 years	 	 	215	 	
After 10 years	 	 	297	 	
Total	 	$	750	 	

Nuclear Incident Liability

I&M carries insurance coverage for property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion. I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M utilizes an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $38 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $10.8 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $300 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $101 million on each licensed reactor in the U.S. payable in annual installments of $15 million. As a result, I&M could be assessed $202 million per nuclear incident payable in annual installments of $30 million. The number of incidents for which payments could be required is not limited. Under an industry-wide program insuring workers at nuclear facilities, I&M is also obligated for assessments of up to $6 million for potential claims until December 31, 2007.

In the event of an incident of a catastrophic nature, we are initially covered for the first $300 million through commercially available insurance. The next level of liability coverage of up to $10.8 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and under the Price-Anderson Act, we would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, results of operations, cash flows and financial condition could be adversely affected.

        11.   BUSINESS SEGMENTS

Our primary business strategy and the core of our business focus on our electric utility operations. Within our Utility Operations segment, we centrally dispatch all generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Generation/supply in Ohio and Virginia continue to have commission-determined transition rates. Virginia is currently considering returning to regulation for generation. While our Utility Operations segment remains our primary business segment, the emergence of other areas of our business prompted us to identify two new business segments in 2006. One of these new segments is our MEMCO Operations segment, which reflects our significant ongoing barging activities. We also identified our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities in the ERCOT market area. We no longer consider Investments - Gas Operations and Investments - UK Operations as reportable segments because we have sold substantially all of those assets.
 
Starting in the fourth quarter of 2006, our new segments and their related business activities are as follows:

Utility Operations
·	Generation of electricity for sale to U.S. retail and wholesale customers.	
·	Electricity transmission and distribution in the U.S.	

MEMCO Operations
·	Bulk commodity barging operations.	

Generation and Marketing
·	IPPs, wind farms and marketing and risk management activities in ERCOT.	

The remainder of our company’s activities is presented as All Other. While not considered a business segment, All Other includes:

·	Parent company’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.	
·	Our UK operations, which were sold in 2004.	
·	Our gas pipeline and storage operations, which were sold in 2004 and 2005.	
·	Other energy supply related businesses, including the Plaquemine Cogeneration Facility.	

The tables below present our reportable segment information for the years ended December 31, 2006, 2005 and 2004 and balance sheet information as of December 31, 2006 and 2005. These amounts include certain estimates and allocations where necessary. We reclassified prior year amounts to conform to the current year’s presentation.  
 
 	 	 	 	 	  Nonutility Operations	 	 	 	 	 	 	 	 	 	 	 	
 	 	  Utility Operations	 	 MEMCO Operations	 	 Generation and Marketing	 	 All Other (a)	 	 	 Reconciling Adjustments	 	 Consolidated	 	
 	 	  (in millions)	 	
Year Ended December 31, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues from:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
External Customers	 	$	12,066	 	$	520	 	$	62	 	$	(26	)	 	$	-	 	$	12,622	 	
Other Operating Segments	 	 	(55	)	 	12	 	 	-	 	 	97	 	 	 	(54	)	 	-	 	
Total Revenues	 	$	12,011	 	$	532	 	$	62	 	$	71	 	 	$	(54	)	$	12,622	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	$	1,435	 	$	11	 	$	17	 	$	4	 	 	$	-	 	$	1,467	 	
Interest Income	 	 	36	 	 	-	 	 	2	 	 	91	 	 	 	(68	)	 	61	 	
Interest Expense	 	 	667	 	 	4	 	 	11	 	 	118	 	 	 	(68	)	 	732	 	
Income Tax Expense (Credit)	 	 	543	 	 	42	 	 	(19	)	 	(81	)	 	 	-	 	 	485	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (Loss) Before Discontinued  Operations,
  Extraordinary  Loss and Cumulative Effect of
  Accounting Changes	 	$	1,028	 	$	80	 	$	12	 	$	(128	)	 	$	-	 	$	992	 	
Discontinued Operations, Net of Tax	 	 	-	 	 	-	 	 	-	 	 	10	 	 	 	-	 	 	10	 	
Net Income (Loss)	 	$	1,028	 	$	80	 	$	12	 	$	(118	)	 	$	-	 	$	1,002	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross Property Additions	 	$	3,494	 	$	7	 	$	1	 	$	26	 (b	)	$	-	 	$	3,528	 	

 	 	 	 	Nonutility Operations	 	 	 	 	 	 	 	
 	 	Utility Operations	 	MEMCO
Operations	 	Generation
and Marketing	 	All Other (a)	 	Reconciling Adjustments	 	Consolidated	 	
 	 	(in millions)	 	
Year Ended December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	  	 	
Revenues from:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
External Customers	 	$	11,157	 	$	344	 	$	73	 	$	537	 	$	-	 	$	12,111	 	
Other Operating Segments	 	 	232	 	 	11	 	 	-	 	 	(174	)	 	(69	)	 	-	 	
Total Revenues	 	$	11,389	 	$	355	 	$	73	 	$	363	 	$	(69	)	$	12,111	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	$	1,315	 	$	11	 	$	17	 	$	5	 	$	-	 	$	1,348	 	
Interest Income	 	 	31	 	 	-	 	 	2	 	 	80	 	 	(54	)	 	59	 	
Interest Expense	 	 	588	 	 	3	 	 	16	 	 	144	 	 	(54	)	 	697	 	
Income Tax Expense (Credit)	 	 	475	 	 	10	 	 	(28	)	 	(27	)	 	-	 	 	430	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (Loss) Before Discontinued  Operations,
  Extraordinary  Loss and Cumulative Effect of
  Accounting Changes	 	$	1,018	 	$	21	 	$	16	 	$	(26	)	$	-	 	$	1,029	 	
Discontinued Operations, Net of Tax	 	 	-	 	 	-	 	 	-	 	 	27	 	 	-	 	 	27	 	
Extraordinary Loss, Net of Tax	 	 	(225	)	 	-	 	 	-	 	 	-	 	 	-	 	 	(225	)	
Cumulative Effect of Accounting  Changes, Net of Tax	 	 	(17	)	 	-	 	 	-	 	 	-	 	 	-	 	 	(17	)	
Net Income	 	$	776	 	$	21	 	$	16	 	$	1	 	$	-	 	$	814	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross Property Additions	 	$	2,755	 	$	7	 	$	-	 	$	2	 	$	-	 	$	2,764	 	

 	 	 	 	Nonutility Operations	 	 	 	 	 	 	 	
 	 	Utility Operations	 	MEMCO
Operations	 	Generation
and Marketing	 	All Other (a)	 	Reconciling Adjustments	 	Consolidated	 	
 	 	(in millions)	 	
Year Ended December 31, 2004	 	  	 	  	 	  	 	  	 	  	 	  	 	
Revenues from:	 	  	 	  	 	  	 	  	 	  	 	  	 	
External Customers	 	$	10,620	 	$ 	272	 	$ 	90	 	$ 	3,263	 	$ 	-	 	$ 	14,245	 	
Other Operating Segments	 	 	144	 	 	11	 	 	3	 	 	55	 	 	(213	)	 	-	 	
Total Revenues	 	$	10,764	 	$	283	 	$	93	 	$	3,318	 	$	(213	)	$	14,245	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	$	1,281	 	$	11	 	$	18	 	$	14	 	$	-	 	$	1,324	 	
Interest Income	 	 	16	 	 	1	 	 	3	 	 	52	 	 	(39	)	 	33	 	
Interest Expense	 	 	621	 	 	3	 	 	15	 	 	181	 	 	(39	)	 	781	 	
Income Tax Expense (Credit)	 	 	558	 	 	5	 	 	18	 	 	(9	)	 	-	 	 	572	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (Loss) Before Discontinued  Operations,
  Extraordinary  Loss and Cumulative Effect of
  Accounting Changes	 	$	1,175	 	$	12	 	$	73	 	$	(133	)	$	-	 	$	1,127	 	
Discontinued Operations, Net of Tax	 	 	-	 	 	-	 	 	-	 	 	83	 	 	-	 	 	83	 	
Extraordinary Loss, Net of Tax	 	 	(121	)	 	-	 	 	-	 	 	-	 	 	-	 	 	(121	)	
Net Income (Loss)	 	$	1,054	 	$	12	 	$	73	 	$	(50	)	$	-	 	$	1,089	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross Property Additions	 	$	1,471	 	$	5	 	$	-	 	$	161	 	$	-	 	$	1,637	 	

 	 	 	 	Nonutility Operations	 	 	 	 	 	 	 	
 	 	Utility Operations	 	MEMCO
Operations	 	Generation
and
Marketing	 	All Other
(a)	 	Reconciling Adjustments
(c)	 	Consolidated	 	
 	 	(in millions)	 	
As of December 31, 2006	 	  	 	  	 	  	 	  	 	  	 	  	 	
Total Property, Plant and Equipment	 	$	41,420	 	$	239	 	$	327	 	$	35	 	$	-	 	$	42,021	 	
Accumulated Depreciation and  Amortization	 	 	15,101	 	 	51	 	 	83	 	 	5	 	 	-	 	 	15,240	 	
Total Property, Plant and Equipment -  Net	 	$	26,319	 	$	188	 	$	244	 	$	30	 	$	-	 	$	26,781	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	36,632	 	$	315	 	$	342	 	$	11,460	 	$	(10,762	)	$	37,987	 	
Assets Held for Sale	 	 	44	 	 	-	 	 	-	 	 	-	 	 	-	 	 	44	 	
Investments in Equity Method  Subsidiaries	 	 	-	 	 	-	 	 	42	 	 	-	 	 	-	 	 	42	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
As of December 31, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Property, Plant and Equipment	 	$	38,283	 	$	233	 	$	327	 	$	278	 	$	-	 	$	39,121	 	
Accumulated Depreciation and  Amortization	 	 	14,723	 	 	41	 	 	66	 	 	7	 	 	-	 	 	14,837	 	
Total Property, Plant and Equipment -  Net	 	$	23,560	 	$	192	 	$	261	 	$	271	 	$	-	 	$	24,284	 	

Total Assets	 	$	34,344	 	$	297	 	$	396	 	$	12,672	 	$	(11,537	)	$	36,172	 	
Assets Held for Sale	 	 	44	 	 	-	 	 	-	 	 	-	 	 	-	 	 	44	 	
Investments in Equity Method  Subsidiaries	 	 	-	 	 	-	 	 	40	 	 	12	 	 	-	 	 	52	 	

(a)	All Other includes:	
 	·	Parent company’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.	
 	·	Our UK operations, which were sold in 2004.	
 	·	Our gas pipeline and storage operations, which were sold in 2004 and 2005.	
 	·	Other energy supply related businesses, including the Plaquemine Cogeneration Facility.	
(b)	Gross Property Additions for All Other includes the $25 million acquisition of turbines by one of our nonregulated, wholly-owned subsidiaries. These turbines will be refurbished and transferred to a generating facility within our Utility Operations segment by the second half of 2008.	
(c)	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.	
       
         12.   DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS

DERIVATIVES AND HEDGING

SFAS 133 requires recognition of all qualifying derivative instruments as either assets or liabilities in the statement of financial position at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. Because energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to MTM accounting treatment and are recognized on the accrual or settlement basis.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis in the Consolidated Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the Consolidated Statements of Income depending on the relevant facts and circumstances.

Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge. For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), we recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in earnings during the period of change. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets until the period the hedged item affects earnings. We recognize any hedge ineffectiveness in earnings immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Fair Value Hedging Strategies

Prior to the sale of HPL in the first quarter of 2005, to hedge the risks associated with our domestic gas pipeline and storage activities, we entered into natural gas derivative transactions to hedge natural gas inventory. The purpose of this hedging activity was to protect the natural gas inventory against changes in fair value due to changes in spot gas prices. The derivative transactions designated as fair value hedges of our natural gas inventory were MTM each month based upon changes in the NYMEX forward prices, whereas the natural gas inventory was MTM on a monthly basis based upon changes in the Gas Daily spot price at the end of the month. The differences between the indices used to MTM the natural gas inventory and the derivative transactions designated as fair value hedges can result in volatility in our reported net income. However, over time gains or losses on the sale of the natural gas inventory will be offset by gains or losses on the fair value hedges, resulting in the realization of gross margin we anticipated at the time the transaction was structured. In the third quarter of 2004, the gas-related fair value hedges were de-designated. As a result, the existing hedged inventory was held at the market price on the fair value hedge de-designation date with subsequent additions to inventory carried at cost. As a result of the sale of HPL in 2005, we no longer employ this risk management strategy. During 2005 and 2004, we recognized a pretax loss of zero and approximately $27 million, respectively, in Revenues on our Consolidated Statements of Income related to hedge ineffectiveness and changes in time value excluded from the assessment of hedge ineffectiveness.

We enter into interest rate derivative transactions in order to manage existing fixed interest rate risk exposure. These interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. We record gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as offsetting changes in the fair value of the debt being hedged, in Interest Expense on our Consolidated Statements of Income. During 2006, 2005 and 2004, we recognized no hedge ineffectiveness related to these derivative transactions.

Cash Flow Hedging Strategies

At times we are exposed to foreign currency exchange rate risks primarily because we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The accumulated gains or losses related to our foreign currency hedges, which are immaterial, are reclassified from Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets into Operating Expenses on our Consolidated Statements of Income over the same period as the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships. We do not hedge all foreign currency exposure.

We enter into interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence because the proceeds will be used to fund existing debt maturities as well as fund projected capital expenditures. We reclassify gains and losses on the hedges from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During 2006 and 2005, we reclassified immaterial amounts into earnings due to hedge ineffectiveness. During 2004, we reclassified an immaterial amount to earnings because the original forecasted transaction did not occur within the originally specified time period.

We enter into, and designate as cash flow hedges, certain derivative transactions for the purchase and sale of electricity and natural gas in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We closely monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect margins for a portion of future electricity sales and fuel purchases. Realized gains and losses on these derivatives designated as cash flow hedges are included in Revenues or Fuel and Other Consumables Used for Electric Generation on our Consolidated Statements of Income, depending on the specific nature of the risk being hedged. We do not hedge all variable price risk exposure related to energy commodities. During 2006, 2005 and 2004, we recognized immaterial amounts in earnings related to hedge ineffectiveness.

We entered into natural gas futures contracts to protect against the reduction in value of forecasted cash flows resulting from spot purchases and sales of natural gas at Houston Ship Channel (HSC). Realized gains and losses on these derivatives designated as cash flow hedges are included in Revenues. As a result of the sale of HPL in 2005, we no longer employ this risk management strategy. During 2005 and 2004, we recognized immaterial amounts in earnings related to hedge ineffectiveness.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheet at December 31, 2006 are:
 
 	 	Hedging
Assets (a)	 	Hedging
Liabilities (a)	 	Accumulated Other Comprehensive Income (Loss) A fter Tax	 	Portion Expected to be Reclassified to Earnings During the Next
Twelve Months	 	
 	 	(in millions)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Power	 	$	30	 	$	(4	)	$	17	 	$	17	 	
Interest Rate	 	 	4	 	 	(4	)	 	(23	) (b)	 	(2	)	
Total 	 	$	34	 	$	(8	)	$	(6	)	$	15	 	

(a)	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Consolidated Balance Sheet.	
(b)	Includes $1 million loss recorded in an equity investment.	
 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheet at December 31, 2005 are:
 
 	 	Hedging
Assets (a)	 	Hedging
Liabilities (a)	 	 
Accumulated Other Comprehensive Income (Loss) After Tax	 	Portion Expected to be Reclassified to Earnings
During the Next
Twelve Months	 	
 	 	(in millions)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Power and Gas	 	$	11	 	$	20	 	$	(6	)	$	(5	)	
Interest Rate	 	 	3	 	 	-	 	 	(21	) (b)	 	(2	)	
Total	 	$	14	 	$	20	 	$	(27	)	$	(7	)	

(a)	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Consolidated Balance Sheet.	
(b)	Includes $1 million loss recorded in an equity investment.	

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ due to market price changes. As of December 31, 2006, the maximum length of time that we are hedging, with SFAS 133 designated contracts, our exposure to variability in future cash flows related to forecasted transactions is forty-two-months.

The following table represents the activity in Accumulated Other Comprehensive Income (Loss) for derivative contracts that qualify as cash flow hedges at December 31, 2006:
 
 	 	Amount	 	
 	 	(in millions)	 	
Balance at December 31, 2003	 	$	(94	)	
Changes in fair value	 	 	8	 	
Reclasses from AOCI to net earnings	 	 	86	 	
Balance at December 31, 2004	 	 	-	 	
Changes in fair value	 	 	(5	)	
Reclasses from AOCI to net earnings	 	 	(22	)	
Balance, at December 31, 2005	 	 	(27	)	
Changes in fair value	 	 	13	 	
Reclasses from AOCI to net earnings	 	 	8	 	
Balance at December 31, 2006	 	$	(6	)	

FINANCIAL INSTRUMENTS

The fair value of Long-term Debt is based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of significant financial instruments at December 31, 2006 and 2005 are summarized in the following tables.
 
  	 	2006	 	2005	 	
 	 	Book Value	 	Fair Value	 	Book Value	 	Fair Value	 	
 	 	(in millions)	 	
Long-term Debt	 	$	13,698	 	$	13,743	 	$	12,226	 	$	12,416	 	

        13. INCOME TAXES

The details of our consolidated income taxes before discontinued operations, extraordinary loss and cumulative effect of accounting change as reported are as follows:
 
 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Federal:	 	  	 	  	 	  	 	
Current	 	$	429	 	$	375	 	$	262	 	
Deferred	 	 	5	 	 	28	 	 	263	 	
Total	 	 	434	 	 	403	 	 	525	 	
 	 	 	 	 	 	 	 	 	 	 	
State and Local:	 	 	 	 	 	 	 	 	 	 	
Current	 	 	61	 	 	25	 	 	49	 	
Deferred	 	 	(10	)	 	4	 	 	(3	)	
Total	 	 	51	 	 	29	 	 	46	 	
 	 	 	 	 	 	 	 	 	 	 	
International:	 	 	 	 	 	 	 	 	 	 	
Current	 	 	-	 	 	(2	)	 	1	 	
Deferred	 	 	-	 	 	-	 	 	-	 	
Total	 	 	-	 	 	(2	)	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	
Total Income Tax Expense Before Discontinued  Operations, Extraordinary
  Loss and  Cumulative Effect of Accounting Change	 	$	485	 	$	430	 	$	572	 	

The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported.

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Net Income	 	$	1,002	 	$	814	 	$	1,089	 	
Discontinued Operations (net of income tax of $(1) million, $(30) million and $75
  million in 2006, 2005 and 2004, respectively)	 	 	(10	)	 	(27	)	 	(83	)	
Extraordinary Loss, (net of income tax of $(121) million and $(64) million in 2005
  and 2004,  respectively)	 	 	-	 	 	225	 	 	121	 	
Cumulative Effect of Accounting Change (net of income tax of $(9) million in 2005)	 	 	-	 	 	17	 	 	-	 	
Preferred Stock Dividends	 	 	3	 	 	7	 	 	6	 	
Income Before Preferred Stock Dividends of Subsidiaries	 	 	995	 	 	1,036	 	 	1,133	 	
Income Tax Expense Before Discontinued Operations, Extraordinary Loss and
  Cumulative Effect of  Accounting Change	 	 	485	 	 	430	 	 	572	 	
Pretax Income	 	$	1,480	 	$	1,466	 	$	1,705	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Taxes on Pretax Income at Statutory Rate (35%)	 	$	518	 	$	513	 	$	597	 	
Increase (Decrease) in Income Taxes Resulting from the Following Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	38	 	 	39	 	 	36	 	
Investment Tax Credits, Net	 	 	(29	)	 	(32	)	 	(29	)	
Tax Effects of International Operations	 	 	-	 	 	(2	)	 	1	 	
Energy Production Credits	 	 	(19	)	 	(18	)	 	(16	)	
State Income Taxes	 	 	33	 	 	19	 	 	30	 	
Removal Costs	 	 	(15	)	 	(14	)	 	(12	)	
AFUDC	 	 	(18	)	 	(14	)	 	(11	)	
Medicare Subsidy	 	 	(12	)	 	(13	)	 	(10	)	
Tax Reserve Adjustments	 	 	9	 	 	(11	)	 	(14	)	
Other	 	 	(20	)	 	(37	)	 	-	 	
Total Income Tax Expense Before Discontinued Operations, Extraordinary
   Loss and  Cumulative Effect of Accounting Change	 	$	485	 	$	430	 	$	572	 	
 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	32.8	%	 	29.3	%	 	33.5	%	

The following table shows elements of the net deferred tax liability and significant temporary differences.

 	 	As of December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Deferred Tax Assets	 	$	2,384	 	$	2,085	 	
Deferred Tax Liabilities	 	 	(7,074	)	 	(6,895	)	
Net Deferred Tax Liabilities	 	$	(4,690	)	$	(4,810	)	
 	 	 	 	 	 	 	 	
Property Related Temporary Differences	 	$	(3,292	)	$	(3,301	)	
Amounts Due From Customers For Future Federal Income Taxes	 	 	(193	)	 	(186	)	
Deferred State Income Taxes	 	 	(318	)	 	(384	)	
Transition Regulatory Assets	 	 	(46	)	 	(176	)	
Securitized Transition Assets	 	 	(809	)	 	(232	)	
Regulatory Assets	 	 	(334	)	 	(492	)	
Accrued Pensions	 	 	(155	)	 	(345	)	
Deferred Income Taxes on Other Comprehensive Loss	 	 	120	 	 	14	 	
All Other, Net	 	 	337	 	 	292	 	
Net Deferred Tax Liabilities	 	$	(4,690	)	$	(4,810	)	

We join in the filing of a consolidated federal income tax return with our affiliated companies in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

The IRS and other taxing authorities routinely examine our tax returns. We believe that we have filed tax returns with positions that may be challenged by these tax authorities. We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for years prior to 1997. We have reached a negotiated settlement of all outstanding proposed IRS adjustments for years 1997 through 1999 and through June 2000 for the CSW pre-merger tax period and anticipate payment for the agreed adjustments to occur during 2007. Returns for the years 2000 through 2003 are presently being audited by the IRS.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. As of December 31, 2006, we have total provisions for uncertain tax positions of approximately $32 million. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

In 2005, the Energy Tax Incentives Act of 2005 was signed into law. This act created a limited amount of tax credits for the building of IGCC plants. The credit is 20% of the eligible property in the construction of new plant or 20% of the total cost of repowering of an existing plant using IGCC technology. In the case of a newly constructed IGCC plant, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment. We announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits. We filed applications for the Mountaineer and Great Bend projects with the DOE and the IRS. Both projects were certified by the DOE and qualified by the IRS. However, neither project was awarded credits during this round of credit awards. We will continue to pursue credits for the next round of credits in 2009.

The Energy Tax Incentives Act of 2005 also changed the tax depreciation life for transmission assets from 20 years to 15 years. This act also allows for the accelerated amortization of atmospheric pollution control equipment placed in service after April 11, 2005 and installed on plants placed in service on or after January 1, 1976. This provision allows for tax amortization of the equipment over eighty-four months in lieu of taking a depreciation deduction over twenty-years. This act also allows for the transfer (“poured-over”) of funds held in nonqualifying nuclear decommissioning trusts into qualified nuclear decommissioning trusts. The tax deduction may be claimed, as the nonqualified funds are poured-over; the funds are poured-over during the remaining life of the plant. The earnings on funds held in a qualified nuclear decommissioning fund are taxed at a 20% federal rate as opposed to a 35% federal tax rate for nonqualified funds. The tax law changes discussed in this paragraph have not materially affected our results of operations, cash flows, or financial condition.

After Hurricanes Katrina, Rita and Wilma in 2005, a series of tax acts were placed into law to aid in the recovery of the Gulf coast region. The Katrina Emergency Tax Relief Act of 2005 (enacted September 23, 2005) and the Gulf Opportunity Zone Act of 2005 (enacted December 21, 2005) contained a number of provisions to aid businesses and individuals impacted by these hurricanes. The application of these tax acts has not materially affected our results of operations, cash flows, or financial condition.

On June 30, 2005, the Governor of Ohio signed Ohio House Bill 66 into law enacting sweeping tax changes impacting all companies doing business in Ohio. Most of the significant tax changes will be phased in over a five-year period, while some of the less significant changes became fully effective July 1, 2005. Changes to the Ohio franchise tax, nonutility property taxes, and the new commercial activity tax are subject to phase-in. The Ohio franchise tax will fully phase-out over a five-year period beginning with a 20% reduction in state franchise tax for taxable income accrued during 2005. In 2005, we reversed deferred state income tax liabilities of $83 million that are not expected to reverse during the phase-out. We recorded $4 million as a reduction to Income Tax Expense and, for the Ohio companies, established a regulatory liability for $57 million pending rate-making treatment in Ohio. See “Ormet” section of Note 4 for further discussion. For those companies in which state income taxes flow through for rate-making purposes, the adjustments reduced the regulatory assets associated with the deferred state income tax liabilities by $22 million. In November 2006, the PUCO ordered that the $57 million be amortized to income as an offset to power supply contract losses incurred by CSPCo and OPCo for sales to Ormet.

The new legislation also imposes a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts. The new tax is being phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate. The increase in Taxes Other than Income Taxes was approximately $4 million and $2 million for 2006 and 2005, respectively.

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109. Based on the new law, we reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006, we recorded a net reduction to Deferred Income Taxes on our Consolidated Balance Sheet of $48 million of which $2 million was credited to Income Tax Expense and $46 million was credited to Regulatory Assets based upon the related rate-making treatment.

The Tax Increase Prevention and Reconciliation Act of 2005 (TIPRA 2005) was passed May 17, 2006. The majority of the provisions in TIPRA 2005 were directed toward individual income tax relief including the extension of reduced tax rates for dividends and capital gains through 2010. We believe the application of this act will not materially affect our results of operations, cash flows, or financial condition.

The President signed the Pension Protection Act of 2006 (PPA 2006) into law on August 17, 2006. This law is directed toward strengthening qualified retirement plans and adding new restrictions on charitable contributions. Specifically, PPA 2006 concentrates on the funding of defined benefit plans and the health of the Pension Benefit Guaranty Corporation. PPA 2006 imposes new minimum funding rules for multiemployer plans as well as increasing the deduction limitation for contributions to multiemployer defined benefit plans. Due to the significant funding of the AEP pension plans in 2005, the Act will not materially affect our results of operations, cash flows, or financial condition.

On December 20, 2006, the Tax Relief and Health Care Act of 2006 (TRHCA 2006) was signed into law. The primary purpose of the bill was to extend expiring tax provisions for individuals and business taxpayers and provide increased tax flexibility around medical benefits. In addition to extending the lower capital gains and dividend tax rates for individuals, TRHCA 2006 extended the research credit and for 2007 provides a new alternative formula for deterring the research credit. The application of TRHCA 2006 is not expected to materially affect our results of operations, cash flows or financial condition.

        14.    LEASES

Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Net Lease Expense on Operating Leases	 	$	340	 	$	298	 	$	308	 	
Amortization of Capital Leases	 	 	64	 	 	57	 	 	54	 	
Interest on Capital Leases	 	 	17	 	 	13	 	 	11	 	
Total Lease Rental Costs	 	$	421	 	$	368	 	$	373	 	

The following table shows the property, plant and equipment under capital leases and related obligations recorded on our Consolidated Balance Sheets. Capital lease obligations are included in Current Liabilities - Other and Noncurrent Liabilities - Deferred Credits and Other on our Consolidated Balance Sheets.

 	 	December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Property, Plant and Equipment Under Capital Leases	 	  	 	  	 	
Production	 	$	94	 	$	95	 	
Distribution	 	 	15	 	 	15	 	
Other	 	 	360	 	 	331	 	
Construction Work in Progress	 	 	30	 	 	-	 	
Total Property, Plant and Equipment Under Capital Leases	 	 	499	 	 	441	 	
Accumulated Amortization	 	 	210	 	 	190	 	
Net Property, Plant and Equipment Under Capital Leases	 	$	289	 	$	251	 	
 	 	 	 	 	 	 	 	
Obligations Under Capital Leases	 	 	 	 	 	 	 	
Noncurrent Liability	 	$	210	 	$	193	 	
Liability Due Within One Year	 	 	81	 	 	58	 	
Total Obligations Under Capital Leases	 	$	291	 	$	251	 	

Future minimum lease payments consisted of the following at December 31, 2006:

 	 	Capital Leases	 	Noncancelable Operating Leases	 	
 	 	(in millions)	 	
2007	 	$	90	 	$	331	 	
2008	 	 	68	 	 	312	 	
2009	 	 	49	 	 	287	 	
2010	 	 	28	 	 	260	 	
2011	 	 	15	 	 	230	 	
Later Years	 	 	126	 	 	1,893	 	
Total Future Minimum Lease Payments	 	$	376	 	$	3,313	 	
Less Estimated Interest Element	 	 	85	 	 	 	 	
Estimated Present Value of Future  Minimum Lease Payments	 	$	291	 	 	 	 	
 
Rockport Lease

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale and leaseback transaction as of December 31, 2006 are as follows:

 	 	AEGCo	 	I&M	 	
 	 	(in millions)	 	
2007	 	$	74	 	$	74	 	
2008	 	 	74	 	 	74	 	
2009	 	 	74	 	 	74	 	
2010	 	 	74	 	 	74	 	
2011	 	 	74	 	 	74	 	
Later Years	 	 	812	 	 	812	 	
Total Future Minimum Lease Payments	 	$	1,182	 	$	1,182	 	

Railcar Lease

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years. At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years; (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value; or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. We intend to renew the lease for the full twenty years. This operating lease agreement allows us to avoid a large initial capital expenditure and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the current lease term from approximately 86% to 77% of the projected fair market value of the equipment. At December 31, 2006, the maximum potential loss was approximately $31 million ($20 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. We have other railcar lease arrangements that do not utilize this type of financing structure.

Sabine Dragline Lease

In December 2006, Sabine Mining Company (Sabine), an entity consolidated under FIN 46, entered into a capital lease agreement with a nonaffiliated company to finance the purchase of a $51 million electric dragline for Sabine’s mining operations. The initial capital outlay for the dragline was $26 million with an additional estimated $25 million of transportation, assembly and upgrade costs to be incurred prior to the completion date of mid-2008. These additional costs will be added to our consolidated lease assets and capital lease obligations as they are incurred. Sabine will pay interim rent on a quarterly basis starting in March 2007 and continue through the completion date of mid-2008. Once the dragline is fully assembled, Sabine will pay capital and interest payments on the outstanding lease obligation. At December 31, 2006, the capital lease asset is included in Construction Work in Progress and the capital lease obligation is included in Noncurrent Liabilities - Deferred Credits and Other on our 2006 Consolidated Balance Sheet. We calculated future payments using both interim rent prior to completion and capital and interest from completion until the maturity of the lease solely using the initial capital outlay of $26 million.

         15.   FINANCING ACTIVITIES

Common Stock

Common Stock Repurchase

In February 2005, our Board of Directors authorized the repurchase of up to $500 million of our common stock from time to time through 2006. In March 2005, we purchased 12.5 million shares of our outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share plus transaction fees. The purchase of shares in the open market was completed by a broker-dealer in May 2005 and we received a purchase price adjustment of $6.45 million based on the actual cost of the shares repurchased. Based on this adjustment, our actual stock purchase price averaged $34.18 per share. Management has not established a timeline for the buyback of the remaining stock under this plan.

Equity Units and Remarketing of Senior Notes

In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consisted of a forward purchase contract and a senior note. In June 2005, we remarketed and settled $345 million of our 5.75% senior notes at a new interest rate of 4.709%. The senior notes mature on August 16, 2007. We did not receive any proceeds from the mandatory remarketing.

Issuance of Common Stock

On August 16, 2005, we issued approximately 8.4 million shares of common stock in connection with the settlement of forward purchase contracts that formed a part of our outstanding 9.25% equity units. In exchange for $50 per equity unit, holders of the equity units received 1.2225 shares of AEP common stock for each purchase contract and cash in lieu of fractional shares. Each holder was not required to make any additional cash payment. The equity unit holder’s purchase obligation was satisfied from the proceeds of a portfolio of U.S. Treasury securities held in a collateral account that matured on August 1, 2005. The portfolio of U.S. Treasury securities was acquired in connection with the June 2005 remarketing of the senior notes discussed above.

We issued 2.3 million, 1.9 million and 0.5 million shares of common stock in connection with our stock option plan during 2006, 2005 and 2004, respectively.

Set forth below is a reconciliation of common stock share activity for the years ended December 31, 2006, 2005 and 2004:
 
Shares of Common Stock	 	Issued	 	Held in Treasury	 	
Balance, January 1, 2004	 	 	404,016,413	 	 	8,999,992	 	
Issued	 	 	841,732	 	 	-	 	
Balance, December 31, 2004	 	 	404,858,145	 	 	8,999,992	 	
Issued	 	 	10,360,685	 	 	-	 	
Treasury Stock Acquisition	 	 	-	 	 	12,500,000	 	
Balance, December 31, 2005	 	 	415,218,830	 	 	21,499,992	 	
Issued	 	 	2,955,898	 	 	-	 	
Balance, December 31, 2006	 	 	418,174,728	 	 	21,499,992	 	

Preferred Stock

Information about the components of preferred stock of our subsidiaries is as follows:

 	 	December 31, 2006	 	
 	 	Call Price
Per Share (a)	 	Shares
Authorized (b)	 	Shares
Outstanding (c)	 	Amount
(in millions)	 	
Not Subject to Mandatory Redemption:	 	 	 	 	 	 	 	  	 	
4.00% - 5.00%	 	 	$102-$110	 	 	1,525,903	 	 	607,044	 	$	61	 	
 	 	 	
 	 	December 31, 2005  	
	 	  Call Price
Per Share (a)	 	  Shares
Authorized (b)	 	  Shares Outstanding (c)	 	  Amount
(in millions)	 	
Not Subject to Mandatory Redemption:	 	 	 	 	 	 	 	 	 	 	 	 	 	
4.00% - 5.00%	 	 	$102-$110	 	 	1,525,903	 	 	607,642	 	$	61	 	

(a)	At the option of the subsidiary, the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares.	
(b)	As of December 31, 2006, the subsidiaries had 14,487,993 shares of $100 par value preferred stock, 22,200,000 shares of $25 par value preferred stock and 7,822,366 shares of no par value preferred stock that were authorized but unissued. As of December 31, 2005, the subsidiaries had 14,487,597 shares of $100 par value preferred stock, 22,200,000 shares of $25 par value preferred stock and 7,822,164 shares of no par value preferred stock that were authorized but unissued.	
(c)	The number of shares of preferred stock redeemed is 598 shares in 2006, 664,470 shares in 2005 and 96,378 shares in 2004.	

Long-term Debt
Type of Debt and	 	Weighted Average Interest Rate
December 31,	 	Interest Rate Range at
December 31,	 	December 31,	 	
Maturity	 	2006	 	2006	 	2005	 	2006	 	2005	 	
 	 	 	 	 	 	 	 	(in millions)	 	
SENIOR UNSECURED NOTES (a)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2006-2011	 	5.11%	 	3.60%-6.91%	 	3.60%-6.91%	 	$	3,085	 	$	3,529	 	
 	2012-2017	 	5.41%	 	4.85%-6.375%	 	4.85%-6.375%	 	 	2,793	 	 	2,568	 	
 	2032-2037	 	6.20%	 	5.625%-6.65%	 	5.625%-6.65%	 	 	2,775	 	 	2,125	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
POLLUTION CONTROL BONDS (b)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2006-2011	 	4.12%	 	3.60%-4.90%	 	2.70%-4.55%	 	 	181	 	 	204	 	
 	2014-2024	 	4.28%	 	3.50%-6.05%	 	2.625%-6.10%	 	 	811	 	 	794	 	
 	2025-2038	 	4.06%	 	3.53%-6.125%	 	2.625%-6.55%	 	 	958	 	 	937	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NOTES PAYABLE (c)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2006-2017	 	6.86%	 	4.47%-9.60%	 	4.47%-15.25%	 	 	337	 	 	904	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SECURITIZATION BONDS (d)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2008-2021	 	5.32%	 	4.98%-6.25%	 	5.01%-6.25%	 	 	2,335	 	 	648	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
FIRST MORTGAGE BONDS (e)	 	
 	2006-2008 (f)	 	7.07%	 	7.00%-7.75%	 	6.20%-7.75%	 	 	117	 	 	222	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NOTES PAYABLE TO TRUST  	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2043	 	5.25%	 	5.25%	 	5.25%	 	 	113	 	 	113	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SPENT NUCLEAR FUEL OBLIGATION (g)	 	 	 	 	 	 	 	 	247	 	 	236	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
OTHER LONG-TERM DEBT (h)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2026	 	13.718%	 	13.718%	 	13.718%	 	 	2	 	 	4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unamortized Discount (net)	 	 	 	 	 	 	 	 	(56	)	 	(58	)	
Total Long-term Debt Outstanding	 	 	 	 	 	 	 	 	13,698	 	 	12,226	 	
Less Portion Due Within One Year	 	 	 	 	 	 	 	 	1,269	 	 	1,153	 	
Long-term Portion	 	 	 	 	 	 	 	$	12,429	 	$	11,073	 	
 
(a)	Certain senior unsecured notes have been adjusted for MTM of Fair Value Hedges associated with the debt.	
(b)	For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.	
(c)	Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.	
(d)	In October 2006, AEP Texas Central Transition Funding II LLC (TFII), a subsidiary of TCC, issued $1.7 billion in securitization bonds with interest rates ranging from 4.98% to 5.3063% and final maturity dates ranging from January 2012 to July 2021. Scheduled final payment dates range from January 2010 to July 2020. TFII is the sole owner of the transition charges and the original transition property. The holders of the securitization bonds do not have recourse to any assets or revenues of TCC. The creditors of TCC do not have recourse to any assets or revenues of TFII, including, without limitation, the original transition property.	
(e)	First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment. There are certain limitations on establishing additional liens against our assets under our indentures.	
(f)	In May 2004, we deposited cash and treasury securities with a trustee to defease all of TCC’s outstanding First Mortgage Bonds. The defeased TCC First Mortgage Bonds had balances of $19 million in 2006 and 2005. Trust fund assets related to this obligation of $2 million are included in Other Temporary Cash Investments and $21 million are included in Other Noncurrent Assets on our Consolidated Balance Sheets at December 31, 2006 and 2005. In December 2005, we deposited cash and treasury securities with a trustee to defease the remaining TNC outstanding First Mortgage Bond. The defeased TNC First Mortgage Bond has a balance of $8 million at December 31, 2006 and 2005. Trust fund assets related to this obligation of $9 million and $1 million at December 31, 2006 and 2005, respectively, are included in Other Temporary Cash Investments and $8 million is included in Other Noncurrent Assets on our Consolidated Balance Sheets at December 31, 2005. Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.	
(g)	Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 10).	
(h)	Other long-term debt consists of a financing obligation under a sale and leaseback agreement.	

LONG-TERM DEBT OUTSTANDING AT DECEMBER 31, 2006 IS PAYABLE AS FOLLOWS:

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After 2011	 	Total	 	
 	 	(in millions)	 	
Principal Amount	 	$	1,269	 	$	650	 	$	485	 	$	1,315	 	$	596	 	$	9,439	 	$	13,754	 	
Unamortized Discount	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(56	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	13,698	 	

Dividend Restrictions

Under the Federal Power Act, AEP’s public utility subsidiaries can only pay dividends out of retained or current earnings unless they obtain prior FERC approval.

Trust Preferred Securities

SWEPCo has a wholly-owned business trust that issued trust preferred securities. Effective July 1, 2003, the trust was deconsolidated due to the implementation of FIN 46. The SWEPCo trust, which holds mandatorily redeemable trust preferred securities, is reported as two components on our Consolidated Balance Sheets. The investment in the trust, which was $3 million as of December 31, 2006 and 2005, is included in Deferred Charges and Other within Other Noncurrent Assets. The Junior Subordinated Debentures, in the amount of $113 million as of December 31, 2006 and 2005, are reported as Notes Payable to Trust within Long-term Debt.

The business trust is treated as a nonconsolidated subsidiary of SWEPCo. The only asset of the business trust is the subordinated debentures issued by SWEPCo as specified above. In addition to the obligations under the subordinated debentures, SWEPCo also agreed to a security obligation, which represents a full and unconditional guarantee of its capital trust obligation.

Lines of Credit and Short-term Debt - AEP System

We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2006, we had credit facilities totaling $3 billion to support our commercial paper program. As of December 31, 2006, AEP’s commercial paper outstanding related to the corporate borrowing program was $0. For the corporate borrowing program the maximum amount of commercial paper outstanding during the year was $325 million in March 2006 and the weighted average interest rate of commercial paper outstanding during the year was 4.96%. Our outstanding short-term debt was as follows:

 	 	At December 31, 2006	 	At December 31, 2005	 	
Type of Debt	 	Outstanding
Amount	 	Interest
Rate	 	Outstanding
Amount	 	Interest
Rate	 	
 	 	(in millions)	 	  	 	(in millions)	 	  	 	
Commercial Paper - JMG (a)	 	$	1	 	 	5.56	%	$	10	 	 	4.47	%	
Line of Credit - Sabine	 	 	17	 	 	6.38	%	 	-	 	 	-	 	
Total	 	$	18	 	 	 	 	$	10	 	 	 	 	

(a)	This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility. This commercial paper does not reduce our available liquidity.	

Sale of Receivables - AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires from affiliated utility subsidiaries to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” allowing the receivables to be taken off of AEP Credit’s balance sheet and allowing AEP Credit to repay any debt obligations. We have no ownership interest in the commercial paper conduits and are not required to consolidate these entities in accordance with GAAP. AEP Credit continues to service the receivables. We entered into this off-balance sheet transaction to allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables, and accelerate AEP Credit’s cash collections.

AEP Credit’s sale of receivables agreement expires on August 24, 2007. We intend to extend or replace the sale of receivables agreement. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2006, $536 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent receivables purchased by AEP Credit from certain Registrant Subsidiaries. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit also purchases accounts receivable from KGPCo.

Comparative accounts receivable information for AEP Credit is as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
 	 	($ in millions)	 	
Proceeds from Sale of Accounts Receivable	 	$	6,849	 	$	5,925	 	$	5,163	 	
Loss on Sale of Accounts Receivable	 	$	31	 	$	18	 	$	7	 	
Average Variable Discount Rate	 	 	5.02	%	 	3.23	%	 	1.50	%	

 	 	December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Accounts Receivable Retained Interest and Pledged as 
  Collateral Less  Uncollectible Accounts	 	$	87	 	$	106	 	
Deferred Revenue from Servicing Accounts Receivable	 	 	1	 	 	1	 	
Retained Interest if 10% Adverse Change in  Uncollectible Accounts	 	 	85	 	 	103	 	
Retained Interest if 20% Adverse Change in  Uncollectible Accounts	 	 	83	 	 	101	 	
 
Historical loss and delinquency amounts for the AEP System’s customer accounts receivable managed portfolio is as follows:
 
 	 	Face Value
December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Customer Accounts Receivable Retained	 	$	676	 	$	826	 	
Accrued Unbilled Revenues Retained	 	 	350	 	 	374	 	
Miscellaneous Accounts Receivable Retained	 	 	44	 	 	51	 	
Allowance for Uncollectible Accounts Retained	 	 	(30	)	 	(31	)	
Total Net Balance Sheet Accounts Receivable	 	 	1,040	 	 	1,220	 	
Customer Accounts Receivable Securitized	 	 	536	 	 	516	 	
Total Accounts Receivable Managed	 	$	1,576	 	$	1,736	 	
 	 	 	 	 	 	 	 	
Net Uncollectible Accounts Written Off	 	$	31	 	$	74	 	

Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous accounts receivable have been fully retained and not securitized.

Delinquent customer accounts receivable for the electric utility affiliates that AEP Credit currently factors were $29 million and $30 million at December 31, 2006 and 2005, respectively. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

         16.   STOCK-BASED COMPENSATION

As previously approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP) authorizes the use of 19,200,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. A maximum of 9,000,000 shares may be used under this plan for full value shares awards, which include performance units, restricted shares and restricted stock units. The Board of Directors and shareholders both adopted the original LTIP in 2000 and the amended and restated version in 2005. We have not granted options as part of our regular stock-based compensation program since 2003. However, we have used options in limited circumstances totaling 149,000 options in 2004, 10,000 options in 2005 and none during 2006. The following sections provide further information regarding each type of stock-based compensation award granted by the Board of Directors.

We adopted SFAS 123R, effective January 1, 2006. S ee the SFAS 123 (revised 2004) “Share-Based Payment (SFAS 123R)” section of Note 2 for additional information.

Stock Options

For all stock options granted, the exercise price equaled or exceeded the market price of AEP’s common stock on the date of grant. Stock options were granted with a ten-year term and generally vested, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1 st of the year following the first, second and third anniversary of the grant date. Compensation cost for stock options is recorded over the vesting period based on the fair value on the grant date. The LTIP does not specify a maximum contractual term for stock options.

CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, we converted all CSW stock options outstanding into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. We adjusted the exercise price for each CSW stock option for the exchange ratio. No CSW stock options remained outstanding as of December 31, 2006. The remaining stock options were exercised in the fourth quarter of 2006.

The total fair value of stock options vested and the total intrinsic value of options exercised during the years ended December 31, 2006, 2005 and 2004 are as follows:
 
 	 	2006	 	2005	 	2004	 	
Stock Options	 	(in thousands)	 	
Fair Value of Stock Options Vested	 	$	3,667	 	$	5,036	 	$	14,504	 	
Intrinsic Value of Options Exercised (a)	 	 	16,823	 	 	12,091	 	 	3,182	 	

(a) Intrinsic value is calculated as market price at exercise date less the option exercise price.

A summary of AEP stock option transactions during the years ended December 31, 2006, 2005 and 2004 is as follows:
 
 	 	2006	 	2005	 	2004	 	
 	 	Options	 	Weighted Average Exercise Price	 	Options	 	Weighted Average Exercise Price	 	Options	 	Weighted Average Exercise Price	 	
 	 	(in thousands)	 	 	 	(in thousands)	 	  	 	(in thousands)	 	 	 	
 	 	 	 	  	 	 	 	  	 	 	 	  	 	
Outstanding at January 1,	 	 	6,222	 	$	34.16	 	 	8,230	 	$	33.29	 	 	9,095	 	$	33.03	 	
Granted	 	 	-	 	 	N/A	 	 	10	 	 	38.65	 	 	149	 	 	30.76	 	
Exercised/Converted	 	 	(2,343	)	 	33.12	 	 	(1,886	)	 	36.94	 	 	(525	)	 	27.10	 	
Forfeited/Expired	 	 	(209	)	 	41.58	 	 	(132	)	 	31.97	 	 	(489	)	 	34.33	 	
Outstanding at December 31,	 	 	3,670	 	 	34.41	 	 	6,222	 	 	34.16	 	 	8,230	 	 	33.29	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Options exercisable at December 31,	 	 	3,411	 	$	34.83	 	 	5,199	 	$	35.40	 	 	6,069	 	$	35.05	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average exercise price of options:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Granted above Market Price	 	 	 	 	 	N/A	 	 	 	 	 	N/A	 	 	 	 	 	N/A	 	
Granted at Market Price	 	 	 	 	 	N/A	 	 	 	 	$	38.65	 	 	 	 	$	30.76	 	

The following table summarizes information about AEP stock options outstanding at December 31, 2006.

  Options Outstanding
2006 Range of
Exercise Prices	 	  Number
Outstanding	 	  Weighted
Average
Remaining Life	 	Weighted
Average
Exercise Price	 	Aggregate
Intrinsic Value	 	
 	 	  (in thousands)	 	  (in years)	 	  	 	(in thousands)	 	
$25.73 - $27.95	 	 	902	 	 	6.07	 	$	27.45	 	$	13,651	 	
$30.76 - $38.65	 	 	2,401	 	 	3.29	 	 	35.34	 	 	17,392	 	
$43.79 - $49.00	 	 	367	 	 	4.39	 	 	45.43	 	 	-	 	
Total   (a)	 	 	3,670	 	 	4.08	 	 	34.41	 	$	31,043	 	
 
(a) Options outstanding are not significantly different from the number of shares expected to vest.
 
The following table summarizes information about AEP stock options exercisable at December 31, 2006.

  Options Exercisable
2006 Range of
Exercise Prices	 	  Number
Exercisable	 	  Weighted
Average
Remaining Life	 	Weighted
Average
Exercise Price	 	Aggregate
Intrinsic
Value	 	
 	 	  (in thousands)	 	  (in years)	 	  	 	(in thousands)	 	
$25.73 - $27.95	 	 	702	 	 	5.83	 	$	27.32	 	$	10,715	 	
$30.76 - $35.63	 	 	2,342	 	 	3.19	 	 	35.42	 	 	16,766	 	
$43.79 - $49.00	 	 	367	 	 	4.39	 	 	45.43	 	 	-	 	
Total	 	 	3,411	 	 	3.86	 	 	34.83	 	$	27,481	 	

We include the proceeds received from exercised stock options in common stock and paid-in capital. For options granted through December 31, 2006, we estimated the grant date fair value of each option award using a Black-Scholes option-pricing model with weighted average assumptions. We estimated expected volatilities using the historical monthly volatility of our common stock for the thirty-six-month period prior to each grant. We also assumed a seven-year average expected term. The risk-free rate is the yield for U.S. Treasury securities with a remaining life equal to the expected seven-year term of AEP stock options on the grant date.

We used the following weighted average assumptions to estimate the fair value of AEP stock options granted in 2005 and 2004. No stock options were granted in 2006.
 	 	2006	 	2005	 	2004	 	
Risk Free Interest Rate	 	 	N/A	 	 	4.14	%	 	4.14	%	
Expected Volatility	 	 	N/A	 	 	24.63	%	 	28.17	%	
Expected Dividend Yield	 	 	N/A	 	 	4.00	%	 	4.84	%	
Expected Life	 	 	N/A	 	 	7 years	 	 	7 years	 	
 	 	 	 	 	 	 	 	 	 	 	
Weighted average fair value of options:	 	 	 	 	 	 	 	 	 	 	
Granted above Market Price	 	 	N/A	 	 	N/A	 	 	N/A	 	
Granted at Market Price	 	 	N/A	 	$	7.60	 	$	6.06	 	

Performance Units

Our performance units are equal in value to an equivalent number of shares of AEP common stock. The number of performance units held is multiplied by a performance score to determine the actual number of performance units realized. The performance score is determined at the end of the performance period based on performance measure(s) established for each grant at the beginning of the performance period by the Human Resources Committee of the Board of Directors (HR Committee) and can range from 0 percent to 200 percent. Performance units are typically paid in cash at the end of a three-year performance and vesting period, unless they are needed to satisfy a participant’s stock ownership requirement, in which case they are mandatorily deferred as AEP Career Shares, a form of phantom stock units, until after the end of the participant’s AEP career. AEP Career Shares have a value equivalent to the market value of an equal number of AEP common shares and are generally paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP Career Shares accrue as additional units. The compensation cost for performance units is recorded over the vesting period and the liability, recorded in Employee Benefits and Pension Obligations on our Consolidated Balance Sheets, for both the performance units and AEP Career Shares is adjusted for changes in value. The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation. The vesting period of all performance units is three years.

Our Board of Directors awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the years ended December 31, 2006, 2005 and 2004 as follows:

 	 	2006	 	2005	 	2004	 	
Performance Units	 	 	 	
Awarded Units (in thousands)	 	 	1,635	 	 	1,013	 	 	119	 	
Weighted Average Unit Fair Value at Grant Date	 	$	39.75	 	$	34.02	(a)	$	30.76	(a)	
Vesting Period (years)	 	 	3	 	 	3	 	 	3	 	

(a)    The unit fair value is the actual value at the grant date because there was only one award in that period.	

Performance Units and AEP Career Shares
(Reinvested Dividends Portion)	 	 	 	 	 	 	 	 	 	 	
Awarded Units (in thousands)	 	 	118	 	 	89	 	 	61	 	
Weighted Average Grant Date Fair Value	 	$	36.87	 	$	36.25	 	$	32.92	 	
Vesting Period (years)	 	 	(a)	 	 	(a)	 	 	(a)	 	

(a)	Vesting Period (years) range from 0 to 3 years. The Vesting Period of the reinvested dividends is equal to the remaining life of the related performance units and AEP Career Shares.	

Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures. The HR Committee has discretion to reduce or eliminate the value of final awards, but may not increase them. The performance scores for all open performance periods are dependent on two equally-weighted performance measures: three-year total shareholder return measured relative to the S&P Utilities Index and three-year cumulative earnings per share measured relative to a board-approved target.   The value of each performance unit earned equals the average closing price of AEP common stock for the last 20 days of the performance period.  In January 2006, the HR Committee certified a performance score for the three-year period ended December 31, 2005 of 49%. As a result, 108,486 performance units were earned. Of this amount 33,296 were mandatorily deferred as AEP Career Shares, 4,360 were voluntarily deferred into the Incentive Compensation Deferral Program and the remainder were paid in cash.  The certified performance score for the three-year performance period ended December 31, 2004 was 0%.

Due to the anticipated 2004 CEO succession, on December 10, 2003 the HR Committee made performance unit grants for the shortened performance period of December 10, 2003 through December 31, 2004. No performance period ended on December 31, 2006 because this performance period was shorter than the normal three-year period used by us and there were no other performance unit grants in 2003. In 2005, the HR Committee certified a performance factor of 123.1% for performance units granted on December 10, 2003 and 946,789 performance units were mandatorily deferred into AEP stock units, of which 917,032 units vested on December 31, 2006 and the remainder were forfeited due to participant terminations. These stock units have the same value, dividend rights, vesting and accounting treatment as the performance units that gave rise to them, except that they are no longer subject to performance measures.
 
The cash payouts for the years ended December 31, 2006, 2005 and 2004 were as follows:
 
 	 	2006	 	2005	 	2004	 	
 	 	(in thousands)	 	
Cash Payouts for Performance Units	 	$	2,630	 	$	-	 	$	-	 	
Cash Payouts for AEP Career Share Distributions	 	 	1,079	 	 	1,373	 	 	673	 	

Restricted Shares and Restricted Stock Units

Our Board of Directors granted 300,000 restricted shares to the Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment. Of these restricted shares, 50,000 vested on January 1, 2005 and 50,000 vested on January 1, 2006. The remaining 200,000 restricted shares vest, subject to his continued employment, in approximately equal thirds on November 30, 2009, 2010 and 2011. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of shares granted by the grant date market price of $30.76. The maximum term for these restricted shares is eight years. The Board of Directors has not granted other restricted shares. Dividends on our restricted shares are paid in cash.

Our Board of Directors may also grant restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments on the anniversaries of the grant date. Amounts equivalent to dividends paid on RSUs accrue as additional RSUs and vest on the last vesting date associated with the underlying units. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of units granted by the grant date market price. The maximum contractual term of RSUs is six years.

In January 2006, our Board of Directors also granted RSUs with performance vesting conditions to certain employees who are integral to our project to design and build proposed IGCC power plants. Twenty percent of these awards vest on each of the first three anniversaries of the grant date. An additional 20% vest on the date the IGCC plant achieves commercial operations. The remaining 20% vest one year after the IGCC plant achieves commercial operations, subject to achievement of plant availability targets.

Our Board of Directors awarded RSUs, including units awarded for dividends, for the years ended December 31, 2006, 2005 and 2004 as follows:
 
  	 	2006	 	2005	 	2004	 	
Restricted Stock Units	 	 	 	
Awarded Units (in thousands)	 	 	65	 	 	166	 	 	106	 	
Weighted Average Grant Date Fair Value	 	$	37.47	 	$	35.67	 	$	32.03	 	

The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the years ended December 31, 2006, 2005 and 2004 were as follows:
 
 	 	2006	 	2005	 	2004	 	
Restricted Shares and Restricted Stock Units	 	(in thousands)	 	
Fair Value of Restricted Shares and Restricted Stock Units Vested	 	$	3,939	 	$	3,087	 	$	577	 	
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested (a)	 	 	4,686	 	 	3,703	 	 	809	 	

(a)	Intrinsic value is calculated as market price.	

A summary of the status of our nonvested restricted shares and RSUs as of December 31, 2006, and changes during the year ended December 31, 2006 are as follows:
 
Nonvested Restricted Shares and
Restricted Stock Units	 	Shares/Units	 	  Weighted Average Grant Date Fair Value	 	
 	 	(in thousands)	 	  	 	
Nonvested at January 1, 2006	 	 	497	 	$	32.19	 	
Granted	 	 	65	 	 	37.47	 	
Vested	 	 	(129	)	 	30.63	 	
Forfeited	 	 	(25	)	 	35.72	 	
Nonvested at December 31, 2006	 	 	408	 	 	33.31	 	

The total aggregate intrinsic value of nonvested restricted shares and RSUs as of December 31, 2006 was $17 million and the weighted average remaining contractual life was 2.74 years.

Other Stock-Based Plans

We also have a Stock Unit Accumulation Plan for Non-Employee Directors providing each nonemployee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The Non-Employee Directors vest immediately upon award of the stock units. Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash payments for stock units are calculated based on the average closing price of AEP common stock for the 20 trading days immediately preceding the payment date.

The compensation cost for stock units is recorded when the units are awarded, and the liability is adjusted for changes in value based on the current 20-day average closing price of AEP common stock at the date of valuation.

We had no material cash payouts for stock unit distributions for the years ended December 31, 2006, 2005 and 2004.

Our Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2006, 2005 and 2004 as follows:
 	 	2006	 	2005	 	2004	 	
Stock Unit Accumulation Plan for Non-Employee Directors	 	 	 	
Awarded Units (in thousands)	 	 	33	 	 	27	 	 	30	 	
Weighted Average Grant Date Fair Value	 	$	36.66	 	$	36.74	 	$	32.81	 	

Share-based Compensation Plans

Compensation cost and the actual tax benefit realized for the tax deductions from compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2006, 2005 and 2004 were as follows:
 
 	 	2006	 	2005	 	2004	 	
Share-based Compensation Plans	 	(in thousands)	 	
Compensation Cost for Share-based Payment Arrangements (a)	 	$ 	45,842	 	$ 	28,660	 	$ 	19,721	 	
Actual Tax Benefit Realized	 	 	16,045	 	 	10,031	 	 	6,902	 	
Total Compensation Cost Capitalized	 	 	10,953	 	 	5,113	 	 	3,518	 	
 
(a)	  Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance on our Consolidated Statements of Income.	
 
During the years ended December 31, 2006, 2005 and 2004, there were no significant modifications affecting any of our share-based payment arrangements.

As of December 31, 2006, there was $90 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the LTIP. Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the liability is revalued each period and forfeitures for all award types are realized. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.64 years.

Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended December 31, 2006, 2005 and 2004 were as follows:

 	 	2006	 	2005	 	2004	 	
Share-based Compensation Plans	 	(in thousands)	 	
Cash received from stock options exercised	 	$	77,534	 	$	57,546	 	$	14,250	 	
Actual tax benefit realized for the tax deductions from stock options exercised	 	 	5,825	 	 	4,235	 	 	1,107	 	

Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting. Although we do not currently anticipate any changes to this practice, we could use reacquired shares, shares acquired in the open market specifically for distribution under the LTIP or any combination thereof for this purpose. The number of new shares issued to fulfill vesting RSUs is generally reduced, at the participant’s election, to offset AEP’s tax withholding obligation.
 
         17.   PROPERTY, PLANT AND EQUIPMENT

We provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class as follows:

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class
of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate Ranges	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate Ranges	 	Depreciable Life Ranges	
 	 	(in millions)	 	(%)	 	(in years)	 	(in millions)	 	(%)	 	(in years)	
Production	 	$	7,892	 	$	4,437	 	2.6 - 3.8	 	30 - 121	 	$	8,895	 	$	3,886	 	2.57 - 9.15	 	20 - 121	
Transmission	 	 	7,018	 	 	2,332	 	1.6 - 2.9	 	25 - 87	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	11,338	 	 	3,121	 	3.0 - 4.0	 	11 - 75	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	1,423	 	 	(41	)	N.M.	 	N.M.	 	 	2,050	 	 	2	 	N.M.	 	N.M.	
Other	 	 	2,400	 	 	1,067	 	6.7 - 11.5	 	24 - 55	 	 	1,005	 	 	436	 	N.M.	 	N.M.	
Total	 	$	30,071	 	$	10,916	 	 	 	 	 	$	11,950	 	$	4,324	 	 	 	 	

 
2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class
of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate Ranges	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate Ranges	 	Depreciable Life Ranges	
 	 	(in millions)	 	(%)	 	(in years)	 	(in millions)	 	(%)	 	(in years)	
Production	 	$	7,411	 	$	4,166	 	2.7 - 3.8	 	30 - 120	 	$	9,095	 	$	4,019	 	2.6 - 3.3	 	20 - 120	
Transmission	 	 	6,433	 	 	2,280	 	1.7 - 3.0	 	25 - 75	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	10,702	 	 	3,085	 	3.1 - 4.1	 	10 - 75	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	1,341	 	 	(14	) 	N.M.	 	N.M.	 	 	 876	 	 	(3	) 	N.M.	 	N.M.	
Other	 	 	2,266	 	 	992	 	5.1 - 16.0	 	N.M.	 	 	997	 	 	312	 	2.0 - 4.9	 	2 - 37	
Total	 	$	28,153	 	$	10,509	 	 	 	 	 	$	10,968	 	$	4,328	 	 	 	 	

 
2004	 	Regulated	 	 Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate Ranges	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate Ranges	 	Depreciable Life Ranges	 	
 	 	(%)	 	(in years)	 	(%)	 	(in years)	 	
Production	 	2.7 - 3.8	 	30 - 120	 	2.6 - 3.9	 	20 - 120	 	
Transmission	 	1.7 - 3.0	 	25 - 75	 	N.M.	 	N.M.	 	
Distribution	 	3.2 - 4.1	 	10 - 75	 	N.M.	 	N.M.	 	
Other	 	5.4 - 16.4	 	N.M.	 	2.0 - 14.2	 	0 - 50	 	

N.M. = Not Meaningful

We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense. Average amortization rates for coal rights and mine development costs were $0.66, $0.66 and $0.65 per ton in 2006, 2005 and 2004, respectively.

For cost-based rate-regulated operations, the composite depreciation rate generally includes a component for nonasset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred (see “Accounting for Asset Retirement Obligations (ARO)” section of this note).

Accounting for Asset Retirement Obligations (ARO)

We implemented SFAS 143 effective January 1, 2003. SFAS 143 requires entities to record a liability at fair value for any legal obligations for future asset retirements when the related assets are acquired or constructed. Upon establishment of a legal liability, SFAS 143 requires a corresponding ARO asset to be established, which will be depreciated over its useful life. ARO accounting is being followed for regulated and nonregulated property that has a legal obligation related to asset retirement. Upon settlement of an ARO, any difference between the ARO liability and actual costs is recognized as income or expense.

We adopted FIN 47 during the fourth quarter of 2005. FIN 47 interprets the application of SFAS 143, “Accounting for Asset Retirement Obligations.” It clarifies that conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Entities are required to record a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO.

We completed a review of our FIN 47 conditional ARO during the fourth quarter of 2005 and concluded that we have legal liabilities for asbestos removal and disposal in general buildings and generating plants. In 2005, we recorded $55 million of conditional ARO in accordance with FIN 47. The cumulative effect of certain retirement costs for asbestos removal related to our regulated operations was generally charged to regulatory liability. Of the $55 million, we recorded an unfavorable cumulative effect of $26 million ($17 million, net of tax) for our nonregulated generation operations related to asbestos removal in the Utility Operations segment.

We have legal obligations for asbestos removal and for the retirement of certain ash ponds, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. As of December 31, 2006 and 2005, our ARO liability was $1,028 million and $946 million, respectively, and included $803 million and $731 million for nuclear decommissioning of the Cook Plant. As of December 31, 2006 and 2005, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $974 million and $870 million, respectively, relating to the Cook Plant and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on our Consolidated Balance Sheets.

We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets, as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.

Pro forma net income and earnings per share are not presented for the year ended December 31, 2004 because the pro forma application of FIN 47 would result in pro forma net income and earnings per share not materially different from the actual amounts reported during those periods. As of December 31, 2004, the pro forma liability for conditional ARO which has been calculated as if FIN 47 had been adopted at the beginning of each period was $52 million.
 
The following is a reconciliation of the 2005 and 2006 aggregate carrying amounts of ARO:

 	 	Amount
(in millions)	 	
ARO at January 1, 2005, Including Held for Sale	 	$	1,076	 	
Accretion Expense	 	 	63	 	
Liabilities Incurred (a)	 	 	76	 	
Liabilities Settled	 	 	(4	)	
Revisions in Cash Flow Estimates	 	 	(9	)	
Less ARO Liability for:	 	 	 	 	
South Texas Project (b)	 	 	(256	)	
ARO at December 31, 2005 (c)	 	 	946	 	
Accretion Expense	 	 	63	 	
Liabilities Incurred	 	 	9	 	
Liabilities Settled	 	 	(20	)	
Revisions in Cash Flow Estimates	 	 	30	 	
ARO at December 31, 2006 (d)	 	$	1,028	 	

(a)	Includes $55 million of ARO relating to the adoption of FIN 47.	
(b)	The ARO related to nuclear decommissioning costs for TCC’s share of STP was transferred to the buyer in connection with the May 2005 sale (see “Dispositions” section of Note 8).	
(c)	The current portion of our ARO, totaling $10 million, is included in Other in the Current Liabilities section of our 2005 Consolidated Balance Sheet.	
(d)	The current portion of our ARO, totaling $5 million is included in Other in the Current Liabilities section of our 2006 Consolidated Balance Sheet.	

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The amounts of AFUDC were $30.2 million, $20.9 million and $14.5 million in 2006, 2005 and 2004, respectively, and are included in Allowance For Equity Funds Used During Construction on our Consolidated Statements of Income. The amounts of interest capitalized and allowance for borrowed funds used during construction were $82.3 million, $35.6 million and $22.4 million in 2006, 2005 and 2004, respectively, and are included in Interest Expense on our Consolidated Statements of Income.

Jointly-owned Electric Utility Plant

We have generating units that are jointly-owned with nonaffiliated companies. We are obligated to pay a share of the costs of these jointly-owned facilities in the same proportion as our ownership interest. Our proportionate share of the operating costs associated with such facilities is included in our Consolidated Statements of Income and the investments and accumulated depreciation are reflected in our Consolidated Balance Sheets under Property, Plant and Equipment as follows:

 	 	 	 	 	 	Company’s Share at December 31, 2006	 	
 	 	Fuel
Type	 	Percent of Ownership	 	Utility Plant in Service	 	Construction Work in Progress (h)	 	Accumulated
Depreciation	 	
 	 	 	 	 	 	(in millions)	 	
W.C. Beckjord Generating Station  (Unit No. 6) (a)	 	 	Coal	 	 	12.5	%	$	16	 	$	-	 	$	8	 	
Conesville Generating Station (Unit No. 4) (b)	 	 	Coal	 	 	43.5	 	 	85	 	 	32	 	 	49	 	
J.M. Stuart Generating Station (c)	 	 	Coal	 	 	26.0	 	 	284	 	 	102	 	 	128	 	
Wm. H. Zimmer Generating Station (a)	 	 	Coal	 	 	25.4	 	 	751	 	 	5	 	 	302	 	
Dolet Hills Generating Station (Unit No. 1) (d)	 	 	Lignite	 	 	40.2	 	 	240	 	 	5	 	 	167	 	
Flint Creek Generating Station (Unit No. 1) (e)	 	 	Coal	 	 	50.0	 	 	97	 	 	2	 	 	57	 	
Pirkey Generating Station (Unit No. 1) (e)	 	 	Lignite	 	 	85.9	 	 	481	 	 	5	 	 	310	 	
Oklaunion Generating Station (Unit No. 1) (f)	 	 	Coal	 	 	78.1	 	 	417	 	 	3	 	 	200	 	
Transmission	 	 	N/A	 	 	(g	)	 	63	 	 	-	 	 	42	 	

 	 	 	 	 	 	Company’s Share at December 31, 2005	 	
 	 	Fuel
Type	 	Percent of Ownership	 	Utility Plant in Service	 	Construction Work in Progress (h)	 	Accumulated
Depreciation	 	
 	 	 	 	 	 	(in millions)	 	
W.C. Beckjord Generating Station  (Unit No. 6) (a)	 	 	Coal	 	 	12.5	%	$	16	 	$	-	 	$	7	 	
Conesville Generating Station (Unit No. 4) (b)	 	 	Coal	 	 	43.5	 	 	85	 	 	8	 	 	48	 	
J.M. Stuart Generating Station (c)	 	 	Coal	 	 	26.0	 	 	266	 	 	35	 	 	121	 	
Wm. H. Zimmer Generating Station (a)	 	 	Coal	 	 	25.4	 	 	749	 	 	2	 	 	280	 	
Dolet Hills Generating Station (Unit No. 1) (d)	 	 	Lignite	 	 	40.2	 	 	238	 	 	4	 	 	160	 	
Flint Creek Generating Station (Unit No. 1) (e)	 	 	Coal	 	 	50.0	 	 	94	 	 	2	 	 	55	 	
Pirkey Generating Station (Unit No. 1) (e)	 	 	Lignite	 	 	85.9	 	 	460	 	 	10	 	 	298	 	
Oklaunion Generating Station (Unit No. 1) (f)	 	 	Coal	 	 	78.1	 	 	415	 	 	3	 	 	192	 	
Transmission	 	 	N/A	 	 	(g	)	 	63	 	 	1	 	 	41	 	

(a)	Operated by Duke Energy Corporation, a nonaffiliated company.	
(b)	Operated by CSPCo.	
(c)	Operated by The Dayton Power & Light Company, a nonaffiliated company.	
(d)	Operated by Cleco Corporation, a nonaffiliated company.	
(e)	Operated by SWEPCo.	
(f)	TCC’s 7.8% interest in Oklaunion Generating Station amounted to $40 million at December 31, 2006 and 2005. These amounts are included in Assets Held for Sale on our Consolidated Balance Sheets. Oklaunion Generating Station is operated by PSO.	
(g)	Varying percentages of ownership.	
(h)	Primarily relates to environmental upgrades, including the installation of flue gas desulfurization projects at Conesville Generating Station and J.M. Stuart Generating Station.	
 	 	
N/A	= Not Applicable	
 
         18. UNAUDITED QUARTERLY FINANCIAL INFORMATION

In our opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. Our unaudited quarterly financial information is as follows:
 
 	 	  2006 Quarterly Periods Ended	 	
  (In Millions - Except Per Share Amounts)	 	  March 31	 	 June 30	 	 September 30	 	 December 31	 	
Revenues	 	$	3,108	 	$	2,936	 	$	3,594	 	$	2,984	 	
Operating Income	 	 	689	 	 	371	 	 	535	 	 	371	 	
Income Before Discontinued Operations, Extraordinary
   Loss and  Cumulative Effect of Accounting Changes	 	 	378	 	 	172	 	 	265	 	 	177	 	
Net Income	 	 	381	 	 	175	 	 	265	 	 	181	 	
Basic Earnings per Share:	 	  	 	  	 	  	 	  	 	
Earnings per Share Before Discontinued Operations, 
Extraordinary  Loss and Cumulative Effect of Accounting Changes	 	 	0.96	 	 	0.44	 	 	0.67	 	 	0.45	 	
Earnings per Share	 	 	0.97	 	 	0.44	 	 	0.67	 	 	0.46	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted Earnings per Share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings per Share Before Discontinued   Operations, 
Extraordinary  Loss and Cumulative Effect of Accounting Changes (e)	 	 	0.95	 	 	0.43	 	 	0.67	 	 	0.44	 	
Earnings per Share	 	 	0.96	 	 	0.44	 	 	0.67	 	 	0.46	 	

 	 	2005 Quarterly Periods Ended	 	
(In Millions - Except Per Share Amounts)	 	March 31	 	June 30	 	September 30	 	December 31	 	
Revenues	 	$	3,065	 	$	2,819	 	$	3,328	 	$	2,899	 	
Operating Income	 	 	660	 	 	455	 	 	624	 	 	188	 	
Income Before Discontinued Operations,   Extraordinary Loss and
   Cumulative Effect   of Accounting Changes	 	 	354	 	 	218	 	 	365	 	 	92	 	
Extraordinary Loss, Net of Tax (a)	 	 	-	 	 	-	 	 	-	 	 	(225	)	
Net Income (Loss)	 	 	355	 	 	221	 	 	387	 	 	(149	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic Earnings (Loss) per Share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings per Share Before Discontinued Operations, 
Extraordinary  Loss and   Cumulative Effect  of Accounting Changes	 	 	0.90	 	 	0.57	 	 	0.94	 	 	0.23	 	
Extraordinary Loss per Share (b)	 	 	-	 	 	-	 	 	-	 	 	(0.57	)	
Earnings (Loss) per Share	 	 	0.90	 	 	0.58	 	 	0.99	 	 	(0.38	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted Earnings (Loss) per Share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings per Share Before Discontinued   Operations, 
Extraordinary  Loss  and Cumulative Effect  of Accounting Changes (c)	 	 	0.90	 	 	0.57	 	 	0.94	 	 	0.23	 	
Extraordinary Loss per Share (b)	 	 	-	 	 	-	 	 	-	 	 	(0.57	)	
Earnings (Loss) per Share (d)	 	 	0.90	 	 	0.58	 	 	0.99	 	 	(0.38	)	

(a)	See “Extraordinary Items” section of Note 2 for a discussion of the extraordinary loss booked in the fourth quarter of 2005.	
(b)	Amounts for 2005 do not add to $(0.58) for Extraordinary Loss per Share due to differences between the weighted average number of shares outstanding for the fourth quarter of 2005 and the year 2005.	
(c)	Amounts for 2005 do not add to $2.63 for Diluted Earnings (Loss) per Share before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Changes due to rounding.	
(d)	Amounts for 2005 do not add to $2.08 for Diluted Earnings (Loss) per Share due to rounding.	
(e)	Amounts for the quarter ended December 31, 2006 do not add to $2.50 for Diluted Earnings (Loss) per Share Before Discontinued Operations due to rounding.	

 

 

 

AEP GENERATING COMPANY

 

 

 

 

AEP GENERATING COMPANY
SELECTED FINANCIAL DATA
(in thousands)

 	 	2006  	 	2005  	 	2004  	 	2003  	 	2002  	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STATEMENTS OF INCOME DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	309,814	 	$	270,755	 	$	241,788	 	$	233,165	 	$	213,281	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	12,918	 	$	10,901	 	$	10,130	 	$	8,456	 	$	7,511	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	10,914	 	$	8,695	 	$	7,842	 	$	7,964	 	$	7,552	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	704,434	 	$	699,342	 	$	692,841	 	$	674,174	 	$	652,332	 	
Accumulated Depreciation and Amortization	 	 	398,422	 	 	382,925	 	 	368,484	 	 	351,062	 	 	330,187	 	
Net Property, Plant and Equipment	 	$	306,012	 	$	316,417	 	$	324,357	 	$	323,112	 	$	322,145	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	393,331	 	$	376,703	 	$	376,393	 	$	380,045	 	$	377,716	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder's Equity	 	$	55,376	 	$	50,472	 	$	48,671	 	$	45,875	 	$	42,597	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt   (a)	 	$	44,837	 	$	44,828	 	$	44,820	 	$	44,811	 	$	44,802	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	12,001	 	$	12,227	 	$	12,474	 (b) 	$	269	 	$	501	 	

(a)	Including portion due within one year.	
(b)	Increased primarily due to a new coal transportation lease. See Note 14.	

AEP GENERATING COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As co-owner of Unit 1 of the Rockport Plant, we engage in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. I&M operates and co-owns Unit 1 of the Rockport Plant. Unit 2 of the Rockport Plant is owned by a third party and leased to I&M and us. See Off-Balance Sheet Arrangements below.

We derive operating revenues from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements through December 2022. Under the terms of its unit power agreement, I&M agreed to purchase all of our Rockport energy and capacity unless it is sold to other utilities or affiliates. I&M assigned 30% of its rights to energy and capacity to KPCo.

The unit power agreements provide for a FERC approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Under the terms of the unit power agreements, we accumulate all expenses monthly and prepare bills for our affiliates. In the month the expenses are incurred, we recognize the billing revenues and establish a receivable from the affiliated companies. The co-owners divide the costs of operating the plant.

Results of Operations

Net Income increased $2.2 million for 2006 compared with 2005. The fluctuation in Net Income is a result of terms in the unit power agreements which allow for a return on total capital of the Rockport Plant calculated and adjusted monthly for over/under billings.

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Net Income
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	8.7	 	
 	 	 	 	 	 	 	 	
Change in Gross Margin:	 	 	 	 	 	 	 	
Wholesale Sales	 	 	 	 	 	0.5	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	0.8	 	 	 	 	
Depreciation and Amortization	 	 	0.1	 	 	 	 	
Taxes Other Than Income Taxes	 	 	0.6	 	 	 	 	
Other Income (Expense)	 	 	(0.1	)	 	 	 	
Interest Expense	 	 	(0.5	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	0.9	 	
 	 	 	 	 	 	 	 	
Income Tax Credit	 	 	 	 	 	0.8	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	10.9	 	

Gross Margin, defined as Operating Revenues less Fuel for Electric Generation, increased $0.5 million primarily due to higher earnings on increased plant and capital investment.

Other Operation and Maintenance expenses decreased $0.8 million primarily due to decreased maintenance cost reflecting less planned and forced outages at the Rockport Plant in 2006 than 2005.

Taxes Other Than Income Taxes decreased $0.6 million primarily due to lower real and personal property taxes as the prior year accrual was adjusted to the actual amount paid.

Interest Expense increased $0.5 million primarily due to increased rates on short-term borrowing and higher borrowed amounts.

Income Taxes

Income Tax Credit increased $0.8 million primarily due to the recording of tax return adjustments and changes in certain book/tax differences accounted for on a flow-through basis, offset in part by an increase in pretax book income.

Off-Balance Sheet Arrangements

Rockport Plant Unit 2

In 1989, we, along with I&M, entered into a sale and leaseback transaction with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (Rockport 2). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. Neither we, nor I&M or AEP has an ownership interest in the Owner Trustee and do not guarantee its debt.

We deferred the gain from the sale and amortize it over the term of the lease, which expires in 2022. The Owner Trustee owns Rockport 2 and leases it to I&M and us. We account for the lease as an operating lease with the payment obligations included in the lease footnote (see Note 14). Our future minimum lease payments are $1.2 billion as of December 31, 2006. The lease term is for 33 years with potential renewal options. At the end of the lease term, we, along with I&M, have the option to renew the lease or the Owner Trustee can sell Rockport 2.

Summary Obligation Information

Our contractual obligations include amounts reported on our Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payments due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	53.6	 	$	-	 	$	-	 	$	-	 	$	53.6	 	
Interest on Long-term Debt (b)	 	 	2.0	 	 	4.0	 	 	4.0	 	 	26.0	 	 	36.0	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	-	 	 	-	 	 	45.0	 	 	-	 	 	45.0	 	
Capital Lease Obligations (d)	 	 	1.0	 	 	2.0	 	 	1.9	 	 	16.1	 	 	21.0	 	
Noncancelable Operating Leases (d)	 	 	77.3	 	 	154.7	 	 	153.9	 	 	814.5	 	 	1,200.4	 	
Construction Contracts for Capital Assets (e)	 	 	96.3	 	 	-	 	 	-	 	 	-	 	 	96.3	 	
Total	 	$	230.2	 	$	160.7	 	$	204.8	 	$	856.6	 	$	1,452.3	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 14.	
(e)	Represents only capital assets that are contractual obligations.	

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for additional discussion of factors relevant to us.

Plant Acquisition -   Lawrenceburg Generating Station

In January 2007, we agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from Public Service Enterprise Group for approximately $325 million and to assume liabilities of approximately $2 million. We expect to complete the transaction in the second quarter of 2007 after receipt of regulatory approvals. The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant. The combined-cycle, natural gas power plant has a generating capacity of 1,096 MW. This new generation acquisition will be financed by a capital contribution from AEP and issuance of debt related to this acquisition.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and the impact of new accounting pronouncements.

AEP GENERATING COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
 	 	 	 	 	 	 	 	
OPERATING REVENUES	 	$	309,814	 	$	270,755	 	$	241,788	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel for Electric Generation	 	 	178,654	 	 	140,077	 	 	112,470	 	
Rent - Rockport Plant Unit 2	 	 	68,283	 	 	68,283	 	 	68,283	 	
Other Operation	 	 	12,808	 	 	11,902	 	 	10,998	 	
Maintenance	 	 	9,776	 	 	11,518	 	 	12,152	 	
Depreciation and Amortization	 	 	23,911	 	 	24,009	 	 	23,579	 	
Taxes Other Than Income Taxes	 	 	3,464	 	 	4,065	 	 	4,176	 	
TOTAL	 	 	296,896	 	 	259,854	 	 	231,658	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	12,918	 	 	10,901	 	 	10,130	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	-	 	 	24	 	 	-	 	
Allowance for Equity Funds Used During   Construction	 	 	24	 	 	98	 	 	42	 	
Interest Expense	 	 	(2,947	)	 	(2,437	)	 	(2,446	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	9,995	 	 	8,586	 	 	7,726	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Credit	 	 	(919	)	 	(109	)	 	(116	)	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	$	10,914	 	$	8,695	 	$	7,842	 	

STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
 	 	 	 	 	 	 	 	
BALANCE AT BEGINNING OF PERIOD	 	$	26,038	 	$	24,237	 	$	21,441	 	
 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	 	10,914	 	 	8,695	 	 	7,842	 	
 	 	 	 	 	 	 	 	 	 	 	
Cash Dividends Declared	 	 	6,010	 	 	6,894	 	 	5,046	 	
 	 	 	 	 	 	 	 	 	 	 	
BALANCE AT END OF PERIOD	 	$	30,942	 	$	26,038	 	$	24,237	 	

The common stock of AEGCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY
BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Accounts Receivable - Affiliated Companies	 	$	31,060	 	$	29,671	 	
Fuel	 	 	37,701	 	 	14,897	 	
Materials and Supplies	 	 	7,873	 	 	7,017	 	
Accrued Tax Benefits	 	 	3,808	 	 	2,074	 	
Prepayments and Other	 	 	57	 	 	9	 	
TOTAL	 	 	80,499	 	 	53,668	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric - Production	 	 	686,776	 	 	684,721	 	
Other	 	 	2,460	 	 	2,369	 	
Construction Work in Progress	 	 	15,198	 	 	12,252	 	
Total	 	 	704,434	 	 	699,342	 	
Accumulated Depreciation and Amortization	 	 	398,422	 	 	382,925	 	
TOTAL - NET	 	 	306,012	 	 	316,417	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	5,438	 	 	5,572	 	
Deferred Charges and Other	 	 	1,382	 	 	1,046	 	
TOTAL	 	 	6,820	 	 	6,618	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	393,331	 	$	376,703	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY
BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	53,646	 	$	35,131	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	549	 	 	926	 	
Affiliated Companies	 	 	27,935	 	 	22,161	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	-	 	 	44,828	 	
Accrued Taxes	 	 	3,685	 	 	3,055	 	
Accrued Rent - Rockport Plant Unit 2	 	 	4,963	 	 	4,963	 	
Other	 	 	1,200	 	 	1,228	 	
TOTAL	 	 	91,978	 	 	112,292	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	44,837	 	 	-	 	
Deferred Income Taxes	 	 	19,749	 	 	23,617	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	79,650	 	 	82,689	 	
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2	 	 	88,762	 	 	94,333	 	
Deferred Credits and Other	 	 	12,979	 	 	13,300	 	
TOTAL	 	 	245,977	 	 	213,939	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	337,955	 	 	326,231	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - Par Value - $1,000 Per Share:
  Authorized - 1,000 Shares
  Outstanding - 1,000 Shares	 	 	1,000	 	 	1,000	 	
Paid-in Capital	 	 	23,434	 	 	23,434	 	
Retained Earnings	 	 	30,942	 	 	26,038	 	
TOTAL	 	 	55,376	 	 	50,472	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	 	$	393,331	 	$	376,703	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	10,914	 	$	8,695	 	$	7,842	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	23,911	 	 	24,009	 	 	23,579	 	
Deferred Income Taxes	 	 	(6,730	)	 	(1,666	)	 	(2,219	)	
Deferred Investment Tax Credits	 	 	(3,433	)	 	(3,532	)	 	(3,339	)	
Amortization of Deferred Gain on Sale and  Leaseback - Rockport Plant Unit 2	 	 	(5,571	)	 	(5,571	)	 	(5,571	)	
Change in Other Noncurrent Assets	 	 	(3,295	)	 	(654	)	 	3,266	 	
Change in Other Noncurrent Liabilities	 	 	3,169	 	 	2,204	 	 	(2,511	)	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	(1,389	)	 	(6,593	)	 	1,670	 	
Fuel, Materials and Supplies	 	 	(23,660	)	 	452	 	 	3,192	 	
Accounts Payable	 	 	5,397	 	 	4,739	 	 	1,939	 	
Accrued Taxes, Net	 	 	(1,104	)	 	(7,825	)	 	2,736	 	
Other Current Assets	 	 	(48	)	 	(9	)	 	-	 	
Other Current Liabilities	 	 	(28	)	 	34	 	 	196	 	
Net Cash Flows From (Used For) Operating Activities	 	 	(1,867	)	 	14,283	 	 	30,780	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(10,403	)	 	(15,372	)	 	(15,757	)	
Proceeds from Sales of Assets	 	 	75	 	 	-	 	 	-	 	
Net Cash Flows Used For Investing Activities	 	 	(10,328	)	 	(15,372	)	 	(15,757	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Change in Advances from Affiliates, Net	 	 	18,515	 	 	8,216	 	 	(9,977	)	
Principal Payments for Capital Lease Obligations	 	 	(310	)	 	(233	)	 	-	 	
Dividends Paid on Common Stock	 	 	(6,010	)	 	(6,894	)	 	(5,046	)	
Net Cash Flows From (Used For) Financing Activities	 	 	12,195	 	 	1,089	 	 	(15,023	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Change in Cash and Cash Equivalents	 	 	-	 	 	-	 	 	-	 	
Cash and Cash Equivalents at Beginning of Period	 	 	-	 	 	-	 	 	-	 	
Cash and Cash Equivalents at End of Period	 	$	-	 	$	-	 	$	-	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	2,597	 	$	2,170	 	$	2,179	 	
Net Cash Paid for Income Taxes	 	 	10,149	 	 	13,435	 	 	542	 	
Noncash Acquisitions Under Capital Leases	 	 	84	 	 	45	 	 	12,297	 	

   See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to AEGCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to AEGCo.

 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 8	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholder of
AEP Generating Company:

We have audited the accompanying balance sheets of AEP Generating Company (the “Company”) as of December 31, 2006 and 2005, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company   as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007 

 

 

 

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

 

 

 

 

 

 

 

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	  2006  	 	2005  	 	2004  	 	2003  	 	2002  	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STATEMENTS OF OPERATIONS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	664,664	 	$	793,246	 	$	1,212,849	 	$	1,797,686	 	$	1,739,853	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	129,097	 	$	177,281	 	$	244,081	 	$	452,966	 	$	541,132	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Extraordinary Loss and  Cumulative Effect
  of Accounting Change	 	$	41,569	 	$	50,772	 	$	294,656	 	$	217,547	 	$	275,941	 	
Extraordinary Loss on Stranded Cost  Recovery,
  Net of Tax (a)	 	 	-	 	 	(224,551	)	 	(120,534	)	 	-	 	 	-	 	
Cumulative Effect of Accounting  Change, Net of Tax	 	 	-	 	 	-	 	 	-	 	 	122	 	 	-	 	
Net Income (Loss)	 	$	41,569	 	$	(173,779	)	$	174,122	 	$	217,669	 	$	275,941	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	2,870,032	 	$	2,657,195	 	$	2,495,921	 	$	2,428,004	 	$	2,338,100	 	
Accumulated Depreciation and Amortization	 	 	630,239	 	 	636,078	 	 	726,771	 	 	697,023	 	 	663,266	 	
Net Property, Plant and Equipment	 	$	2,239,793	 	$	2,021,117	 	$	1,769,150	 	$	1,730,981	 	$	1,674,834	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	5,323,731	 	$	4,904,912	 	$	5,678,320	 	$	5,820,360	 	$	5,565,599	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder's Equity	 	$	405,116	 	$	947,630	 	$	1,268,643	 	$	1,209,049	 	$	1,101,134	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory  Redemption	 	$	5,921	 	$	5,940	 	$	5,940	 	$	5,940	 	$	5,942	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trust Preferred Securities	 	$	-	 	$	-	 	$	-	 	$	-	 	$	136,250	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (b)	 	$	3,015,614	 (c)	$	1,853,496	 	$	1,907,294	 	$	2,291,625	 	$	1,438,565	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (b)	 	$	4,097	 	$	1,378	 	$	880	 	$	1,043	 	$	-	 	

(a)	See “Extraordinary Items” section of Note 2 and “TCC Texas Restructuring” section of Note 4.	
(b)	Including portion due within one year.	
(c)	Increased due to issuance of securitization bonds in October 2006. See Note 15.	

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the transmission and distribution of electric power to 738,000 retail customers through REPs in our service territory in southern and central Texas. We consolidate AEP Texas Central Transition Funding LLC and AEP Texas Central Transition Funding II LLC, our wholly-owned subsidiaries.
 
Under the Texas Restructuring Legislation, we completed the final stage of exiting the generation business and have ceased serving retail load. Based on the corporate separation and generation divestiture, the nature of our business is no longer compatible with our participation in the CSW Operating Agreement and the SIA since these agreements involve the coordinated planning and operation of power supply facilities. Accordingly, we sought and received FERC approval to be removed from those agreements. Our sharing of margins under the CSW Operating Agreement ceased on May 1, 2006. The sharing of margins with AEP East companies under the SIA ceased on April 1, 2006. These trading and marketing margins affected our results of operations and cash flows.
 
Prior to May 1, 2006, as a member of the CSW Operating Agreement, we were compensated for energy delivered to other members based upon our incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenues and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies were generally shared among the members based upon the relative magnitude of the energy each member provided to make such sales.

Prior to April 1, 2006, under the SIA, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities were shared among AEP East companies and AEP West companies. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.
 
Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income Before Extraordinary Loss
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	51	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Off-system Sales	 	 	(125	)	 	 	 	
Texas Wires	 	 	17	 	 	 	 	
Transmission Revenues	 	 	(12	)	 	 	 	
Other	 	 	23	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	(97	)	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	58	 	 	 	 	
Depreciation and Amortization	 	 	(18	)	 	 	 	
Taxes Other Than Income Taxes	 	 	9	 	 	 	 	
Carrying Costs Income	 	 	88	 	 	 	 	
Other Income	 	 	(7	)	 	 	 	
Interest Expense	 	 	(32	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	98	 	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(10	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	42	 	

Income Before Extraordinary Loss decreased $9 million primarily due to a decrease in Gross Margin of $97 million and a $10 million increase in Income Tax Expense, partially offset by a decrease in Operating Expenses and Other of $98 million. We substantially exited the generation market with the sale of STP in May 2005.

The major components of our change in Gross Margin, defined as revenues less the related direct costs of fuel, including the consumption of emissions allowances, and purchased power were as follows:

·	Margins from Off-system Sales decreased $125 million primarily due to the sale of STP, which resulted in lower revenues of $74 million and a $36 million adjustment to the provision for refund primarily due to the fuel reconciliation adjustment in 2005. An additional $17 million decrease was primarily due to a decrease in our allocation of off-system sales margins under the SIA. As of May 1, 2006, we no longer share off-system sales margins under the SIA or the CSW Operating Agreement. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Texas Wires revenues increased $17 million primarily due to favorable prices and a four percent increase in degree days.	
·	Transmission Revenues decreased $12 million primarily due to lower ERCOT transmission rates and reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.	
·	Other revenues increased $23 million. This increase was due in part to $29 million of revenue from securitization transition charges primarily resulting from new financing in October 2006. This increase was partially offset by a $13 million decrease in third party construction project revenues related to work performed for the Lower Colorado River Authority. Securitization transition charges represent amounts collected to recover securitization bond principal and interest payments related to our securitized transition assets and are fully offset by amortization and interest expenses. See the “TCC Texas Restructuring” section of Note 4.	
 
Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses decreased $58 million primarily due to the sale of STP, which resulted in a decrease in generation-related operation and maintenance expenses of $29 million. An additional $12 million decrease resulted from lower expenses related to construction projects performed for third parties, primarily the Lower Colorado River Authority. The remaining decrease primarily related to lower administrative and general expenses, including outside services and regulatory expenses.	
·	Depreciation and Amortization expense increased $18 million primarily due to the amortization of the Securitization Bonds issued in October 2006 of $10 million and a $9 million increase related to the refund and amortization of excess earnings credits in 2005.	
·	Taxes Other Than Income Taxes decreased $9 million primarily due to lower property-related and other taxes as a result of the sale of STP in 2005 and a favorable settlement of a state use tax audit in 2006.	
·	Carrying Costs Income increased $88 million primarily due to negative adjustments of $29 million and $8 million made in the first and third quarters of 2005, respectively, related to our True-up Proceeding orders received from the PUCT. The remaining increase is due to the disallowance of carrying costs of $71 million in 2005 partially offset by lower amounts of carrying costs in 2006 (see “TCC Texas Restructuring” section of Note 4).	
·	Other Income decreased $7 million primarily due to interest income recorded in the prior year related to the 2005 Texas Court of Appeals order (see “Other Texas Restructuring Matters - Excess Earnings” section of Note 4).	
·	Interest Expense increased $32 million primarily due to a $22 million increase in accrued interest related to the CTC liability (see “TCC Texas Restructuring - TCC’s 2006 CTC Proceeding” section of Note 4) and a $23 million increase in long-term debt interest primarily related to the affiliated note issuances and the Securitization Bonds issued in October 2006, partially offset by a $4 million decrease in interest expense related to Utility Money Pool borrowings and AFUDC.	

Income Taxes

Income Tax Expense increased $10 million primarily due to the recording of tax reserve adjustments, a decrease in consolidated tax savings from Parent and an increase in state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Our current ratings are as follows:

 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	
First Mortgage Bonds	Baa1	 	BBB	 	A	
Senior Unsecured Debt	Baa2	 	BBB	 	A-	
 
Summary Obligation Information

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payments Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Interest on Fixed Rate Portion of Long-term Debt (a)	 	$	129.0	 	$	290.0	 	$	260.0	 	$	1,023.0	 	$	1,702.0	 	
Fixed Rate Portion of Long-term Debt (b)	 	 	78.0	 	 	281.0	 	 	307.0	 	 	2,191.0	 	 	2,857.0	 	
Variable Rate Portion of Long-term Debt (c)	 	 	-	 	 	-	 	 	-	 	 	161.0	 	 	161.0	 	
Capital Lease Obligations (d)	 	 	1.6	 	 	2.4	 	 	0.5	 	 	-	 	 	4.5	 	
Noncancelable Operating Leases (d)	 	 	6.2	 	 	9.7	 	 	6.6	 	 	3.1	 	 	25.6	 	
Construction Contracts for Assets (e)	 	 	82.1	 	 	-	 	 	-	 	 	-	 	 	82.1	 	
Total	 	$	296.9	 	$	583.1	 	$	574.1	 	$	3,378.1	 	$	4,832.2	 	

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(b)	See Note 15. Represents principal only excluding interest.	
(c)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.60% and 3.75% at December 31, 2006.	
(d)	See Note 14.	
(e)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2006 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period
(in millions)

Other Commercial
Commitments	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 Years	 	Total	 	
Guarantees of Our Performance (a)	 	$	443	 	$	-	 	$	-	 	$	-	 	$	443	 	
Transmission Facilities for Third Parties (b)	 	 	21	 	 	12	 	 	-	 	 	-	 	 	33	 	
Total	 	$	464	 	$	12	 	$	-	 	$	-	 	$	476	 	

(a)	See “Contracts” section of Note 6.	
(b)	As construction agent for third party owners of transmission facilities, we have committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.	
 
Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

Texas Restructuring

Texas Restructuring Legislation established customer choice on January 1, 2002 and allowed electric utility companies to file for recovery of securitizable stranded generation plant costs, generation related regulatory assets and non-securitizable other restructuring true-up items. These recoverable and refundable items were recorded as true-up regulatory assets and liabilities.

TCC will recover its PUCT approved net true-up regulatory asset under the Texas Restructuring Legislation using two mechanisms: (a) by issuing securitization bonds in the amount of its net stranded generation costs and implementing a transition charge (TC) rate rider to collect the bond interest and principal over the term of the bonds and (b) by implementing a credit competition transition charge (CTC) rate rider to refund its net regulatory liability for other true-up items.

In February 2006, the PUCT issued an order in TCC’s True-up Proceeding, which determined that TCC’s recoverable net true-up regulatory asset, for both securitizable net stranded generation cost regulatory assets and net other true-up items regulatory liabilities, was $1.475 billion as of September 30, 2005. The order disallowed specific items which included, among other things, a significant portion of TCC’s wholesale capacity auction true-up revenues and a portion of TCC’s stranded costs determined from the sale of the ERCOT generating units.

TCC appealed the PUCT true-up orders seeking relief in both state and federal court on the grounds that the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. The significant items appealed by TCC are:

·	The PUCT ruling that TCC did not comply with the statute and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues,	
·	The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled out of the money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant cost, and	
·	The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation. See “TCC and TNC Deferred Fuel” and “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections of Note 4.	

Municipal customers and other intervenors appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. On February 1, 2007 the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final True-up order with two significant exceptions. The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) method to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. However, the District Court did not rule that the carrying cost rate was inappropriate. He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future revenues.

In response to a request by TCC, the District Court judge will hear additional argument on March 22, 2007 regarding use of the ECOM method to value TCC’s nuclear plant stranded cost. TCC anticipates that the final judgment will be entered after that hearing. TCC intends to appeal any final adverse rulings of the District Court regarding these two matters along with certain of the judge’s other preliminary determinations that affirm the PUCT’s decisions. It is possible that the PUCT could also appeal any final adverse rulings regarding these two matters.

Although management cannot predict the ultimate outcome of these preliminary District Court determinations, any future remanded PUCT proceedings or any future court appeals, management has concluded that it is probable that the District Court’s preliminary ruling regarding the use of an ECOM method in lieu of a sales method to determine securitizable stranded cost will not be upheld on appeal. The judge has also determined in his letter ruling that if the sales method is permitted for valuing the nuclear plant, the PUCT improperly reduced stranded costs in connection with the sales process, which could have a materially favorable effect on TCC.

Management also concluded if the District Court’s preliminary carrying cost rate ruling is ultimately remanded to the PUCT for reconsideration, the PUCT could either confirm the existing carrying cost rate or redetermine the rate. If the PUCT changes the rate, it could result in a material adverse change to TCC’s recoverable carrying costs. However, management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

If the District Court judge’s original 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. TCC cannot estimate the amount at this time, but the amount could exceed its Common Shareholder’s Equity at December 31, 2006. If it were finally concluded that the ECOM method must be used to value TCC’s nuclear plant stranded cost, and/or that the PUCT’s rule on carrying costs was invalid, it could, after the PUCT remand decisions, have a substantial adverse impact on future results of operations, cash flows and financial condition.

If TCC ultimately succeeds in its appeals on other than the above two matters, it could have a favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, including their appeals of the two matters discussed above, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

Our MTM Risk Management Contract Net Assets were zero as of December 31, 2006. For further explanation, see “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4. The following table summarizes the reasons for changes in our total MTM value as compared to December 31, 2005.

MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	5,426	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(1,615	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	-	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	-	 	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	-	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	(3,428	)	
Changes Due to SIA and CSW Operating Agreement (c)	 	 	(383	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	-	 	
Total MTM Risk Management Contract Net Assets	 	 	-	 	
Net Cash Flow Hedge Contracts	 	 	-	 	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	-	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

Our MTM Risk Management Contract Net Assets were zero as of December 31, 2006. Therefore, there is no maturity and source of fair value to report.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on our future cash flows. We do not hedge all commodity price risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)
 	 	Power	 	
Beginning Balance in AOCI December 31, 2005	 	$	(224	)	
Changes in Fair Value	 	 	-	 	
Impact Due to Changes in SIA (a)	 	 	218	 	
Reclassifications from AOCI to Net Loss for Cash Flow Hedges Settled	 	 	6	 	
Ending Balance in AOCI December 31, 2006	 	$	-	 	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Our MTM Risk Management Contract Net Assets were zero as of December 31, 2006. Therefore, the ending VaR at December 31, 2006 was zero.

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $81 million and $93 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	623,840	 	$	729,815	 	$	1,148,930	 	
Sales to AEP Affiliates	 	 	6,403	 	 	14,973	 	 	47,039	 	
Other	 	 	34,421	 	 	48,458	 	 	16,880	 	
TOTAL	 	 	664,664	 	 	793,246	 	 	1,212,849	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	6,591	 	 	13,363	 	 	60,725	 	
Fuel from Affiliates Used for Electric Generation	 	 	77	 	 	84	 	 	101,906	 	
Purchased Electricity for Resale	 	 	4,093	 	 	28,947	 	 	206,304	 	
Purchased Electricity from AEP Affiliates	 	 	-	 	 	-	 	 	6,140	 	
Other Operation	 	 	240,795	 	 	286,708	 	 	307,939	 	
Maintenance	 	 	38,466	 	 	50,888	 	 	63,599	 	
Depreciation and Amortization	 	 	164,773	 	 	146,258	 	 	131,154	 	
Taxes Other Than Income Taxes	 	 	80,772	 	 	89,717	 	 	91,001	 	
TOTAL	 	 	535,567	 	 	615,965	 	 	968,768	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	129,097	 	 	177,281	 	 	244,081	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	7,488	 	 	16,228	 	 	6,604	 	
Carrying Costs Income (Expense)	 	 	69,080	 	 	(19,293	)	 	301,644	 	
Allowance for Equity Funds Used During Construction	 	 	2,688	 	 	1,003	 	 	1,170	 	
Interest Expense	 	 	(144,134	)	 	(112,006	)	 	(123,785	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	64,219	 	 	63,213	 	 	429,714	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	22,650	 	 	12,441	 	 	135,058	 	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE EXTRAORDINARY LOSS	 	 	41,569	 	 	50,772	 	 	294,656	 	
 	 	 	 	 	 	 	 	 	 	 	
EXTRAORDINARY LOSS ON STRANDED COST  RECOVERY, NET OF TAX	 	 	-	 	 	(224,551	)	 	(120,534	)	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME (LOSS)	 	 	41,569	 	 	(173,779	)	 	174,122	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements	 	 	241	 	 	241	 	 	241	 	
Gain on Reacquired Preferred Stock	 	 	6	 	 	-	 	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK	 	$	41,334	 	$	(174,020	)	$	173,881	 	

The common stock of TCC is owned by a wholly-owned subsidiary of AEP.	
 	
See Notes to Financial Statements of Registrant Subsidiaries.	

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	55,292	 	$	132,606	 	$	1,083,023	 	$	(61,872	)	$	1,209,049	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(172,000	)	 	 	 	 	(172,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(241	)	 	 	 	 	(241	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,036,808	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income, Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $1,338	 	 	 	 	 	 	 	 	 	 	 	2,485	 	 	2,485	 	
Minimum Pension Liability, Net of Tax of $31,790	 	 	 	 	 	 	 	 	 	 	 	55,228	 	 	55,228	 	
NET INCOME	 	 	 	 	 	 	 	 	174,122	 	 	 	 	 	174,122	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	231,835	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	55,292	 	 	132,606	 	 	1,084,904	 	 	(4,159	)	 	1,268,643	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(150,000	)	 	 	 	 	(150,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(241	)	 	 	 	 	(241	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,118,402	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE LOSS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $474	 	 	 	 	 	 	 	 	 	 	 	(881	)	 	(881	)	
Minimum Pension Liability, Net of Tax of $42	 	 	 	 	 	 	 	 	 	 	 	3,888	 	 	3,888	 	
NET LOSS	 	 	 	 	 	 	 	 	(173,779	)	 	 	 	 	(173,779	)	
TOTAL COMPREHENSIVE LOSS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(170,772	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	55,292	 	 	132,606	 	 	760,884	 	 	(1,152	)	 	947,630	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(585,000	)	 	 	 	 	(585,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(241	)	 	 	 	 	(241	)	
Gain on Reacquired Preferred Stock	 	 	 	 	 	 	 	 	6	 	 	 	 	 	6	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	362,395	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income, Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $121	 	 	 	 	 	 	 	 	 	 	 	224	 	 	224	 	
Minimum Pension Liability, Net of Tax   of $108	 	 	 	 	 	 	 	 	 	 	 	200	 	 	200	 	
NET INCOME	 	 	 	 	 	 	 	 	41,569	 	 	 	 	 	41,569	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	41,993	 	
Minimum Pension Liability Elimination, Net of Tax   of $392	 	 	 	 	 	 	 	 	 	 	 	728	 	 	728	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2006	 	$	55,292	 	$	132,606	 	$	217,218	 	$	-	 	$	405,116	 	

   See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	779	 	$	-	 	
Other Cash Deposits	 	 	104,203	 	 	66,153	 	
Advances to Affiliates	 	 	394,004	 	 	-	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	31,215	 	 	209,957	 	
Affiliated Companies	 	 	8,613	 	 	23,486	 	
Accrued Unbilled Revenues	 	 	10,093	 	 	25,606	 	
Allowance for Uncollectible Accounts	 	 	(49	)	 	(143	)	
   Total Accounts Receivable	 	 	49,872	 	 	258,906	 	
Unbilled Construction Costs	 	 	4,535	 	 	19,440	 	
Materials and Supplies	 	 	28,347	 	 	13,897	 	
Risk Management Assets	 	 	-	 	 	14,311	 	
Prepayments and Other	 	 	1,137	 	 	5,231	 	
TOTAL	 	 	582,877	 	 	377,938	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Transmission	 	 	904,527	 	 	817,351	 	
Distribution	 	 	1,579,498	 	 	1,476,683	 	
Other	 	 	220,028	 	 	233,361	 	
Construction Work in Progress	 	 	165,979	 	 	129,800	 	
Total	 	 	2,870,032	 	 	2,657,195	 	
Accumulated Depreciation and Amortization	 	 	630,239	 	 	636,078	 	
TOTAL - NET	 	 	2,239,793	 	 	2,021,117	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	193,111	 	 	1,688,787	 	
Securitized Transition Assets	 	 	2,158,408	 	 	593,401	 	
Long-term Risk Management Assets	 	 	-	 	 	11,609	 	
Employee Benefits and Pension Assets	 	 	35,574	 	 	114,733	 	
Deferred Charges and Other	 	 	69,493	 	 	53,011	 	
TOTAL	 	 	2,456,586	 	 	2,461,541	 	
 	 	 	 	 	 	 	 	
Assets Held for Sale - Texas Generation Plant	 	 	44,475	 	 	44,316	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	5,323,731	 	$	4,904,912	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	-	 	$	82,080	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	26,934	 	 	82,666	 	
Affiliated Companies	 	 	21,234	 	 	65,574	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	78,227	 	 	152,900	 	
Risk Management Liabilities	 	 	-	 	 	13,024	 	
Customer Deposits	 	 	18,742	 	 	10,658	 	
Accrued Taxes	 	 	74,499	 	 	54,566	 	
Accrued Interest	 	 	44,712	 	 	32,497	 	
Other	 	 	34,762	 	 	35,269	 	
TOTAL	 	 	299,110	 	 	529,234	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	2,937,387	 	 	1,550,596	 	
Long-term Debt - Affiliated	 	 	-	 	 	150,000	 	
Long-term Risk Management Liabilities	 	 	-	 	 	7,857	 	
Deferred Income Taxes	 	 	1,034,123	 	 	1,048,372	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	598,027	 	 	652,143	 	
Deferred Credits and Other	 	 	44,047	 	 	13,140	 	
TOTAL	 	 	4,613,584	 	 	3,422,108	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	4,912,694	 	 	3,951,342	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	5,921	 	 	5,940	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - Par Value - $25 Per Share:	 	 	 	 	 	 	 	
Authorized - 12,000,000 Shares	 	 	 	 	 	 	 	
Outstanding - 2,211,678 Shares	 	 	55,292	 	 	55,292	 	
Paid-in Capital	 	 	132,606	 	 	132,606	 	
Retained Earnings	 	 	217,218	 	 	760,884	 	
Accumulated Other Comprehensive Income (Loss)	 	 	-	 	 	(1,152	)	
TOTAL	 	 	405,116	 	 	947,630	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	5,323,731	 	$	4,904,912	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income (Loss)	 	$	41,569	 	$	(173,779	)	$	174,122	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	164,773	 	 	146,258	 	 	131,154	 	
Deferred Income Taxes	 	 	24,200	 	 	(91,387	)	 	16,490	 	
Extraordinary Loss on Stranded Cost Recovery, Net of Tax	 	 	-	 	 	224,551	 	 	120,534	 	
Carrying Costs on Stranded Cost Recovery	 	 	(69,080	)	 	19,293	 	 	(301,644	)	
Mark-to-Market of Risk Management Contracts	 	 	5,426	 	 	4,275	 	 	2,241	 	
Wholesale Capacity Auction True-up	 	 	(826	)	 	769	 	 	(79,973	)	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(3,953	)	 	(61,910	)	
Fuel Over/Under Recovery, Net	 	 	(12,424	)	 	(34,328	)	 	61,500	 	
Change in Other Noncurrent Assets	 	 	(15,263	)	 	(12,644	)	 	91,502	 	
Change in Other Noncurrent Liabilities	 	 	(59,568	)	 	3,609	 	 	(3,473	)	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	209,034	 	 	(28,947	)	 	2,352	 	
Fuel, Materials and Supplies	 	 	(15,303	)	 	(1,559	)	 	(10,641	)	
Accounts Payable	 	 	(105,537	)	 	6,797	 	 	26,008	 	
Accrued Taxes, Net	 	 	19,933	 	 	(128,022	)	 	116,996	 	
Other Current Assets	 	 	18,999	 	 	(14,313	)	 	1,817	 	
Other Current Liabilities	 	 	18,180	 	 	11,113	 	 	(467	)	
Net Cash Flows From (Used For) Operating Activities	 	 	224,113	 	 	(72,267	)	 	286,608	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(270,330	)	 	(178,628	)	 	(106,656	)	
Change in Other Cash Deposits, Net	 	 	(37,407	)	 	68,953	 	 	(70,062	)	
Change in Advances to Affiliates, Net	 	 	(394,004	)	 	-	 	 	60,699	 	
Purchases of Investment Securities	 	 	-	 	 	(154,364	)	 	(99,667	)	
Sales of Investment Securities	 	 	-	 	 	149,804	 	 	87,471	 	
Proceeds from Sale of Assets	 	 	9,380	 	 	315,318	 	 	429,553	 	
Other	 	 	-	 	 	-	 	 	(36,191	)	
Net Cash Flows From (Used For) Investing Activities	 	 	(692,361	)	 	201,083	 	 	265,147	 	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	1,715,285	 	 	316,901	 	 	-	 	
Issuance of Long-term Debt - Affiliated	 	 	195,000	 	 	150,000	 	 	-	 	
Change in Advances from Affiliates, Net	 	 	(82,080	)	 	81,873	 	 	207	 	
Retirement of Long-term Debt - Nonaffiliated	 	 	(427,900	)	 	(526,897	)	 	(380,096	)	
Retirement of Long-term Debt - Affiliated	 	 	(345,000	)	 	-	 	 	-	 	
Retirement of Cumulative Preferred Stock	 	 	(13	)	 	-	 	 	-	 	
Principal Payments for Capital Lease Obligations	 	 	(1,024	)	 	(478	)	 	(436	)	
Dividends Paid on Common Stock	 	 	(585,000	)	 	(150,000	)	 	(172,000	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(241	)	 	(241	)	 	(241	)	
Net Cash Flows From (Used For) Financing Activities	 	 	469,027	 	 	(128,842	)	 	(552,566	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	779	 	 	(26	)	 	(811	)	
Cash and Cash Equivalents at Beginning of Period	 	 	-	 	 	26	 	 	837	 	
Cash and Cash Equivalents at End of Period	 	$	779	 	$	-	 	$	26	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	105,896	 	$	104,701	 	$	117,325	 	
Net Cash Paid (Received) for Income Taxes	 	 	(24,649	)	 	235,697	 	 	(1,058	)	
Noncash Acquisitions Under Capital Leases	 	 	3,572	 	 	977	 	 	348	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	16,502	 	 	11,037	 	 	1,838	 	

   See Notes to Financial Statements of Registrant Subsidiaries .

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to TCC’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to TCC.

 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 8	
Benefit Plans	Note 9	
Nuclear	Note 10	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 

 

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
AEP Texas Central Company:

We have audited the accompanying consolidated balance sheets of AEP Texas Central Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company   and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the consolidated financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006, and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007 

 

 

 

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

 

 

 

 

 

 

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
 	 	 	 	 	 	 	 	 	 	 	 	
STATEMENTS OF OPERATIONS DATA	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	329,470	 	$	458,888	 	$	553,458	 	$	533,511	 	$	503,408	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income (Loss)	 	$	35,287	 	$	76,699	 	$	91,071	 	$	107,405	 	$	(6,250	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (Loss) Before Extraordinary Loss and Cumulative Effect of
  Accounting Changes	 	$	14,943	 	$	41,476	 	$	47,659	 	$	55,663	 	$	(13,677	)	
Extraordinary Loss, Net of Tax	 	 	-	 	 	-	 	 	-	 	 	(177	)	 	-	 	
Cumulative Effect of Accounting Changes,  Net of Tax	 	 	-	 	 	(8,472	)	 	-	 	 	3,071	 	 	-	 	
Net Income (Loss)	 	$	14,943	 	$	33,004	 	$	47,659	 	$	58,557	 	$	(13,677	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	1,328,893	 	$	1,285,114	 	$	1,305,571	 	$	1,281,620	 	$	1,249,996	 	
Accumulated Depreciation and Amortization	 	 	486,961	 	 	478,519	 	 	527,770	 	 	507,420	 	 	493,981	 	
Net Property, Plant and Equipment	 	$	841,932	 	$	806,595	 	$	777,801	 	$	774,200	 	$	756,015	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	967,514	 	$	1,043,834	 	$	1,043,162	 	$	978,801	 	$	965,916	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder's Equity	 	$	306,356	 	$	313,919	 	$	310,421	 	$	238,275	 	$	180,744	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	$	2,349	 	$	2,357	 	$	2,357	 	$	2,357	 	$	2,367	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)	 	$	276,936	 	$	276,845	 	$	314,357	 	$	356,754	 	$	132,500	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	1,643	 	$	724	 	$	534	 	$	473	 	$	-	 	

(a)	Including portion due within one year.	

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the transmission and distribution of electric power to 189,000 retail customers through REPs in our service territory in western and central Texas. Although we engage in the generation and purchase of electric power for sale to the market and to meet wholesale contracts, the deregulation of electric power in the state of Texas requires this activity to be separated from our transmission and distribution activities. We also sell electric power at wholesale to other utilities, municipalities, rural electric cooperatives and REPs in Texas. We consolidate Texas North Generation Company, LLC, our wholly-owned subsidiary.

Under the Texas Restructuring Legislation, we completed the final stage of exiting the generation business and ceased serving retail load. Based on the corporate separation and generation divestiture, the nature of our business is no longer compatible with our participation in the CSW Operating Agreement and the SIA since these agreements involve the coordinated planning and operation of power supply facilities. Accordingly, we sought and received FERC approval to be removed from those agreements. Our sharing of margins under the CSW Operating Agreement ceased on May 1, 2006. The sharing of margins with AEP East companies under the SIA ceased on April 1, 2006. These trading and marketing margins affected our results of operations and cash flows.

Prior to May 1, 2006, as a member of the CSW Operating Agreement, we were compensated for energy delivered to other members based upon our incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenues and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies were generally shared among the members based upon the relative magnitude of the energy each member provided to make such sales.

Prior to April 1, 2006, under the SIA, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities were shared among AEP East companies and AEP West companies. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.
 
Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	41	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Off-system Sales	 	 	(35	)	 	 	 	
Texas Wires	 	 	(3	)	 	 	 	
Transmission Revenues	 	 	(4	)	 	 	 	
Other	 	 	(39	)	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	(81	)	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	41	 	 	 	 	
Depreciation and Amortization	 	 	(1	)	 	 	 	
Taxes Other Than Income Taxes	 	 	1	 	 	 	 	
Other Income	 	 	(2	)	 	 	 	
Interest Expense	 	 	2	 	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	41	 	
 	 	 	 	 	 	 	 	
Income Tax   Expense	 	 	 	 	 	14	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	15	 	

Income Before Cumulative Effect of Accounting Change decreased $26 million primarily due to a decrease in Gross Margin of $81 million partially offset by a reduction in Other Operation and Maintenance expenses of $41 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, consumption of emissions allowances and purchased power were as follows:

·	Margins from Off-system Sales decreased $35 million primarily due to a $28 million decrease in dedicated energy and capacity sales, which resulted from the market conditions within ERCOT. An additional $7 million decrease was primarily due to a decrease in our allocation of off-system sales margins under the SIA. As of May 1, 2006, we no longer share off-system sales margins under the SIA or the CSW Operating Agreement. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Transmission Revenues decreased $4 million primarily due to reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.	
·	Other revenues decreased $39 million primarily resulting from the completion of third party construction projects related to work performed for the Lower Colorado River Authority.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses decreased $41 million primarily resulting from the completion of third party construction projects related to work performed for the Lower Colorado River Authority.	

Income Taxes

Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.
 
Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook, except for Fitch, which has us on a negative outlook. Our current ratings are as follows:

 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	
First Mortgage Bonds	A3	 	BBB	 	A	
Senior Unsecured Debt	Baa1	 	BBB	 	A-	

Summary Obligation Information

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payments due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Interest on Fixed Rate Portion of Long-term Debt (a)	 	$	15.0	 	$	30.0	 	$	30.0	 	$	41.0	 	$	116.0	 	
Fixed Rate Portion of Long-term Debt (b)	 	 	8.2	 	 	-	 	 	-	 	 	269.3	 	 	277.5	 	
Capital Lease Obligations (c)	 	 	0.6	 	 	0.9	 	 	0.3	 	 	-	 	 	1.8	 	
Noncancelable Operating Leases (c)	 	 	2.7	 	 	4.8	 	 	3.2	 	 	2.0	 	 	12.7	 	
Construction Contracts for Capital Assets (d)	 	 	31.6	 	 	-	 	 	-	 	 	-	 	 	31.6	 	
Total	 	$	58.1	 	$	35.7	 	$	33.5	 	$	312.3	 	$	439.6	 	

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(b)	See Note 15. Represents principal only excluding interest.	
(c)	See Note 14.	
(d)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.
 
Oklaunion PPA between TNC and AEP Energy Partners

On January 1, 2007, we began a twenty-year Power Purchase and Sale Agreement (PPA) with an affiliate, AEP Energy Partners (AEPEP), whereby we will sell the output from its undivided interest (54.69%) in the Oklaunion plant to AEPEP. A portion of the payment is a fixed capacity payment that is required to be paid even if no power is taken by AEPEP.

We treat this arrangement as an operating lease. The payments that we expect to receive from AEPEP for 2007 are estimated to total $96 million, which include capacity, operations and maintenance, fuel, other taxes and depreciation.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow Hedges	 	Total	 	
Current Assets	 	$	-	 	$	-	 	$	-	 	
Noncurrent Assets	 	 	-	 	 	-	 	 	-	 	
Total MTM Derivative Contract Assets	 	 	-	 	 	-	 	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	-	 	 	-	 	 	-	 	
Noncurrent Liabilities	 	 	-	 	 	(1,081	)	 	(1,081	)	
Total MTM Derivative Contract Liabilities	 	 	-	 	 	(1,081	)	 	(1,081	)	
 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	-	 	$	(1,081	)	$	(1,081	)	

MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	2,698	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(804	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	-	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	-	 	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	-	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	(1,080	)	
Changes Due to SIA and CSW Operating Agreement (c)	 	 	(814	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	-	 	
Total MTM Risk Management Contract Net Assets	 	 	-	 	
Net Cash Flow Hedge Contracts	 	 	(1,081	)	
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2006	 	$	(1,081	)	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

Our MTM Risk Management Net Assets are zero as of December 31, 2006. Therefore, there is no maturity and source value to report.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)
 	 	Power	 	
Beginning Balance in AOCI December 31, 2005	 	$	(111	)	
Changes in Fair Value	 	 	(703	)	
Impact Due to Changes in SIA (a)	 	 	98	 	
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled	 	 	14	 	
Ending Balance in AOCI December 31, 2006	 	$	(702	)	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is zero.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Our MTM Risk Management Contract Net Assets are zero as of December 31, 2006. Therefore, the ending VaR at December 31, 2006 was zero.

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $12 million and $13 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	295,930	 	$	369,954	 	$	447,908	 	
Sales to AEP Affiliates	 	 	33,225	 	 	47,164	 	 	51,680	 	
Other	 	 	315	 	 	41,770	 	 	53,870	 	
TOTAL	 	 	329,470	 	 	458,888	 	 	553,458	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	46,173	 	 	46,953	 	 	54,447	 	
Fuel from Affiliates Used for Electric Generation	 	 	537	 	 	629	 	 	46,496	 	
Purchased Electricity for Resale	 	 	72,760	 	 	125,567	 	 	133,770	 	
Purchased Electricity from AEP Affiliates	 	 	5,948	 	 	23	 	 	5,211	 	
Other Operation	 	 	81,437	 	 	120,618	 	 	140,206	 	
Maintenance	 	 	21,846	 	 	23,636	 	 	20,602	 	
Depreciation and Amortization	 	 	42,914	 	 	41,466	 	 	39,025	 	
Taxes Other Than Income Taxes	 	 	22,568	 	 	23,297	 	 	22,630	 	
TOTAL	 	 	294,183	 	 	382,189	 	 	462,387	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	35,287	 	 	76,699	 	 	91,071	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	643	 	 	2,447	 	 	665	 	
Allowance for Equity Funds Used During Construction	 	 	886	 	 	724	 	 	417	 	
Interest Expense	 	 	(17,619	)	 	(19,817	)	 	(21,985	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	19,197	 	 	60,053	 	 	70,168	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	4,254	 	 	18,577	 	 	22,509	 	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	 	 	14,943	 	 	41,476	 	 	47,659	 	
 	 	 	 	 	 	 	 	 	 	 	
CUMULATIVE EFFECT OF ACCOUNTING CHANGE,  NET OF TAX	 	 	-	 	 	(8,472	)	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	14,943	 	 	33,004	 	 	47,659	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements	 	 	103	 	 	104	 	 	103	 	
Gain on Reacquired Preferred Stock	 	 	2	 	 	-	 	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$	14,842	 	$	32,900	 	$	47,556	 	

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	137,214	 	$	2,351	 	$	125,428	 	$	(26,718	)	$	238,275	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(2,000	)	 	 	 	 	(2,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(103	)	 	 	 	 	(103	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	236,172	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income, Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $477	 	 	 	 	 	 	 	 	 	 	 	886	 	 	886	 	
Minimum Pension Liability, Net of Tax   of $13,841	 	 	 	 	 	 	 	 	 	 	 	25,704	 	 	25,704	 	
NET INCOME	 	 	 	 	 	 	 	 	47,659	 	 	 	 	 	47,659	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	74,249	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	137,214	 	 	2,351	 	 	170,984	 	 	(128	)	 	310,421	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(29,026	)	 	 	 	 	(29,026	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(104	)	 	 	 	 	(104	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	281,291	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $213	 	 	 	 	 	 	 	 	 	 	 	(396	)	 	(396	)	
Minimum Pension Liability, Net of Tax   of $11	 	 	 	 	 	 	 	 	 	 	 	20	 	 	20	 	
NET INCOME	 	 	 	 	 	 	 	 	33,004	 	 	 	 	 	33,004	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	32,628	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	137,214	 	 	2,351	 	 	174,858	 	 	(504	)	 	313,919	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(12,750	)	 	 	 	 	(12,750	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(103	)	 	 	 	 	(103	)	
Gain on Reacquired Preferred Stock	 	 	 	 	 	 	 	 	2	 	 	 	 	 	2	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	301,068	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $318	 	 	 	 	 	 	 	 	 	 	 	(591	)	 	(591	)	
Minimum Pension Liability, Net of Tax   of $37	 	 	 	 	 	 	 	 	 	 	 	68	 	 	68	 	
NET INCOME	 	 	 	 	 	 	 	 	14,943	 	 	 	 	 	14,943	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	14,420	 	
Minimum Pension Liability Elimination, Net of Tax   of $175	 	 	 	 	 	 	 	 	 	 	 	325	 	 	325	 	
SFAS 158 Adoption, Net of Tax of $5,092	 	 	 	 	 	 	 	 	 	 	 	(9,457	)	 	(9,457	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2006	 	$	137,214	 	$	2,351	 	$	176,950	 	$	(10,159	)	$	306,356	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	84	 	$	-	 	
Other Cash Deposits	 	 	8,863	 	 	1,432	 	
Advances to Affiliates	 	 	13,543	 	 	34,286	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	21,742	 	 	77,678	 	
Affiliated Companies	 	 	5,634	 	 	26,149	 	
Accrued Unbilled Revenues	 	 	2,292	 	 	5,016	 	
Allowance for Uncollectible Accounts	 	 	(9	)	 	(18	)	
   Total Accounts Receivable	 	 	29,659	 	 	108,825	 	
Fuel	 	 	8,559	 	 	2,636	 	
Materials and Supplies	 	 	9,319	 	 	6,858	 	
Risk Management Assets	 	 	-	 	 	7,114	 	
Prepayments and Other	 	 	1,681	 	 	3,772	 	
TOTAL	 	 	71,708	 	 	164,923	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	290,485	 	 	288,934	 	
Transmission	 	 	327,845	 	 	289,029	 	
Distribution	 	 	512,265	 	 	492,878	 	
Other	 	 	159,451	 	 	167,849	 	
Construction Work in Progress	 	 	38,847	 	 	46,424	 	
Total	 	 	1,328,893	 	 	1,285,114	 	
Accumulated Depreciation and Amortization	 	 	486,961	 	 	478,519	 	
TOTAL - NET	 	 	841,932	 	 	806,595	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	38,402	 	 	9,787	 	
Long-term Risk Management Assets	 	 	-	 	 	5,772	 	
Employee Benefits and Pension Assets	 	 	12,867	 	 	46,289	 	
Deferred Charges and Other	 	 	2,605	 	 	10,468	 	
TOTAL	 	 	53,874	 	 	72,316	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	967,514	 	$	1,043,834	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	$	4,448	 	$	19,739	 	
Affiliated Companies	 	 	43,993	 	 	84,923	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	8,151	 	 	-	 	
Risk Management Liabilities	 	 	-	 	 	6,475	 	
Accrued Taxes	 	 	21,782	 	 	21,212	 	
Other	 	 	14,934	 	 	21,050	 	
TOTAL	 	 	93,308	 	 	153,399	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	268,785	 	 	276,845	 	
Long-term Risk Management Liabilities	 	 	1,081	 	 	3,906	 	
Deferred Income Taxes	 	 	124,048	 	 	132,335	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	139,429	 	 	139,732	 	
Deferred Credits and Other	 	 	32,158	 	 	21,341	 	
TOTAL	 	 	565,501	 	 	574,159	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	658,809	 	 	727,558	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	2,349	 	 	2,357	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - Par Value - $25 Per Share:	 	 	 	 	 	 	 	
Authorized - 7,800,000 Shares	 	 	 	 	 	 	 	
Outstanding - 5,488,560 Shares	 	 	137,214	 	 	137,214	 	
Paid-in Capital	 	 	2,351	 	 	2,351	 	
Retained Earnings	 	 	176,950	 	 	174,858	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(10,159	)	 	(504	)	
TOTAL	 	 	306,356	 	 	313,919	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	967,514	 	$	1,043,834	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	  2006	 	  2005	 	  2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	14,943	 	$	33,004	 	$	47,659	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	42,914	 	 	41,466	 	 	39,025	 	
Deferred Income Taxes	 	 	(227	)	 	(4,578	)	 	4,236	 	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	8,472	 	 	-	 	
Mark-to-Market of Risk Management Contracts	 	 	2,698	 	 	1,494	 	 	428	 	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(1,409	)	 	(21,172	)	
Fuel Over/Under Recovery, Net	 	 	2,915	 	 	996	 	 	10,100	 	
Change in Other Noncurrent Assets	 	 	(7,136	)	 	(3,003	)	 	(9,264	)	
Change in Other Noncurrent Liabilities	 	 	(7,812	)	 	(1,897	)	 	12,444	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	79,166	 	 	(2,513	)	 	(20,620	)	
Fuel, Materials and Supplies	 	 	(8,384	)	 	1,927	 	 	8,374	 	
Accounts Payable	 	 	(54,379	)	 	35,659	 	 	8,238	 	
Accrued Taxes, Net	 	 	570	 	 	(16,057	)	 	14,392	 	
Unbilled Construction Costs	 	 	37	 	 	20,744	 	 	(5,122	)	
Other Current Assets	 	 	2,053	 	 	(99	)	 	764	 	
Other Current Liabilities	 	 	(5,943	)	 	5,138	 	 	90	 	
Net Cash Flows From Operating Activities	 	 	61,415	 	 	119,344	 	 	89,572	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(70,350	)	 	(63,014	)	 	(35,901	)	
Change in Other Cash Deposits, Net	 	 	1,203	 	 	876	 	 	555	 	
Change In Advances to Affiliates, Net	 	 	20,743	 	 	17,218	 	 	(9,911	)	
Proceeds from Sale of Assets	 	 	330	 	 	1,033	 	 	510	 	
Other	 	 	-	 	 	(8,469	)	 	-	 	
Net Cash Flows Used for Investing Activities	 	 	(48,074	)	 	(52,356	)	 	(44,747	)	

FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Retirement of Long-term Debt - Nonaffiliated	 	 	-	 	 	(37,609	)	 	(42,506	)	
Retirement of Cumulative Preferred Stock	 	 	(6	)	 	-	 	 	-	 	
Principal Payments for Capital Lease Obligations	 	 	(398	)	 	(249	)	 	(216	)	
Dividends Paid on Common Stock	 	 	(12,750	)	 	(29,026	)	 	(2,000	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(103	)	 	(104	)	 	(103	)	
Net Cash Flows Used For Financing Activities	 	 	(13,257	)	 	(66,988	)	 	(44,825	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase in Cash and Cash Equivalents	 	 	84	 	 	-	 	 	-	 	
Cash and Cash Equivalents at Beginning of Period	 	 	-	 	 	-	 	 	-	 	
Cash and Cash Equivalents at End of Period	 	$	84	 	$	-	 	$	-	 	

SUPPLEMENTARY INFORMATION	 	  	 	  	 	  	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	15,457	 	$	19,042	 	$	20,860	 	
Net Cash Paid for Income Taxes	 	 	5,834	 	 	41,306	 	 	6,905	 	
Noncash Acquisitions Under Capital Leases	 	 	1,291	 	 	442	 	 	282	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	1,317	 	 	3,159	 	 	1,034	 	

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to TNC’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to TNC.
 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
AEP Texas North Company:

We have audited the accompanying consolidated balance sheets of AEP Texas North Company and subsidiary (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas North Company and subsidiary   as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006. As discussed in Note 17 to the consolidated financial statements, the Company adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations,” effective December 31, 2005.   As discussed in Note 9 to the consolidated financial statements, the Company adopted FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007

 

 

 

 
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 

 

 

 

 

 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
 	 	 	 	 	 	 	 	 	 	 	 	
STATEMENTS OF INCOME DATA	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	2,394,028	 	$	2,176,273	 	$	1,957,846	 	$	1,950,867	 	$	1,848,258	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	365,643	 	$	283,388	 	$	328,561	 	$	416,410	 	$	430,189	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of  Accounting Changes	 	$	181,449	 	$	135,832	 	$	153,115	 	$	202,783	 	$	205,492	 	
Cumulative Effect of Accounting Changes,  Net of Tax	 	 	-	 	 	(2,256	)	 	-	 	 	77,257	 	 	-	 	
Net Income	 	$	181,449	 	$	133,576	 	$	153,115	 	$	280,040	 	$	205,492	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	8,000,278	 	$	7,176,961	 	$	6,563,207	 	$	6,174,158	 	$	5,929,348	 	
Accumulated Depreciation and Amortization	 	 	2,476,290	 	 	2,524,855	 	 	2,456,417	 	 	2,334,013	 	 	2,343,507	 	
Net Property, Plant and Equipment	 	$	5,523,988	 	$	4,652,106	 	$	4,106,790	 	$	3,840,145	 	$	3,585,841	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	7,016,316	 	$	6,254,093	 	$	5,239,918	 	$	4,977,011	 	$	4,722,442	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder’s Equity	 	$	2,036,174	 	$	1,803,701	 	$	1,409,718	 	$	1,336,987	 	$	1,166,057	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)	 	$	2,598,664	 	$	2,151,378	 	$	1,784,598	 	$	1,864,081	 	$	1,893,861	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	$	17,763	 	$	17,784	 	$	17,784	 	$	17,784	 	$	17,790	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock  Subject to Mandatory Redemption	 	$	-	 	$	-	 	$	-	 	$	5,360	 	$	10,860	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	11,859	 	$	14,892	 	$	19,878	 	$	25,352	 	$	33,589	 	

(a)	Including portion due within one year.	

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 949,000 retail customers in our service territory in southwestern Virginia and southern West Virginia. We consolidate Cedar Coal Company, Central Appalachian Coal Company and Southern Appalachian Coal Company, our wholly-owned subsidiaries. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of power and gas trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. Management is unable to predict the ultimate effect on future results of operations and cash flows but expects an increase in margins accruing to the AEP East companies as a result of the SIA change. Our impact will also depend upon the level of future trading and marketing margins in PJM and MISO and sharing mechanisms with customers for off-system sales margins in West Virginia and Virginia. The 2006 results of operations and cash flows reflect nine months of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.
 
Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	136	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	57	 	 	 	 	
Off-system Sales	 	 	51	 	 	 	 	
Transmission Revenues	 	 	(42	)	 	 	 	
Other	 	 	11	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	77	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	20	 	 	 	 	
Depreciation and Amortization	 	 	(15	)	 	 	 	
Carrying Costs Income	 	 	11	 	 	 	 	
Other Income	 	 	10	 	 	 	 	
Interest Expense	 	 	(23	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	3	 	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(35	)	
 	 	 	 	 	 	 	 	
   Year Ended December 31, 2006	 	 	 	 	$	181	 	

Income Before Cumulative Effect of Accounting Change increased $45 million to $181 million in 2006 primarily due to an increase in Gross Margin of $77 million, partially offset by an increase in Income Tax Expense of $35 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins increased $57 million in comparison to 2005 primarily due to:	
 	·	A $71 million increase in retail revenues primarily related to a new industrial customer transferred from an affiliate in 2006 and new rates implemented in relation to our Virginia general rate case subject to refund. See the “APCo Virginia Base Rate Case” section of Note 4.	
 	·	A $27 million reduction in capacity settlement payments under the Interconnection Agreement due to our lower MLR share and our increased capacity, partially from our purchase of the Ceredo Generating Station in 2005.	
 	·	A $20 million increase in fuel recovery mainly caused by the reactivation of the West Virginia fuel clause in July 2006. See the “APCo West Virginia Rate Case” section of Note 4.	
 	These increases were partially offset by:	
 	·	A $45 million decrease related to the Expanded Net Energy Cost (ENEC) mechanism with West Virginia retail customers primarily due to pass-through of off-system sales margins. The   mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case. See the “APCo West Virginia Rate Case” section of Note 4.  	
 	·	An $18 million decrease in retail sales primarily due to decreased demand in the residential class associated with unfavorable weather conditions. Heating degree days decreased approximately 19% and cooling degree days decreased approximately 12%.	
·	Margins from Off-system Sales increased $51 million primarily due to a $51 million increase in physical sales margins and a $26 million increase in our allocation of off-system sales margins under the SIA, offset by a $26 million decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Transmission Revenues decreased $42 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $11 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 4.	
·	Other revenue increased $11 million primarily due to the reversal of previously deferred gains on sales of allowances associated with the Virginia Environmental and Reliability Costs (E&R) case. See “APCo Virginia Environmental and Reliability Costs” section of Note 4.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses decreased $20 million mainly due to a decrease in expenses associated with the Transmission Equalization Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.	
·	Depreciation and Amortization expenses increased $15 million primarily due to the disallowance of certain depreciation expenses previously capitalized in our E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 4.	
·	Carrying Costs Income increased $11 million related to carrying costs associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 4.	
·	Other Income increased $10 million primarily due to interest income related to an increase in Advances to Affiliates during the year and an increase in AFUDC related to our environmental investment program.	
·	Interest Expense increased $23 million primarily due to long-term debt issuances in 2006, partially offset by an increase in allowance for borrowed funds used during construction.	

Income Taxes

Income Tax Expense increased $35 million primarily due to an increase in pretax book income and state income taxes.  

2005 Compared to 2004

Reconciliation of Year Ended December 31, 2004 to Year Ended December 31, 2005
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2004	 	 	 	 	$	153	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	(55	)	 	 	 	
Off-system Sales	 	 	60	 	 	 	 	
Transmission Revenues	 	 	(15	)	 	 	 	
Other	 	 	2	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	(8	)	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(40	)	 	 	 	
Depreciation and Amortization	 	 	3	 	 	 	 	
Carrying Costs Income	 	 	14	 	 	 	 	
Other Income	 	 	2	 	 	 	 	
Interest Expense	 	 	(7	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(28	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	19	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2005	 	 	 	 	$	136	 	
 
Income Before Cumulative Effect of Accounting Change decreased $17 million to $136 million in 2005. The key drivers of the decrease were a $28 million net increase in operating expenses and other and an $8 million net decrease in Gross Margin offset by a $19 million decrease in Income Tax Expense.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins decreased $55 million in comparison to 2004 primarily due to :	
 	·	A $57 million increase in capacity settlement payments to affiliates under the Interconnection Agreement due to our higher MLR share caused by our new peak demand that was established in December 2004 .	
 	·	A $27 million decrease in fuel margins resulting from higher delivered fuel costs.	
 	The decreases were partially offset by:	
 	·	A $26 million increase in retail sales due to favorable weather conditions. Cooling degree days increased approximately 11%.	
·	Off-system Sales for 2005 increased $60 million compared to 2004 primarily due to increased AEP Power Pool physical sales as well as favorable optimization activities.	
·	Transmission Revenues decreased $15 million primarily due to the elimination of revenues related to through and out rates partially offset by revenues from replacement SECA rates. See “Transmission Rate Proceedings at The FERC” section of Note 4.	
 
Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $40 million primarily due to a $15 million increase in generation operation and maintenance expenses, a $10 million increase in system dispatch costs related to our operation in PJM and a $9 million increase in costs associated with the AEP Transmission Equalization Agreement.	
·	Carrying Costs Income increased $14 million primarily related to the establishment of a regulatory asset for carrying costs associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 4.	
·	Interest Expense increased $7 million primarily due to long-term debt issuances in 2005.	

Income Taxes

Income Tax Expense decreased $19 million primarily due to a decrease in pretax book income and a reduction of 2005 state income taxes due in part to the phase-out of the Ohio Franchise Tax.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	
Senior Unsecured Debt	Baa2	 	BBB	 	BBB+	
 
Cash Flow

Cash flows for 2006, 2005 and 2004 were as follows:

 	 	2006	 	2005	 	2004	 	
 	 	(in thousands)	 	
Cash and Cash Equivalents at Beginning of Period	 	$	1,741	 	$	1,543	 	$	4,714	 	
Cash Flows From (Used For):	 	 	 	 	 	 	 	 	 	 	
Operating Activities	 	 	468,275	 	 	151,474	 	 	406,324	 	
Investing Activities	 	 	(880,397	)	 	(687,515	)	 	(391,904	)	
Financing Activities	 	 	412,699	 	 	536,239	 	 	(17,591	)	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	577	 	 	198	 	 	(3,171	)	
Cash and Cash Equivalents at End of Period	 	$	2,318	 	$	1,741	 	$	1,543	 	

Operating Activities

Net Cash Flows From Operating Activities were $468 million in 2006. We produced income of $181 million during the period and noncash expense items of $206 million for Depreciation and Amortization and $17 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had no significant items in 2006.

Net Cash Flows From Operating Activities were $151 million in 2005. We produced income of $134 million during the period and noncash expense items of $191 million for Depreciation and Amortization and $73 million for Deferred Income Taxes offset by an increase in Pension Contributions to Qualified Plan Trusts of $129 million. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had one significant item, a decrease in Accrued Taxes, Net of $74 million. During 2005, we made federal income tax payments of $75 million .

Net Cash Flows From Operating Activities were $406 million in 2004. We produced income of $153 million during the period and noncash expense items of $194 million for Depreciation and Amortization and $48 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had one significant item, an increase in Accrued Taxes, Net of $40 million. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. A payment was made in March 2005 when the 2004 federal income tax return extension was filed.

Investing Activities

Net Cash Flows Used For Investing Activities during 2006, 2005, and 2004 primarily reflect our construction expenditures of $893 million, $598 million, and $437 million, respectively. Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades. In 2006, 2005 and 2004, capital projects for transmission expenditures are primarily related to the Wyoming-Jacksons Ferry 765 KV line placed into service in June 2006. Environmental upgrades include the installation of selective catalytic reduction equipment on our plants and the flue gas desulfurization project at the Amos and Mountaineer plants. In 2005, we also acquired the Ceredo Generating Station for approximately $100 million.

Financing Activities

Net Cash Flows From Financing Activities were $413 million in 2006. We issued $500 million in Senior Unsecured Notes and $50 million in Pollution Control Bonds. We also received Capital Contributions from Parent Company of $100 million and retired $100 million of First Mortgage Bonds. We reduced short-term borrowings from the Utility Money Pool by $159 million. In addition, we received funds of $68 million related to a long-term coal purchase contract amended in March 2006, partially offset by repayments of $24 million. See “Coal Contract Amendment” within “Significant Factors” for additional information.

Net Cash Flows From Financing Activities were $536 million in 2005. We issued Senior Unsecured Notes of $850 million and Notes Payable - Affiliated of $100 million. We also received Capital Contributions from Parent Company of $200 million. We retired $450 million of Senior Unsecured Notes and three series of First Mortgage Bonds totaling $125 million. We reduced short-term borrowings from the Utility Money Pool by $17 million.

Net Cash Flows Used For Financing Activities were $18 million in 2004. We issued Senior Unsecured Notes of $125 million and reacquired First Mortgage Bonds, Senior Unsecured Notes, and Installment Purchase Contracts of $116 million, $50 million, and $40 million, respectively, at higher stated interest rates. We also increased borrowings from the Utility Money Pool of $128 million and paid common dividends of $50 million.

Summary Obligation Information

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payments Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	35.0	 	$	-	 	$	-	 	$	-	 	$	35.0	 	
Interest on Fixed Rate Portion of Long-term  Debt (b)	 	 	124.0	 	 	216.0	 	 	174.0	 	 	1,196.0	 	 	1,710.0	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	200.0	 	 	350.0	 	 	500.0	 	 	1,301.0	 	 	2,351.0	 	
Variable Rate Portion of Long-term Debt (d)	 	 	124.0	 	 	-	 	 	-	 	 	139.0	 	 	263.0	 	
Capital Lease Obligations (e)	 	 	4.8	 	 	6.3	 	 	1.8	 	 	0.3	 	 	13.2	 	
Noncancelable Operating Leases (e)	 	 	12.4	 	 	19.9	 	 	13.5	 	 	14.7	 	 	60.5	 	
Fuel Purchase Contracts (f)	 	 	627.2	 	 	873.6	 	 	548.8	 	 	1,847.8	 	 	3,897.4	 	
Energy and Capacity Purchase Contracts (g)	 	 	3.2	 	 	4.8	 	 	7.1	 	 	1.5	 	 	16.6	 	
Construction Contracts for Capital Assets (h)	 	 	323.8	 	 	252.0	 	 	-	 	 	323.1	 	 	898.9	 	
Total	 	$	1,454.4	 	$	1,722.6	 	$	1,245.2	 	$	4,823.4	 	$	9,245.6	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.50% and 5.69% at December 31, 2006.	
(e)	See Note 14.	
(f)	Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.	
(g)	Represents contractual cash flows of energy and capacity purchase contracts.	
(h)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Coal Contract Amendment

We negotiated an amendment to a nonderivative coal contract that was assigned to a new owner of a coal supplier to which we were contractually obligated. The amended contract includes adjustments in the quantity related to the shortfall of tons in prior years, escalated tonnage deliveries in 2006 and a pricing change related to future coal deliveries. In March 2006, the new owner agreed to pay us $80 million for the settlement, release and amendment of the original contract. With respect to prior years’ undelivered coal, the new owner paid us $12 million for the shortfall tons. With respect to deliveries of coal in 2006-2007, the third party paid us the remaining $68 million for the agreed upon price increase.

The receipt of funds reduces the risk that the third party will short future deliveries. However, if they fail to deliver, we are not contractually obligated to repay any portion of the settlement payment. Our net coal price will not materially change from the original contract price as a result of the $68 million payment that we received for future coal deliveries through 2007.

Since there are no further requirements related to the liquidation of the shortfall tons, we recognized the $12 million shortfall payment in the first quarter of 2006. We recorded a $5 million reduction in Regulatory Assets on our Consolidated Balance Sheet and recorded the remaining $7 million as a reduction to Fuel and Other Consumables for Electric Generation on our Consolidated Statement of Income . We recorded the $68 million payment within Deferred Credits and Other on our Consolidated Balance Sheet. To the extent tons are received, payment of the higher contracted price per ton will effectively result in a repayment of funds to the coal supplier of which $24 million occurred in 2006 and $44 million is expected to occur in 2007. The remaining $44 million is recorded in Current Liabilities - Other on our Consolidated Balance Sheet at December 31, 2006.

New Generation

In January 2006, we filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to our existing Mountaineer generating station in Mason County, West Virginia. In January 2007, the WVPSC issued an order granting our motion to delay the Commission’s statutory deadline for issuing an order on the certificate for the construction of the proposed IGCC plant. The WVPSC approved a deadline of December 3, 2007. Through December 31, 2006, we deferred pre-construction IGCC costs totaling $10 million.

Virginia Restructuring
 
In February 2007, the Virginia legislature adopted amendments to its electric restructuring law. The amendments would shorten the transition period by two years (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. We are in the process of evaluating the impact of the legislation if it is signed into law.
 
Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, cash flows and financial condition.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included on our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow &
Fair Value Hedges	 	DETM Assignment (a)	 	Total	 	
Current Assets	 	$	96,437	 	$	8,939	 	$	-	 	$	105,376	 	
Noncurrent Assets	 	 	88,780	 	 	126	 	 	-	 	 	88,906	 	
Total MTM Derivative Contract Assets	 	 	185,217	 	 	9,065	 	 	-	 	 	194,282	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(77,028	)	 	(1,696	)	 	(2,390	)	 	(81,114	)	
Noncurrent Liabilities	 	 	(55,700	)	 	(375	)	 	(8,834	)	 	(64,909	)	
Total MTM Derivative Contract Liabilities	 	 	(132,728	)	 	(2,071	)	 	(11,224	)	 	(146,023	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	52,489	 	$	6,994	 	$	(11,224	)	$	48,259	 	

(a)	See “Natural Gas Contracts with DETM” section of Note 16.	
 
MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	56,407	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(9,668	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	499	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	(279	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	316	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	5,007	 	
Changes Due to SIA Agreement (c)	 	 	(6,533	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	6,740	 	
Total MTM Risk Management Contract Net Assets	 	 	52,489	 	
Net Cash Flow & Fair Value Hedge Contracts	 	 	6,994	 	
DETM Assignment (e)	 	 	(11,224	)	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	48,259	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	
(e)	See “Natural Gas Contracts with DETM” section of Note 16.	
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Prices Actively Quoted - Exchange Traded Contracts	 	$	5,379	 	$	3,847	 	$	645	 	$	-	 	$	-	 	$	-	 	$	9,871	 	
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)	 	 	15,738	 	 	5,180	 	 	7,521	 	 	-	 	 	-	 	 	-	 	 	28,439	 	
Prices Based on Models and Other Valuation Methods (b)	 	 	(1,708	)	 	781	 	 	3,860	 	 	8,631	 	 	1,137	 	 	1,478	 	 	14,179	 	
Total	 	$	19,409	 	$	9,808	 	$	12,026	 	$	8,631	 	$	1,137	 	$	1,478	 	$	52,489	 	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

We use forward contracts and collars as cash flow hedges to lock-in prices on certain transactions denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	Foreign
Currency	 	Interest
Rate	 	Total	 	
Beginning Balance in AOCI December 31, 2005	 	$	(1,480	)	$	(171	)	$	(14,770	)	$	(16,421	)	
Changes in Fair Value	 	 	5,414	 	 	-	 	 	4,951	 	 	10,365	 	
Impact due to Changes in SIA (a)	 	 	(442	)	 	-	 	 	-	 	 	(442	)	
Reclassifications from AOCI to Net Income for Cash Flow  Hedges Settled	 	 	1,840	 	 	7	 	 	2,104	 	 	3,951	 	
Ending Balance in AOCI December 31, 2006	 	$	5,332	 	$	(164	)	$	(7,715	)	$	(2,547	)	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $3,709 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$756	 	$1,915	 	$658	 	$358	 	 	 	 	$732	 	$1,216	 	$579	 	$209	

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $153 million and $142 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	2,145,639	 	$	1,845,170	 	$	1,698,220	 	
Sales to AEP Affiliates	 	 	238,592	 	 	322,333	 	 	252,128	 	
Other	 	 	9,797	 	 	8,770	 	 	7,498	 	
TOTAL	 	 	2,394,028	 	 	2,176,273	 	 	1,957,846	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	638,862	 	 	549,773	 	 	432,420	 	
Purchased Electricity for Resale	 	 	123,592	 	 	110,693	 	 	84,433	 	
Purchased Electricity from AEP Affiliates	 	 	492,756	 	 	453,600	 	 	370,953	 	
Other Operation	 	 	284,350	 	 	315,605	 	 	279,075	 	
Maintenance	 	 	190,697	 	 	179,119	 	 	175,283	 	
Depreciation and Amortization	 	 	205,666	 	 	191,128	 	 	194,356	 	
Taxes Other Than Income Taxes	 	 	92,462	 	 	92,967	 	 	92,765	 	
TOTAL	 	 	2,028,385	 	 	1,892,885	 	 	1,629,285	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	365,643	 	 	283,388	 	 	328,561	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	8,648	 	 	2,540	 	 	1,985	 	
Carrying Costs Income	 	 	25,666	 	 	14,438	 	 	255	 	
Allowance for Equity Funds Used During Construction	 	 	12,014	 	 	7,956	 	 	6,560	 	
Interest Expense	 	 	(129,106	)	 	(106,301	)	 	(99,135	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	282,865	 	 	202,021	 	 	238,226	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	101,416	 	 	66,189	 	 	85,111	 	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	 	 	181,449	 	 	135,832	 	 	153,115	 	
 	 	 	 	 	 	 	 	 	 	 	
CUMULATIVE EFFECT OF ACCOUNTING CHANGE,  NET OF TAX	 	 	-	 	 	(2,256	)	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	181,449	 	 	133,576	 	 	153,115	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements including Capital Stock  Expense and Other	 	 	952	 	 	2,178	 	 	3,215	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$	180,497	 	$	131,398	 	$	149,900	 	

The common stock of APCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	260,458	 	$	719,899	 	$	408,718	 	$	(52,088	)	$	1,336,987	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(50,000	)	 	 	 	 	(50,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(800	)	 	 	 	 	(800	)	
Capital Stock Expense	 	 	 	 	 	2,415	 	 	(2,415	)	 	 	 	 	-	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,286,187	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Loss, Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $4,176	 	 	 	 	 	 	 	 	 	 	 	(7,755	)	 	(7,755	)	
Minimum Pension Liability, Net of Tax of $11,754	 	 	 	 	 	 	 	 	 	 	 	(21,829	)	 	(21,829	)	
NET INCOME	 	 	 	 	 	 	 	 	153,115	 	 	 	 	 	153,115	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	123,531	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	260,458	 	 	722,314	 	 	508,618	 	 	(81,672	)	 	1,409,718	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital Contributions From Parent	 	 	 	 	 	200,000	 	 	 	 	 	 	 	 	200,000	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(5,000	)	 	 	 	 	(5,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(800	)	 	 	 	 	(800	)	
Capital Stock Expense and Other	 	 	 	 	 	2,523	 	 	(1,378	)	 	 	 	 	1,145	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,605,063	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $3,821	 	 	 	 	 	 	 	 	 	 	 	(7,097	)	 	(7,097	)	
Minimum Pension Liability, Net of Tax of $38,855	 	 	 	 	 	 	 	 	 	 	 	72,159	 	 	72,159	 	
NET INCOME	 	 	 	 	 	 	 	 	133,576	 	 	 	 	 	133,576	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	198,638	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	260,458	 	 	924,837	 	 	635,016	 	 	(16,610	)	 	1,803,701	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital Contributions From Parent	 	 	 	 	 	100,000	 	 	 	 	 	 	 	 	100,000	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(10,000	)	 	 	 	 	(10,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(800	)	 	 	 	 	(800	)	
Capital Stock Expense and Other	 	 	 	 	 	157	 	 	(152	)	 	 	 	 	5	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,892,906	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $7,471	 	 	 	 	 	 	 	 	 	 	 	13,874	 	 	13,874	 	
Minimum Pension Liability, Net of Tax   of $8	 	 	 	 	 	 	 	 	 	 	 	(14	)	 	(14	)	
NET INCOME	 	 	 	 	 	 	 	 	181,449	 	 	 	 	 	181,449	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	195,309	 	
Minimum Pension Liability Elimination , Net of Tax   of $110	 	 	 	 	 	 	 	 	 	 	 	203	 	 	203	 	
SFAS 158 Adoption, Net of Tax of $28,132	 	 	 	 	 	 	 	 	 	 	 	(52,244	)	 	(52,244	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2006	 	$	260,458	 	$	1,024,994	 	$	805,513	 	$	(54,791	)	$	2,036,174	 	

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	2,318	 	$	1,741	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	180,190	 	 	141,810	 	
Affiliated Companies	 	 	98,237	 	 	153,453	 	
Accrued Unbilled Revenues	 	 	46,281	 	 	51,201	 	
Miscellaneous	 	 	3,400	 	 	527	 	
Allowance for Uncollectible Accounts	 	 	(4,334	)	 	(1,805	)	
   Total Accounts Receivable	 	 	323,774	 	 	345,186	 	
Fuel	 	 	77,077	 	 	64,657	 	
Materials and Supplies	 	 	56,235	 	 	54,967	 	
Risk Management Assets	 	 	105,376	 	 	132,247	 	
Accrued Tax Benefits	 	 	3,748	 	 	32,979	 	
Regulatory Asset for Under-Recovered Fuel Costs	 	 	29,526	 	 	30,697	 	
Prepayments and Other	 	 	20,126	 	 	44,432	 	
TOTAL	 	 	618,180	 	 	706,906	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	2,844,803	 	 	2,798,157	 	
Transmission	 	 	1,620,512	 	 	1,266,855	 	
Distribution	 	 	2,237,887	 	 	2,141,153	 	
Other	 	 	339,450	 	 	323,158	 	
Construction Work in Progress	 	 	957,626	 	 	647,638	 	
Total	 	 	8,000,278	 	 	7,176,961	 	
Accumulated Depreciation and Amortization	 	 	2,476,290	 	 	2,524,855	 	
TOTAL - NET	 	 	5,523,988	 	 	4,652,106	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	622,153	 	 	457,294	 	
Long-term Risk Management Assets	 	 	88,906	 	 	176,231	 	
Deferred Charges and Other	 	 	163,089	 	 	261,556	 	
TOTAL	 	 	874,148	 	 	895,081	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	7,016,316	 	$	6,254,093	 	

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	  2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	34,975	 	$	194,133	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	296,437	 	 	230,570	 	
Affiliated Companies	 	 	105,525	 	 	85,941	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	324,191	 	 	146,999	 	
Risk Management Liabilities	 	 	81,114	 	 	121,165	 	
Customer Deposits	 	 	56,364	 	 	79,854	 	
Accrued Taxes	 	 	60,056	 	 	49,833	 	
Other	 	 	172,943	 	 	108,746	 	
TOTAL	 	 	1,131,605	 	 	1,017,241	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	2,174,473	 	 	1,904,379	 	
Long-term Debt - Affiliated	 	 	100,000	 	 	100,000	 	
Long-term Risk Management Liabilities	 	 	64,909	 	 	147,117	 	
Deferred Income Taxes	 	 	957,229	 	 	952,497	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	309,724	 	 	201,230	 	
Deferred Credits and Other	 	 	224,439	 	 	110,144	 	
TOTAL	 	 	3,830,774	 	 	3,415,367	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	4,962,379	 	 	4,432,608	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	17,763	 	 	17,784	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - No Par Value:	 	 	 	 	 	 	 	
Authorized - 30,000,000 Shares	 	 	 	 	 	 	 	
Outstanding - 13,499,500 Shares	 	 	260,458	 	 	260,458	 	
Paid-in Capital	 	 	1,024,994	 	 	924,837	 	
Retained Earnings	 	 	805,513	 	 	635,016	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(54,791	)	 	(16,610	)	
TOTAL	 	 	2,036,174	 	 	1,803,701	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	7,016,316	 	$	6,254,093	 	

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	  2006	 	  2005	 	  2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	181,449	 	$	133,576	 	$	153,115	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	205,666	 	 	191,128	 	 	194,356	 	
Deferred Income Taxes	 	 	17,225	 	 	72,763	 	 	47,585	 	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	2,256	 	 	-	 	
Carrying Costs Income	 	 	(25,666	)	 	(14,438	)	 	(255	)	
Mark-to-Market of Risk Management Contracts	 	 	2,824	 	 	(13,701	)	 	5,391	 	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(129,117	)	 	(1,429	)	
Fuel Over/Under Recovery, Net	 	 	11,532	 	 	(36,499	)	 	(10,861	)	
Change in Other Noncurrent Assets	 	 	(67,865	)	 	(15,009	)	 	(24,059	)	
Change in Other Noncurrent Liabilities	 	 	54,745	 	 	(13,741	)	 	36,022	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	21,412	 	 	(26,665	)	 	(6,608	)	
Fuel, Materials and Supplies	 	 	(13,688	)	 	(25,419	)	 	(2,795	)	
Accounts Payable	 	 	37,533	 	 	61,086	 	 	(21,696	)	
Customer Deposits	 	 	(23,490	)	 	37,032	 	 	8,892	 	
Accrued Taxes, Net	 	 	39,454	 	 	(73,550	)	 	40,145	 	
Other Current Assets	 	 	25,252	 	 	(24,831	)	 	(3,237	)	
Other Current Liabilities	 	 	1,892	 	 	26,603	 	 	(8,242	)	
Net Cash Flows From Operating Activities	 	 	468,275	 	 	151,474	 	 	406,324	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(892,816	)	 	(597,808	)	 	(436,535	)	
Change in Other Cash Deposits, Net	 	 	(945	)	 	(24	)	 	41,040	 	
Purchase of Ceredo Generating Station	 	 	-	 	 	(100,000	)	 	-	 	
Proceeds from Sales of Assets	 	 	13,364	 	 	10,317	 	 	3,591	 	
Net Cash Flows Used For Investing Activities	 	 	(880,397	)	 	(687,515	)	 	(391,904	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Capital Contributions from Parent Company	 	 	100,000	 	 	200,000	 	 	-	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	561,710	 	 	840,469	 	 	124,398	 	
Issuance of Long-term Debt - Affiliated	 	 	-	 	 	100,000	 	 	-	 	
Change in Advances from Affiliates, Net	 	 	(159,158	)	 	(16,927	)	 	128,066	 	
Retirement of Long-term Debt - Nonaffiliated	 	 	(117,511	)	 	(575,010	)	 	(206,008	)	
Retirement of Cumulative Preferred Stock	 	 	(16	)	 	-	 	 	(5,360	)	
Principal Payments for Capital Lease Obligations	 	 	(5,166	)	 	(6,493	)	 	(7,887	)	
Funds From Amended Coal Contract	 	 	68,078	 	 	-	 	 	-	 	
Amortization of Funds From Amended Coal Contract	 	 	(24,438	)	 	-	 	 	-	 	
Dividends Paid on Common Stock	 	 	(10,000	)	 	(5,000	)	 	(50,000	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(800	)	 	(800	)	 	(800	)	
Net Cash Flows From (Used For) Financing Activities	 	 	412,699	 	 	536,239	 	 	(17,591	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	577	 	 	198	 	 	(3,171	)	
Cash and Cash Equivalents at Beginning of Period	 	 	1,741	 	 	1,543	 	 	4,714	 	
Cash and Cash Equivalents at End of Period	 	$	2,318	 	$	1,741	 	$	1,543	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	118,220	 	$	91,373	 	$	92,773	 	
Net Cash Paid (Received) for Income Taxes	 	 	50,830	 	 	75,160	 	 	(831	)	
Noncash Acquisitions Under Capital Leases	 	 	3,017	 	 	1,988	 	 	3,791	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	130,558	 	 	82,640	 	 	37,356	 	

In connection with the acquisition of Ceredo Generating Station in December 2005, we assumed $556 thousand of liabilities.

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to APCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo.

 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 8	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Appalachian Power Company:

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company   and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Notes 2 and 9 to the consolidated financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006, and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus,Ohio
February 28, 2007 

 

 

 

COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES

 

 

 

 

 

 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
STATEMENTS OF INCOME DATA	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	1,806,735	 	$	1,542,332	 	$	1,447,925	 	$	1,420,549	 	$	1,424,583	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	337,650	 	$	242,880	 	$	258,579	 	$	295,412	 	$	344,178	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of Accounting Changes	 	$	185,579	 	$	137,799	 	$	140,258	 	$	173,147	 	$	181,173	 	
Cumulative Effect of Accounting Changes,  Net of Tax	 	 	-	 	 	(839	)	 	-	 	 	27,283	 	 	-	 	
Net Income	 	$	185,579	 	$	136,960	 	$	140,258	 	$	200,430	 	$	181,173	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	4,336,191	 	$	4,026,653	 	$	3,717,075	 	$	3,598,388	 	$	3,497,187	 	
Accumulated Depreciation and Amortization	 	 	1,611,043	 	 	1,500,858	 	 	1,475,457	 	 	1,395,113	 	 	1,375,035	 	
Net Property, Plant and Equipment	 	$	2,725,148	 	$	2,525,795	 	$	2,241,618	 	$	2,203,275	 	$	2,122,152	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	3,520,689	 	$	3,432,794	 	$	3,029,896	 	$	2,838,366	 	$	2,849,261	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder's Equity	 	$	1,056,017	 	$	981,546	 	$	898,650	 	$	897,881	 	$	847,664	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)	 	$	1,197,322	 	$	1,196,920	 	$	987,626	 	$	897,564	 	$	621,626	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	8,472	 	$	9,576	 	$	12,514	 	$	15,618	 	$	27,610	 	

(a)	Including portion due within one year.	

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 742,000 retail customers in central and southern Ohio. We consolidate Colomet, Inc., Conesville Coal Preparation Company and Simco, Inc., our wholly-owned subsidiaries. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of power and gas trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. Management is unable to predict the ultimate effect on future results of operations and cash flows but expects an increase in margins accruing to the AEP East companies as a result of the SIA change. Our impact will also depend upon the level of future trading and marketing margins in PJM and MISO. The 2006 results of operations and cash flows reflect nine months of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	138	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	113	 	 	 	 	
Off-system Sales	 	 	44	 	 	 	 	
Transmission Revenues	 	 	(21	)	 	 	 	
Other	 	 	9	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	145	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(32	)	 	 	 	
Asset Impairments and Other Related Charges	 	 	39	 	 	 	 	
Depreciation and Amortization	 	 	(51	)	 	 	 	
Taxes Other Than Income Taxes	 	 	(6	)	 	 	 	
Carrying Costs Income	 	 	(6	)	 	 	 	
Other Income	 	 	5	 	 	 	 	
Interest Expense	 	 	(7	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(58	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(39	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	186	 	

Income Before Cumulative Effect of Accounting Change increased $48 million to $186 million in 2006. The key drivers of the increase were a $145 million increase in Gross Margin and a $39 million asset impairment of Units 1 and 2 at our Conesville Plant in 2005, partially offset by a $51 million increase in Depreciation and Amortization expense, a $39 million increase in Income Tax Expense and a $32 million increase in Other Operation and Maintenance expenses.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins increased $113 million primarily due to the RSP and Transition Regulatory Asset rate increases effective January 1, 2006, lower capacity settlement costs, and the addition of Monongahela Power’s Ohio customers on December 31, 2005, partially offset by an increase in delivered fuel costs.	
·	Margins from Off-system Sales increased $44 million due to a $39 million increase in physical sales margins and a $14 million increase in our allocation of off-system sales margins under the SIA, partially offset by a $10 million decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Transmission Revenues decreased $21 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $6 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 4.	
·	Other revenues increased $9 million primarily due to increased gains on sales of emission allowances.	
 
Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $32 million primarily due to a $12 million increase in transmission expenses related to the AEP Transmission Equalization Agreement, a $6 million increase related to factored receivables, a $4 million increase in removal costs at the Conesville and Stuart plants, and a $4 million increase in boiler plant maintenance costs at the Conesville, Waterford and Zimmer Plants. The increase in expenses related to the factoring of accounts receivable is primarily due to an increase in accounts receivable factored, an increase in bad debt write-offs and an increase in short-term interest rates.	
·	Asset Impairments and Other Related Charges in the amount of $39 million were recorded last year due to the 2005 retirement of Units 1 and 2 at our Conesville Plant.	
·	Depreciation and Amortization expense increased $51 million primarily due to a $42 million increase in the amortization of regulatory assets and a larger depreciable base resulting primarily from the acquisitions of the Waterford Plant and Monongahela Power’s Ohio assets. In addition, the 2005 RSP order resulted in a reversal of unused shopping credits of $18 million offset by the establishment of a $7 million regulatory liability to benefit low-income customers and economic development.	
·	Taxes Other Than Income Taxes increased $6 million due to increases in state excise taxes and property taxes associated with the Waterford and Monongahela asset additions, partially offset by accrual adjustments to property taxes that were favorable in 2006 and unfavorable in 2005.	
·	Carrying Costs Income decreased $6 million primarily due to the completion of deferrals of carrying costs on environmental capital expenditures from 2004 and 2005 that we continue to recover through 2008 in accordance with the RSP.	
·	Other Income increased $5 million due to interest income on tax refunds received for the years 1991 through 1996.	
·	Interest Expense increased $7 million primarily due to a new long-term debt issuance during the fourth quarter of 2005.	

Income Taxes

Income Tax Expense increased $39 million primarily due to an increase in pretax book income and the recording of the tax reserve adjustments.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 	 	 	 	 	 	 	 	 	 	 	 	 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Debt	A3	 	BBB	 	A-	
 
Summary Obligation Information

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payment Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	0.7	 	$	-	 	$	-	 	$	-	 	$	0.7	 	
Interest on Fixed Rate Portion of Long-term Debt (b)	 	 	63.0	 	 	117.0	 	 	99.0	 	 	726.0	 	 	1,005.0	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	-	 	 	112.0	 	 	250.0	 	 	750.0	 	 	1,112.0	 	
Variable Rate Portion of Long-term Debt (d)	 	 	-	 	 	-	 	 	-	 	 	92.0	 	 	92.0	 	
Capital Lease Obligations (e)	 	 	3.2	 	 	4.7	 	 	1.4	 	 	0.1	 	 	9.4	 	
Noncancelable Operating Leases (e)	 	 	5.3	 	 	8.8	 	 	5.7	 	 	4.5	 	 	24.3	 	
Fuel Purchase Contracts (f)	 	 	163.3	 	 	317.5	 	 	286.1	 	 	340.4	 	 	1,107.3	 	
Energy and Capacity Purchase Contracts (g)	 	 	35.8	 	 	3.0	 	 	4.5	 	 	1.0	 	 	44.3	 	
Construction Contracts Assets (h)	 	 	161.0	 	 	50.0	 	 	-	 	 	4.6	 	 	215.6	 	
Total	 	$	432.3	 	$	613.0	 	$	646.7	 	$	1,918.6	 	$	3,610.6	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.53% and 3.75% at December 31, 2006.	
(e)	See Note 14.	
(f)	Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.	
(g)	Represents contractual cash flows of energy and capacity purchase contracts.	
(h)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
 
Plant Acquisition - Darby Electric Generating Station

In November 2006, we agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the first half of 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW. This new generation acquisition will be financed by internally generated funds and short-term borrowings.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow Hedges	 	DETM Assignment (a)	 	Total	 	
Current Assets	 	$	60,541	 	$	5,697	 	$	-	 	$	66,238	 	
Noncurrent Assets	 	 	56,126	 	 	80	 	 	-	 	 	56,206	 	
Total MTM Derivative Contract Assets	 	 	116,667	 	 	5,777	 	 	-	 	 	122,444	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(47,204	)	 	(557	)	 	(1,524	)	 	(49,285	)	
Noncurrent Liabilities	 	 	(34,830	)	 	(17	)	 	(5,630	)	 	(40,477	)	
Total MTM Derivative Contract  Liabilities	 	 	(82,034	)	 	(574	)	 	(7,154	)	 	(89,762	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	34,633	 	$	5,203	 	$	(7,154	)	$	32,682	 	

(a)	See “Natural Gas Contracts with DETM” section of Note 16.	
 
MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	33,322	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(8,256	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	599	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	(132	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	380	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	12,290	 	
Changes Due to SIA Agreement (c)	 	 	(3,864	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	294	 	
Total MTM Risk Management Contract Net Assets	 	 	34,633	 	
Net Cash Flow Hedge Contracts	 	 	5,203	 	
DETM Assignment (e)	 	 	(7,154	)	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	32,682	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	
(e)	See “Natural Gas Contracts with DETM” section of Note 16.	
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Prices Actively Quoted - Exchange Traded Contracts	 	$	3,316	 	$	2,383	 	$	411	 	$	-	 	$	-	 	$	-	 	$	6,110	 	
Prices Provided by Other External Sources - OTC Broker  Quotes (a)	 	 	10,446	 	 	3,309	 	 	4,794	 	 	-	 	 	-	 	 	-	 	 	18,549	 	
Prices Based on Models and Other Valuation Methods (b)	 	 	(425	)	 	772	 	 	2,460	 	 	5,500	 	 	725	 	 	942	 	 	9,974	 	
Total	 	$	13,337	 	$	6,464	 	$	7,665	 	$	5,500	 	$	725	 	$	942	 	$	34,633	 	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.
 
Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	
Beginning Balance in AOCI December 31, 2005	 	$	(859	)	
Changes in Fair Value	 	 	3,438	 	
Impact due to Changes in SIA (a)	 	 	(261	)	
Reclassifications from AOCI to Net Income for Cash  Flow Hedges Settled	 	 	1,080	 	
Ending Balance in AOCI December 31, 2006	 	$	3,398	 	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $3,357 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$482	 	$1,224	 	$404	 	$228	 	 	 	 	$424	 	$705	 	$335	 	$121	

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $70 million and $86 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	1,715,542	 	$	1,413,056	 	$	1,340,152	 	
Sales to AEP Affiliates	 	 	85,726	 	 	124,410	 	 	104,747	 	
Other	 	 	5,467	 	 	4,866	 	 	3,026	 	
TOTAL	 	 	1,806,735	 	 	1,542,332	 	 	1,447,925	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	294,841	 	 	255,913	 	 	211,314	 	
Fuel from Affiliates Used for Electric Generation	 	 	-	 	 	-	 	 	10,603	 	
Purchased Electricity for Resale	 	 	115,420	 	 	37,012	 	 	25,322	 	
Purchased Electricity from AEP Affiliates	 	 	365,510	 	 	362,959	 	 	347,002	 	
Other Operation	 	 	256,479	 	 	225,896	 	 	217,381	 	
Maintenance	 	 	88,654	 	 	87,303	 	 	95,036	 	
Asset Impairments and Other Related Charges	 	 	-	 	 	39,109	 	 	-	 	
Depreciation and Amortization	 	 	193,251	 	 	142,346	 	 	148,529	 	
Taxes Other Than Income Taxes	 	 	154,930	 	 	148,914	 	 	134,159	 	
TOTAL	 	 	1,469,085	 	 	1,299,452	 	 	1,189,346	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	337,650	 	 	242,880	 	 	258,579	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	8,885	 	 	3,972	 	 	1,993	 	
Carrying Costs Income	 	 	4,122	 	 	10,367	 	 	486	 	
Allowance for Equity Funds Used During Construction	 	 	1,865	 	 	1,579	 	 	1,117	 	
Interest Expense	 	 	(66,100	)	 	(59,539	)	 	(54,246	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	286,422	 	 	199,259	 	 	207,929	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	100,843	 	 	61,460	 	 	67,671	 	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	 	 	185,579	 	 	137,799	 	 	140,258	 	
 	 	 	 	 	 	 	 	 	 	 	
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX	 	 	-	 	 	(839	)	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	185,579	 	 	136,960	 	 	140,258	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements including Capital Stock  Expense and  Other Expense	 	 	157	 	 	2,620	 	 	1,015	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$ 	185,422	 	$ 	134,340	 	$ 	139,243	 	

The common stock of CSPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	41,026	 	$	576,400	 	$	326,782	 	$	(46,327	)	$	897,881	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(125,000	)	 	 	 	 	(125,000	)	
Capital Stock Expense	 	 	 	 	 	1,015	 	 	(1,015	)	 	 	 	 	-	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	772,881	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $641	 	 	 	 	 	 	 	 	 	 	 	1,191	 	 	1,191	 	
Minimum Pension Liability, Net of Tax of $8,443	 	 	 	 	 	 	 	 	 	 	 	(15,680	)	 	(15,680	)	
NET INCOME	 	 	 	 	 	 	 	 	140,258	 	 	 	 	 	140,258	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	125,769	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	41,026	 	 	577,415	 	 	341,025	 	 	(60,816	)	 	898,650	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(114,000	)	 	 	 	 	(114,000	)	
Capital Stock Expense and Other	 	 	 	 	 	2,620	 	 	(2,620	)	 	 	 	 	-	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	784,650	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss), Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $1,212	 	 	 	 	 	 	 	 	 	 	 	(2,252	)	 	(2,252	)	
Minimum Pension Liability, Net of Tax of $33,486	 	 	 	 	 	 	 	 	 	 	 	62,188	 	 	62,188	 	
NET INCOME	 	 	 	 	 	 	 	 	136,960	 	 	 	 	 	136,960	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	196,896	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	41,026	 	 	580,035	 	 	361,365	 	 	(880	)	 	981,546	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(90,000	)	 	 	 	 	(90,000	)	
Capital Stock Expense and Other	 	 	 	 	 	157	 	 	(157	)	 	 	 	 	-	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	891,546	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $2,292	 	 	 	 	 	 	 	 	 	 	 	4,257	 	 	4,257	 	
Minimum Pension Liability, Net of Tax  of $2	 	 	 	 	 	 	 	 	 	 	 	(4	)	 	(4	)	
NET INCOME	 	 	 	 	 	 	 	 	185,579	 	 	 	 	 	185,579	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	189,832	 	
Minimum Pension Liability Elimination,   Net of Tax   of $14	 	 	 	 	 	 	 	 	 	 	 	25	 	 	25	 	
SFAS 158 Adoption, Net of Tax of   $13,670	 	 	 	 	 	 	 	 	 	 	 	(25,386	)	 	(25,386	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2006	 	$	41,026	 	$	580,192	 	$	456,787	 	$	(21,988	)	$	1,056,017	 	

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	1,319	 	$	940	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	49,362	 	 	43,143	 	
Affiliated Companies	 	 	62,866	 	 	67,694	 	
Accrued Unbilled Revenues	 	 	11,042	 	 	10,086	 	
Miscellaneous	 	 	4,895	 	 	2,012	 	
Allowance for Uncollectible Accounts	 	 	(546	)	 	(1,082	)	
   Total Accounts Receivable	 	 	127,619	 	 	121,853	 	
Fuel	 	 	37,348	 	 	28,579	 	
Materials and Supplies	 	 	31,765	 	 	27,519	 	
Emission Allowances	 	 	3,493	 	 	20,181	 	
Risk Management Assets	 	 	66,238	 	 	76,507	 	
Accrued Tax Benefits	 	 	4,763	 	 	36,838	 	
Margin Deposits	 	 	7,747	 	 	16,832	 	
Prepayments and Other	 	 	8,360	 	 	6,714	 	
TOTAL	 	 	288,652	 	 	335,963	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	1,896,073	 	 	1,874,652	 	
Transmission	 	 	479,119	 	 	457,937	 	
Distribution	 	 	1,475,758	 	 	1,380,722	 	
Other	 	 	191,103	 	 	184,096	 	
Construction Work in Progress	 	 	294,138	 	 	129,246	 	
Total	 	 	4,336,191	 	 	4,026,653	 	
Accumulated Depreciation and Amortization	 	 	1,611,043	 	 	1,500,858	 	
TOTAL - NET	 	 	2,725,148	 	 	2,525,795	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	298,304	 	 	231,599	 	
Long-term Risk Management Assets	 	 	56,206	 	 	101,512	 	
Deferred Charges and Other	 	 	152,379	 	 	237,925	 	
TOTAL	 	 	506,889	 	 	571,036	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	3,520,689	 	$	3,432,794	 	

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	696	 	$	17,609	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	112,431	 	 	59,134	 	
Affiliated Companies	 	 	59,538	 	 	59,399	 	
Risk Management Liabilities	 	 	49,285	 	 	69,036	 	
Customer Deposits	 	 	34,991	 	 	47,013	 	
Accrued Taxes	 	 	166,551	 	 	157,729	 	
Accrued Interest	 	 	20,868	 	 	18,908	 	
Other	 	 	37,143	 	 	31,321	 	
TOTAL	 	 	481,503	 	 	460,149	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	1,097,322	 	 	1,096,920	 	
Long-term Debt - Affiliated	 	 	100,000	 	 	100,000	 	
Long-term Risk Management Liabilities	 	 	40,477	 	 	84,291	 	
Deferred Income Taxes	 	 	475,888	 	 	498,232	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	179,048	 	 	165,344	 	
Deferred Credits and Other	 	 	90,434	 	 	46,312	 	
TOTAL	 	 	1,983,169	 	 	1,991,099	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	2,464,672	 	 	2,451,248	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - No Par Value:	 	 	 	 	 	 	 	
Authorized - 24,000,000 Shares	 	 	 	 	 	 	 	
Outstanding - 16,410,426 Shares	 	 	41,026	 	 	41,026	 	
Paid-in Capital	 	 	580,192	 	 	580,035	 	
Retained Earnings	 	 	456,787	 	 	361,365	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(21,988	)	 	(880	)	
TOTAL	 	 	1,056,017	 	 	981,546	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	 	$	3,520,689	 	$	3,432,794	 	

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	185,579	 	$	136,960	 	$	140,258	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	193,251	 	 	142,346	 	 	148,529	 	
Deferred Income Taxes	 	 	(10,900	)	 	19,209	 	 	13,395	 	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	839	 	 	-	 	
Asset Impairments and Other Related Charges	 	 	-	 	 	39,109	 	 	-	 	
Carrying Costs Income	 	 	(4,122	)	 	(10,367	)	 	(486	)	
Mark-to-Market of Risk Management Contracts	 	 	(1,299	)	 	(8,915	)	 	2,887	 	
   Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(85,871	)	 	(32	)	
Change in Other Noncurrent Assets	 	 	(33,812	)	 	(26,711	)	 	(23,837	)	
Change in Other Noncurrent Liabilities	 	 	16,013	 	 	9,979	 	 	3,904	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	(5,766	)	 	12,182	 	 	9,681	 	
Fuel, Materials and Supplies	 	 	(13,015	)	 	2,030	 	 	(20,636	)	
Accounts Payable	 	 	29,063	 	 	3,075	 	 	(1,604	)	
Customer Deposits	 	 	(12,022	)	 	22,123	 	 	5,163	 	
Accrued Taxes, Net	 	 	40,897	 	 	(78,278	)	 	62,431	 	
Other Current Assets	 	 	25,592	 	 	(12,001	)	 	(7,802	)	
Other Current Liabilities	 	 	6,738	 	 	5,525	 	 	(1,864	)	
Net Cash Flows From Operating Activities	 	 	416,197	 	 	171,234	 	 	329,987	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(306,559	)	 	(165,452	)	 	(147,102	)	
Change in Other Cash Deposits, Net	 	 	(1,151	)	 	-	 	 	-	 	
Change in Advances to Affiliates, Net	 	 	-	 	 	141,550	 	 	(141,550	)	
Purchase of Waterford Plant	 	 	-	 	 	(218,357	)	 	-	 	
Purchase of Monongahela Power’s Ohio Assets	 	 	-	 	 	(41,762	)	 	-	 	
Proceeds from Sale of Assets	 	 	1,827	 	 	4,639	 	 	3,393	 	
Net Cash Flows Used For Investing Activities	 	 	(305,883	)	 	(279,382	)	 	(285,259	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	-	 	 	244,733	 	 	89,883	 	
Issuance of Long-term Debt - Affiliated	 	 	-	 	 	-	 	 	100,000	 	
Change in Advances from Affiliates, Net	 	 	(16,913	)	 	17,609	 	 	(6,517	)	
Retirement of Long-term Debt - Nonaffiliated	 	 	-	 	 	(36,000	)	 	(103,245	)	
Principal Payments for Capital Lease Obligations	 	 	(3,022	)	 	(3,312	)	 	(3,933	)	
Dividends Paid on Common Stock	 	 	(90,000	)	 	(114,000	)	 	(125,000	)	
Net Cash Flows From (Used For) Financing Activities	 	 	(109,935	)	 	109,030	 	 	(48,812	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	379	 	 	882	 	 	(4,084	)	
Cash and Cash Equivalents at Beginning of Period	 	 	940	 	 	58	 	 	4,142	 	
Cash and Cash Equivalents at End of Period	 	$	1,319	 	$	940	 	$	58	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	62,806	 	$	54,767	 	$	48,461	 	
Net Cash Paid (Received) for Income Taxes	 	 	92,295	 	 	136,239	 	 	(5,282	)	
Noncash Acquisitions Under Capital Leases	 	 	2,286	 	 	998	 	 	1,302	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	35,627	 	 	11,254	 	 	5,955	 	

In connection with the acquisition of the Waterford Plant in September 2005, we assumed $2.3 million of liabilities. In connection with the acquisition of Monongahela Power’s Ohio assets in December 2005, we assumed $1.8 million of liabilities.	

   See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to CSPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to CSPCo.
 	Footnote
Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 8	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholder of
Columbus Southern Power Company:

We have audited the accompanying consolidated balance sheets of Columbus Southern Power Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company   and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Notes 2 and 9 to the consolidated financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006, and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/Deloite & Touche LLP
 
Columbus, Ohio
February 28, 2007 

 

 

 

 

 
 
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

 

 

 

 

 

 

 

 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
STATEMENTS OF INCOME DATA	 	  	 	  	 	  	 	  	 	  	 	
Total Revenues	 	$	1,976,947	 	$	1,892,602	 	$	1,741,485	 	$	1,650,505	 	$	1,609,047	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	252,191	 	$	286,660	 	$	269,559	 	$	204,654	 	$	206,825	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of   Accounting Change	 	$	121,168	 	$	146,852	 	$	133,222	 	$	89,548	 	$	73,992	 	
Cumulative Effect of Accounting Change, Net  of Tax	 	 	-	 	 	-	 	 	-	 	 	(3,160	)	 	-	 	
Net Income	 	$	121,168	 	$	146,852	 	$	133,222	 	$	86,388	 	$	73,992	 	

BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	6,226,730	 	$	5,962,282	 	$	5,717,480	 	$	5,465,207	 	$	5,209,982	 	
Accumulated Depreciation, Depletion and Amortization	 	 	2,914,131	 	 	2,822,558	 	 	2,708,122	 	 	2,597,634	 	 	2,428,835	 	
Net Property, Plant and Equipment	 	$	3,312,599	 	$	3,139,724	 	$	3,009,358	 	$	2,867,573	 	$	2,781,147	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	5,546,437	 	$	5,262,309	 	$	4,863,222	 	$	4,654,171	 	$	4,832,832	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder’s Equity	 	$	1,289,439	 	$	1,220,092	 	$	1,091,498	 	$	1,078,047	 	$	1,018,653	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	$	8,082	 	$	8,084	 	$	8,084	 	$	8,101	 	$	8,101	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Subject to Mandatory Redemption	 	$	-	 	$	-	 	$	61,445	 	$	63,445	 	$	64,945	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)	 	$	1,555,135	 	$	1,444,940	 	$	1,312,843	 	$	1,339,359	 	$	1,617,062	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	43,056	 	$	43,976	 	$	50,732	 	$	37,843	 	$	50,848	 	

(a)	Including portion due within one year.	

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 582,000 retail customers in our service territory in northern and eastern Indiana and a portion of southwestern Michigan. We consolidate Blackhawk Coal Company and Price River Coal Company, our wholly-owned subsidiaries. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities and electric cooperatives. Our River Transportation Division (RTD) provides barging services to affiliates and nonaffiliated companies. The revenues from barging are the majority of our other revenues.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Under unit power agreements, we purchase AEGCo’s 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo’s Rockport Plant capacity to KPCo through 2022. Therefore, we purchase 910 MW of AEGCo’s 50% share of Rockport Plant capacity.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of power and gas trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. Management is unable to predict the ultimate effect on future results of operations and cash flows but expects an increase in margins accruing to the AEP East companies as a result of the SIA change. Our impact will also depend upon the level of future trading and marketing margins in PJM and MISO and sharing mechanisms with customers for off-system sales margins in certain areas of Michigan. The 2006 results of operations and cash flows reflect nine months of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Net Income
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	147	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	(90	)	 	 	 	
FERC Municipals and Cooperatives	 	 	44	 	 	 	 	
Off-system Sales	 	 	44	 	 	 	 	
Transmission Revenues	 	 	(18	)	 	 	 	
Other	 	 	7	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	(13	)	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(9	)	 	 	 	
Depreciation and Amortization	 	 	(13	)	 	 	 	
Other Income	 	 	11	 	 	 	 	
Interest Expense	 	 	(7	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(18	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	5	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	121	 	

Net Income decreased $26 million to $121 million in 2006. The key drivers of the decrease were a $13 million decrease in Gross Margin and a $13 million increase in Depreciation and Amortization.

The major components of our decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins decreased $90 million primarily due to a reduction in capacity settlement revenues of $50 million under the Interconnection Agreement and lower fuel recovery as fuel cost increases could not be recovered from customers due to the Indiana fuel cap. Capacity revenues declined due to our new peak demand in July 2006 and our affiliates’ addition of generating capacity in 2005. The Indiana fuel rate cap ends July 1, 2007.	
·	FERC Municipals and Cooperatives margins increased $44 million due to the addition of new municipal contracts including new rates and increased demand beginning January 2006.	
·	Margins from Off-system Sales increased $44 million primarily due to a $41 million increase in physical sales margins and a $15 million increase in our allocation of off-system sales margins under the SIA, partially offset by a $12 million decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Transmission Revenues decreased $18 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a $6 million provision for potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 4.	
·	Other revenues   increased $7 million primarily due to increased River Transportation Division (RTD) revenues for barging coal and increased gains on sales of emission allowances. Related expenses which offset the RTD revenue increase are included in Other Operation on the Consolidated Statements of Income resulting in our earning only a return approved under regulatory order.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $9 million primarily due to:	
 	·	An $11 million increase in transmission expense due to our reduced credits under the Transmission Equalization Agreement. Our credits decreased due to our July 2006 peak and due to APCo’s addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006 thus increasing the investment pool to be shared.	
 	·	A $9 million increase in nuclear power generation expense due to the abandonment of digital turbine control equipment at the Cook Plant.	
 	·	A $6 million increase in RTD expenses.	
 	·	A $6 million increase reflecting a refund for the 2005 settlement of corporate owned life insurance policies.	
 	These increases were partially offset by:	
 	·	A $12 million decrease in steam generation costs.	
 	·	An $11 million decrease in distribution maintenance expense for overhead power lines including the cost of service restoration from a January 2005 ice storm and reliability initiatives.	
·	Depreciation and Amortization increased $13 million primarily due to higher depreciation expense related to capital additions.	
·	Other Income increased $11 million primarily due to an increase in interest income related to tax accrual adjustments and higher equity AFUDC.	
·	Interest Expense increased $7 million primarily due to an increase in outstanding long-term debt and higher interest rates.	

Income Taxes

Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income and state income taxes, offset in part by tax reserve adjustments and a decrease in consolidated tax savings from Parent.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings, unchanged since first quarter of 2003, are as follows:

 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	
Senior Unsecured Debt	Baa2	 	BBB	 	BBB	
 
Off-Balance Sheet Arrangements

In prior years, we entered into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. The following identifies significant off-balance sheet arrangements:

Rockport Plant Unit 2

In 1989, we, along with AEGCo, entered into a sale and leaseback transaction with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (Rockport 2). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. Neither we, nor AEGCo or AEP, has an ownership interest in the Owner Trustee and do not guarantee its debt.

We deferred the gain from the sale and amortize it over the term of the lease, which expires in 2022. The Owner Trustee owns Rockport 2 and leases it to AEGCo and us. We account for the lease as an operating lease with the payment obligations included in the lease footnote (see Note 14). Our future minimum lease payments are $1.2 billion as of December 31, 2006. The lease term is for 33 years with potential renewal options. At the end of the lease term, we, along with AEGCo, have the option to renew the lease or the Owner Trustee can sell Rockport 2.

Summary Obligation Information  

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payment Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	91.2	 	$	-	 	$	-	 	$	-	 	$	91.2	 	
Interest on Fixed Rate Portion of Long-term  Debt (b)	 	 	56.0	 	 	115.0	 	 	111.0	 	 	867.0	 	 	1,149.0	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	50.0	 	 	50.0	 	 	-	 	 	1,197.0	 	 	1,297.0	 	
Variable Rate Portion of Long-term Debt (d)	 	 	-	 	 	45.0	 	 	-	 	 	217.0	 	 	262.0	 	
Capital Lease Obligations (e)	 	 	17.1	 	 	13.1	 	 	4.7	 	 	19.2	 	 	54.1	 	
Noncancelable Operating Leases (e)	 	 	98.9	 	 	194.9	 	 	184.8	 	 	873.8	 	 	1,352.4	 	
Fuel Purchase Contracts (f)	 	 	284.1	 	 	470.7	 	 	326.9	 	 	172.7	 	 	1,254.4	 	
Energy and Capacity Purchase Contracts (g)	 	 	2.1	 	 	3.2	 	 	4.7	 	 	1.0	 	 	11.0	 	
Construction Contracts for Capital Assets (h)	 	 	73.0	 	 	52.0	 	 	18.7	 	 	0.9	 	 	144.6	 	
Total	 	$	672.4	 	$	943.9	 	$	650.8	 	$	3,348.6	 	$	5,615.7	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.50% and 3.90% at December 31, 2006.	
(e)	See Note 14.	
(f)	Represents contractual obligations to purchase coal as fuel for electric generation along with related transportation of the fuel.	
(g)	Represents contractual cash flows of energy and capacity purchase contracts.	
(h)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Cook Plant

In 2006, during a regular refueling outage, Cook Plant Unit 1 completed the planned replacement of major components, including the reactor vessel head, at a cost of $119 million. These improvements and replacement of major components should increase efficiency as well as adding 40 MW of capacity in the winter. We refueled Cook Plant Unit 2 during March and April 2006 and plan to replace its vessel head during its next refueling outage scheduled for the fall of 2007.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what their eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, cash flows and financial condition.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our Consolidated Balance Sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow Hedges	 	DETM
Assignment (a)	 	Total	 	
Current Assets	 	$	63,765	 	$	5,987	 	$	-	 	$	69,752	 	
Noncurrent Assets	 	 	59,053	 	 	84	 	 	-	 	 	59,137	 	
Total MTM Derivative Contract Assets	 	 	122,818	 	 	6,071	 	 	-	 	 	128,889	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(49,897	)	 	(585	)	 	(1,601	)	 	(52,083	)	
Noncurrent Liabilities	 	 	(36,707	)	 	(18	)	 	(5,916	)	 	(42,641	)	
Total MTM Derivative Contract Liabilities	 	 	(86,604	)	 	(603	)	 	(7,517	)	 	(94,724	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	36,214	 	$	5,468	 	$	(7,517	)	$	34,165	 	

(a)	See “Natural Gas Contracts with DETM” section of Note 16.	
 
MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	33,932	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(1,010	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	-	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered  During the Period	 	 	(146	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	-	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	(557	)	
Changes Due to SIA Agreement (c)	 	 	(3,940	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	7,935	 	
Total MTM Risk Management Contract Net Assets	 	 	36,214	 	
Net Cash Flow Hedge Contracts	 	 	5,468	 	
DETM Assignment (e)	 	 	(7,517	)	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	34,165	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in our Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	
(e)	See “Natural Gas Contracts with DETM” section of Note 16.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Prices Actively Quoted - Exchange  Traded Contracts	 	$	3,502	 	$	2,515	 	$	432	 	$	-	 	$	-	 	$	-	 	$	6,449	 	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	10,919	 	 	3,476	 	 	5,037	 	 	-	 	 	-	 	 	-	 	 	19,432	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	(551	)	 	768	 	 	2,585	 	 	5,780	 	 	761	 	 	990	 	 	10,333	 	
Total	 	$	13,870	 	$	6,759	 	$	8,054	 	$	5,780	 	$	761	 	$	990	 	$	36,214	 	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	Interest Rate	 	Total	 	
Beginning Balance in AOCI December 31, 2005	 	$	(877	)	$	(2,590	)	$	(3,467	)	
Changes in Fair Value	 	 	3,603	 	 	(10,179	)	 	(6,576	)	
Impact due to Changes in SIA (a)	 	 	(267	)	 	-	 	 	(267	)	
Reclassifications from AOCI to Net Income for Cash  Flow Hedges Settled	 	 	1,112	 	 	236	 	 	1,348	 	
Ending Balance in AOCI December 31, 2006	 	$	3,571	 	$	(12,533	)	$	(8,962	)	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,521 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$506	 	$1,283	 	$418	 	$240	 	 	 	 	$433	 	$720	 	$343	 	$124	

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $93 million and $55 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	1,601,135	 	$	1,445,866	 	$	1,378,844	 	
Sales to AEP Affiliates	 	 	291,033	 	 	366,032	 	 	286,310	 	
Other - Affiliated	 	 	52,598	 	 	46,719	 	 	42,968	 	
Other - Nonaffiliated	 	 	32,181	 	 	33,985	 	 	33,363	 	
TOTAL	 	 	1,976,947	 	 	1,892,602	 	 	1,741,485	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	373,741	 	 	327,263	 	 	286,211	 	
Purchased Electricity for Resale	 	 	62,098	 	 	48,378	 	 	37,013	 	
Purchased Electricity from AEP Affiliates	 	 	343,156	 	 	306,117	 	 	272,452	 	
Other Operation	 	 	472,404	 	 	451,553	 	 	458,820	 	
Maintenance	 	 	190,866	 	 	202,909	 	 	168,304	 	
Depreciation and Amortization	 	 	208,633	 	 	196,037	 	 	186,513	 	
Taxes Other Than Income Taxes	 	 	73,858	 	 	73,685	 	 	62,613	 	
TOTAL	 	 	1,724,756	 	 	1,605,942	 	 	1,471,926	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	252,191	 	 	286,660	 	 	269,559	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	9,868	 	 	2,006	 	 	2,011	 	
Allowance for Equity Funds Used During Construction	 	 	7,937	 	 	4,457	 	 	2,338	 	
Interest Expense	 	 	(72,723	)	 	(65,041	)	 	(69,071	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	197,273	 	 	228,082	 	 	204,837	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	76,105	 	 	81,230	 	 	71,615	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	121,168	 	 	146,852	 	 	133,222	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements including Capital Stock  Expense and Other	 	 	339	 	 	395	 	 	474	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$	120,829	 	$	146,457	 	$	132,748	 	

The common stock of I&M is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	56,584	 	$	858,694	 	$	187,875	 	$	(25,106	)	$	1,078,047	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(99,293	)	 	 	 	 	(99,293	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(340	)	 	 	 	 	(340	)	
Capital Stock Expense	 	 	 	 	 	141	 	 	(134	)	 	 	 	 	7	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	978,421	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Loss,   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $2,314	 	 	 	 	 	 	 	 	 	 	 	(4,298	)	 	(4,298	)	
Minimum Pension Liability, Net of Tax  of $8,533	 	 	 	 	 	 	 	 	 	 	 	(15,847	)	 	(15,847	)	
NET INCOME	 	 	 	 	 	 	 	 	133,222	 	 	 	 	 	133,222	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	113,077	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	56,584	 	 	858,835	 	 	221,330	 	 	(45,251	)	 	1,091,498	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(62,000	)	 	 	 	 	(62,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(339	)	 	 	 	 	(339	)	
Capital Stock Expense and Other	 	 	 	 	 	2,455	 	 	(56	)	 	 	 	 	2,399	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,031,558	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income,  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $328	 	 	 	 	 	 	 	 	 	 	 	609	 	 	609	 	
Minimum Pension Liability, Net of Tax   of $22,116	 	 	 	 	 	 	 	 	 	 	 	41,073	 	 	41,073	 	
NET INCOME	 	 	 	 	 	 	 	 	146,852	 	 	 	 	 	146,852	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	188,534	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	56,584	 	 	861,290	 	 	305,787	 	 	(3,569	)	 	1,220,092	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(40,000	)	 	 	 	 	(40,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(339	)	 	 	 	 	(339	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,179,753	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Loss,  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $2,959	 	 	 	 	 	 	 	 	 	 	 	(5,495	)	 	(5,495	)	
Minimum Pension Liability, Net of Tax of $70	 	 	 	 	 	 	 	 	 	 	 	(129	)	 	(129	)	
NET INCOME	 	 	 	 	 	 	 	 	121,168	 	 	 	 	 	121,168	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	115,544	 	
Minimum Pension Liability Elimination, Net of Tax of $124	 	 	 	 	 	 	 	 	 	 	 	231	 	 	231	 	
SFAS 158 Adoption, Net of Tax of $3,278	 	 	 	 	 	 	 	 	 	 	 	(6,089	)	 	(6,089	)	
DECEMBER 31, 2006	 	$	56,584	 	$	861,290	 	$	386,616	 	$	(15,051	)	$	1,289,439	 	

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	1,369	 	$	854	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	84,308	 	 	62,614	 	
Affiliated Companies	 	 	108,288	 	 	127,981	 	
Miscellaneous	 	 	1,838	 	 	1,982	 	
Allowance for Uncollectible Accounts	 	 	(601	)	 	(898	)	
   Total Accounts Receivable	 	 	193,833	 	 	191,679	 	
Fuel	 	 	64,669	 	 	25,894	 	
Materials and Supplies	 	 	129,953	 	 	118,039	 	
Risk Management Assets	 	 	69,752	 	 	78,134	 	
Accrued Tax Benefits	 	 	27,378	 	 	51,846	 	
Prepayments and Other	 	 	15,170	 	 	31,303	 	
TOTAL	 	 	502,124	 	 	497,749	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	3,363,813	 	 	3,128,078	 	
Transmission	 	 	1,047,264	 	 	1,028,496	 	
Distribution	 	 	1,102,033	 	 	1,029,498	 	
Other (including nuclear fuel and coal mining)	 	 	529,727	 	 	465,130	 	
Construction Work in Progress	 	 	183,893	 	 	311,080	 	
Total	 	 	6,226,730	 	 	5,962,282	 	
Accumulated Depreciation, Depletion and Amortization	 	 	2,914,131	 	 	2,822,558	 	
TOTAL - NET	 	 	3,312,599	 	 	3,139,724	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	314,805	 	 	222,686	 	
Spent Nuclear Fuel and Decommissioning Trusts	 	 	1,248,319	 	 	1,133,567	 	
Long-term Risk Management Assets	 	 	59,137	 	 	103,645	 	
Deferred Charges and Other	 	 	109,453	 	 	164,938	 	
TOTAL	 	 	1,731,714	 	 	1,624,836	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	5,546,437	 	$	5,262,309	 	

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	91,173	 	$	93,702	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	146,733	 	 	139,334	 	
Affiliated Companies	 	 	65,497	 	 	60,324	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	50,000	 	 	364,469	 	
Risk Management Liabilities	 	 	52,083	 	 	71,032	 	
Customer Deposits	 	 	34,946	 	 	49,258	 	
Accrued Taxes	 	 	59,652	 	 	56,567	 	
Other	 	 	128,461	 	 	112,839	 	
TOTAL	 	 	628,545	 	 	947,525	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	1,505,135	 	 	1,080,471	 	
Long-term Risk Management Liabilities	 	 	42,641	 	 	86,159	 	
Deferred Income Taxes	 	 	335,000	 	 	335,264	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	753,402	 	 	710,015	 	
Asset Retirement Obligations	 	 	809,853	 	 	737,959	 	
Deferred Credits and Other	 	 	174,340	 	 	136,740	 	
TOTAL	 	 	3,620,371	 	 	3,086,608	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	4,248,916	 	 	4,034,133	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	8,082	 	 	8,084	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - No Par Value:	 	 	 	 	 	 	 	
Authorized - 2,500,000 Shares	 	 	 	 	 	 	 	
Outstanding - 1,400,000 Shares	 	 	56,584	 	 	56,584	 	
Paid-in Capital	 	 	861,290	 	 	861,290	 	
Retained Earnings	 	 	386,616	 	 	305,787	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(15,051	)	 	(3,569	)	
TOTAL	 	 	1,289,439	 	 	1,220,092	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	5,546,437	 	$	5,262,309	 	

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	121,168	 	$	146,852	 	$	133,222	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	208,633	 	 	196,037	 	 	186,513	 	
Deferred Income Taxes	 	 	13,626	 	 	26,873	 	 	(5,548	)	
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	 	 	(23,893	)	 	21,273	 	 	13,082	 	
Amortization of Nuclear Fuel	 	 	50,313	 	 	56,038	 	 	52,455	 	
Mark-to-Market of Risk Management Contracts	 	 	(2,059	)	 	(7,331	)	 	2,756	 	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(90,668	)	 	(3,888	)	
Change in Other Noncurrent Assets	 	 	4,809	 	 	12,990	 	 	10,322	 	
Change in Other Noncurrent Liabilities	 	 	26,822	 	 	22,288	 	 	40,875	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	(2,154	)	 	(785	)	 	983	 	
Fuel, Materials and Supplies	 	 	(50,689	)	 	(13,373	)	 	(10,977	)	
Accounts Payable	 	 	37,651	 	 	9,630	 	 	(1,304	)	
Customer Deposits	 	 	(14,312	)	 	19,892	 	 	7,411	 	
Accrued Taxes, Net	 	 	27,553	 	 	(118,438	)	 	80,970	 	
Other Current Assets	 	 	16,208	 	 	(14,608	)	 	(2,167	)	
Other Current Liabilities	 	 	11,951	 	 	25,476	 	 	6,198	 	
Net Cash Flows From Operating Activities	 	 	425,627	 	 	292,146	 	 	510,903	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(325,390	)	 	(298,632	)	 	(179,414	)	
Change in Advances to Affiliates, Net	 	 	-	 	 	5,093	 	 	(5,093	)	
Purchases of Investment Securities	 	 	(691,956	)	 	(606,936	)	 	(901,356	)	
Sales of Investment Securities	 	 	630,555	 	 	556,667	 	 	862,976	 	
Acquisitions of Nuclear Fuel	 	 	(89,100	)	 	(52,579	)	 	(50,865	)	
Other	 	 	6,458	 	 	16,794	 	 	2,788	 	
Net Cash Flows Used For Investing Activities	 	 	(469,433	)	 	(379,593	)	 	(270,964	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	443,743	 	 	123,761	 	 	268,057	 	
Change in Advances from Affiliates, Net	 	 	(2,529	)	 	93,702	 	 	(98,822	)	
Retirement of Long-term Debt - Nonaffiliated	 	 	(350,000	)	 	-	 	 	(304,017	)	
Retirement of Cumulative Preferred Stock	 	 	(1	)	 	(61,445	)	 	(2,011	)	
Principal Payments for Capital Lease Obligations	 	 	(6,553	)	 	(5,889	)	 	(6,916	)	
Dividends Paid on Common Stock	 	 	(40,000	)	 	(62,000	)	 	(99,293	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(339	)	 	(339	)	 	(340	)	
Net Cash Flows From (Used For) Financing Activities	 	 	44,321	 	 	87,790	 	 	(243,342	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	515	 	 	343	 	 	(3,403	)	
Cash and Cash Equivalents at Beginning of Period	 	 	854	 	 	511	 	 	3,914	 	
Cash and Cash Equivalents at End of Period	 	$	1,369	 	$	854	 	$	511	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	84,354	 	$	59,339	 	$	70,988	 	
Net Cash Paid (Received) for Income Taxes	 	 	56,506	 	 	184,061	 	 	(2,244	)	
Noncash Acquisitions Under Capital Leases	 	 	5,968	 	 	2,639	 	 	20,557	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	37,287	 	 	38,523	 	 	16,530	 	
Noncash Acquisition of Nuclear Fuel Included in Accounts Payable  at December 31,	 	 	210	 	 	24,053	 	 	-	 	

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to I&M’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M.

 	Footnote
Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Benefit Plans	Note 9	
Nuclear	Note 10	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 

 

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company   and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the consolidated financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006, and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007 

 

 

KENTUCKY POWER COMPANY

 

 

 

 

 

 

 

 KENTUCKY POWER COMPANY
SELECTED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
 	 	 	 	 	 	 	 	 	 	 	 	
STATEMENTS OF INCOME DATA	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	585,867	 	$	531,343	 	$	448,961	 	$	412,667	 	$	391,516	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	81,625	 	$	60,831	 	$	63,339	 	$	70,749	 	$	57,579	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of Accounting Change	 	$	35,035	 	$	20,809	 	$	25,905	 	$	33,464	 	$	20,567	 	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	-	 	 	-	 	 	(1,134	)	 	-	 	
Net Income	 	$	35,035	 	$	20,809	 	$	25,905	 	$	32,330	 	$	20,567	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	1,445,133	 	$	1,414,426	 	$	1,367,138	 	$	1,355,315	 	$	1,301,332	 	
Accumulated Depreciation and Amortization	 	 	442,778	 	 	425,817	 	 	398,608	 	 	382,022	 	 	373,874	 	
Net Property, Plant and Equipment	 	$	1,002,355	 	$	988,609	 	$	968,530	 	$	973,293	 	$	927,458	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	1,310,565	 	$	1,320,026	 	$	1,243,247	 	$	1,221,634	 	$	1,188,342	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder’s Equity	 	$	369,651	 	$	347,841	 	$	320,980	 	$	317,138	 	$	298,018	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)	 	$	446,968	 	$	486,990	 	$	508,310	 	$	487,602	 	$	466,632	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	2,647	 	$	3,168	 	$	4,363	 	$	5,292	 	$	7,248	 	

(a)	Including portion due within one year.	

 

KENTUCKY POWER COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 176,000 retail customers in our service territory in eastern Kentucky. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Under a unit power agreement with AEGCo, an affiliated company that is not a member of the AEP Power Pool, we purchase 15% of the total output of the 2,600 MW Rockport Plant capacity. Therefore, we purchase 390 MW of Rockport Plant capacity. The unit power agreement expires in December 2022. We pay a demand charge for the right to receive the power, which is payable even if the power is not taken.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of power and gas trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. Management is unable to predict the ultimate effect on future results of operations and cash flows but expects an increase in margins accruing to the AEP East companies as a result of the SIA change. Our impact will also depend upon the level of future trading and marketing margins in PJM and MISO and sharing mechanisms with customers for off-system sales margins in Kentucky. The 2006 results of operations and cash flows reflect nine months of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Net Income
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	21	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	21	 	 	 	 	
Off-system Sales	 	 	13	 	 	 	 	
Transmission Revenues	 	 	(10	)	 	 	 	
Other	 	 	4	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	28	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(7	)	 	 	 	
Depreciation and Amortization	 	 	(1	)	 	 	 	
Taxes Other Than Income Taxes	 	 	1	 	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(7	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(7	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	35	 	

Net Income increased $14 million to $35 million in 2006. The key driver of the increase was a $28 million increase in Gross Margin, partially offset by an increase in Other Operation and Maintenance expenses of $7 million and an increase in Income Tax Expense of $7 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins increased $21 million primarily due to rate relief of $33 million from the March 2006 approval of the settlement agreement in our base rate case. The above was partially offset by a $6 million decrease related to increased credits to retail customers of a portion of off-system sales margins due to higher off-system sales. Another partial offset is a result of increased capacity charges of $4 million due to changes in the relative peak demands and generating capacity of the AEP Power Pool members.	
·	Margins from Off-system Sales increased $13 million primarily due to a $12 million increase in physical sales margins and a $6 million increase in our allocation of off-system sales margins under the SIA, offset by a $5 million decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Transmission Revenues decreased $10 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $3 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 4.	
·	Other revenues increased $4 million primarily due to a $3 million unfavorable adjustment of the Demand Side Management Program regulatory asset in March 2005.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $7 million primarily due to maintenance of overhead lines as well as an increase in transmission costs associated with the Transmission Equalization Agreement. This increase in transmission costs was due to the addition of the Wyoming-Jacksons Ferry 765 kV line which was energized and placed into service in June 2006.	

Income Taxes

Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

Financial Condition

Credit Ratings
 
The rating agencies currently have us on stable outlook. Current ratings are as follows:
 
 	 	  Moody’s	 	S&P	 	Fitch	 	
 	 	  	 	 	 	 	 	
Senior Unsecured Debt	 	 	Baa2	 	 	BBB	 	 	BBB	 	

Summary Obligation Information

Our contractual obligations include amounts reported on our Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payment Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	30.6	 	$	-	 	$	-	 	$	-	 	$	30.6	 	
Interest on Fixed Rate Portion of  Long-term Debt (b)	 	 	24.0	 	 	13.0	 	 	11.0	 	 	92.0	 	 	140.0	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	322.0	 	 	30.0	 	 	-	 	 	95.0	 	 	447.0	 	
Capital Lease Obligations (d)	 	 	1.2	 	 	1.2	 	 	0.4	 	 	0.1	 	 	2.9	 	
Noncancelable Operating Leases (d)	 	 	2.1	 	 	3.2	 	 	2.3	 	 	2.3	 	 	9.9	 	
Fuel Purchase Contracts (e)	 	 	81.8	 	 	28.6	 	 	7.9	 	 	22.5	 	 	140.8	 	
Energy and Capacity Purchase Contracts (f)	 	 	0.7	 	 	1.1	 	 	1.7	 	 	0.3	 	 	3.8	 	
Construction Contracts for Capital Assets (g)	 	 	30.0	 	 	10.0	 	 	-	 	 	41.1	 	 	81.1	 	
Total	 	$	492.4	 	$	87.1	 	$	23.3	 	$	253.3	 	$	856.1	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 14.	
(e)	Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.	
(f)	Represents contractual cash flows of energy and capacity purchase contracts.	
(g)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Big Sandy Plant Scrubber

Completion of construction of a scrubber at our Big Sandy Plant was previously scheduled for 2010. We suspended the project in the second quarter of 2006 after a generation engineering evaluation determined that there was a substantially higher estimated capital cost due to increases in labor and material costs, refinements of preliminary costs estimates and an increase in cost per ton of removed SO 2 . We currently estimate the project to have an in-service date of 2014 or beyond. Management continues to review its emission compliance plans given changing market conditions and the evolving legislative and regulatory environment.

We transferred the total project expenditures of $17 million during 2006 from Construction Work in Progress to Deferred Charges and Other on our Balance Sheet. If management does not resume the project, the balance of incurred expenditures would negatively impact future earnings unless a regulatory asset could be established due to probable recovery through rates.

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow &
Fair Value Hedges	 	DETM
Assignment (a)	 	Total	 	
Current Assets	 	$	23,049	 	$	2,575	 	$	-	 	$	25,624	 	
Noncurrent Assets	 	 	21,252	 	 	30	 	 	-	 	 	21,282	 	
Total MTM Derivative Contract Assets	 	 	44,301	 	 	2,605	 	 	-	 	 	46,906	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(18,302	)	 	(1,126	)	 	(573	)	 	(20,001	)	
Noncurrent Liabilities	 	 	(13,301	)	 	(6	)	 	(2,119	)	 	(15,426	)	
Total MTM Derivative Contract Liabilities	 	 	(31,603	)	 	(1,132	)	 	(2,692	)	 	(35,427	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	12,698	 	$	1,473	 	$	(2,692	)	$	11,479	 	

(a)	See “Natural Gas Contracts with DETM” section of Note 16.	

MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	13,518	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(225	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	-	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	(62	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	-	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	(553	)	
Changes Due to SIA Agreement (c)	 	 	(1,565	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	1,585	 	
Total MTM Risk Management Contract Net Assets	 	 	12,698	 	
Net Cash Flow & Fair Value Hedge Contracts	 	 	1,473	 	
DETM Assignment (e)	 	 	(2,692	)	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	11,479	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	
(e)	See “Natural Gas Contracts with DETM” section of Note 16.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Prices Actively Quoted - Exchange  Traded Contracts	 	$	1,281	 	$	917	 	$	155	 	$	-	 	$	-	 	$	-	 	$	2,353	 	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	3,820	 	 	1,243	 	 	1,804	 	 	-	 	 	-	 	 	-	 	 	6,867	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	(355	)	 	210	 	 	926	 	 	2,070	 	 	273	 	 	354	 	 	3,478	 	
Total	 	$	4,746	 	$	2,370	 	$	2,885	 	$	2,070	 	$	273	 	$	354	 	$	12,698	 	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	Interest Rate	 	Total	 	
Beginning Balance in AOCI December 31, 2005	 	$	(352	)	$	158	 	$	(194	)	
Changes in Fair Value	 	 	1,295	 	 	201	 	 	1,496	 	
Impact due to Changes in SIA (a)	 	 	(106	)	 	-	 	 	(106	)	
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled	 	 	442	 	 	(86	)	 	356	 	
Ending Balance in AOCI December 31, 2006	 	$	1,279	 	$	273	 	$	1,552	 	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,340 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$181	 	$459	 	$158	 	$86	 	 	 	 	$174	 	$289	 	$138	 	$50	

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $13 million at December 31, 2006 and 2005. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.

KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	526,432	 	$	458,858	 	$	397,581	 	
Sales to AEP Affiliates	 	 	58,287	 	 	70,803	 	 	48,717	 	
Other	 	 	1,148	 	 	1,682	 	 	2,663	 	
TOTAL	 	 	585,867	 	 	531,343	 	 	448,961	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	152,335	 	 	142,672	 	 	103,881	 	
Purchased Electricity for Resale	 	 	8,724	 	 	7,213	 	 	3,407	 	
Purchased Electricity from AEP Affiliates	 	 	192,080	 	 	176,350	 	 	140,758	 	
Other Operation	 	 	60,674	 	 	59,024	 	 	51,782	 	
Maintenance	 	 	35,430	 	 	30,652	 	 	32,802	 	
Depreciation and Amortization	 	 	46,387	 	 	45,110	 	 	43,847	 	
Taxes Other Than Income Taxes	 	 	8,612	 	 	9,491	 	 	9,145	 	
TOTAL	 	 	504,242	 	 	470,512	 	 	385,622	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	81,625	 	 	60,831	 	 	63,339	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	656	 	 	880	 	 	462	 	
Allowance for Equity Funds Used During Construction	 	 	241	 	 	305	 	 	245	 	
Interest Expense	 	 	(28,832	)	 	(29,071	)	 	(29,470	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	53,690	 	 	32,945	 	 	34,576	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	18,655	 	 	12,136	 	 	8,671	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	$	35,035	 	$	20,809	 	$	25,905	 	

The common stock of KPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

 

KENTUCKY POWER COMPANY
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	  Common Stock	 	  Paid-in Capital	 	  Retained Earnings	 	  Accumulated Other Comprehensive Income (Loss)	 	 Total	 	
DECEMBER 31, 2003	 	$	50,450	 	$	208,750	 	$	64,151	 	$	(6,213	)	$	317,138	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(19,501	)	 	 	 	 	(19,501	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	297,637	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $212	 	 	 	 	 	 	 	 	 	 	 	393	 	 	393	 	
 Minimum Pension Liability, Net of Tax   of $1,592	 	 	 	 	 	 	 	 	 	 	 	(2,955	)	 	(2,955	)	
NET INCOME	 	 	 	 	 	 	 	 	25,905	 	 	 	 	 	25,905	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	23,343	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	50,450	 	 	208,750	 	 	70,555	 	 	(8,775	)	 	320,980	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(2,500	)	 	 	 	 	(2,500	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	318,480	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $542	 	 	 	 	 	 	 	 	 	 	 	(1,007	)	 	(1,007	)	
 Minimum Pension Liability, Net of Tax   of $5,147	 	 	 	 	 	 	 	 	 	 	 	9,559	 	 	9,559	 	
NET INCOME	 	 	 	 	 	 	 	 	20,809	 	 	 	 	 	20,809	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	29,361	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	50,450	 	 	208,750	 	 	88,864	 	 	(223	)	 	347,841	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(15,000	)	 	 	 	 	(15,000	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	332,841	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income,   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $940	 	 	 	 	 	 	 	 	 	 	 	1,746	 	 	1,746	 	
Minimum Pension Liability, Net of Tax  of $16	 	 	 	 	 	 	 	 	 	 	 	29	 	 	29	 	
NET INCOME	 	 	 	 	 	 	 	 	35,035	 	 	 	 	 	35,035	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	36,810	 	
DECEMBER 31, 2006	 	$	50,450	 	$	208,750	 	$	108,899	 	$	1,552	 	$	369,651	 	

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	702	 	$	526	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	30,112	 	 	26,533	 	
Affiliated Companies	 	 	10,540	 	 	23,525	 	
Accrued Unbilled Revenues	 	 	3,602	 	 	6,311	 	
Miscellaneous	 	 	327	 	 	35	 	
Allowance for Uncollectible Accounts	 	 	(227	)	 	(147	)	
   Total Accounts Receivable	 	 	44,354	 	 	56,257	 	
Fuel	 	 	16,070	 	 	8,490	 	
Materials and Supplies	 	 	8,726	 	 	10,181	 	
Risk Management Assets	 	 	25,624	 	 	31,437	 	
Accrued Tax Benefits	 	 	1,021	 	 	6,598	 	
Margin Deposits	 	 	2,923	 	 	6,895	 	
Prepayments and Other	 	 	2,425	 	 	6,324	 	
TOTAL	 	 	101,845	 	 	126,708	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	478,955	 	 	472,575	 	
Transmission	 	 	394,419	 	 	386,945	 	
Distribution	 	 	481,083	 	 	456,063	 	
Other	 	 	61,089	 	 	63,382	 	
Construction Work in Progress	 	 	29,587	 	 	35,461	 	
Total	 	 	1,445,133	 	 	1,414,426	 	
Accumulated Depreciation and Amortization	 	 	442,778	 	 	425,817	 	
TOTAL - NET	 	 	1,002,355	 	 	988,609	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	136,139	 	 	117,432	 	
Long-term Risk Management Assets	 	 	21,282	 	 	41,810	 	
Deferred Charges and Other	 	 	48,944	 	 	45,467	 	
TOTAL	 	 	206,365	 	 	204,709	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	1,310,565	 	$	1,320,026	 	

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY
BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	30,636	 	$	6,040	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	31,490	 	 	32,454	 	
Affiliated Companies	 	 	23,658	 	 	29,326	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	322,048	 	 	-	 	
Long-term Debt Due Within One Year - Affiliated	 	 	-	 	 	39,771	 	
Risk Management Liabilities	 	 	20,001	 	 	28,770	 	
Customer Deposits	 	 	16,095	 	 	21,643	 	
Accrued Taxes	 	 	18,775	 	 	8,805	 	
Other	 	 	26,303	 	 	21,524	 	
TOTAL	 	 	489,006	 	 	188,333	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	104,920	 	 	427,219	 	
Long-term Debt - Affiliated	 	 	20,000	 	 	20,000	 	
Long-term Risk Management Liabilities	 	 	15,426	 	 	35,302	 	
Deferred Income Taxes	 	 	242,133	 	 	234,719	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	49,109	 	 	56,794	 	
Deferred Credits and Other	 	 	20,320	 	 	9,818	 	
TOTAL	 	 	451,908	 	 	783,852	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	940,914	 	 	972,185	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - $50 Par Value Per Share:	 	 	 	 	 	 	 	
Authorized - 2,000,000 Shares	 	 	 	 	 	 	 	
Outstanding - 1,009,000 Shares	 	 	50,450	 	 	50,450	 	
Paid-in Capital	 	 	208,750	 	 	208,750	 	
Retained Earnings	 	 	108,899	 	 	88,864	 	
Accumulated Other Comprehensive Income (Loss)	 	 	1,552	 	 	(223	)	
TOTAL	 	 	369,651	 	 	347,841	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	 	$	1,310,565	 	$	1,320,026	 	

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	35,035	 	$	20,809	 	$	25,905	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	46,387	 	 	45,110	 	 	43,847	 	
Deferred Income Taxes	 	 	2,596	 	 	10,555	 	 	12,774	 	
Mark-to-Market of Risk Management Contracts	 	 	580	 	 	(3,465	)	 	1,020	 	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(18,894	)	 	(451	)	
Change in Other Noncurrent Assets	 	 	(4,738	)	 	(419	)	 	(6,902	)	
Change in Other Noncurrent Liabilities	 	 	2,621	 	 	3,844	 	 	9,126	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	11,903	 	 	(3,681	)	 	(1,177	)	
Fuel, Materials and Supplies	 	 	(6,125	)	 	(2,735	)	 	2,724	 	
Accounts Payable	 	 	(3,436	)	 	13,184	 	 	(1,745	)	
Customer Deposits	 	 	(5,548	)	 	9,334	 	 	2,415	 	
Accrued Taxes, Net	 	 	15,547	 	 	(7,041	)	 	1,919	 	
Other Current Assets	 	 	7,867	 	 	(9,261	)	 	474	 	
Other Current Liabilities	 	 	3,953	 	 	1,589	 	 	65	 	
Net Cash Flows From Operating Activities	 	 	106,642	 	 	58,929	 	 	89,994	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(77,848	)	 	(56,979	)	 	(36,957	)	
Change in Other Cash Deposits, Net	 	 	5	 	 	(5	)	 	-	 	
Change in Advances to Affiliates, Net	 	 	-	 	 	16,127	 	 	(16,127	)	
Proceeds from Sales of Assets	 	 	2,956	 	 	300	 	 	1,538	 	
Net Cash Flows Used For Investing Activities	 	 	(74,887	)	 	(40,557	)	 	(51,546	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Long-term Debt - Affiliated	 	 	-	 	 	-	 	 	20,000	 	
Change in Advances from Affiliates, Net	 	 	24,596	 	 	6,040	 	 	(38,096	)	
Retirement of Long-term Debt - Affiliated	 	 	(40,000	)	 	(20,000	)	 	-	 	
Principal Payments for Capital Lease Obligations	 	 	(1,175	)	 	(1,518	)	 	(1,605	)	
Dividends Paid on Common Stock	 	 	(15,000	)	 	(2,500	)	 	(19,501	)	
Net Cash Flows Used For Financing Activities	 	 	(31,579	)	 	(17,978	)	 	(39,202	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	176	 	 	394	 	 	(754	)	
Cash and Cash Equivalents at Beginning of Period	 	 	526	 	 	132	 	 	886	 	
Cash and Cash Equivalents at End of Period	 	$	702	 	$	526	 	$	132	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	27,887	 	$	27,354	 	$	28,367	 	
Net Cash Paid (Received) for Income Taxes	 	 	11,516	 	 	11,655	 	 	(3,233	)	
Noncash Acquisitions Under Capital Leases	 	 	648	 	 	419	 	 	925	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	3,357	 	 	6,553	 	 	2,936	 	

See Notes to Financial Statements of Registrant Subsidiaries.	

 
KENTUCKY POWER COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to KPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to KPCo.

 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 

 

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholder of
Kentucky Power Company:

We have audited the accompanying balance sheets of Kentucky Power Company (the “Company”) as of December 31, 2006 and 2005, and the related statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company   as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006, and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007  

 

 

 

OHIO POWER COMPANY CONSOLIDATED

 

 

 

 

 

 

 OHIO POWER COMPANY CONSOLIDATED
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
STATEMENTS OF INCOME DATA	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	2,724,875	 	$	2,634,549	 	$	2,372,725	 	$	2,250,132	 	$	2,163,082	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	425,291	 	$	425,487	 	$	419,539	 	$	491,844	 	$	433,983	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of Accounting Changes	 	$	228,643	 	$	250,419	 	$	210,116	 	$	251,031	 	$	220,023	 	
Cumulative Effect of Accounting Changes, Net of Tax	 	 	-	 	 	(4,575	)	 	-	 	 	124,632	 	 	-	 	
Net Income	 	$	228,643	 	$	245,844	 	$	210,116	 	$	375,663	 	$	220,023	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	8,405,645	 	$	7,523,288	 	$	6,858,771	 	$	6,575,577	 	$	5,732,008	 	
Accumulated Depreciation and Amortization	 	 	2,836,584	 	 	2,738,899	 	 	2,633,203	 	 	2,500,918	 	 	2,486,982	 	
Net   Property, Plant and Equipment	 	$	5,569,061	 	$	4,784,389	 	$	4,225,568	 	$	4,074,659	 	$	3,245,026	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets (a)	 	$	6,818,733	 	$	6,330,670	 	$	5,593,265	 	$	5,374,518	 	$	4,554,023	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder’s Equity	 	$	2,008,342	 	$	1,767,947	 	$	1,473,838	 	$	1,464,025	 	$	1,233,114	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	$	16,630	 	$	16,639	 	$	16,641	 	$	16,645	 	$	16,648	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Subject to Mandatory Redemption	 	$	-	 	$	-	 	$	5,000	 	$	7,250	 	$	8,850	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)(b)	 	$	2,401,741	 	$	2,199,670	 	$	2,011,060	 	$	2,039,940	 	$	1,067,314	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (b)	 	$	34,966	 	$	39,924	 	$	40,733	 	$	34,688	 	$	65,626	 	

(a)	Due to the implementation of FIN 46, OPCo was required to consolidate JMG during the third quarter of 2003.	
(b)	Including portion due within one year.	

 
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 712,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio. We consolidate JMG Funding LP, a variable interest entity. As a member of the AEP Power Pool, we share in the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of power and gas trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. Management is unable to predict the ultimate effect on future results of operations and cash flows but expects an increase in margins accruing to the AEP East companies as a result of the SIA change. Our impact will also depend upon the level of future trading and marketing margins in PJM and MISO. The 2006 results of operations and cash flows reflect nine months of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

To minimize the credit requirements and operating constraints of operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	250	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	59	 	 	 	 	
Off-system Sales	 	 	55	 	 	 	 	
Transmission Revenues	 	 	(32	)	 	 	 	
Other	 	 	3	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	85	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(63	)	 	 	 	
Depreciation and Amortization	 	 	(19	)	 	 	 	
Taxes Other Than Income Taxes	 	 	(2	)	 	 	 	
Carrying Costs Income	 	 	(35	)	 	 	 	
Interest Expense	 	 	6	 	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(113	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	7	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	229	 	

Income Before Cumulative Effect of Accounting Change decreased $21 million to $229 million in 2006. The key driver of the decrease was a $113 million increase in Operating Expenses and Other partially offset by an $85 million increase in Gross Margin.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins increased $59 million primarily due to the following:	
 	·	A $120 million increase related to the RSP rate increase effective January 1, 2006.	
 	·	A $20 million increase in capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak.	
 	·	An $11 million decrease in allowance expenses driven by a decrease in the average unit price of allowances.	
 	·	A $6 million decrease in consumables primarily due to a decrease in commodity prices.	
 	These increases were partially offset by:	
 	·	An $87 million decrease related to a decrease in fuel margins primarily due to higher fuel costs and a decrease in industrial revenue due to the transfer of a significant customer to an affiliate.	
 	·	An $8 million decrease in revenues associated with SO 2 allowances received from Buckeye Power, Inc. under the Cardinal Station Allowance Agreement.	
·	Margins from Off-system Sales increased $55 million primarily due to a $70 million increase in physical sales margins and a $20 million increase in our allocation of off-system sales margins under the SIA offset by a $35 million decrease in margins from optimization activities. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies” section of Note 4. Margins from Off-system Sales also increased as a result of decreased fuel costs and favorable optimization activities related to our purchase power and sale agreement with the Dow Chemical Company (Dow). This increase in margin related to Dow was offset by a corresponding increase in Other Operation and Maintenance expenses. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.	
·	Transmission Revenues decreased $32 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $8 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 4.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $63 million primarily due to the following:	
 	·	A $30 million increase in maintenance from planned and forced outages at the Gavin, Muskingum River, Kammer and Sporn plants related to major boiler and turbine overhauls and boiler tube inspections.	
 	·	A $21 million unfavorable variance due to increased maintenance costs and increased rental expense related to our purchase power and sale agreement with Dow. These increases in Other Operation and Maintenance expenses, which includes an indemnification adjustment related to our purchase power and sale agreement with Dow were offset by a corresponding increase in margins from Off-system Sales. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.	
 	·	An $8 million increase in removal costs related to maintenance.	
 	These increases were partially offset by:	
 	·	A $10 million variance due to the reduction of liabilities related to sold coal companies.	
·	Depreciation and Amortization increased $19 million primarily due to a $17 million increase in amortization of regulatory assets partially offset by the 2005 establishment of a $7 million regulatory liability to benefit low-income customers and for economic development, as ordered in our RSP. In addition, an $8 million increase in depreciation is attributable to a higher depreciable base in electric utility assets.	
·	Carrying Costs Income decreased $35 million primarily due to the completion of deferrals of the environmental carrying costs from 2004 and 2005 that are now being recovered during 2006 through 2008 according to the RSP.	
·	Interest Expense decreased $6 million primarily due to a $26 million increase in AFUDC partially offset by a $17 million increase in interest due to long-term debt issuances since November 2005.	

Income Taxes

Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income and state income taxes offset in part by tax return and tax reserve adjustments and changes in certain book/tax differences accounted for on a flow-through basis.
 
2005 Compared to 2004

Reconciliation of Year Ended December 31, 2004 to Year Ended December 31, 2005
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2004	 	 	 	 	$	210	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail Margins	 	 	35	 	 	 	 	
Off-system Sales	 	 	45	 	 	 	 	
Transmission Revenues	 	 	(15	)	 	 	 	
Other	 	 	1	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	66	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(32	)	 	 	 	
Depreciation and Amortization	 	 	(16	)	 	 	 	
Taxes Other Than Income Taxes	 	 	(12	)	 	 	 	
Carrying Costs Income	 	 	48	 	 	 	 	
Interest Expense	 	 	15	 	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	3	 	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(29	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2005	 	 	 	 	$	250	 	

Income Before Cumulative Effect of Accounting Change increased by $40 million in 2005. The key drivers of the increase were a $66 million increase in Gross Margin and a $48 million increase in Carrying Costs Income partially offset by a $32 million increase in Other Operation and Maintenance expenses and a $29 million increase in Income Tax Expense.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail Margins were $35 million higher than the prior period primarily due to:	
 	·	A $44 million increase in retail sales primarily due to increased residential, commercial and industrial sales from higher usage and favorable weather conditions.	
 	·	An $18 million favorable variance primarily due to the receipt of SO 2 allowances from Buckeye Power, Inc. under the Cardinal Station Allowance Agreement.	
 	·	A $7 million increase in capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak.	
 	These increases were partially offset by:	
 	·	An $18 million decrease in fuel margins partially due to an amendment to the PJM Services and Cost Allocation Agreement and the Buckeye Station Agreement of $9 million.	
·	Off-system Sales increased $45 million primarily due to increased AEP Power Pool physical sales and our purchase power and sale agreement with Dow. The increase in margin related to Dow was offset by a corresponding increase in Other Operation and Maintenance expenses. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.	
·	Transmission Revenues decreased $15 million primarily due to the loss of through-and-out rates, net of replacement SECA rates. See “Transmission Rate Proceedings at the FERC” section of Note 4.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $32 million primarily due to increased planned outages and maintenance on several units, maintenance of overhead lines due to increased tree trimming expenses and decreased expenses in 2004 as a result of a settlement related to the sale of the coal companies prior to 2003. These increases were partially offset by the settlement and cancellation of the COLI (corporate owned life insurance) policy in February 2005 and decreased administrative expenses related to the Gavin scrubber. Other Operation and Maintenance expenses also increased due to increased maintenance and rental expenses related to our purchase power and sale agreement with Dow. These increases in Other Operation and Maintenance expenses, which includes an indemnification adjustment related to Dow were offset by a corresponding increase in margins from Off-system Sales. See “Plaquemine Cogeneration Facility” section of “Significant Factors” for additional discussion of Dow.	
·	Depreciation and Amortization expense increased $16 million due to the establishment of a $7 million regulatory liability to benefit low-income customers and for economic development, as ordered in our RSP. The increase is also attributable to a higher depreciation base in electric utility plants.	
·	Taxes Other Than Income Taxes increased $12 million primarily due to an increase in property tax accruals as a result of increased property values. The increase is also a result of increased state excise taxes due to higher taxable KWH sales.	
·	Carrying Costs Income increased $48 million primarily due to the carrying costs on environmental capital expenditures as a result of our RSP order.	
·	Interest Expense decreased $15 million primarily due to capitalized interest related to construction of the Mitchell Plant and Cardinal Plant scrubbers and the Mitchell Plant SCR project that began after June 2004. Interest Expense also decreased due to optional redemptions and subsequent refinancings with lower cost debt.	

Income Taxes

Income Tax Expense increased $29 million primarily due to an increase in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 	 	Moody’s	 	S&P	 	Fitch	 	
 	 	 	 	 	 	 	 	
Senior Unsecured Debt	 	 	A3	 	 	BBB	 	 	BBB+	 	

Cash Flow

Cash flows for 2006, 2005 and 2004 were as follows:

 	 	2006	 	2005	 	2004	 	
 	 	(in thousands)	 	
 	 	  	 	  	 	  	 	
Cash and Cash Equivalents at Beginning of Period	 	$	1,240	 	$	9,337	 	$	7,294	 	
Cash Flows From (Used For):	 	 	 	 	 	 	 	 	 	 	
Operating Activities	 	 	626,246	 	 	368,805	 	 	545,855	 	
Investing Activities	 	 	(986,095	)	 	(571,184	)	 	(324,392	)	
Financing Activities	 	 	360,234	 	 	194,282	 	 	(219,420	)	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	385	 	 	(8,097	)	 	2,043	 	
Cash and Cash Equivalents at End of Period	 	$	1,625	 	$	1,240	 	$	9,337	 	

Operating Activities

Net Cash Flows From Operating Activities were $626 million in 2006. We produced Net Income of $229 million during the period and a noncash expense item of $322 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items, including a $116 million decrease in Accounts Receivable, Net. Accounts Receivable, Net decreased due to the collection of receivables related to power sales to affiliates, settled litigation and emission allowances.

Net Cash Flows From Operating Activities were $369 million in 2005. We produced Net Income of $246 million during the period and a noncash expense item of $302 million for Depreciation and Amortization. We made contributions of $132 million to our pension trust fund. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items including a $114 million decrease in Accrued Taxes, Net. During 2005, we made federal income tax payments of $198 million.

Net Cash Flows From Operating Activities were $546 million in 2004. We produced Net Income of $210 million during the period and noncash expense items of $286 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items, including a $100 million increase in Accrued Taxes, Net. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment was made in March 2005 when the 2004 federal income tax return extension was filed.

Investing Activities

Our net cash flows used for investing activities in 2006, 2005 and 2004 were $986 million, $571 million and $324 million, respectively, primarily due to Construction Expenditures for environmental upgrades, as well as projects to improve service reliability for transmission and distribution.

Financing Activities

Net Cash Flows From Financing Activities were $360 million in 2006. We issued $350 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds. We received a capital contribution from our Parent Company of $70 million. These amounts were partially offset by a $200 million retirement of affiliated notes payable.

Net Cash Flows From Financing Activities were $194 million in 2005. We issued $353 million of Pollution Control Bonds and $200 million of Senior Unsecured Notes. These amounts were partially offset by a $353 million retirement of Pollution Control Bonds.

Net Cash Flows Used For Financing Activities were $219 million in 2004. We retired $363 million of Senior Unsecured Notes Payable and paid $174 million dividends on common stock. These amounts were partially offset by a $400 million long-term debt issuance from AEP.

Summary Obligation Information

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payment Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Short-term Debt (a)	 	$	1.2	 	$	-	 	$	-	 	$	-	 	$	1.2	 	
Advances from Affiliates (b)	 	 	181.3	 	 	-	 	 	-	 	 	-	 	 	181.3	 	
Interest on Fixed Rate Portion of Long-term  Debt (c)	 	 	112.0	 	 	217.0	 	 	194.0	 	 	910.0	 	 	1,433.0	 	
Fixed Rate Portion of Long-term Debt (d)	 	 	18.0	 	 	133.0	 	 	200.0	 	 	1,589.0	 	 	1,940.0	 	
Variable Rate Portion of Long-term Debt (e)	 	 	-	 	 	-	 	 	-	 	 	468.0	 	 	468.0	 	
Capital Lease Obligations (f)	 	 	9.3	 	 	12.2	 	 	5.9	 	 	20.9	 	 	48.3	 	
Noncancelable Operating Leases (f)	 	 	21.3	 	 	37.4	 	 	31.6	 	 	71.0	 	 	161.3	 	
Fuel Purchase Contracts (g)	 	 	761.2	 	 	1,280.2	 	 	1,227.9	 	 	3,604.5	 	 	6,873.8	 	
Energy and Capacity Purchase Contracts (h)	 	 	2.4	 	 	3.6	 	 	5.4	 	 	1.1	 	 	12.5	 	
Construction Contracts for Capital Assets (i)	 	 	626.5	 	 	41.0	 	 	-	 	 	124.1	 	 	791.6	 	
Total	 	$	1,733.2	 	$	1,724.4	 	$	1,664.8	 	$	6,788.6	 	$	11,911.0	 	

(a)	Represents principal only excluding interest.	
(b)	Represents short-term borrowing from the Utility Money Pool.	
(c)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(d)	See Note 15. Represents principal only excluding interest.	
(e)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 3.60% and 3.85% at December 31, 2006.	
(f)	See Note 14.	
(g)	Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.	
(h)	Represents contractual cash flows of energy and capacity purchase contracts.	
(i)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Plaquemine Cogeneration   Facility

In 2000, Juniper Capital L.P. financed AEP’s nonregulated ownership interest in the Plaquemine Cogeneration Facility (the Facility) near Plaquemine, Louisiana. AEP subleased the Facility to Dow Chemical Company (Dow). As outlined in the “OPCo Indemnification Agreement with AEP Resources” section of Note 16, we entered into a purchase power and sale agreement with Dow and a corresponding indemnification agreement with a nonutility subsidiary of AEP. As a result, our results of operations included sales to nonaffiliated companies and offsetting maintenance expense with no effect on our Net Income. In the fourth quarter of 2006, AEP sold the Facility to Dow. With the sale of the Facility, we terminated our purchase power and sale agreement with Dow. This sale did not have an impact on our 2006 results of operations. In 2006, the operation of the facility affected revenues, Fuel and Other Consumables Used for Electric Generation, Purchased Electricity for Resale, Other Operation expense and Maintenance expense by approximately $157 million, $134 million, ($7) million, $19 million and $11 million, respectively, with no effect on net income. These revenues and expenses will not recur in 2007.

Muskingum River Project Deferral

Completion of construction of the Muskingum River Unit 5 flue gas desulfurization (FGD) project was previously scheduled for 2008. We suspended the project in 2006 following a review of a new SO 2 and mercury compliance plan evaluation, updated coal market information reflecting the contraction of the low sulfur price differentials and the latest project costs. We currently estimate the project to have an in-service date in 2014 or beyond. Management continues to review its emission compliance plans given changing market conditions and the evolving legislative and regulatory environment.

We transferred the total project expenditures of $33 million from Construction Work in Progress to Deferred Charges and Other on our Consolidated Balance Sheet. If management does not resume the project, the balance of incurred expenditures would negatively impact future earnings unless a regulatory asset could be established due to probable recovery through rates.

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow Hedges	 	DETM
Assignment (a)	 	Total	 	
Current Assets	 	$	80,175	 	$	6,772	 	$	-	 	$	86,947	 	
Noncurrent Assets	 	 	69,997	 	 	95	 	 	-	 	 	70,092	 	
Total MTM Derivative Contract Assets	 	 	150,172	 	 	6,867	 	 	-	 	 	157,039	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(70,913	)	 	(662	)	 	(1,811	)	 	(73,386	)	
Noncurrent Liabilities	 	 	(46,217	)	 	(20	)	 	(6,692	)	 	(52,929	)	
Total MTM Derivative Contract  Liabilities	 	 	(117,130	)	 	(682	)	 	(8,503	)	 	(126,315	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	33,042	 	$	6,185	 	$	(8,503	)	$	30,724	 	

(a)	See “Natural Gas Contracts with DETM” section of Note 16.	

MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	40,894	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(5,340	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	713	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	(486	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	451	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	1,460	 	
Changes Due to SIA Agreement (c)	 	 	(4,984	)	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	334	 	
Total MTM Risk Management Contract Net Assets	 	 	33,042	 	
Net Cash Flow Hedge Contracts	 	 	6,185	 	
DETM Assignment (e)	 	 	(8,503	)	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	30,724	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	
(e)	See “Natural Gas Contracts with DETM” section of Note 16.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	 	2007 	 	 	 2008	 	 	2009 	 	 	2010 	 	 	2011 	 	 	After
2011 	 	 	Total  	
Prices Actively Quoted -   ExchangeTraded Contracts	 	$	4,751	 	$	3,330	 	$	489	 	$	
-	 	$	
-	 	$	
-	 	$	8,570	
Prices Provided by Other External Sources - OTC Broker Quotes  (a)	 	 	9,784	 	 	3,876	 	 	5,698	 	 	-	 	 	-	 	 	-	 	 	19,358	
Prices Based on Models and Other Valuation Methods (b)	 	 	(5,273	)	 	(1,061	)	 	2,924	 	 	6,543	 	 	861	 	 	1,120	 	 	5,114	
Total	 	$	9,262	 	$	6,145	 	$	9,111	 	$	6,543	 	$	861	 	$	1,120	 	$	33,042	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

We use forward contracts and collars as cash flow hedges to lock-in prices on certain transactions denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	Foreign
Currency	 	Interest Rate	 	Total	 	
Beginning Balance in AOCI December 31, 2005	 	$	(392	)	$	(344	)	$	1,491	 	$	755	 	
Changes in Fair Value	 	 	4,138	 	 	-	 	 	2,761	 	 	6,899	 	
Impact due to Changes in SIA (a)	 	 	(337	)	 	-	 	 	-	 	 	(337	)	
Reclassifications from AOCI to Net Income for   Cash Flow Hedges Settled	 	 	631	 	 	13	 	 	(699	)	 	(55	)	
Ending Balance in AOCI December 31, 2006	 	$	4,040	 	$	(331	)	$	3,553	 	$	7,262	 	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $4,791 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$573	 	$1,451	 	$500	 	$271	 	 	 	 	$583	 	$968	 	$461	 	$166	

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $110 million and $111 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	2,006,279	 	$	1,922,280	 	$	1,752,766	 	
Sales to AEP Affiliates	 	 	685,343	 	 	681,852	 	 	594,357	 	
Other - Affiliated	 	 	16,775	 	 	15,437	 	 	15,013	 	
Other - Nonaffiliated	 	 	16,478	 	 	14,980	 	 	10,589	 	
TOTAL	 	 	2,724,875	 	 	2,634,549	 	 	2,372,725	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	960,119	 	 	975,180	 	 	819,787	 	
Purchased Electricity for Resale	 	 	100,958	 	 	77,173	 	 	64,229	 	
Purchased Electricity from AEP Affiliates	 	 	113,651	 	 	116,890	 	 	89,355	 	
Other Operation	 	 	382,573	 	 	340,085	 	 	336,330	 	
Maintenance	 	 	228,151	 	 	207,226	 	 	179,290	 	
Depreciation and Amortization	 	 	321,954	 	 	302,495	 	 	286,300	 	
Taxes Other Than Income Taxes	 	 	192,178	 	 	190,013	 	 	177,895	 	
TOTAL	 	 	2,299,584	 	 	2,209,062	 	 	1,953,186	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	425,291	 	 	425,487	 	 	419,539	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	2,363	 	 	3,311	 	 	3,155	 	
Carrying Costs Income	 	 	13,841	 	 	48,510	 	 	735	 	
Allowance for Equity Funds Used During Construction	 	 	2,556	 	 	1,441	 	 	1,482	 	
Interest Expense	 	 	(97,084	)	 	(103,352	)	 	(118,685	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	346,967	 	 	375,397	 	 	306,226	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	118,324	 	 	124,978	 	 	96,110	 	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE CUMULATIVE EFFECT OF   ACCOUNTING CHANGE	 	 	228,643	 	 	250,419	 	 	210,116	 	
 	 	 	 	 	 	 	 	 	 	 	
CUMULATIVE EFFECT OF ACCOUNTING CHANGE,   NET OF TAX	 	 	-	 	 	(4,575	)	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	228,643	 	 	245,844	 	 	210,116	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements including Other Expense	 	 	732	 	 	906	 	 	733	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$	227,911	 	$	244,938	 	$	209,383	 	

The common stock of OPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	  Common
Stock	 	 Paid-in
Capital	 	 Retained Earnings	 	 Accumulated Other Comprehensive Income (Loss)	 	 Total	 	
DECEMBER 31, 2003	 	$	321,201	 	$	462,484	 	$	729,147	 	$	(48,807	)	$	1,464,025	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(174,114	)	 	 	 	 	(174,114	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(733	)	 	 	 	 	(733	)	
Capital Stock Gains	 	 	 	 	 	1	 	 	 	 	 	 	 	 	1	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,289,179	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $723	 	 	 	 	 	 	 	 	 	 	 	1,344	 	 	1,344	 	
Minimum Pension Liability, Net of Tax of $14,432	 	 	 	 	 	 	 	 	 	 	 	(26,801	)	 	(26,801	)	
NET INCOME	 	 	 	 	 	 	 	 	210,116	 	 	 	 	 	210,116	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	184,659	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	321,201	 	 	462,485	 	 	764,416	 	 	(74,264	)	 	1,473,838	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(30,000	)	 	 	 	 	(30,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(732	)	 	 	 	 	(732	)	
Other	 	 	 	 	 	4,152	 	 	(174	)	 	 	 	 	3,978	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,447,084	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $262	 	 	 	 	 	 	 	 	 	 	 	(486	)	 	(486	)	
Minimum Pension Liability, Net of Tax of $40,657	 	 	 	 	 	 	 	 	 	 	 	75,505	 	 	75,505	 	
NET INCOME	 	 	 	 	 	 	 	 	245,844	 	 	 	 	 	245,844	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	320,863	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	321,201	 	 	466,637	 	 	979,354	 	 	755	 	 	1,767,947	 	
Capital Contributions from Parent Company	 	 	 	 	 	70,000	 	 	 	 	 	 	 	 	70,000	 	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(732	)	 	 	 	 	(732	)	
Gain on Reacquired Preferred Stock	 	 	 	 	 	2	 	 	 	 	 	 	 	 	2	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,837,217	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),  Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $3,504	 	 	 	 	 	 	 	 	 	 	 	6,507	 	 	6,507	 	
Minimum Pension Liability, Net of Tax  of $110	 	 	 	 	 	 	 	 	 	 	 	(204	)	 	(204	)	
NET INCOME	 	 	 	 	 	 	 	 	228,643	 	 	 	 	 	228,643	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	234,946	 	
Minimum Pension Liability Elimination, Net of Tax of $110	 	 	 	 	 	 	 	 	 	 	 	204	 	 	204	 	
SFAS 158 Adoption, Net of Tax of $34,475	 	 	 	 	 	 	 	 	 	 	 	(64,025	)	 	(64,025	)	
DECEMBER 31, 2006	 	$	321,201	 	$	536,639	 	$	1,207,265	 	$	(56,763	)	$	2,008,342	 	
 
See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	1,625	 	$	1,240	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	86,116	 	 	125,404	 	
Affiliated Companies	 	 	108,214	 	 	167,579	 	
Accrued Unbilled Revenues	 	 	10,106	 	 	14,817	 	
Miscellaneous	 	 	1,819	 	 	15,644	 	
Allowance for Uncollectible Accounts	 	 	(824	)	 	(1,517	)	
Total Accounts Receivable	 	 	205,431	 	 	321,927	 	
Fuel	 	 	120,441	 	 	97,600	 	
Materials and Supplies	 	 	74,840	 	 	60,937	 	
Emission Allowances	 	 	10,388	 	 	39,251	 	
Risk Management Assets	 	 	86,947	 	 	115,020	 	
Accrued Tax Benefits	 	 	22,909	 	 	39,965	 	
Prepayments and Other	 	 	18,416	 	 	27,439	 	
TOTAL	 	 	540,997	 	 	703,379	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	4,413,340	 	 	4,278,553	 	
Transmission	 	 	1,030,934	 	 	1,002,255	 	
Distribution	 	 	1,322,103	 	 	1,258,518	 	
Other	 	 	299,637	 	 	293,794	 	
Construction Work in Progress	 	 	1,339,631	 	 	690,168	 	
Total	 	 	8,405,645	 	 	7,523,288	 	
Accumulated Depreciation and Amortization	 	 	2,836,584	 	 	2,738,899	 	
TOTAL - NET	 	 	5,569,061	 	 	4,784,389	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	414,180	 	 	398,007	 	
Long-term Risk Management Assets	 	 	70,092	 	 	144,015	 	
Deferred Charges and Other	 	 	224,403	 	 	300,880	 	
TOTAL	 	 	708,675	 	 	842,902	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	6,818,733	 	$	6,330,670	 	

See Notes to Financial Statements of Registrant Subsidiaries.

 
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	181,281	 	$	70,071	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	250,025	 	 	210,752	 	
Affiliated Companies	 	 	145,197	 	 	147,470	 	
Short-term Debt - Nonaffiliated	 	 	1,203	 	 	10,366	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	17,854	 	 	12,354	 	
Long-term Debt Due Within One Year - Affiliated	 	 	-	 	 	200,000	 	
Risk Management Liabilities	 	 	73,386	 	 	108,797	 	
Customer Deposits	 	 	31,465	 	 	51,209	 	
Accrued Taxes	 	 	165,338	 	 	158,774	 	
Accrued Interest	 	 	35,497	 	 	36,298	 	
Other	 	 	123,631	 	 	111,480	 	
TOTAL	 	 	1,024,877	 	 	1,117,571	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	2,183,887	 	 	1,787,316	 	
Long-term Debt - Affiliated	 	 	200,000	 	 	200,000	 	
Long-term Risk Management Liabilities	 	 	52,929	 	 	119,247	 	
Deferred Income Taxes	 	 	911,221	 	 	987,386	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	185,895	 	 	168,492	 	
Deferred Credits and Other	 	 	219,127	 	 	154,770	 	
TOTAL	 	 	3,753,059	 	 	3,417,211	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	4,777,936	 	 	4,534,782	 	
 	 	 	 	 	 	 	 	
Minority Interest	 	 	15,825	 	 	11,302	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	16,630	 	 	16,639	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - No Par Value:	 	 	 	 	 	 	 	
Authorized - 40,000,000 Shares	 	 	 	 	 	 	 	
Outstanding - 27,952,473 Shares	 	 	321,201	 	 	321,201	 	
Paid-in Capital	 	 	536,639	 	 	466,637	 	
Retained Earnings	 	 	1,207,265	 	 	979,354	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(56,763	)	 	755	 	
TOTAL	 	 	2,008,342	 	 	1,767,947	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	6,818,733	 	$	6,330,670	 	

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	  2006	 	  2005	 	  2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	228,643	 	$	245,844	 	$	210,116	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	321,954	 	 	302,495	 	 	286,300	 	
Deferred Income Taxes	 	 	(43,997	)	 	59,593	 	 	23,329	 	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	4,575	 	 	-	 	
Carrying Costs Income	 	 	(13,841	)	 	(48,510	)	 	(735	)	
Mark-to-Market of Risk Management Contracts	 	 	6,545	 	 	(2,372	)	 	1,171	 	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(132,496	)	 	(764	)	
Change in Other Noncurrent Assets	 	 	(735	)	 	5,806	 	 	(10,398	)	
Change in Other Noncurrent Liabilities	 	 	10,126	 	 	(15,180	)	 	(2,563	)	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	116,496	 	 	(60,627	)	 	(22,640	)	
Fuel, Materials and Supplies	 	 	(36,744	)	 	(32,659	)	 	1,329	 	
Accounts Payable	 	 	(14,114	)	 	56,403	 	 	31,023	 	
Customer Deposits	 	 	(19,744	)	 	28,589	 	 	5,312	 	
Accrued Taxes, Net	 	 	23,620	 	 	(114,217	)	 	100,233	 	
Other Current Assets	 	 	39,692	 	 	44,516	 	 	(71,141	)	
Other Current Liabilities	 	 	8,345	 	 	27,045	 	 	(4,717	)	
Net Cash Flows From Operating Activities	 	 	626,246	 	 	368,805	 	 	545,855	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(999,603	)	 	(710,536	)	 	(320,215	)	
Change in Other Cash Deposits, Net	 	 	(1,806	)	 	(29	)	 	50,956	 	
Change in Advances to Affiliates, Net	 	 	-	 	 	125,971	 	 	(58,053	)	
Other	 	 	15,314	 	 	13,410	 	 	2,920	 	
Net Cash Flows Used For Investing Activities	 	 	(986,095	)	 	(571,184	)	 	(324,392	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Capital Contributions from Parent Company	 	 	70,000	 	 	-	 	 	-	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	408,710	 	 	545,746	 	 	-	 	
Issuance of Long-term Debt - Affiliated	 	 	-	 	 	-	 	 	400,000	 	
Change in Short-term Debt, Net - Nonaffiliated	 	 	(9,163	)	 	(13,132	)	 	(2,443	)	
Change in Advances from Affiliates, Net	 	 	111,210	 	 	70,071	 	 	-	 	
Retirement of Long-term Debt - Nonaffiliated	 	 	(12,354	)	 	(365,354	)	 	(431,854	)	
Retirement of Long-term Debt - Affiliated	 	 	(200,000	)	 	-	 	 	-	 	
Retirement of Cumulative Preferred Stock	 	 	(7	)	 	(5,000	)	 	(2,254	)	
Principal Payments for Capital Lease Obligations	 	 	(7,430	)	 	(7,317	)	 	(8,022	)	
Dividends Paid on Common Stock	 	 	-	 	 	(30,000	)	 	(174,114	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(732	)	 	(732	)	 	(733	)	
Net Cash Flows From (Used For) Financing Activities	 	 	360,234	 	 	194,282	 	 	(219,420	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	385	 	 	(8,097	)	 	2,043	 	
Cash and Cash Equivalents at Beginning of Period	 	 	1,240	 	 	9,337	 	 	7,294	 	
Cash and Cash Equivalents at End of Period	 	$	1,625	 	$	1,240	 	$	9,337	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	94,051	 	$	102,656	 	$	119,562	 	
Net Cash Paid (Received) for Income Taxes	 	 	142,895	 	 	198,078	 	 	(21,600	)	
Noncash Acquisitions Under Capital Leases	 	 	3,288	 	 	9,218	 	 	14,727	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	125,962	 	 	74,848	 	 	35,470	 	
 	 	 	 	 	 	 	 	 	 	 	
See Notes to Financial Statements of Registrant Subsidiaries.	

OHIO POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to OPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo.

 	Footnote
Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 

 

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Ohio Power Company:

We have audited the accompanying consolidated balance sheets of Ohio Power Company Consolidated (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company Consolidated as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006. As discussed in Note 17 to the consolidated financial statements, the Company adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations,” effective December 31, 2005. As discussed in Note 9 to the consolidated financial statements, the Company adopted FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.
 
/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007 

 

 

 

PUBLIC SERVICE COMPANY OF OKLAHOMA

 

 

 

 

 

 

 PUBLIC SERVICE COMPANY OF OKLAHOMA
SELECTED FINANCIAL DATA
(in thousands)

 	 	2006	 	2005	 	2004	 	2003	 	2002	 	
STATEMENTS OF INCOME DATA	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	1,441,784	 	$	1,304,078	 	$	1,047,820	 	$	1,107,931	 	$	793,282	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	90,993	 	$	118,016	 	$	82,806	 	$	135,840	 	$	101,911	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	36,860	 	$	57,893	 	$	37,542	 	$	53,891	 	$	41,060	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	3,186,294	 	$	2,994,995	 	$	2,875,839	 	$	2,818,514	 	$	2,771,161	 	
Accumulated Depreciation and Amortization	 	 	1,187,107	 	 	1,175,858	 	 	1,117,535	 	 	1,069,417	 	 	1,037,222	 	
Net   Property, Plant and Equipment	 	$	1,999,187	 	$	1,819,137	 	$	1,758,304	 	$	1,749,097	 	$	1,733,939	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	2,579,046	 	$	2,355,464	 	$	2,066,825	 	$	1,976,477	 	$	1,987,077	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder’s Equity	 	$	585,438	 	$	548,597	 	$	529,256	 	$	483,008	 	$	399,247	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock  Not Subject to Mandatory Redemption	 	$	5,262	 	$	5,262	 	$	5,262	 	$	5,267	 	$	5,267	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trust Preferred Securities	 	$	-	 	$	-	 	$	-	 	$	-	 	$	75,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (a)	 	$	669,998	 	$	571,071	 	$	546,092	 	$	574,298	 	$	545,437	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (a)	 	$	4,816	 	$	2,534	 	$	1,284	 	$	1,010	 	$	-	 	

(a)	Including portion due within one year.	

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 520,000 retail customers in our service territory in eastern and southwestern Oklahoma. As a member of the CSW Operating Agreement with SWEPCo, we share in the revenues and expenses of the members’ sales to neighboring utilities and power marketers. We also sell electric power at wholesale to other utilities, municipalities and rural electric cooperatives.

Effective May 1, 2006, the FERC approved the removal of TCC and TNC from the CSW Operating Agreement. Under the Texas Restructuring Legislation, TCC and TNC completed the final stage of exiting the generation business and ceased serving retail load. TCC and TNC are no longer involved in the coordinated planning and operation of power supply facilities or share trading and marketing margins, as contemplated by both the CSW Operating Agreement and the SIA. Consequently, our proportionate share of trading and marketing margins increased, although the level of margins depends upon future market conditions. We share these margins with our customers.

Members of the CSW Operating Agreement are compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. We share the revenues and costs of sales to neighboring utilities and power marketers made by AEPSC on our behalf with SWEPCo based upon the relative magnitude of the energy each company provides to make such sales. We share off-system sales margins, if positive on an annual basis, with our customers.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of SWEPCo and us. Margins resulting from other transactions are allocated among the AEP East companies, SWEPCo and us in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. Management expects, due to our generating capacity situation in SPP, a decrease in margins for SWEPCo and us as a result of the SIA change. Our impact will depend upon the level of future trading and marketing margins in SPP and sharing mechanisms with customers for off-system sales margins in Oklahoma. Our results of operations and cash flows for 2006 reflect the new allocation method following the approval of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with SWEPCo. Power and gas risk management activities are allocated based on the CSW Operating Agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

Effective January 1, 2007, we locked in our margins on our ERCOT trading and marketing contracts and transferred commodity price risk to AEP Energy Partners, LP (AEPEP), a wholly-owned subsidiary of AEP. This was achieved by a combination of transferring certain existing ERCOT energy marketing contracts to AEPEP and entering into financial and physical purchase and sale agreements with AEPEP. We will not be a party to new contracts in ERCOT. For future periods as the contracts mature, we will realize the fixed margin on the portfolio of ERCOT contracts as it existed on December 31, 2006 and will not be exposed to commodity price risk and resulting earnings variations for these contracts.

We are jointly and severally liable for activity conducted by AEPSC on our behalf and the behalf of AEP East companies and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to December 31, 2006
Net Income
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	58	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail and Off-system Sales Margins	 	 	4	 	 	 	 	
Transmission Revenues	 	 	(3	)	 	 	 	
Other	 	 	6	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	7	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(35	)	 	 	 	
Depreciation and Amortization	 	 	(1	)	 	 	 	
Taxes Other Than Income Taxes	 	 	2	 	 	 	 	
Other Income, Net	 	 	 (2	) 	 	 	 	
Interest Expense	 	 	(7	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(43	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	15	 	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	37	 	

Net Income decreased $21 million to $37 million in 2006. The key driver of the decrease was a $43 million increase in Operating Expenses and Other, partially offset by a $15 million decrease in Income Tax Expense and a $7 million increase in Gross Margin.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail and Off-system Sales Margins increased $4 million primarily due to:	
 	·	A $19 million increase in retail base margins due primarily to a $12 million increase in Distribution Vegetation Management (DVM) revenues and a slight increase in KWH sales, partially offset by:	
 	·	A $15 million decrease in off-system sales margins retained. Total off-system sales margins decreased $54 million due to decreased physical sales and a decrease in our allocation of off-system sales margins under the SIA, partially offset by $41 million of the decrease flowing through the fuel adjustment clause and having no impact on Gross Margin. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
·	Other revenues increased $6 million primarily due to a $3 million increase in rental income for pole attachments and a $2 million increase in revenues for third-party construction projects.	

Operating Expenses and Other increased between years as follows:

·	Other Operation and Maintenance expenses increased $35 million due to:	
 	·	A $15 million increase in distribution maintenance primarily related to increased DVM expenses.	
 	·	An $11 million increase in administrative and general expenses, mostly due to increased employee-related expenses.	
 	·	A $5 million increase in expenses related to the factoring of accounts receivable. The $5 million increase in expenses related to the factoring of accounts receivable is primarily due to an increase in accounts receivable factored, an increase in bad debt write-offs and an increase in short-term interest rates.	
 	·	A $4 million increase in forced and scheduled power plant maintenance.	
·	Interest Expense increased $7 million primarily due to increased borrowings from the Utility Money Pool during the year and the issuance of long-term debt in 2006. The proceeds were primarily used to finance our construction expenditures during the year.	

Income Taxes

Income Tax Expense decreased $15 million primarily due to a decrease in pretax book income and the recording of the tax reserve adjustments.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:
 
 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	
Senior Unsecured Debt	Baa1	 	BBB	 	A-	

Summary Obligation Information

Our contractual obligations include amounts reported on our Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payment Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	76.3	 	$	-	 	$	-	 	$	-	 	$	76.3	 	
Interest on Fixed Rate Portion of Long-term  Debt (b)	 	 	35.0	 	 	69.0	 	 	57.0	 	 	305.0	 	 	466.0	 	
Fixed Rate Portion of Long-term Debt (c)	 	 	-	 	 	50.0	 	 	225.0	 	 	363.0	 	 	638.0	 	
Variable Rate Portion of Long-term Debt (d)	 	 	-	 	 	-	 	 	-	 	 	34.0	 	 	34.0	 	
Capital Lease Obligations (e)	 	 	1.7	 	 	2.7	 	 	0.9	 	 	0.1	 	 	5.4	 	
Noncancelable Operating Leases (e)	 	 	6.8	 	 	8.8	 	 	6.7	 	 	5.8	 	 	28.1	 	
Fuel Purchase Contracts (f)	 	 	228.7	 	 	228.9	 	 	136.9	 	 	191.9	 	 	786.4	 	
Energy and Capacity Purchase Contracts (g)	 	 	68.1	 	 	151.6	 	 	125.7	 	 	156.0	 	 	501.4	 	
Construction Contracts for Capital Assets (h)	 	 	119.3	 	 	-	 	 	-	 	 	0.9	 	 	120.2	 	
Total	 	$	535.9	 	$	511.0	 	$	552.2	 	$	1,056.7	 	$	2,655.8	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(c)	See Note 15. Represents principal only excluding interest.	
(d)	See Note 15. Represents principal only excluding interest. Variable rate debt had an interest rate of 3.60% at December 31, 2006.	
(e)	See Note 14.	
(f)	Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.	
(g)	Represents contractual cash flows of energy and capacity purchase contracts.	
(h)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

As of December 31, 2006, we have no outstanding standby letters of credit or guarantees of performance.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

New Generation

In September 2005, we sought proposals for new peaking generation to be online in 2008, and in December 2005 we sought proposals for base load generation to be online in 2011. We received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from a neutral third party. In March 2006, we announced plans to add 170 MW of peaking generation to our Riverside Station plant in Jenks, Oklahoma where we will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, we announced plans to add 170 MW of peaking generation to our Southwestern Station plant in Anadarko, Oklahoma where we will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Combined preliminary cost estimates for these additions are approximately $120 million. In July 2006, we announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. We will own 50% of the new unit. We, along with OG&E and OMPA, signed an agreement in February 2007 with Red Rock Power Partners to begin the first phase of the project. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion, and 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. We expect to begin construction on all of these additions in 2007. Expenditures related to construction of these facilities are expected to total $125 million in 2007.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow
Hedges	 	Total	 	
Current Assets	 	$	100,802	 	$	-	 	$	100,802	 	
Noncurrent Assets	 	 	17,066	 	 	-	 	 	17,066	 	
Total MTM Derivative Contract Assets	 	 	117,868	 	 	-	 	 	117,868	 	
 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(88,469	)	 	-	 	 	(88,469	)	
Noncurrent Liabilities	 	 	(11,448	)	 	-	 	 	(11,448	)	
Total MTM Derivative Contract Liabilities	 	 	(99,917	)	 	-	 	 	(99,917	)	
 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets	 	$	17,951	 	$	-	 	$	17,951	 	

MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	14,214	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	290	 	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	-	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entere  During the Period	 	 	(485	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	-	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	(167	)	
Changes Due to SIA and CSW Operating Agreement (c)	 	 	10,185	 	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	(6,086	)	
Total MTM Risk Management Contract Net Assets	 	 	17,951	 	
Net Cash Flow Hedge Contracts	 	 	-	 	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	17,951	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Prices Actively Quoted - Exchange  Traded Contracts	 	$	(16,504	)	$	1,569	 	$	(241	)	$	-	 	$	-	 	$	-	 	$	(15,176	)	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	28,827	 	 	4,201	 	 	(572	)	 	-	 	 	-	 	 	-	 	 	32,456	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	10	 	 	(422	)	 	1,082	 	 	1	 	 	-	 	 	-	 	 	671	 	
Total	 	$	12,333	 	$	5,348	 	$	269	 	$	1	 	$	-	 	$	-	 	$	17,951	 	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.
 
Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	Interest Rate	 	Total	 	
Beginning Balance in AOCI December 31, 2005	 	$	(629	)	$	(483	)	$	(1,112	)	
Changes in Fair Value	 	 	-	 	 	(728	)	 	(728	)	
Impact Due to Change in SIA (a)	 	 	506	 	 	-	 	 	506	 	
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled	 	 	123	 	 	141	 	 	264	 	
Ending Balance in AOCI December 31, 2006	 	$	-	 	$	(1,070	)	$	(1,070	)	

(a)	See “Allocation Agreement between AEP East companies and AEP West Companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $183 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$380	 	$1,842	 	$676	 	$58	 	 	 	 	$311	 	$517	 	$246	 	$89	

The High VaR for the twelve months ended December 31, 2006 occurred in the fourth quarter due to volatility in the ERCOT region.

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $39 million and $34 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	1,384,549	 	$	1,261,424	 	$	1,035,306	 	
Sales to AEP Affiliates	 	 	51,993	 	 	39,678	 	 	10,690	 	
Other	 	 	5,242	 	 	2,976	 	 	1,824	 	
TOTAL	 	 	1,441,784	 	 	1,304,078	 	 	1,047,820	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	703,252	 	 	619,657	 	 	434,420	 	
Purchased Electricity for Resale	 	 	199,094	 	 	116,345	 	 	79,325	 	
Purchased Electricity from AEP Affiliates	 	 	69,406	 	 	105,361	 	 	104,001	 	
Other Operation	 	 	170,201	 	 	156,451	 	 	155,441	 	
Maintenance	 	 	88,676	 	 	67,077	 	 	63,529	 	
Depreciation and Amortization	 	 	87,543	 	 	86,762	 	 	89,711	 	
Taxes Other Than Income Taxes	 	 	32,619	 	 	34,409	 	 	38,587	 	
TOTAL	 	 	1,350,791	 	 	1,186,062	 	 	965,014	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	90,993	 	 	118,016	 	 	82,806	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	1,917	 	 	3,591	 	 	166	 	
Allowance for Equity Funds Used During Construction	 	 	715	 	 	865	 	 	336	 	
Interest Expense	 	 	(40,778	)	 	(34,094	)	 	(37,957	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	52,847	 	 	88,378	 	 	45,351	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	15,987	 	 	30,485	 	 	7,809	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	36,860	 	 	57,893	 	 	37,542	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements	 	 	213	 	 	213	 	 	213	 	
Gain on Reacquired Preferred Stock	 	 	-	 	 	-	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$	36,647	 	$	57,680	 	$	37,331	 	

The common stock of PSO is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	157,230	 	$	230,016	 	$	139,604	 	$	(43,842	)	$	483,008	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(35,000	)	 	 	 	 	(35,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(213	)	 	 	 	 	(213	)	
Gain on Reacquired Preferred Stock	 	 	 	 	 	 	 	 	2	 	 	 	 	 	2	 	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	447,797	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income,   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $131	 	 	 	 	 	 	 	 	 	 	 	244	 	 	244	 	
Minimum Pension Liability, Net of Tax  of $23,516	 	 	 	 	 	 	 	 	 	 	 	43,673	 	 	43,673	 	
NET INCOME	 	 	 	 	 	 	 	 	37,542	 	 	 	 	 	37,542	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	81,459	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	157,230	 	 	230,016	 	 	141,935	 	 	75	 	 	529,256	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(37,000	)	 	 	 	 	(37,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(213	)	 	 	 	 	(213	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	492,043	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $814	 	 	 	 	 	 	 	 	 	 	 	(1,512	)	 	(1,512	)	
Minimum Pension Liability, Net of Tax  of $93	 	 	 	 	 	 	 	 	 	 	 	173	 	 	173	 	
NET INCOME	 	 	 	 	 	 	 	 	57,893	 	 	 	 	 	57,893	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	56,554	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	157,230	 	 	230,016	 	 	162,615	 	 	(1,264	)	 	548,597	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(213	)	 	 	 	 	(213	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	548,384	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income,   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $22	 	 	 	 	 	 	 	 	 	 	 	42	 	 	42	 	
Minimum Pension Liability, Net of Tax of $14	 	 	 	 	 	 	 	 	 	 	 	25	 	 	25	 	
NET INCOME	 	 	 	 	 	 	 	 	36,860	 	 	 	 	 	36,860	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	36,927	 	
Minimum Pension Liability Elimination, Net of Tax of $68	 	 	 	 	 	 	 	 	 	 	 	127	 	 	127	 	
DECEMBER 31, 2006	 	$	157,230	 	$	230,016	 	$	199,262	 	$	(1,070	)	$	585,438	 	

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	
Cash and Cash Equivalents	 	$	1,651	 	$	1,520	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	70,319	 	 	37,740	 	
Affiliated Companies	 	 	73,318	 	 	73,321	 	
Miscellaneous	 	 	10,270	 	 	10,501	 	
Allowance for Uncollectible Accounts	 	 	(5	)	 	(240	)	
   Total Accounts Receivable	 	 	153,902	 	 	121,322	 	
Fuel	 	 	20,082	 	 	16,431	 	
Materials and Supplies	 	 	48,375	 	 	38,545	 	
Risk Management Assets	 	 	100,802	 	 	40,383	 	
Accrued Tax Benefits	 	 	4,679	 	 	11,972	 	
Regulatory Asset for Under-Recovered Fuel Costs	 	 	7,557	 	 	108,732	 	
Margin Deposits	 	 	35,270	 	 	10,051	 	
Prepayments and Other	 	 	5,732	 	 	4,236	 	
TOTAL	 	 	378,050	 	 	353,192	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	1,091,910	 	 	1,072,928	 	
Transmission	 	 	503,638	 	 	479,272	 	
Distribution	 	 	1,215,236	 	 	1,140,535	 	
Other	 	 	234,227	 	 	211,805	 	
Construction Work in Progress	 	 	141,283	 	 	90,455	 	
Total	 	 	3,186,294	 	 	2,994,995	 	
Accumulated Depreciation and Amortization	 	 	1,187,107	 	 	1,175,858	 	
TOTAL - NET	 	 	1,999,187	 	 	1,819,137	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	142,905	 	 	50,723	 	
Long-term Risk Management Assets	 	 	17,066	 	 	33,566	 	
Employee Benefits and Pension Assets	 	 	30,161	 	 	82,559	 	
Deferred Charges and Other	 	 	11,677	 	 	16,287	 	
TOTAL	 	 	201,809	 	 	183,135	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	2,579,046	 	$	2,355,464	 	

See Notes to Financial Statements of Registrant Subsidiaries.

 
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	76,323	 	$	75,883	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	165,618	 	 	130,627	 	
Affiliated Companies	 	 	65,134	 	 	89,786	 	
Long-term Debt Due Within One Year - Affiliated	 	 	-	 	 	50,000	 	
Risk Management Liabilities	 	 	88,469	 	 	38,243	 	
Customer Deposits	 	 	51,335	 	 	53,844	 	
Accrued Taxes	 	 	19,984	 	 	22,420	 	
Other	 	 	58,651	 	 	51,548	 	
TOTAL	 	 	525,514	 	 	512,351	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	669,998	 	 	521,071	 	
Long-term Risk Management Liabilities	 	 	11,448	 	 	22,582	 	
Deferred Income Taxes	 	 	414,197	 	 	436,382	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	315,584	 	 	284,640	 	
Deferred Credits and Other	 	 	51,605	 	 	24,579	 	
TOTAL	 	 	1,462,832	 	 	1,289,254	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	1,988,346	 	 	1,801,605	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	5,262	 	 	5,262	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - $15 Par Value Per Share:	 	 	 	 	 	 	 	
Authorized - 11,000,000 Shares	 	 	 	 	 	 	 	
Issued - 10,482,000 Shares	 	 	 	 	 	 	 	
Outstanding - 9,013,000 Shares	 	 	157,230	 	 	157,230	 	
Paid-in Capital	 	 	230,016	 	 	230,016	 	
Retained Earnings	 	 	199,262	 	 	162,615	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(1,070	)	 	(1,264	)	
TOTAL	 	 	585,438	 	 	548,597	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	2,579,046	 	$	2,355,464	 	

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	36,860	 	$	57,893	 	$	37,542	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	87,543	 	 	86,762	 	 	89,711	 	
Deferred Income Taxes	 	 	(23,672	)	 	46,342	 	 	22,034	 	
Mark-to-Market of Risk Management Contracts	 	 	(3,737	)	 	557	 	 	(714	)	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(286	)	 	(48,701	)	
Fuel Over/Under Recovery, Net	 	 	101,175	 	 	(108,366	)	 	23,804	 	
Change in Other Noncurrent Assets	 	 	23,117	 	 	(30,602	)	 	(24,711	)	
Change in Other Noncurrent Liabilities	 	 	(17,920	)	 	8,603	 	 	24,848	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	(32,580	)	 	(33,924	)	 	(37,826	)	
Fuel, Materials and Supplies	 	 	(13,481	)	 	(5,223	)	 	6,731	 	
Margin Deposits	 	 	(25,219	)	 	(7,170	)	 	1,470	 	
Accounts Payable	 	 	3,906	 	 	86,314	 	 	23,535	 	
Customer Deposits	 	 	(2,509	)	 	20,087	 	 	7,210	 	
Accrued Taxes, Net	 	 	4,857	 	 	(8,387	)	 	(8,322	)	
Other Current Assets	 	 	(1,502	)	 	(911	)	 	(715	)	
Other Current Liabilities	 	 	5,529	 	 	16,511	 	 	(4,353	)	
Net Cash Flows From Operating Activities	 	 	142,367	 	 	128,200	 	 	111,543	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(240,238	)	 	(134,358	)	 	(82,618	)	
Change in Other Cash Deposits, Net	 	 	6	 	 	(6	)	 	10,258	 	
Proceeds from Sales of Assets	 	 	226	 	 	-	 	 	458	 	
Net Cash Flows Used For Investing Activities	 	 	(240,006	)	 	(134,364	)	 	(71,902	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	148,695	 	 	74,405	 	 	82,255	 	
Issuance of Long-term Debt - Affiliated	 	 	-	 	 	-	 	 	50,000	 	
Change in Advances from Affiliates, Net	 	 	440	 	 	20,881	 	 	22,138	 	
Retirement of Long-term Debt - Nonaffiliated	 	 	-	 	 	(50,000	)	 	(162,020	)	
Retirement of Long-term Debt - Affiliated	 	 	(50,000	)	 	-	 	 	-	 	
Gain on Reacquired Preferred Stock	 	 	-	 	 	-	 	 	(2	)	
Principal Payments for Capital Lease Obligations	 	 	(1,152	)	 	(668	)	 	(520	)	
Dividends Paid on Common Stock	 	 	-	 	 	(37,000	)	 	(35,000	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(213	)	 	(213	)	 	(213	)	
Net Cash Flows From (Used For) Financing Activities	 	 	97,770	 	 	7,405	 	 	(43,362	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease) in Cash and Cash Equivalents	 	 	131	 	 	1,241	 	 	(3,721	)	
Cash and Cash Equivalents at Beginning of Period	 	 	1,520	 	 	279	 	 	4,000	 	
Cash and Cash Equivalents at End of Period	 	$	1,651	 	$	1,520	 	$	279	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	32,652	 	$	29,607	 	$	32,961	 	
Net Cash Paid (Received) for Income Taxes	 	 	29,879	 	 	(5,244	)	 	2,387	 	
Noncash Acquisitions Under Capital Leases	 	 	3,435	 	 	1,918	 	 	796	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	14,928	 	 	8,495	 	 	2,477	 	

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to PSO’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO.

 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 

 

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Public Service Company of Oklahoma:

We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the “Company”) as of December 31, 2006 and 2005, and the related statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006, and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007

 

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 

 

 

 

 

 

 

 

 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)

 	 	 	2006 	 	 	2005 	 	 	2004 	 	 	2003 	 	 	2002 	 	
STATEMENTS OF INCOME DATA  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Revenues	 	$	1,431,839	 	$	1,405,379	 	$	1,091,072	 	$	1,148,812	 	$	1,085,100	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Income	 	$	189,618	 	$	160,537	 	$	179,239	 	$	203,778	 	$	174,711	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Cumulative Effect of  Accounting Changes	 	$	91,723	 	$	75,190	 	$	89,457	 	$	89,624	 	$	82,992	 	
Cumulative Effect of Accounting  Changes, Net of Tax	 	 	-	 	 	(1,252	)	 	-	 	 	8,517	 	 	-	 	
Net Income	 	$	91,723	 	$	73,938	 	$	89,457	 	$	98,141	 	$	82,992	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEETS DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment	 	$	4,328,247	 	$	4,006,639	 	$	3,892,508	 	$	3,804,600	 	$	3,600,407	 	
Accumulated Depreciation and Amortization	 	 	1,834,145	 	 	1,776,216	 	 	1,710,850	 	 	1,619,178	 	 	1,477,904	 	
Net Property, Plant and Equipment	 	$	2,494,102	 	$	2,230,423	 	$	2,181,658	 	$	2,185,422	 	$	2,122,503	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Assets	 	$	3,190,968	 	$	2,797,347	 	$	2,646,849	 	$	2,581,727	 	$	2,429,366	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Shareholder's Equity	 	$	821,202	 	$	782,378	 	$	768,618	 	$	696,660	 	$	661,769	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	$	4,697	 	$	4,700	 	$	4,700	 	$	4,700	 	$	4,701	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trust Preferred Securities (a)	 	$	-	 	$	-	 	$	-	 	$	-	 	$	110,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt (b)	 	$	729,006	 	$	744,641	 	$	805,369	 	$	884,308	 	$	693,448	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases (b)	 	$	84,715	 (c)	$	42,545	 	$	34,546	 	$	21,542	 	$	-	 	

(a)	See “Trust Preferred Securities” section of Note 15.	
(b)	Including portion due within one year.	
(c)	Increased primarily due to new leases for coal handling equipment.	

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

As a public utility, we engage in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 456,000 retail customers in our service territory in northeastern Texas, northwestern Louisiana and western Arkansas. We consolidate Southwest Arkansas Utilities Corporation and Dolet Hills Lignite Company, LLC, our wholly-owned subsidiaries. We also consolidate Sabine Mining Company, a variable interest entity. As a member of the CSW Operating Agreement with PSO, we share in the revenues and expenses of the members’ sales to neighboring utilities and power marketers. We also sell electric power at wholesale to other utilities, municipalities and electric cooperatives.

Effective May 1, 2006, the FERC approved the removal of TCC and TNC from the CSW Operating Agreement. Under the Texas Restructuring Legislation, TCC and TNC completed the final stage of exiting the generation business and ceased serving retail load. TCC and TNC are no longer involved in the coordinated planning and operation of power supply facilities or share trading and marketing margins, as contemplated by both the CSW Operating Agreement and the SIA. Consequently, our proportionate share of trading and marketing margins increased, although the level of margins depends upon future market conditions. We share these margins with our customers.

Members of the CSW Operating Agreement are compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. We share the revenues and costs for sales to neighboring utilities and power marketers made by AEPSC on our behalf with PSO based upon the relative magnitude of the energy each company provides to make such sales. We share these margins with our customers.

Prior to April 1, 2006, under the SIA, we shared revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management activities among AEP East companies and AEP West companies based on an allocation methodology established at the time of the AEP-CSW merger. Sharing in a calendar year was based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger. This activity resulted in an AEP East companies’ and AEP West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year were also based upon the relative generating capacity of the AEP East companies and AEP West companies in the event the pre-merger activity level was exceeded. The capacity-based allocation mechanism was triggered in July 2005 and 2004, resulting in an allocation factor of approximately 70% and 30% for the AEP East companies and AEP West companies, respectively, for the remainder of each year.

Effective April 1, 2006, we base the allocation methodology of trading and marketing activities upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and us. Margins resulting from other transactions are allocated among the AEP East companies, PSO and us in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months. We expect, due to our generating capacity situation in SPP, a decrease in margins for PSO and us as a result of the SIA change. Our impact will depend upon the level of future trading and marketing margins in SPP and sharing mechanisms with customers for off-system sales margins in Arkansas, Louisiana and Texas. Our results of operations and cash flows for 2006 reflect the new allocation method following the approval of the SIA change.

AEPSC conducts power, gas and coal risk management activities on our behalf. We share in the revenues and expenses associated with these risk management activities with PSO. Power and gas risk management activities are allocated based on the CSW Operating Agreement and the SIA. We share in coal risk management activities based on our proportion of coal burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas and coal. The electricity, gas and coal contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. We settle the majority of the physical forward contracts by entering into offsetting contracts.

Effective January 1, 2007, we locked in our margins on our ERCOT trading and marketing contracts and transferred commodity price risk to AEP Energy Partners, LP (AEPEP), a wholly-owned subsidiary of AEP. This was achieved by a combination of transferring certain existing ERCOT energy marketing contracts to AEPEP and entering into financial and physical purchase and sale agreements with AEPEP. We will not be a party to new contracts in ERCOT. For future periods as the contracts mature, we will realize the fixed margin on the portfolio of ERCOT contracts as it existed on December 31, 2006 and will not be exposed to commodity price risk and resulting earnings variations for these contracts.

We are jointly and severally liable for activity conducted by AEPSC on our behalf and the behalf of AEP East companies and PSO related to power purchase and sale activity pursuant to the SIA.

Results of Operations

2006 Compared to 2005

Reconciliation of Year Ended December 31, 2005 to Year Ended December 31, 2006
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2005	 	 	 	 	$	75	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail and Off-system Sales Margins (a)	 	 	14	 	 	 	 	
Transmission Revenues	 	 	2	 	 	 	 	
Other	 	 	22	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	38	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(11	)	 	 	 	
Taxes Other Than Income Taxes	 	 	4	 	 	 	 	
Interest Expense	 	 	(5	)	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(12	)	
 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	 	 	 	(9	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2006	 	 	 	 	$	92	 	

(a)	Includes firm wholesale sales to municipals and cooperatives.	

Income Before Cumulative Effect of Accounting Change increased $17 million in 2006. The key driver of the increase was a $38 million increase in Gross Margin, partially offset by a $12 million increase in Operating Expenses and Other and a $9 million increase in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail and Off-system Sales Margins increased $14 million primarily due to:	
 	·	A $22 million increase in retail margins primarily due to favorable prices, increased usage and new contracts related to wholesale sales and increased ancillary services, partially offset by:	
 	·	An $8 million decrease in off-system sales margins retained. Total off-system margins decreased $51 million due to decreased physical sales and a decrease in our allocation of off-system sales margins under the SIA, partially offset by $38 million of the decrease flowing through the fuel adjustment clause, and having no impact on Gross Margin, and a $6 million increase in other off-system sales not flowed through the fuel adjustment clause. The change in allocation methodology of the SIA occurred on April 1, 2006. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Agreement” section of Note 4.	
·	Other revenues increased $22 million primarily due to gains on sales of emission allowances.	

Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related expenses.	
·	Taxes Other Than Income Taxes decreased $4 million primarily due to an adjustment to the provision for state sales and use tax in 2006.	
·	Interest Expense increased $5 million primarily due to increased Utility Money Pool borrowings in 2006.	

Income Taxes

Income Tax Expense increased $9 million primarily due to an increase in pretax book income and state income taxes, offset in part, by the recording of the tax return adjustments.

2005 Compared to 2004

Reconciliation of Year Ended December 31, 2004 to Year Ended December 31, 2005
Income Before Cumulative Effect of Accounting Change
(in millions)

Year Ended December 31, 2004	 	 	 	 	$	89	 	
 	 	 	 	 	 	 	 	
Changes in Gross Margin:	 	 	 	 	 	 	 	
Retail and Off-system Sales Margins (a)	 	 	23	 	 	 	 	
Transmission Revenues	 	 	4	 	 	 	 	
Other	 	 	8	 	 	 	 	
Total Change in Gross Margin	 	 	 	 	 	35	 	
 	 	 	 	 	 	 	 	
Changes in Operating Expenses and Other:	 	 	 	 	 	 	 	
Other Operation and Maintenance	 	 	(49	)	 	 	 	
Depreciation and Amortization	 	 	(2	)	 	 	 	
Taxes Other Than Income Taxes	 	 	(3	)	 	 	 	
Other Income	 	 	1	 	 	 	 	
Interest Expense	 	 	4	 	 	 	 	
Total Change in Operating Expenses and Other	 	 	 	 	 	(49	)	
 	 	 	 	 	 	 	 	
Year Ended December 31, 2005	 	 	 	 	$	75	 	

(a)	Includes firm wholesale sales to municipals and cooperatives.	

Income Before Cumulative Effect of Accounting Change decreased $14 million to $75 million in 2005. The key driver of the decrease was a $49 million increase in Other Operation and Maintenance expenses partially offset by a $35 million increase in Gross Margin.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·	Retail and Off-system Sales Margins increased $23 million primarily due to higher wholesale volumes and higher retail sales volumes resulting from a 10% increase in degree days. This was offset by a one-time $9 million refund received in 2004 for purchased capacity. Capacity-related transactions are excluded from fuel adjustment clauses. Therefore, these transactions impact gross margin.	
·	Transmission Revenues increased $4 million primarily due to higher rates within SPP.	
·	Other revenues increased $8 million primarily due to a $4 million increase in pole attachment billings and other miscellaneous revenues.	
 
Operating Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expense increased $49 million. This was primarily due to:	
 	·	A $27 million increase in power plant operation and maintenance during extended planned power plant outages,	
 	·	A $14 million increase in distribution expense, comprised primarily of a $10 million increase in tree trimming and right-of-way clearing and $3 million of storm damage related to hurricanes,	
 	·	A $6 million increase in customer-related expense due to increased collection activities as well as increased factoring expense resulting from higher interest rates and higher volumes of receivables factored.	
·	Taxes Other Than Income Taxes increased $3 million primarily due to higher gross receipts and payroll-related taxes.	
·	Interest Expense decreased $4 million primarily due to decreased long-term debt and decreased interest expense related to fuel recovery.	

Income Taxes

Income Tax expense remained relatively flat in 2005.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 	Moody’s	 	S&P	 	Fitch	
 	 	 	 	 	 	
First Mortgage Bonds	A3	 	A-	 	A	
Senior Unsecured Debt	Baa1	 	BBB	 	A-	

Cash Flow

Cash flows for 2006, 2005 and 2004 were as follows:

 	 	 	2006 	 	 	2005 	 	 	2004 	 	
 	 	 	(in thousands)  	 	
Cash and Cash Equivalents at Beginning of Period	 	$	3,049	 	$	3,715	 	$	6,215	 	
Cash Flows From (Used For):	 	 	 	 	 	 	 	 	 	 	
Operating Activities	 	 	210,136	 	 	208,153	 	 	209,107	 	
Investing Activities	 	 	(323,193	)	 	(115,073	)	 	(65,525	)	
Financing Activities	 	 	112,626	 	 	(93,746	)	 	(146,082	)	
Net Decrease in Cash and Cash Equivalents	 	 	(431	)	 	(666	)	 	(2,500	)	
Cash and Cash Equivalents at End of Period	 	$	2,618	 	$	3,049	 	$	3,715	 	

Operating Activities

Net Cash Flows From Operating Activities were $210 million in 2006. We produced Net Income of $92 million during the period and a noncash expense item of $132 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. Our $74 million inflow related to Fuel Over/Under Recovery, Net was primarily due to the new fuel surcharges effective December 2005 in our Arkansas service territory and in January 2006 in our Texas service territory. The $67 million inflow from Accounts Payable was the result of higher energy purchases. The $52 million outflow from Accounts Receivable, Net was primarily due to an increase in our proportionate share of trading and marketing Accounts Receivable as a result of changes in the CSW Operating Agreement and the SIA. The $40 million outflow from Fuel, Materials and Supplies was the result of increased fuel purchases. The $28 million outflow for Margin Deposits was due to increased trading-related deposits resulting from the amended SIA.

Our Net Cash Flows From Operating Activities were $208 million in 2005. We produced Net Income of $74 million during the period and a noncash expense item of $132 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. The most significant are Accounts Receivable, Accounts Payable, and Customer Deposits, all of which were driven by higher fuel-related costs. Our cash flow related to Fuel Over/Under Recovery, Net was also adversely affected by rising fuel costs. Accounts Receivable increased $28 million due to higher affiliated energy sales. Accounts Payable increased $46 million primarily due to higher energy and fuel-related purchases as well as increased vendor-related payables.

Our Net Cash Flows From Operating Activities were $209 million in 2004. We produced Net Income of $89 million during the period and a noncash expense item of $129 million for Depreciation and Amortization. Pension Contributions to Qualified Plan Trusts were $46 million. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items, the most significant being Accrued Taxes, Fuel, Materials and Supplies, and Accounts Receivable. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Federal income tax payments were made in 2005. The decrease in Fuel and Materials and Supplies was primarily due to lower fuel purchases. Accounts Receivable increased due to higher affiliated energy sales.

Investing Activities

Cash Flows Used For Investing Activities during 2006, 2005 and 2004 were $323 million, $115 million and $66 million, respectively. The cash flows during 2006 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability as well as projects related to new generation facilities. The cash flows during 2005 and 2004 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability offset by Advances to Affiliates.

Financing Activities

Cash Flows From Financing Activities were $113 million during 2006. We had a net increase of $161 million in borrowings from the Utility Money Pool during the fourth quarter. We refinanced (retired and issued) $82 million of Pollution Control Bonds and retired $15 million of long-term debt. We had a net increase in short-term debt of $16 million. In addition, we paid $40 million in common stock dividends.

Cash Flows Used For Financing Activities were $94 million during 2005. During the year, we issued $150 million of Senior Unsecured Notes. Proceeds were used to fund the July 2005 maturity of $200 million of Senior Unsecured Notes. In addition, we had a net increase of $28 million in borrowings from the Utility Money Pool. We paid $55 million in common stock dividends in 2005.

Cash Flows Used For Financing Activities were $146 million during 2004. We retired $120 million of First Mortgage Bonds. Pollution Control Bonds were retired totaling $41 million. During the third quarter of 2004, we issued a Note Payable to AEP for $50 million. We also paid $60 million in common stock dividends in 2004.

Summary Obligation Information

Our contractual obligations include amounts reported on our Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2006:

Payment Due by Period
(in millions)

Contractual Cash Obligations	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Advances from Affiliates (a)	 	$	189.0	 	$	-	 	$	-	 	$	-	 	$	189.0	 	
Short-term Debt (b)	 	 	17.1	 	 	-	 	 	-	 	 	-	 	 	17.1	 	
Interest on Fixed Rate Portion of Long-term  Debt (c)	 	 	27.0	 	 	34.0	 	 	30.0	 	 	48.0	 	 	139.0	 	
Fixed Rate Portion of Long-term Debt (d)	 	 	102.0	 	 	10.0	 	 	56.0	 	 	383.0	 	 	551.0	 	
Variable Rate Portion of Long-term Debt (e)	 	 	-	 	 	-	 	 	41.0	 	 	135.0	 	 	176.0	 	
Capital Lease Obligations (f)	 	 	13.5	 	 	27.5	 	 	17.5	 	 	61.2	 	 	119.7	 	
Noncancelable Operating Leases (f)	 	 	7.4	 	 	12.3	 	 	6.7	 	 	6.1	 	 	32.5	 	
Fuel Purchase Contracts (g)	 	 	347.3	 	 	692.6	 	 	555.6	 	 	2,118.7	 	 	3,714.2	 	
Energy and Capacity Purchase Contracts (h)	 	 	86.4	 	 	184.7	 	 	156.6	 	 	246.8	 	 	674.5	 	
Construction Contracts for Capital Assets (i)	 	 	224.5	 	 	220.0	 	 	-	 	 	1.1	 	 	445.6	 	
Total	 	$	1,014.2	 	$	1,181.1	 	$	863.4	 	$	2,999.9	 	$	6,058.6	 	

(a)	Represents short-term borrowings from the Utility Money Pool.	
(b)	Represents principal only excluding interest.	
(c)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancings, early redemptions or debt issuances.	
(d)	See Note 15. Represents principal only excluding interest.	
(e)	See Note 15. Represents principal only excluding interest. Variable rate debt had interest rates of 3.60% and 5.94% at December 31, 2006.	
(f)	See Note 14.	
(g)	Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.	
(h)	Represents contractual cash flows of energy and capacity purchase contracts.	
(i)	Represents only capital assets that are contractual obligations.	

As discussed in Note 9, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2006 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period
(in millions)

Other Commercial
Commitments	 	Less Than
1 year	 	2-3 years	 	4-5 years	 	After
5 years	 	Total	 	
Standby Letters of Credit (a)	 	$	4	 	$	-	 	$	-	 	$	-	 	$	4	 	
Guarantees of the Performance of Outside Parties (b)	 	 	-	 	 	-	 	 	-	 	 	85	 	 	85	 	
Total	 	$	4	 	$	-	 	$	-	 	$	85	 	$	89	 	

(a)	We have issued standby letters of credit to third parties. These letters of credit cover insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in our ordinary course of business. The maximum future payments of these letters of credit are $4 million maturing in June 2007. There is no recourse to third parties in the event these letters of credit are drawn. See “Letters of Credit” section of Note 6.	
(b)	See “SWEPCo” section of Note 6.	

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. We do, however, assess the probability of loss for such contingencies and accrue a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our regulatory proceedings and pending litigation, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

New Generation

In December 2005, we sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, we announced plans to construct new generation to satisfy the demands of our customers. We will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural gas fired plant at our existing Arsenal Hill Power Plant in Shreveport, Louisiana. We also plan to build a new 600 MW base load coal plant, of which SWEPCo’s investment will be 73%, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of our customers. Preliminary cost estimates for our share of the new facilities are approximately $1.4 billion (this total excludes the related transmission investment and AFUDC). These new facilities are subject to regulatory approvals from our three state commissions. The peaking generation facility at Tontitown, Arkansas has been approved by all three commissions and Units 3 and 4 are projected to be online in July 2007 and the remaining two units by 2008. Construction is expected to begin in 2007 on the intermediate and base load facilities upon approval from the state regulatory commissions. Expenditures related to construction of these facilities are expected to total $349 million in 2007.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our balance sheet as of December 31, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheet
As of December 31, 2006
(in thousands)

 	 	MTM Risk Management Contracts	 	Cash Flow
Hedges	 	Total	 	
Current Assets	 	$	119,560	 	$	476	 	$	120,036	 	
Noncurrent Assets	 	 	20,502	 	 	29	 	 	20,531	 	
Total MTM Derivative Contract Assets	 	 	140,062	 	 	505	 	 	140,567	 	
 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	(105,829	)	 	(3,749	)	 	(109,578	)	
Noncurrent Liabilities	 	 	(14,067	)	 	(16	)	 	(14,083	)	
Total MTM Derivative Contract Liabilities	 	 	(119,896	)	 	(3,765	)	 	(123,661	)	
 	 	 	 	 	 	 	 	 	 	 	
Total MTM Derivative Contract Net Assets (Liabilities)	 	$	20,166	 	$	(3,260	)	$	16,906	 	

MTM Risk Management Contract Net Assets
Year Ended December 31, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	 	$	16,387	 	
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	 	 	(332	)	
Fair Value of New Contracts at Inception When Entered During the Period (a)	 	 	52	 	
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period	 	 	(611	)	
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts	 	 	139	 	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	 	 	(2,003	)	
Changes Due to SIA and CSW Operating Agreement (c)	 	 	11,900	 	
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	 	 	(5,366	)	
Total MTM Risk Management Contract Net Assets	 	 	20,166	 	
Net Cash Flow Hedge Contracts	 	 	(3,260	)	
Total MTM Risk Management Contract Net Assets at December 31, 2006	 	$	16,906	 	

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.	
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.	
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.	
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).	
·	The maturity, by year, of our net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.	

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of December 31, 2006
(in thousands)

 	 	2007	 	2008	 	2009	 	2010	 	2011	 	After
2011	 	Total	 	
Prices Actively Quoted - Exchange  Traded Contracts	 	$	(19,349	)	$	1,909	 	$	(283	)	$	-	 	$	-	 	$	-	 	$	(17,723	)	
Prices Provided by Other External  Sources - OTC Broker Quotes (a)	 	 	33,639	 	 	4,942	 	 	(673	)	 	-	 	 	-	 	 	-	 	 	37,908	 	
Prices Based on Models and Other  Valuation Methods (b)	 	 	(559	)	 	(736	)	 	1,274	 	 	2	 	 	-	 	 	-	 	 	(19	)	
Total	 	$	13,731	 	$	6,115	 	$	318	 	$	2	 	$	-	 	$	-	 	$	20,166	 	

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.	
(b)	“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.	
 	 	
 	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.	

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Consolidated Balance Sheet

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

We use forward contracts and collars as cash flow hedges to lock-in prices on certain transactions denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to December 31, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Year Ended December 31, 2006
(in thousands)

 	 	Power	 	Interest
Rate	 	Foreign
Currency	 	Total	 	
Beginning Balance in AOCI December 31, 2005	 	$	(736	)	$	(5,116	)	$	-	 	$	(5,852	)	
Changes in Fair Value	 	 	-	 	 	(1,858	)	 	25	 	 	(1,833	)	
Impact due to Change in SIA (a)	 	 	592	 	 	-	 	 	-	 	 	592	 	
Reclassifications from AOCI to Net Income for   Cash Flow Hedges Settled	 	 	144	 	 	539	 	 	-	 	 	683	 	
Ending Balance in AOCI December 31, 2006	 	$	-	 	$	(6,435	)	$	25	 	$	(6,410	)	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $755 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the years ended:

December 31, 2006	 	 	 	 	December 31, 2005	
(in thousands)	 	 	 	 	(in thousands)	
End	 	High	 	Average	 	Low	 	 	 	 	End	 	High	 	Average	 	Low	
$447	 	$2,171	 	$794	 	$68	 	 	 	 	$363	 	$604	 	$287	 	$104	

The High VaR for the twelve months ended December 31, 2006 occurred in the fourth quarter due to volatility in the ERCOT region.

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $25 million and $31 million at December 31, 2006 and 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
REVENUES	 	 	 	 	 	 	 	
Electric Generation, Transmission and Distribution	 	$	1,386,653	 	$	1,338,882	 	$	1,018,209	 	
Sales to AEP Affiliates	 	 	42,445	 	 	65,408	 	 	71,190	 	
Other	 	 	2,741	 	 	1,089	 	 	1,673	 	
TOTAL	 	 	1,431,839	 	 	1,405,379	 	 	1,091,072	 	
 	 	 	 	 	 	 	 	 	 	 	
EXPENSES	 	 	 	 	 	 	 	 	 	 	
Fuel and Other Consumables Used for Electric Generation	 	 	471,418	 	 	527,525	 	 	388,380	 	
Purchased Electricity for Resale	 	 	175,124	 	 	133,403	 	 	35,521	 	
Purchased Electricity from AEP Affiliates	 	 	74,458	 	 	70,911	 	 	29,054	 	
Other Operation	 	 	224,750	 	 	213,629	 	 	191,898	 	
Maintenance	 	 	100,962	 	 	101,049	 	 	74,091	 	
Depreciation and Amortization	 	 	132,261	 	 	131,620	 	 	129,329	 	
Taxes Other Than Income Taxes	 	 	63,248	 	 	66,705	 	 	63,560	 	
TOTAL	 	 	1,242,221	 	 	1,244,842	 	 	911,833	 	
 	 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	189,618	 	 	160,537	 	 	179,239	 	
 	 	 	 	 	 	 	 	 	 	 	
Other Income (Expense):	 	 	 	 	 	 	 	 	 	 	
Interest Income	 	 	2,582	 	 	1,499	 	 	1,658	 	
Allowance for Equity Funds Used During Construction	 	 	1,302	 	 	2,394	 	 	781	 	
Interest Expense	 	 	(55,213	)	 	(50,089	)	 	(54,261	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES, MINORITY INTEREST   EXPENSE AND EQUITY 
  EARNINGS	 	 	138,289	 	 	114,341	 	 	127,417	 	
 	 	 	 	 	 	 	 	 	 	 	
Income Tax Expense	 	 	43,697	 	 	34,922	 	 	34,727	 	
Minority Interest Expense	 	 	2,868	 	 	4,226	 	 	3,230	 	
Equity Earnings of Unconsolidated Subsidiaries	 	 	(1	)	 	(3	)	 	(3	)	
 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE CUMULATIVE EFFECT OF   ACCOUNTING CHANGE	 	 	91,723	 	 	75,190	 	 	89,457	 	
 	 	 	 	 	 	 	 	 	 	 	
CUMULATIVE EFFECT OF ACCOUNTING CHANGE,   NET OF TAX	 	 	-	 	 	(1,252	)	 	-	 	
 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	 	91,723	 	 	73,938	 	 	89,457	 	
 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements	 	 	229	 	 	229	 	 	229	 	
 	 	 	 	 	 	 	 	 	 	 	
EARNINGS APPLICABLE TO COMMON STOCK	 	$	91,494	 	$	73,709	 	$	89,228	 	

The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	Common Stock	 	Paid-in Capital	 	Retained Earnings	 	Accumulated Other Comprehensive Income (Loss)	 	Total	 	
DECEMBER 31, 2003	 	$	135,660	 	$	245,003	 	$	359,907	 	$	(43,910	)	$	696,660	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(60,000	)	 	 	 	 	(60,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(229	)	 	 	 	 	(229	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	636,431	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $541	 	 	 	 	 	 	 	 	 	 	 	(1,004	)	 	(1,004	)	
Minimum Pension Liability, Net of Tax  of $23,550	 	 	 	 	 	 	 	 	 	 	 	43,734	 	 	43,734	 	
NET INCOME	 	 	 	 	 	 	 	 	89,457	 	 	 	 	 	89,457	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	132,187	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2004	 	 	135,660	 	 	245,003	 	 	389,135	 	 	(1,180	)	 	768,618	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(55,000	)	 	 	 	 	(55,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(229	)	 	 	 	 	(229	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	713,389	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $2,709	 	 	 	 	 	 	 	 	 	 	 	(5,032	)	 	(5,032	)	
Minimum Pension Liability, Net of Tax   of $44	 	 	 	 	 	 	 	 	 	 	 	83	 	 	
83	 	
NET INCOME	 	 	 	 	 	 	 	 	73,938	 	 	 	 	 	73,938	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	68,989	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DECEMBER 31, 2005	 	 	135,660	 	 	245,003	 	 	407,844	 	 	(6,129	)	 	782,378	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock Dividends	 	 	 	 	 	 	 	 	(40,000	)	 	 	 	 	(40,000	)	
Preferred Stock Dividends	 	 	 	 	 	 	 	 	(229	)	 	 	 	 	(229	)	
TOTAL	 	 	 	 	 	 	 	 	 	 	 	 	 	 	742,149	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Comprehensive Income (Loss),   Net of Taxes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash Flow Hedges, Net of Tax of $515	 	 	 	 	 	 	 	 	 	 	 	(558	)	 	(558	)	
Minimum Pension Liability, Net of Tax  of $35	 	 	 	 	 	 	 	 	 	 	 	65	 	 	65	 	
NET INCOME	 	 	 	 	 	 	 	 	91,723	 	 	 	 	 	91,723	 	
TOTAL COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	 	 	91,230	 	
Minimum Pension Liability Elimination, Net of Tax   of $114	 	 	 	 	 	 	 	 	 	 	 	212	 	 	212	 	
SFAS 158 Adoption, Net of Tax of   $6,671	 	 	 	 	 	 	 	 	 	 	 	(12,389	)	 	(12,389	)	
DECEMBER 31, 2006	 	$	135,660	 	$	245,003	 	$	459,338	 	$	(18,799	)	$	821,202	 	

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2006 and 2005
(in thousands)

 	 	2006	 	2005	 	
CURRENT ASSETS	 	  	 	  	 	
Cash and Cash Equivalents	 	$	2,618	 	$	3,049	 	
Accounts Receivable:	 	 	 	 	 	 	 	
Customers	 	 	88,245	 	 	47,515	 	
Affiliated Companies	 	 	59,679	 	 	49,226	 	
Miscellaneous	 	 	8,595	 	 	7,984	 	
Allowance for Uncollectible Accounts	 	 	(130	)	 	(548	)	
   Total Accounts Receivable	 	 	156,389	 	 	104,177	 	
Fuel	 	 	69,426	 	 	40,333	 	
Materials and Supplies	 	 	46,001	 	 	34,821	 	
Risk Management Assets	 	 	120,036	 	 	47,319	 	
Regulatory Asset for Under-Recovered Fuel Costs	 	 	-	 	 	51,387	 	
Margin Deposits	 	 	41,579	 	 	13,740	 	
Prepayments and Other	 	 	18,256	 	 	20,270	 	
TOTAL	 	 	454,305	 	 	315,096	 	
 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	
Electric:	 	 	 	 	 	 	 	
Production	 	 	1,576,200	 	 	1,513,436	 	
Transmission	 	 	668,008	 	 	645,297	 	
Distribution	 	 	1,228,948	 	 	1,153,026	 	
Other	 	 	595,429	 	 	590,705	 	
Construction Work in Progress	 	 	259,662	 	 	104,175	 	
Total	 	 	4,328,247	 	 	4,006,639	 	
Accumulated Depreciation and Amortization	 	 	1,834,145	 	 	1,776,216	 	
TOTAL - NET	 	 	2,494,102	 	 	2,230,423	 	
 	 	 	 	 	 	 	 	
OTHER NONCURRENT ASSETS	 	 	 	 	 	 	 	
Regulatory Assets	 	 	156,420	 	 	81,776	 	
Long-term Risk Management Assets	 	 	20,531	 	 	39,796	 	
Employee Benefits and Pension Assets	 	 	26,029	 	 	83,330	 	
Deferred Charges and Other	 	 	39,581	 	 	46,926	 	
TOTAL	 	 	242,561	 	 	251,828	 	
 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	3,190,968	 	$	2,797,347	 	

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2006 and 2005

 	 	2006	 	2005	 	
CURRENT LIABILITIES	 	(in thousands)	 	
Advances from Affiliates	 	$	188,965	 	$	28,210	 	
Accounts Payable:	 	 	 	 	 	 	 	
General	 	 	140,424	 	 	71,138	 	
Affiliated Companies	 	 	68,680	 	 	53,019	 	
Short-term Debt - Nonaffiliated	 	 	17,143	 	 	1,394	 	
Long-term Debt Due Within One Year - Nonaffiliated	 	 	102,312	 	 	15,755	 	
Risk Management Liabilities	 	 	109,578	 	 	45,098	 	
Customer Deposits	 	 	48,277	 	 	50,848	 	
Accrued Taxes	 	 	31,591	 	 	42,799	 	
Regulatory Liability for Over-Recovered Fuel Costs	 	 	26,012	 	 	3,181	 	
Other	 	 	85,086	 	 	79,518	 	
TOTAL	 	 	818,068	 	 	390,960	 	
 	 	 	 	 	 	 	 	
NONCURRENT LIABILITIES	 	 	 	 	 	 	 	
Long-term Debt - Nonaffiliated	 	 	576,694	 	 	678,886	 	
Long-term Debt - Affiliated	 	 	50,000	 	 	50,000	 	
Long-term Risk Management Liabilities	 	 	14,083	 	 	27,083	 	
Deferred Income Taxes	 	 	374,548	 	 	409,513	 	
Regulatory Liabilities and Deferred Investment Tax Credits	 	 	346,774	 	 	320,066	 	
Deferred Credits and Other	 	 	183,087	 	 	131,477	 	
TOTAL	 	 	1,545,186	 	 	1,617,025	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES	 	 	2,363,254	 	 	2,007,985	 	
 	 	 	 	 	 	 	 	
Minority Interest	 	 	1,815	 	 	2,284	 	
 	 	 	 	 	 	 	 	
Cumulative Preferred Stock Not Subject to Mandatory Redemption	 	 	4,697	 	 	4,700	 	
 	 	 	 	 	 	 	 	
Commitments and Contingencies (Note 6)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
COMMON SHAREHOLDER’S EQUITY	 	 	 	 	 	 	 	
Common Stock - Par Value - $18 Per Share:	 	 	 	 	 	 	 	
Authorized - 7,600,000 Shares	 	 	 	 	 	 	 	
Outstanding - 7,536,640 Shares	 	 	135,660	 	 	135,660	 	
Paid-in Capital	 	 	245,003	 	 	245,003	 	
Retained Earnings	 	 	459,338	 	 	407,844	 	
Accumulated Other Comprehensive Income (Loss)	 	 	(18,799	)	 	(6,129	)	
TOTAL	 	 	821,202	 	 	782,378	 	
 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	 	$	3,190,968	 	$	2,797,347	 	

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(in thousands)

 	 	2006	 	2005	 	2004	 	
OPERATING ACTIVITIES	 	  	 	  	 	  	 	
Net Income	 	$	91,723	 	$	73,938	 	$	89,457	 	
Adjustments for Noncash Items:	 	 	 	 	 	 	 	 	 	 	
Depreciation and Amortization	 	 	132,261	 	 	131,620	 	 	129,329	 	
Deferred Income Taxes	 	 	(23,667	)	 	(4,942	)	 	12,782	 	
Cumulative Effect of Accounting Change, Net of Tax	 	 	-	 	 	1,252	 	 	-	 	
Mark-to-Market of Risk Management Contracts	 	 	(3,779	)	 	1,140	 	 	(921	)	
Pension Contributions to Qualified Plan Trusts	 	 	-	 	 	(3,450	)	 	(45,688	)	
Change in Other Noncurrent Assets	 	 	29,902	 	 	(27,432	)	 	(20,447	)	
Change in Other Noncurrent Liabilities	 	 	(30,580	)	 	25,625	 	 	36,224	 	
Changes in Certain Components of Working Capital:	 	 	 	 	 	 	 	 	 	 	
Accounts Receivable, Net	 	 	(52,212	)	 	(27,835	)	 	(19,832	)	
Fuel, Materials and Supplies	 	 	(40,273	)	 	6,690	 	 	15,824	 	
Margin Deposits	 	 	(27,839	)	 	(10,321	)	 	1,703	 	
Accounts Payable	 	 	67,452	 	 	45,742	 	 	(2,267	)	
Customer Deposits	 	 	(2,571	)	 	20,298	 	 	6,290	 	
Accrued Taxes, Net	 	 	(11,208	)	 	(2,675	)	 	16,783	 	
   Fuel Over/Under Recovery, Net	 	 	74,218	 	 	 (53,410	) 	 	 12,420	 	
Other Current Assets	 	 	2,134	 	 	2,014	 	 	(845	)	
Other Current Liabilities	 	 	4,575	 	 	29,899	 	 	(21,705	)	
Net Cash Flows From Operating Activities	 	 	210,136	 	 	208,153	 	 	209,107	 	
 	 	 	 	 	 	 	 	 	 	 	
INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Construction Expenditures	 	 	(323,332	)	 	(157,595	)	 	(98,954	)	
Change in Other Cash Deposits, Net	 	 	(120	)	 	3,308	 	 	624	 	
Change in Advances to Affiliates, Net	 	 	-	 	 	39,106	 	 	27,370	 	
Proceeds from Sales of Assets	 	 	259	 	 	108	 	 	5,435	 	
Net Cash Flows Used For Investing Activities	 	 	(323,193	)	 	(115,073	)	 	(65,525	)	
 	 	 	 	 	 	 	 	 	 	 	
FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	
Issuance of Long-term Debt - Nonaffiliated	 	 	80,593	 	 	154,574	 	 	91,999	 	
Issuance of Long-term Debt - Affiliated	 	 	-	 	 	-	 	 	50,000	 	
Change in Short-term Debt, Net - Nonaffiliated	 	 	15,749	 	 	-	 	 	-	 	
Change in Advances from Affiliates, Net	 	 	160,755	 	 	28,210	 	 	-	 	
Retirement of Long-term Debt - Nonaffiliated	 	 	(97,455	)	 	(215,101	)	 	(224,309	)	
Retirement of Cumulative Preferred Stock	 	 	(3	)	 	-	 	 	-	 	
Principal Payments for Capital Lease Obligations	 	 	(6,784	)	 	(6,200	)	 	(3,543	)	
Dividends Paid on Common Stock	 	 	(40,000	)	 	(55,000	)	 	(60,000	)	
Dividends Paid on Cumulative Preferred Stock	 	 	(229	)	 	(229	)	 	(229	)	
Net Cash Flows From (Used For) Financing Activities	 	 	112,626	 	 	(93,746	)	 	(146,082	)	
 	 	 	 	 	 	 	 	 	 	 	
Net Decrease in Cash and Cash Equivalents	 	 	(431	)	 	(666	)	 	(2,500	)	
Cash and Cash Equivalents at Beginning of Period	 	 	3,049	 	 	3,715	 	 	6,215	 	
Cash and Cash Equivalents at End of Period	 	$	2,618	 	$	3,049	 	$	3,715	 	
 	 	 	 	 	 	 	 	 	 	 	
SUPPLEMENTARY INFORMATION	 	 	 	 	 	 	 	 	 	 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	47,610	 	$	43,673	 	$	49,739	 	
Net Cash Paid for Income Taxes	 	 	82,267	 	 	52,756	 	 	11,326	 	
Noncash Acquisitions Under Capital Leases	 	 	48,777	 	 	9,629	 	 	19,687	 	
Construction Expenditures Included in Accounts Payable at December 31,	 	 	27,716	 	 	10,221	 	 	5,475	 	

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to SWEPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.

 	Footnote Reference	
 	 	
Organization and Summary of Significant Accounting Policies	Note 1	
New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Change	Note 2	
Goodwill and Other Intangible Assets	Note 3	
Rate Matters	Note 4	
Effects of Regulation	Note 5	
Commitments, Guarantees and Contingencies	Note 6	
Company-wide Staffing and Budget Review	Note 7	
Benefit Plans	Note 9	
Business Segments	Note 11	
Derivatives, Hedging and Financial Instruments	Note 12	
Income Taxes	Note 13	
Leases	Note 14	
Financing Activities	Note 15	
Related Party Transactions	Note 16	
Property, Plant and Equipment	Note 17	
Unaudited Quarterly Financial Information	Note 18	

 

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
Southwestern Electric Power Company:

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company Consolidated (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion .   An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company   Consolidated as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 9 to the consolidated financial statements, respectively, the Company adopted FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” effective December 31, 2006 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007 

NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:	
 	 	 	
1.	Organization and Summary of Significant Accounting  Policies	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
2.	New Accounting Pronouncements, Extraordinary Items
  and Cumulative Effect of Accounting Change	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
3.	Goodwill and Other Intangible Assets	SWEPCo	
4.	Rate Matters	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
5.	Effects of Regulation	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
6.	Commitments, Guarantees and Contingencies	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
7.	Company-wide Staffing and Budget Review	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
8.	Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	AEGCo, APCo, CSPCo, TCC	
9.	Benefit Plans	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
10.	Nuclear	I&M, TCC	
11.	Business Segments	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
12.	Derivatives, Hedging and Financial Instruments	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
13.	Income Taxes	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
14.	Leases	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
15.	Financing Activities	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
16.	Related Party Transactions	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
17.	Property, Plant and Equipment	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	
18.	Unaudited Quarterly Financial Information	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC	

         1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by nine of AEP’s ten Registrant Subsidiaries is the generation, transmission and distribution of electric power. TCC and TNC are completing the final stage of exiting the generation business. AEGCo is a regulated electricity generation business whose function is to provide power to I&M and KPCo. These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with FERC and other regulatory guidelines. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

With the exception of AEGCo, Registrant Subsidiaries engage in wholesale electricity marketing and risk management activities in the United States. In addition, I&M provides barging services to both affiliated and nonaffiliated companies.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP, AEPSC and its other subsidiaries are regulated by the FERC under the 2005 Public Utility Holding Company Act (2005 PUHCA). AEP’s public utility subsidiaries are regulated by the FERC and state regulatory commissions in the eleven state operating territories. The state regulatory commissions with jurisdiction approve the rates charged and regulate the services and operations of the utility subsidiaries for the generation and supply of power, a majority of transmission energy delivery services and distribution services. The FERC also regulates certain, mostly affiliated, transactions under the 2005 PUHCA.
 
The FERC regulates wholesale power markets and wholesale power transactions. The Registrant Subsidiaries’ wholesale power transactions are generally market-based and are not cost-based regulated unless the Registrant Subsidiaries negotiate and file a cost-based contract with the FERC or the FERC determines that the Registrant Subsidiaries have “market power” in the region in which the transaction is taking place. The Registrant Subsidiaries have wholesale power supply contracts with various municipalities and cooperatives that are FERC regulated, cost-based contracts and wholesale power transactions in the SPP region are all cost-based due to having market power in the SPP region as determined by the FERC. As of December 31, 2006, only SWEPCo, PSO and TNC operate in the SPP region.

The FERC also regulates, on a cost basis, the Registrant Subsidiaries’ wholesale transmission service and rates except in Texas. The FERC has claimed jurisdiction over retail transmission rates when the retail rates are unbundled in connection with restructuring. In Ohio, CSPCo’s and OPCo’s rates are unbundled, therefore their retail transmission rates are based on FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based. Although the retail rates are unbundled in Virginia and Texas, retail transmission rates are still regulated on a cost basis by the state regulatory commissions.

In addition, FERC regulates the East and West Power Pools, East Transmission Equalization Agreement, System Interim Allowance Agreement, and SIA, all of which allocate shared system costs and revenues to the utility subsidiaries that are parties to the agreements.
 
The state regulatory commissions regulate all of the retail public utility operations (generation, transmission and distribution operations) and rates except in states that have enacted restructuring legislation where only transmission and distribution rates are regulated on a cost-basis and unbundled by function. The retail generation/power supply operations and rates are cost-based regulated by the state regulatory commissions except for CSPCo and OPCo in Ohio and APCo in Virginia, which are in transition to market pricing under state restructuring legislation. However, Virginia legislature adopted amendments to its electric restructuring law. If approved, Virginia would return to a form of cost-based regulation. AEP has no Texas jurisdictional retail generation/power supply operations in Texas other than a minor generational supply operation through a commercial and industrial customer REP. See Note 4 for further details of such legislation and its effects on AEP in Ohio, Texas, Virginia and Michigan.
 
In 2004 and 2005, the Registrant Subsidiaries were subject to regulation by the SEC under the Public Utility Holding Company Act of 1935 (1935 PUHCA). The Energy Policy Act of 2005 repealed the 1935 PUHCA effective February 8, 2006 and replaced it with the 2005 PUHCA. With the repeal of the 1935 PUHCA, the SEC no longer has jurisdiction over the activities of registered holding companies, their respective service corporations and their intercompany transactions, which it regulated predominantly at cost. Jurisdiction over holding company-related activities has been transferred to the FERC. Regulation and required reporting under the 2005 PUHCA have been reduced compared to the 1935 PUHCA. However, the FERC has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets, mergers with another electric utility or holding company, inter-company transactions, accounting and AEPSC inter-company service billings which are generally at cost. The inter-company sale of non-power goods and non-AEPSC services to affiliates cannot exceed market under the 2005 PUHCA. The state regulatory commissions in Virginia and West Virginia also regulate certain inter-company transactions under their affiliates statutes.

Both FERC and state regulatory commissions are permitted to review and audit the books and records of any company within a public utility holding company system.

Principles of Consolidation  

The consolidated financial statements for APCo, CSPCo, I&M, OPCo, SWEPCo, TCC and TNC include the registrant and its wholly-owned subsidiaries and/or substantially controlled variable interest entities (VIE). Intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method of accounting; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. OPCo and SWEPCo also consolidate VIEs in accordance with FASB Interpretation Number (FIN) 46 (revised December 2003) “Consolidation of Variable Interest Entities” (FIN 46R) (see “SWEPCo” section of Note 6 and “Gavin Scrubber Financing Arrangement” section of Note 14). CSPCo, OPCo, PSO, SWEPCo, TCC and TNC also have generating units that are jointly-owned with nonaffiliated companies. The proportionate share of the operating costs associated with such facilities is included in the financial statements and the assets and liabilities are reflected in the balance sheets.

Accounting for the Effects of Cost-Based Regulation

As cost-based rate-regulated electric public utility companies, the Registrant Subsidiaries’ financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues. Due to commencement of legislatively required transitions to customer choice and market-based rates, the following Registrant Subsidiaries discontinued the application of SFAS 71, regulatory accounting, for the generation portion of their business as follows: in Ohio for OPCo and CSPCo in September 2000, in Virginia for APCo in June 2000, in Texas for TCC, TNC and the Texas portion of SWEPCo in September 1999. SFAS 101, “Regulated Enterprises - Accounting for the Discontinuance of Application of FASB Statement No. 71” requires the recognition of an impairment of stranded regulatory assets and stranded plants costs if they are not recoverable in regulated rates. Such impairments arising from the discontinuance of SFAS 71 are classified as an extraordinary item. TCC recorded extraordinary impairment losses related to its regulatory assets and plant costs in 2004 and 2005 resulting from the discontinuance of cost-based regulation of its generation businesses without full recovery of the resultant stranded costs.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include but are not limited to inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of the nonregulated operations and investments are stated at their fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are charged to accumulated depreciation. For nonregulated operations, retirements from the plant accounts, net of salvage, are charged to accumulated depreciation and removal costs are charged to expense. The costs of labor, materials and overhead incurred to operate and maintain the plants are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” Equity investments are required to be tested for impairment when it is determined there may be an other than temporary loss in value.

The fair value of an asset and investment is the amount at which that asset and investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. For nonregulated operations including domestic generating assets in Ohio, Texas and Virginia, effective with the discontinuance of SFAS 71 regulatory accounting, interest is capitalized during construction in accordance with SFAS 34, “Capitalization of Interest Costs.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Other Cash Deposits, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability for I&M approximates the best estimate of its fair value.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Other Cash Deposits

Other Cash Deposits include funds held by trustees primarily for the payment of debt and to secure the payments of customers.

Inventory

Fossil fuel inventories are carried at average cost for AEGCo, APCo, I&M, KPCo and SWEPCo. OPCo and CSPCo value fossil fuel inventories at the lower of average cost or market. PSO carries fossil fuel inventories utilizing a LIFO method. TNC carries fossil fuel inventories at the lower of cost or market using a LIFO method. Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized from electric power sales or delivery when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, AEP and certain subsidiaries accrue and recognize, as Accrued Unbilled Revenues, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable for certain subsidiaries, including CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” allowing the receivables to be removed from the company’s balance sheet (see “Sale of Receivables - AEP Credit” section of Note 15).

Concentrations of Credit Risk and Significant Customers

TNC and TCC have significant customers which on a combined basis account for the following percentages of total Operating Revenues for the periods ended and Accounts Receivable - Customers as of December 31:

 	 	2006	 	2005	 	2004	 	
 	 	(in percentage)	 	
TCC -ERCOT and Centrica	 	  	 	  	 	  	 	
Percentage of Operating Revenues	 	 	29	 	 	29	 	 	72	 	
Percentage of Accounts Receivable - Customers	 	 	7	 	 	7	 	 	54	 	
 	 	 	 	 	 	 	 	 	 	 	
TNC -ERCOT, Centrica and City of College Station (2006 only)	 	 	 	 	 	 	 	 	 	 	
Percentage of Operating Revenues	 	 	50	 	 	27	 	 	57	 	
Percentage of Accounts Receivable - Customers	 	 	38	 	 	12	 	 	59	 	

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. Management believes adequate provision for credit loss has been made in the accompanying registrant financial statements.

Deferred Fuel Costs  

The cost of fuel and related chemical and emission allowance consumables are charged to Fuel and Other Consumables Used for Electric Generation Expense when the fuel is burned or the consumable is utilized. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. These deferrals are amortized when refunded or billed to customers in later months with the regulator’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of regulators. On a routine basis, state regulatory commissions audit fuel cost calculations. When a fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their deferrals and record provisions for estimated refunds to recognize these probable outcomes (see Note 4). For TCC & TNC, their deferred fuel balances were included in their True-up Proceedings (see Note 4). Fuel cost over-recovery and under-recovery balances are classified as noncurrent when the fuel clauses have been suspended or terminated as in West Virginia and Texas-ERCOT, respectively.

In general, changes in fuel costs in Kentucky for KPCo, Michigan for I&M, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia and West Virginia for APCo are reflected in rates in a timely manner through the fuel cost adjustment clauses in place in those states. All or a portion of profits from off-system sales are shared with customers through fuel clauses in Texas (SPP area only), Oklahoma, Louisiana, Arkansas, Kentucky, West Virginia (beginning July 1, 2006) and in some areas of Michigan. Where fuel clauses have been eliminated due to the transition to market pricing (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002), changes in fuel costs impact earnings unless recovered in the sales price for electricity. In other state jurisdictions, (Indiana and prior to July 1, 2006 in West Virginia) where fuel clauses have been capped, frozen or suspended for a period of years, fuel costs impact earnings. The Indiana fuel clause suspension ends June 30, 2007. In West Virginia, deferred fuel accounting for over- or under-recovery began July 1, 2006.

Revenue Recognition

Regulatory Accounting

The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, CSPCo, OPCo, SWEPCo, TCC and TNC), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers in cost-based regulated rates. Regulatory liabilities or regulatory assets are also recorded for unrealized MTM gains and losses that occur due to changes in the fair value of physical and financial contracts that are derivatives and that are subject to the regulated ratemaking process when realized.

When regulatory assets are probable of recovery through regulated rates, Registrant Subsidiaries record them as assets on the balance sheet. Registrant Subsidiaries test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the Registrant Subsidiaries write off that regulatory asset as a charge against earnings. A write-off of regulatory assets also reduces future cash flows since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities

Registrant Subsidiaries recognize revenues from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. Registrant Subsidiaries recognize the revenues in the financial statements upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. In general, Registrant Subsidiaries record expenses upon receipt of purchased electricity and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio, Virginia and the ERCOT portion of Texas. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Beginning in July 2004, as a result of the sale of generation assets in AEP’s west zone, AEP’s west zone is short capacity and must purchase physical power to supply retail and wholesale customers. For power purchased under derivative contracts in AEP’s west zone where the AEP West companies are short capacity, prior to settlement, they recognize as Revenues the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period. If the contract results in the physical delivery of power, the Registrant Subsidiaries reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts gross as Purchased Energy for Resale. If the contract does not physically deliver, the Registrant Subsidiaries reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts as Revenues in the financial statements on a net basis (see “Derivatives and Hedging” section of Note 12).

Energy Marketing and Risk Management Activities

All of the Registrant Subsidiaries except AEGCo engage in wholesale electricity, coal and emission allowances marketing and risk management activities focused on wholesale markets where Registrant Subsidiaries own assets. Registrant Subsidiaries’ activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps.

Registrant Subsidiaries recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity. Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow or fair value hedge relationship, or as a normal purchase or sale. The unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in Revenues in the financial statements on a net basis. In jurisdictions subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain wholesale marketing and risk management transactions are designated as hedges of future cash flows as a result of forecasted transactions, a future cash flow (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The gains or losses on derivatives designated as fair value hedges are recognized in Revenues in the financial statements in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged. For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income (Loss) and, depending upon the specific nature of the risk being hedged, subsequently reclassified into Revenues or fuel expenses in the financial statements when the forecasted transaction is realized and affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the financial statements immediately, except in those jurisdictions subject to cost-based regulation. In those regulated jurisdictions the Registrant Subsidiaries defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains) (see “Fair Value Hedging Strategies” and “Cash Flow Hedging Strategies” section of Note 12).

Construction Projects for Outside Parties

TCC and TNC engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue, including the related margin, as project costs are incurred. TCC and TNC include such revenue and related expenses in Other Revenue and Other Operation Expenses, respectively, in the financial statements. TCC and TNC include contractually billable expenses not yet billed in Current Assets in the financial statements.

Levelization of Nuclear Refueling Outage Costs  

In order to match costs with nuclear refueling cycles, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins. I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.

Maintenance

Registrant Subsidiaries expense maintenance costs as incurred. If it becomes probable that Registrant Subsidiaries will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. Maintenance costs during refueling outages at the Cook Plant are deferred and amortized over the period between outages in accordance with rate orders in Indiana and Michigan.

Income Taxes and Investment Tax Credits

Registrant Subsidiaries use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.
 
Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment.

Excise Taxes

Registrant Subsidiaries, as agents for some state and local governments, collect from customers certain excise taxes levied by those state or local governments on customers. Registrant Subsidiaries do not record these taxes as revenue or expense.

Debt and Preferred Stock

Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Some jurisdictions require that these costs be expensed upon reacquisition. We report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Interest Expense.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The amortization expense is included in Interest Expense.

Where reflected in rates, redemption premiums paid to reacquire preferred stock of certain Registrant Subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and reclassified to retained earnings upon the redemption of the entire preferred stock series. The excess of par value over the costs of reacquired preferred stock for nonregulated subsidiaries is credited to retained earnings upon reacquisition.

Goodwill and Intangible Assets

SWEPCo is the only Registrant Subsidiary with an intangible asset with a finite life. SWEPCo amortizes the asset over its estimated life to its residual value (see Note 3). The Registrant Subsidiaries have no recorded goodwill or intangible assets with indefinite lives as of December 31, 2006 and 2005.

Emission Allowances

The Registrant Subsidiaries, except AEGCo, record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. They follow the inventory model for all allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies for all the Registrant Subsidiaries except CSPCo and OPCo, who reflect allowances in Emission Allowances. Allowances with expected consumption beyond one year are included in Other Noncurrent Assets-Deferred Charges and Other. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost. Allowances held for speculation are included in Current Assets-Prepayments and Other for all the Registrant Subsidiaries except CSPCo and OPCo, who reflect allowances in Emission Allowances. The purchases and sales of allowances are reported in the Operating Activities section of the Statements of Cash Flows. The net margin on sales of emission allowances is included in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates Revenues for affiliated transactions because of its integral nature to the production process of energy and the Registrant Subsidiaries revenue optimization strategy for their operations.
 
Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

·	acceptable investments (rated investment grade or above);	
·	maximum percentage invested in a specific type of investment;	
·	prohibition of investment in obligations of the applicable company or its affiliates; and	
·	withdrawals permitted only for payment of decommissioning costs and trust expenses.	

I&M maintains trust funds for each regulatory jurisdiction, which are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification, and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel in Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheet. I&M records these securities at market value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Upon the issuance of FSP 115-1 and 124-1 “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” I&M considers all nuclear decommissioning trust fund and spent nuclear fuel trust fund investments in unrealized loss positions to be other-than-temporary impairments as we do not make specific investment decisions regarding assets held in trusts. Thus, effective in 2006, the other-than-temporary impairments are considered realized losses and will reduce the cost basis of the securities which will affect any future unrealized gain or realized gains or losses. Amounts prior to 2006 were not restated as the other-than-temporary impairments do not affect earnings or AOCI. I&M records unrealized gains and losses from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. See Note 10 for additional discussion of nuclear matters.

Comprehensive Income   (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the balance sheets in the common shareholder’s equity section. Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries as of December 31, 2006 and 2005 is shown in the following table.

 	 	December 31,	 	
 	 	2006	 	2005	 	
 	 	(in thousands)	 	
Components	 	  	 	  	 	
Cash Flow Hedges:	 	  	 	  	 	
APCo	 	$	(2,547	)	$	(16,421	)	
CSPCo	 	 	3,398	 	 	(859	)	
I&M	 	 	(8,962	)	 	(3,467	)	
KPCo	 	 	1,552	 	 	(194	)	
OPCo	 	 	7,262	 	 	755	 	
PSO	 	 	(1,070	)	 	(1,112	)	
SWEPCo	 	 	(6,410	)	 	(5,852	)	
TCC	 	 	-	 	 	(224	)	
TNC	 	 	(702	)	 	(111	)	
 	 	 	 	 	 	 	 	
Minimum Pension Liability:	 	 	 	 	 	 	 	
APCo	 	$	-	 	$	(189	)	
CSPCo	 	 	-	 	 	(21	)	
I&M	 	 	-	 	 	(102	)	
KPCo	 	 	-	 	 	(29	)	
PSO	 	 	-	 	 	(152	)	
SWEPCo	 	 	-	 	 	(277	)	
TCC	 	 	-	 	 	(928	)	
TNC	 	 	-	 	 	(393	)	
 	 	 	 	 	 	 	 	
SFAS 158 Adoption:	 	 	 	 	 	 	 	
APCo	 	$	(52,244	)	$	-	 	
CSPCo	 	 	(25,386	)	 	-	 	
I&M	 	 	(6,089	)	 	-	 	
OPCo	 	 	(64,025	)	 	-	 	
SWEPCo	 	 	(12,389	)	 	-	 	
TNC	 	 	(9,457	)	 	-	 	

Earnings Per Share (EPS)  

AEGCo, APCo, CSPCo, I&M, KPCo and OPCo are wholly-owned subsidiaries of AEP and PSO, SWEPCo, TCC and TNC are owned by a wholly-owned subsidiary of AEP, therefore, none are required to report EPS.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation. These revisions had no impact on the Registrant Subsidiaries’ previously reported results of operations or changes in shareholders’ equity.

On its Consolidated Balance Sheet, SWEPCo reclassified $147 million of mining equipment as of December 31, 2005 from Production to Other within Property, Plant and Equipment.
 
On their statements of income, the Registrant Subsidiaries reclassified regulatory credits related to regulatory asset cost deferral on ARO from Depreciation and Amortization to Other Operation and Maintenance to offset the ARO accretion expense. The following table shows the credits reclassified by the Registrant Subsidiaries in 2005 and 2004:
 	 	Year Ended December 31,	 	
 	 	2005	 	2004	 	
Company	 	(in thousands)	 	
AEGCo	 	$	197	 	$	189	 	
APCo	 	 	912	 	 	831	 	
I&M	 	 	25,008	 	 	14,415	 	
TCC	 	 	4,452	 	 	8,569	 	

         2.   NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine its relevance, if any, to our business. The following represents a summary of new final pronouncements that we have determined relate to our operations.

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

The FASB issued SFAS 123R, requiring entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting.

In 2005, the SEC issued Staff Accounting Bulletin No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued FASB Staff Positions (FSP) that provided additional implementation guidance. The Registrant Subsidiaries applied the principles of SAB 107 and the applicable FSPs in conjunction with their adoption of SFAS 123R in 2006.   The Registrant Subsidiaries adopted SFAS 123R using the modified prospective method without materially affecting their results of operations, cash flows or financial condition.

SFAS 154 “Accounting Changes and Error Corrections” (SFAS 154)

In 2005, the FASB issued SFAS 154. The statement applies to all voluntary changes in accounting principle and changes resulting from adoption of a new accounting pronouncement that do not specify transition requirements. It requires retrospective application to prior periods’ financial statements for changes in accounting principle unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. It also requires that retrospective application of a change in accounting principle should be recognized in the period of the accounting change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 was effective for accounting changes and corrections of errors after January 1, 2006 and is applied as necessary.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. Management expects that the adoption of this standard will impact MTM valuations of certain contracts, but is unable to quantify the effect. Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. The Registrant Subsidiaries will adopt SFAS 157 effective January 1, 2008.

SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

In September 2006, the FASB issued SFAS 158, amending previous standards. It requires employers to fully recognize the obligations associated with defined benefit pension plans and other postretirement employee benefit (OPEB) plans, which include retiree healthcare, in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or OPEB plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to previous standards. It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit or OPEB plan affects net periodic benefit costs for the next fiscal year.

The effect of SFAS 158 is to adjust pretax AOCI at the end of each year, for both underfunded deferred benefit and overfunded pension and OPEB plans, to an amount equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition. The year-end AOCI measure is volatile based on fluctuating investment returns and discount rates. Favorable changes include higher returns that increase plan assets and higher discount rates that reduce the discounted benefit obligation.

The Registrant Subsidiaries adopted SFAS 158 as of December 31, 2006. They recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of their regulated operations that for ratemaking purposes will be deferred for future recovery. The following table shows the incremental effect of this standard on their financial statements versus prior accounting requirements including the additional minimum pension liability provisions of SFAS 87, “Employers’ Accounting for Pensions,” which were replaced by SFAS 158 as follows:

 	 	APCo	 	CSPCo	 	
 	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	
 	 	(in thousands)	 	
Prepaid Benefit Costs	 	$	149,915	 	$	(104,343	)	$	45,572	 	$	127,759	 	$	(92,260	)	$	35,499	 	
Current Accrued Benefit Liability	 	 	-	 	 	(3,781	)	 	(3,781	)	 	-	 	 	(210	)	 	(210	)	
Noncurrent Accrued Benefit Liability	 	 	(17,966	)	 	(96,332	)	 	(114,298	)	 	(3,498	)	 	(41,510	)	 	(45,008	)	
Regulatory Assets	 	 	-	 	 	124,080	 	 	124,080	 	 	-	 	 	94,924	 	 	94,924	 	
Deferred Income Taxes	 	 	110	 	 	28,022	 	 	28,132	 	 	14	 	 	13,656	 	 	13,670	 	
Additional Minimum Liability	 	 	(344	)	 	344	 	 	N/A	 	 	(41	)	 	41	 	 	N/A	 	
Intangible Asset	 	 	31	 	 	(31	)	 	N/A	 	 	2	 	 	(2	)	 	N/A	 	
Net of Tax AOCI Equity Reduction	 	 	203	 	 	52,041	 	 	52,244	 	 	25	 	 	25,361	 	 	25,386	 	
Total	 	$	131,949	 	$	-	 	$	131,949	 	$	124,261	 	$	-	 	$	124,261	 	

 	 	I&M	 	KPCo	 	
 	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	
 	 	(in thousands)	 	
Prepaid Benefit Costs	 	$	78,868	 	$	(51,941	)	$	26,927	 	$	19,056	 	$	(12,428	)	$	6,628	 	
Current Accrued Benefit Liability	 	 	-	 	 	(595	)	 	(595	)	 	-	 	 	-	 	 	-	 	
Noncurrent Accrued Benefit Liability	 	 	(2,094	)	 	(58,504	)	 	(60,598	)	 	(100	)	 	(11,947	)	 	(12,047	)	
Regulatory Assets	 	 	-	 	 	101,673	 	 	101,673	 	 	-	 	 	24,375	 	 	24,375	 	
Deferred Income Taxes	 	 	124	 	 	3,154	 	 	3,278	 	 	-	 	 	-	 	 	-	 	
Additional Minimum Liability	 	 	(400	)	 	400	 	 	N/A	 	 	-	 	 	-	 	 	N/A	 	
Intangible Asset	 	 	45	 	 	(45	)	 	N/A	 	 	-	 	 	-	 	 	N/A	 	
Net of Tax AOCI Equity Reduction	 	 	231	 	 	5,858	 	 	6,089	 	 	-	 	 	-	 	 	-	 	
Total	 	$	76,774	 	$	-	 	$	76,774	 	$	18,956	 	$	-	 	$	18,956	 	

 	 	OPCo	 	PSO	 	
 	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	
 	 	(in thousands)	 	
Prepaid Benefit Costs	 	$	160,400	 	$	(110,708	)	$	49,692	 	$	78,748	 	$	(48,587	)	$	30,161	 	
Current Accrued Benefit Liability	 	 	-	 	 	(237	)	 	(237	)	 	-	 	 	(64	)	 	(64	)	
Noncurrent Accrued Benefit Liability	 	 	(6,408	)	 	(80,284	)	 	(86,692	)	 	(1,238	)	 	(24,552	)	 	(25,790	)	
Regulatory Assets	 	 	-	 	 	92,729	 	 	92,729	 	 	-	 	 	73,203	 	 	73,203	 	
Deferred Income Taxes	 	 	110	 	 	34,365	 	 	34,475	 	 	68	 	 	(68	)	 	-	 	
Additional Minimum Liability	 	 	(398	)	 	398	 	 	N/A	 	 	(201	)	 	201	 	 	N/A	 	
Intangible Asset	 	 	84	 	 	(84	)	 	N/A	 	 	6	 	 	(6	)	 	N/A	 	
Net of Tax AOCI Equity Reduction	 	 	204	 	 	63,821	 	 	64,025	 	 	127	 	 	(127	)	 	-	 	
Total	 	$	153,992	 	$	-	 	$	153,992	 	$	77,510	 	$	-	 	$	77,510	 	

 	 	SWEPCo	 	TCC	 	
 	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	
 	 	(in thousands)	 	
Prepaid Benefit Costs	 	$	78,539	 	$	(52,510	)	$	26,029	 	$	111,889	 	$	(76,315	)	$	35,574	 	
Current Accrued Benefit Liability	 	 	-	 	 	(70	)	 	(70	)	 	-	 	 	(228	)	 	(228	)	
Noncurrent Accrued Benefit Liability	 	 	(1,170	)	 	(26,129	)	 	(27,299	)	 	(2,258	)	 	(28,565	)	 	(30,823	)	
Regulatory Assets	 	 	-	 	 	59,649	 	 	59,649	 	 	-	 	 	105,108	 	 	105,108	 	
Deferred Income Taxes	 	 	114	 	 	6,557	 	 	6,671	 	 	392	 	 	(392	)	 	-	 	
Additional Minimum Liability	 	 	(326	)	 	326	 	 	N/A	 	 	(1,120	)	 	1,120	 	 	N/A	 	
Intangible Asset	 	 	-	 	 	-	 	 	N/A	 	 	-	 	 	-	 	 	N/A	 	
Net of Tax AOCI Equity Reduction	 	 	212	 	 	12,177	 	 	12,389	 	 	728	 	 	(728	)	 	-	 	
Total	 	$	77,369	 	$	-	 	$	77,369	 	$	109,631	 	$	-	 	$	109,631	 	

 	 	TNC	 	
 	 	Before
Application
of
SFAS 158	 	Incremental
Effect	 	After
Application
of
SFAS 158	 	
 	 	(in thousands)	 	
Prepaid Benefit Costs	 	$	45,115	 	$	(32,248	)	$	12,867	 	
Current Accrued Benefit Liability	 	 	-	 	 	(111	)	 	(111	)	
Noncurrent Accrued Benefit Liability	 	 	(1,100	)	 	(11,524	)	 	(12,624	)	
Regulatory Assets	 	 	-	 	 	29,334	 	 	29,334	 	
Deferred Income Taxes	 	 	175	 	 	4,917	 	 	5,092	 	
Additional Minimum Liability	 	 	(500	)	 	500	 	 	N/A	 	
Intangible Asset	 	 	-	 	 	-	 	 	N/A	 	
Net of Tax AOCI Equity Reduction	 	 	325	 	 	9,132	 	 	9,457	 	
Total	 	$	44,015	 	$	-	 	$	44,015	 	

N/A = Not Applicable	

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.

SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. In the event we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted. The statement is applied prospectively upon adoption. We will adopt SFAS 159 effective January 1, 2008.

FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48)

In July 2006, the FASB issued FIN 48. It clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. FIN 48 is effective for fiscal years beginning after December 15, 2006. Although management is in the process of evaluating the impact of FIN 48, management estimates the effect of this interpretation on each of the Registrant Subsidiaries’ financial statements will be an unfavorable adjustment to retained earnings of less than $1 million except for the following:
 
Company	 	 	 	 	(in millions)  	 	
APCo	 	 	 	 	$	7	 	
OPCo	 	 	 	 	 	3	 	
TCC	 	 	 	 	 	2	 	

EITF Issue 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”

This issue focuses on two inventory exchange issues. Purchases or sales of inventory transactions with the same counterparty should be combined under APB Opinion No. 29, “Accounting for Nonmonetary Transactions” if they were entered in contemplation of one another. Nonmonetary exchanges of inventory within the same line of business should be valued at fair value if an entity exchanges finished goods for raw materials or work in progress within the same line of business and if fair value can be determined and the transaction has commercial substance. All other nonmonetary exchanges within the same line of business should be valued at the carrying amount of the inventory transferred. The Registrant Subsidiaries implemented this issue beginning April 1, 2006 without a material impact on their financial statements.

EITF Issue 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF 06-3)

In June 2006, the EITF reached a consensus on the income statement presentation of various types of taxes. The scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes. The presentation of taxes within the scope of this issue on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed. The EITF’s decision on gross/net presentation requires that any such taxes reported on a gross basis be disclosed on an aggregate basis in interim and annual financial statements, for each period for which an income statement is presented, if those amounts are significant.

As disclosed in Note 1, the Registrant Subsidiaries act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on their customers. Their policy is to present these taxes on a net basis. The Registrant Subsidiaries do not recognize these taxes as revenues or expenses. Therefore, this issue did not impact their financial statements.

SAB No. 108 “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements” (SAB 108)

In September 2006, the SEC staff issued SAB 108 addressing diversity in practice when quantifying the effect of an error on financial statements. It provides guidance on the consideration of the effects of prior year misstatements in quantifying misstatements in current year financial statements. The Registrant Subsidiaries’ adoption of SAB 108, effective December 31, 2006, did not have a material impact on their financial statements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including business combinations, revenue recognition, liabilities and equity, derivatives disclosures, leases, insurance, subsequent events and related tax impacts. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on future results of operations and financial position.

EXTRAORDINARY ITEMS

Results for 2005 reflect net adjustments made by TCC to its net true-up regulatory asset for the PUCT’s final order in its True-up Proceeding issued in February 2006. Based on the final order, TCC’s net true-up regulatory asset was reduced by $384 million. Of the $384 million, $345 million ($225 million, net of tax) was recorded as an extraordinary item in accordance with SFAS 101 “Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71” (SFAS 101) and is reflected in Extraordinary Loss on Stranded Cost Recovery, Net of Tax on TCC’s 2005 Consolidated Statement of Operations (see “TCC Texas Restructuring” section of Note 4).

In 2004, as part of its True-up Proceeding, TCC made net adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset related to its transition to retail competition. TCC recorded this adjustment as an extraordinary item in accordance with SFAS 101. This adjustment is included in Extraordinary Loss on Stranded Cost Recovery, Net of Tax on TCC’s 2004 Consolidated Statement of Operations.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE

Asset Retirement Obligations

In 2005, certain Registrant Subsidiaries recorded a net of tax loss as a cumulative effect of accounting change for ARO in accordance with FIN 47. The following is a summary by Registrant Subsidiary of the cumulative effect of changes in accounting principles recorded in 2005 for the adoption of FIN 47 (no effect on AEGCo, I&M, KPCo, PSO or TCC):
 	 	FIN 47 Cumulative Effect	 	
 	 	Pretax Loss	 	Net of Tax Loss	 	
Company	 	(in millions)	 	
APCo	 	$	(3.5	)	$	(2.3	)	
CSPCo	 	 	(1.3	)	 	(0.8	)	
OPCo	 	 	(7.0	)	 	(4.6	)	
SWEPCo	 	 	(1.9	)	 	(1.3	)	
TNC	 	 	(13.0	)	 	(8.5	)	

        3.   GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

There is no goodwill carried by any of the Registrant Subsidiaries.

Other Intangible Assets

SWEPCo’s acquired intangible asset subject to amortization is $12.8 million at December 31, 2006 and $15.8 million at December 31, 2005, net of accumulated amortization and is included in Deferred Charges and Other on SWEPCo’s Consolidated Balance Sheets. The amortization life, gross carrying amount and accumulated amortization are:  
 	 	  	 	December 31, 2006	 	December 31, 2005	 	
 	 	  Amortization Life	 	Gross Carrying Amount	 	Accumulated Amortization	 	Gross Carrying Amount	 	Accumulated Amortization	 	
 	 	  (in years)	 	(in millions)	 	(in millions)	 	
Advanced Royalties	 	 	10	 	$	29.4	 	$	16.6	 	$	29.4	 	$	13.6	 	

Amortization of the intangible asset was $3 million per year for 2006, 2005 and 2004. SWEPCo’s estimated total amortization is $3 million per year for 2007 through 2010 and $1 million in 2011, when the asset will be fully amortized with no residual value.

The Registrant Subsidiaries have no intangible assets that are not subject to amortization.

         4.   RATE MATTERS

The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and state commissions. This note is a discussion of pending rate matters, including industry restructuring and customer choice related proceedings, that could materially impact results of operations and cash flows.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans - Affecting CSPCo and OPCo

Ohio restructuring legislation provided for a transition to market pricing for power supply beginning on January 1, 2006. Open access to power suppliers began in Ohio on January 1, 2001 with a five-year transition to market pricing. Under a 2000 PUCO-approved settlement agreement, CSPCo and OPCo (the Ohio companies) froze their rates through December 31, 2005. In accordance with the approved settlement agreement, CSPCo and OPCo amortize their stranded generation-related transition regulatory assets commensurate with recovery through their frozen rates and starting January 1, 2006 through rate riders that expire in 2008 and 2007, respectively. To date, CSPCo and OPCo have lost very few customers to competing suppliers.

In 2005, the PUCO approved Rate Stabilization Plans (RSPs) for the Ohio companies effective January 1, 2006 and ending December 31, 2008, which allow the Ohio companies to increase their generation rates over three years. The approved three-year RSPs provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7% a year, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year to recover governmentally-mandated costs. During 2006 through 2008, the RSPs also allow the Ohio companies to recover regulatory assets for 2004 and 2005 environmental carrying costs and PJM-related administrative costs and congestion costs, net of financial transmission rights (FTR) revenues, related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program.

Pretax earnings increased by $34 million and $76 million, respectively, for CSPCo and OPCo from the RSP rate increases, net of the amortization of RSP regulatory assets. This increase includes the recovery of unrecognized equity carrying costs for 2004 and 2005. At December 31, 2006, CSPCo’s and OPCo’s unrecognized equity costs total $4 million and $25 million, respectively. As of December 31, 2006, the unamortized RSP regulatory assets to be recovered through December 31, 2008 for CSPCo and OPCo were $6 million and $32 million, respectively.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court challenging the RSPs and also arguing there is no POLR obligation the Ohio companies are entitled to recover. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for the Ohio companies and remanded the case to the PUCO for further proceedings. In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continue collecting RSP revenues, amortizing the RSP costs, and realizing and recognizing related equity carrying costs.

In September 2006, the Ohio companies submitted their proposal to the PUCO to provide additional options for customer participation in the electric market. The proposal provides for the recovery of the cost of providing the additional options. In January 2007, the PUCO set a schedule for interested persons to file comments concerning the proposal.

The Ohio Supreme Court did not address any other issues raised on appeal, stating its decision did not preclude the Ohio Consumers’ Counsel from raising those issues in a future appeal. Management believes that the RSP regulatory assets remain probable of recovery and that the Ohio companies will continue to collect RSP revenues.

In January 2007, CSPCo and OPCo filed with the PUCO under the 4% provision of their RSPs to increase their annual generation rates for 2007 by $24 million and $8 million, respectively, to recover governmentally mandated costs.

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. At this time, management is unable to predict whether the Ohio companies will transition to market pricing, whether the RSP will be extended with or without modification, or whether cost-based regulation will be reinstated on January 1, 2009 when the RSP period ends.

Customer Choice Deferrals - Affecting CSPCo and OPCo

As provided in the restructuring settlement agreement approved by the PUCO in 2000, CSPCo and OPCo established regulatory assets for customer choice implementation costs and related carrying costs in excess of $20 million each for recovery in the next general rate filing to change distribution rates after December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo was further deferred until the next distribution rate filing to change rates after the end of the RSP period dated December 31, 2008. Through December 31, 2006, CSPCo and OPCo incurred $49 million and $50 million, respectively, of such costs and established regulatory assets of $25 million and $24 million, respectively, for such costs. CSPCo and OPCo have each not recognized $5 million of equity carrying costs which are not recognizable until collected. Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates.

IGCC Plant - Affecting CSPCo and OPCo

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology. The application proposed three phases of cost recovery associated with the IGCC plant: Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery, or refund, in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power costs. The proposed recoveries in Phases 1 and 2 would be applied against the 4% limit on additional generation rate increases the Ohio companies could request under their RSPs.

In April 2006, the PUCO issued an order authorizing the Ohio companies to implement Phase 1 of the cost recovery proposal. In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over no more than a twelve-month period effective July 1, 2006. Through December 31, 2006, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $6 million of those costs. The Ohio companies are currently recovering the remaining amounts through June 30, 2007. 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, which are assignable to other jurisdictions, 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.

In August 2006, the Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. Management believes that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. Management, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, the Ohio companies could be required to refund Phase I cost-related recoveries.

Transmission Rate Filing - Affecting CSPCo and OPCo

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders for the Ohio companies. The transmission cost recovery riders are subject to an annual true-up process. In May 2006, the PUCO issued an order approving a two-step increase in the transmission cost recovery riders effective April 1, 2006. The Ohio companies implemented the new tariffs in June 2006. They reflect the Ohio companies’ share of the loss of SECA revenues in step one. The step two increase, effective August 1, 2006, reflects the change in the AEP East Zone transmission rate approved by the FERC related to completion of the new Wyoming-Jacksons Ferry 765 kV line.

In October 2006, the Ohio companies filed for initial true-ups under the transmission cost recovery riders. The filings reflect the refund of a regulatory liability, as of September 30, 2006, of $12 million and $16 million for CSPCo and OPCo, respectively, including carrying charges. These refunds were reflected as part of new transmission cost recovery riders, which became effective for 2007. The net effect of the new transmission cost recovery riders is to increase cost recoveries in 2006 over 2005 levels for CSPCo and OPCo by $27 million and $36 million, respectively. CSPCo and OPCo anticipate a favorable net effect in 2007 over 2005 levels of $15 million and $18 million, respectively.

Distribution Service Reliability and Restoration Costs - Affecting CSPCo and OPCo

In December 2003, the Ohio companies entered into a stipulation agreement regarding distribution service reliability. The stipulation agreement covered the years 2004 and 2005 and, among other features, established certain distribution service reliability measures for the Ohio companies to meet. In July 2006, based on a staff report on service reliability and responses filed by the Ohio companies, the PUCO directed the Ohio companies to earmark $10 million for future measures to improve service reliability without recovery. The PUCO further indicated that it will determine where and how to expend the $10 million.

The Ohio companies implemented storm cost recovery riders effective with September 2006 billings, to recover a portion of previously expensed incremental costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. The riders will continue until they have collected the authorized amounts or one year, whichever is shorter.

As a result, at December 31, 2006 CSPCo and OPCo have regulatory assets of $4 million and $3 million, respectively, for these costs.

Distribution Reliability Plan - Affecting CSPCo and OPCo

In January 2006, the Ohio companies initiated a proceeding at the PUCO seeking a new distribution rate rider to fund enhanced distribution reliability programs. In the fourth quarter of 2006, as directed by the PUCO, the Ohio companies filed a proposed enhanced reliability plan. The plan contemplates CSPCo and OPCo recovering approximately $28 million and $43 million, respectively, in additional distribution revenue during an eighteen-month period beginning July 2007. A hearing is scheduled for April 2007. The OCC filed testimony, which argues that the Ohio companies should be required to improve their distribution service reliability with funds from their existing rates. Management is unable to predict the outcome of this proceeding.

Ormet - Affecting CSPCo and OPCo

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load, under a settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties approved by the PUCO in November 2006. The settlement agreement provides for the recovery in 2007 and 2008 by the Ohio companies of the difference between $43 per MWH to be paid by Ormet for power and a market price, if higher. The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient, an increase in RSP generation rates under the additional 4% provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation services is above the industrial RSP generation tariff but below current market prices. In December 2006, the Ohio companies submitted a market price of $47.69 per MWH, which is pending PUCO approval.

Texas Rate Matters

TCC TEXAS RESTRUCTURING - Affecting TCC

TCC’s True-up Proceedings and 2002 Securitization

Texas Restructuring Legislation established customer choice on January 1, 2002 and allowed electric utility companies to file for recovery of securitizable stranded generation plant costs, generation-related regulatory assets and non-securitizable other restructuring true-up items. These recoverable and refundable items were recorded as true-up regulatory assets and liabilities.

In 2002, TCC securitized $797 million to recover most of its stranded generation related regulatory assets. TCC sold its generating units to establish its stranded costs and recorded an impairment loss, which resulted in an additional net true-up regulatory asset recoverable under the Texas Restructuring Legislation. Beginning in 2002, TCC also recorded wholesale capacity auction true-up revenues and debt-related carrying costs on its net true-up regulatory asset, as additional true-up regulatory assets. Unrecognized equity carrying costs of $224 million included in the net stranded generation cost to be securitized will be recognized, as collected through transition charge securitization revenues, over the fourteen-year term of the securitization bonds.

In December 2004, predominately based on a PUCT disallowance of a specific stranded cost item in other true-up proceedings, TCC reduced its true-up regulatory assets.

In February 2006, the PUCT issued an order in TCC’s True-up Proceeding, which determined that TCC’s recoverable net true-up regulatory asset, for both securitizable net stranded generation cost regulatory assets and net other true-up items regulatory liabilities, was $1.475 billion as of September 30, 2005. The order disallowed specific items which included, among other things, a significant portion of TCC’s wholesale capacity auction true-up revenues and a portion of TCC’s stranded costs determined from the sale of the ERCOT generating units. B ased on the PUCT’s order in December 2005, TCC reduced its true-up regulatory asset. The order also identified a reduction in the net recoverable amount, which represented the present value benefit of ADITC and EDFIT related to the plants sold. See “TCC’s 2006 CTC Proceeding” section below.

TCC will recover its PUCT-approved net true-up regulatory asset under the Texas Restructuring Legislation using two mechanisms: (a) by issuing securitization bonds in the amount of its net stranded generation costs and implementing a transition charge (TC) rate rider to collect the bond interest and principal over the term of the bonds and (b) by implementing a competition transition charge (CTC) rate rider credit to refund its net regulatory liability for other true-up items.  

TCC’s 2006 Securitization Proceeding

TCC filed an application in March 2006 requesting recovery through the issuance of securitization bonds of $1.804 billion of PUCT-approved securitizable net stranded generation costs plus subsequent carrying costs through August 31, 2006 and issuance costs. The securitization request excluded TCC’s net true-up regulatory liability for other true-up items, which will be refunded to customers using a CTC rate rider credit. See the “TCC’s 2006 CTC Proceeding” section of this note. The PUCT approved a settlement in June 2006, which reduced the securitizable amount by $77 million and settled several issues and authorized the issuance of securitization bonds of $1.72 billion as of August 31, 2006. TCC issued securitization bonds on October 11, 2006 for $1.74 billion, which included additional issuance and carrying costs through October 11, 2006.

The securitization order provides for TCC to recover the securitization bond principal and related interest expense from customers over the fourteen-year term of the securitization bonds. Beginning in October 2006, the Securitized Transition Asset is amortized based on the ratio of annual transition revenues to total revenues over the fourteen-year TC collection period.

The June 2006 securitization order reduced the amount to be securitized and recovered by the present value of the ADITC and EDFIT benefit identified above in the April 2006 final true-up order. The securitization order also identified the present value cost-of-money benefit generated through the final year the securitization bonds will be outstanding (fourteen years) as an additional reduction. The present value cost-of-money benefit of $315 million resulted from the ADFIT related to the generation assets. However, rather than reducing the amount to be securitized, the PUCT ordered TCC to refund the ADFIT benefit through the CTC. See the “TCC’s 2006 CTC Proceeding” section below for further details.

TCC’s 2006 CTC Proceeding

In June 2006, TCC filed to refund, through a CTC rate rider credit, its net other true-up items and the ADFIT cost-of-money benefit less the present value benefit of ADITC and EDFIT, discussed above. An interim order required that the CTC refund begin in October 2006 pending a final CTC decision. The PUCT issued a final order in December 2006, which required that TCC refund $356 million of other true-up items and $19 million in estimated interest through the CTC over twenty-one months starting in October 2006. The ADFIT cost-of-money benefit of $315 million has a retrospective portion of $75 million which has been expensed and a prospective portion of $240 million which will be amortized to expense over the fourteen-year securitization bond term consistent with the period over which the cost-of-money benefit is generated and computed in the securitization order. The difference between the amount being refunded and the net other true-up regulatory liability of $219 million ($155 million at December 31, 2006) is predominantly due to the inclusion in the CTC refund of the $240 million unrecorded prospective portion of the ADFIT cost-of-money benefit less the $61 million present value benefit of ADITC and EDFIT applied to reduce the amount securitized above plus $42 million of interest through the date of securitization. The $103 million will be deferred pending a final determination of whether a normalization violation would occur. See “Other Texas Restructuring Matters” section below for further details.

TCC will accrue interest expense until its net CTC refund is completed. The interest expense on the net CTC amount is $22 million for the year ended December 31, 2006 and is included in Interest Expense on TCC’s 2006 Consolidated Statement of Income.

Impairment Assessment of Net True-up Regulatory Assets

TCC performed a probability of recovery impairment test on TCC’s recorded net true-up regulatory asset as of September 30, 2006, after receipt of the final securitization order, and again as of December 31, 2006 after receipt of the final CTC order. At both dates, TCC determined that the projected net cash flows from the securitization less the proposed CTC refund would provide more than sufficient net positive cash flows to recover TCC’s recorded net true-up regulatory asset. Accordingly, no impairment was recorded at either date.

At December 31, 2006, TCC’s Consolidated Balance Sheet reflects a securitization bond liability of $2.335 billion of which $595 million is from the initial 2002 securitization, a securitization transition asset of $2.158 billion of which $542 million is from the initial 2002 securitization, and a net true-up regulatory liability for other true-up items of $155 million.

Texas District Court Appeal Proceedings

TCC appealed the PUCT orders seeking relief in both state and federal court on the grounds that the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. The significant items appealed by TCC are:

·	The PUCT ruling that TCC did not comply with the statute and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues,	
·	The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled out of the money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant cost, and	
·	The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation. See “ TCC and TNC Deferred Fuel” and “ TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections below.	

Municipal customers and other intervenors appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final true-up order with two significant exceptions. The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) method to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. However, the District Court did not rule that the carrying cost rate was inappropriate. He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future revenues.

In response to a request by TCC, the District Court judge will hear additional argument on March 22, 2007 regarding use of the ECOM method to value TCC’s nuclear plant stranded cost. TCC anticipates that the final judgment will be entered after that hearing. TCC intends to appeal any final adverse rulings of the District Court regarding these two matters along with certain of the judge’s other preliminary determinations that affirm the PUCT’s decisions. It is possible that the PUCT could also appeal any final adverse rulings regarding these two matters.

Although management cannot predict the ultimate outcome of these preliminary District Court determinations, any future remanded PUCT proceedings or any future court appeals, management concluded it is probable the District Court’s preliminary ruling regarding the use of an ECOM method in lieu of a sales method to determine securitizable stranded cost will not be upheld on appeal. The judge has also determined in his letter ruling that if the sales method is permitted for valuing the nuclear plant, the PUCT improperly reduced stranded costs in connection with the sales process, which could have a materially favorable effect on TCC.

Management also concluded if the District Court’s preliminary carrying cost rate ruling is ultimately remanded to the PUCT for reconsideration, the PUCT could either confirm the existing carrying cost rate or redetermine the rate. If the PUCT changes the rate, it could result in a material adverse change to TCC’s recoverable carrying costs. However, management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

If the District Court judge’s original 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. TCC cannot estimate the amount at this time, but the amount could exceed its Common Shareholder’s Equity at December 31, 2006. If it were finally concluded that the ECOM method must be used to value TCC’s nuclear plant stranded cost, and/or that the PUCT’s rule on carrying costs was invalid, it could, after the PUCT remand decisions, have a substantial adverse impact on future results of operations, cash flows and financial condition.

If TCC ultimately succeeds in its appeals on other than the above two matters, it could have a favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, including their appeals of the two matters discussed above, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.  

OTHER TEXAS RESTRUCTURING MATTERS

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes - Affecting TCC

In TCC’s true-up and securitization orders, the PUCT reduced net regulatory assets and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generation assets for a total reduction of $61 million.
 
TCC filed a request for a private letter ruling with the IRS in June 2005 regarding the permissibility under the IRS rules and regulations of the ADITC and EDFIT reduction proposed by the PUCT. The IRS issued its private letter ruling in May 2006, which stated that the PUCT’s flow-through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. To address the matter, the PUCT agreed to allow TCC to defer an amount of the CTC refund totaling $103 million ($61 million in present value of ADITC and EDFIT associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of the normalization issue.   It is anticipated that if the normalization issue is resolved consistent with the PUCT’s treatment, TCC will then refund $103 million plus additional carrying costs. If such refund is ultimately determined to cause a normalization violation, TCC anticipates it will be permitted to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impacting future results of operations.
 
If a normalization violation occurs, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, which approximates $104 million as of December 31, 2006, and a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows.

TCC and TNC Deferred Fuel - Affecting TCC and TNC

The TCC deferred fuel over-recovery regulatory liability is a component of the other true-up items net regulatory liability refunded through the CTC discussed above. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances. In its final fuel reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation of additional AEP System off-system sales margins under a FERC-approved SIA. Both TCC and TNC appealed the PUCT’s rulings regarding a number of issues in the fuel orders in state court and challenged the jurisdiction of the PUCT over the allocation of off-system sales margin allocations in the federal court. Intervenors also appealed the PUCT’s rulings in state court.
 
In 2006, the Federal District Court issued orders precluding the PUCT from enforcing the off-system sales allocation portion of its ruling in the final TNC and TCC fuel reconciliation proceedings. The Federal court ruled, in both cases, that the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed both Federal District Court decisions to the United States Court of Appeals. In TNC’s case, the Court of Appeals affirmed the District Court’s decision. TCC awaits a ruling in their appeal. If the PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of $16 million and $8 million, respectively, related to the reversal of the regulatory liabilities.

If the PUCT is unsuccessful in the federal court system, it or another interested party may file a complaint at the FERC to address the allocation issue. If a complaint at the FERC results in the PUCT’s decisions being adopted by the FERC, there could be an adverse effect on results of operations and cash flows. An unfavorable FERC ruling may result in a retroactive reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits. Although management cannot predict the ultimate outcome of this federal litigation, management believes that its allocations were in accordance with the then existing FERC-approved SIA.

In January 2007, TCC began refunding as part of the CTC rate rider credit described above, $149 million of its $165 million over-recovered deferred fuel regulatory liability. The remaining $16 million refund relating to the favorable Federal District Court order may be subject to being refunded only upon a successful appeal by the PUCT. See “TNC’s True-up Proceeding” section below for status of TNC’s over-recovered fuel refund.

Excess Earnings - Affecting TCC

In 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. To date, TCC refunded $55 million of excess earnings, including interest, of which $30 million went to the affiliated REP. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. If the Court of Appeals decision is upheld and the refund mechanism is found to be unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered by the PUCT to refund the excess earnings to ultimate customers and (b) whether it will be able to recover the amounts previously refunded to the REP including the REP TCC sold to Centrica. Management is unable to predict the ultimate outcome of this litigation and its effect on future results of operations and cash flows.

TNC’s True-up Proceeding - Affecting TNC

TNC filed with the PUCT in August 2005 to establish a credit rider to refund its $21 million net true-up regulatory liability. In December 2005, that proceeding was suspended, pending a final ruling from TNC’s appeal to the federal court regarding the fuel proceeding (described above). In August 2006, the suspension was lifted and the proceeding resumed. The PUCT approved a settlement that recommended implementing a $13 million interim refund over six months beginning in September 2006 of the net true-up regulatory liability, exclusive of the $8 million federal court fuel issue. TNC is accruing interest expense on the unrefunded balance and will continue to do so until the balance is fully refunded. TNC anticipates a final PUCT decision regarding this proceeding in 2007. The appeals to the state and federal courts are ongoing.

Texas Restructuring - SPP - Affecting TNC and SWEPCo

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo’s and approximately 3% of TNC’s businesses were in SPP. A petition was filed in May 2006 requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) customers and TNC’s facilities and certificated service territory located in the SPP area to SWEPCo. In January 2007, the final regulatory approval was received for the transfers. The transfers were   effective February 2007. The Arkansas Public Service Commission’s approval requires SWEPCo to amend its fuel recovery tariff so that Arkansas customers do not pay the incremental cost of serving the additional load.
 
OTHER TEXAS RATE MATTERS

ERCOT PTB Fuel Factor Appeal - Affecting TCC and TNC

Several parties including the Office of Public Utility Counsel and the cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s respective former affiliated REPs). In 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued in 2005, the Texas Court of Appeals reversed the District Court. The cities appealed the decision to the Supreme Court of Texas, which ordered full briefing. In February 2007, the Supreme Court of Texas denied review. No motions for rehearing have been filed and management believes the matter is now final.

TCC and TNC Energy Delivery Base Rate Filings - Affecting TCC and TNC

TCC and TNC each filed a rate case for recovery of the cost of transmission and distribution energy delivery services (wires) in Texas. TCC and TNC requested $81 million and $25 million in annual increases, respectively. Both requests include a return on common equity of 11.25% and the impact of the expiration of the CSW merger savings rate credits. TCC and TNC expect the new base wires rates to become effective, subject to refund, in the second quarter of 2007 with a decision from the PUCT expected in the third quarter of 2007.

SWEPCo PUCT Staff Review of Earnings - Affecting SWEPCo

In October 2005, the staff of the PUCT reported the results of its review of SWEPCo’s year end 2004 earnings. Based on the staff’s adjustments to the information submitted by SWEPCo, the report indicates that SWEPCo is receiving excess revenues of approximately $15 million. The staff engaged SWEPCo in discussions to reconcile the earnings calculation and to consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo in April 2006 that they would not pursue the matter further.  

SWEPCo Fuel Reconciliation - Texas - Affecting SWEPCo

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations. SWEPCo sought, in the proceedings, to include underrecoveries related to the reconciliation period of $50 million. In January 2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced. The intervenor recommendations ranged from a $10 million to $28 million reduction. In February 2007, the PUCT staff filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million. SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed rebuttal testimony in February 2007. Management is unable to predict the outcome of this proceeding or its effect on future results of operations and cash flows.

Virginia Rate Matters  

Virginia Restructuring - Affecting APCo

In April 2004, the Governor of Virginia signed legislation that extended 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 bundled 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. Under the restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting. Also, under the restructuring law, APCo is deferring incremental environmental generation costs and incremental reliability costs for future recovery and is amortizing portions of such d eferrals commensurate with recovery. See the “APCo Virginia Environmental and Reliability Costs” section below for further details.
 
In February 2007, the Virginia legislature adopted amendments to its electric restructuring law. The amendments would shorten the transition period by two years (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. We are in the process of evaluating the impact of the legislation if it is signed into law.
 
APCo Virginia Environmental and Reliability Costs - Affecting APCo

The amended Virginia Electric Restructuring Act includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred on and after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 1, 2004 through September 30, 2005.

In November 2006, the Virginia SCC issued a final order that rejected the staff’s and the Hearing Examiner’s interpretation of the law, which would have resulted in the inability to record a regulatory asset and would have ultimately prevented APCo from recovering its full incremental E&R costs incurred since July 1, 2004. The order approved an increase in APCo’s rates to recover $21 million of incremental E&R costs previously incurred from July 1, 2004 through September 30, 2005 by means of a surcharge, effective December 1, 2006 through November 30, 2007. As a result, in the fourth quarter of 2006, APCo commenced recovery of the approved E&R rate rider and deferred as a regulatory asset, $60 million of incremental E&R costs incurred from July 1, 2004 through September 30, 2006 based on the Virginia SCC’s order and reversed $11 million of related AFUDC and capitalized interest, thereby increasing pre-tax earnings by $49 million. In addition, APCo has identified but not recognized $10 million of equity carrying costs on incremental E&R capital expenditures, which are not recognizable until collected. The order requires APCo to keep track, for true-up purposes, of base rate and surcharge recoveries of incremental E&R costs on a continuing basis to avoid any double recovery. During 2007, APCo will file for recovery of incremental E&R costs incurred from October 1, 2005 through September 30, 2006. The Virginia base rate case increase implemented October 2, 2006, subject to refund, is currently recovering an ongoing level of incremental E&R costs incurred since September 30, 2006 and as a result, ceased deferring such costs incurred after that date.

APCo Virginia Base Rate Case - Affecting APCo

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%. In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to the fuel factor where they can be trued-up to actual. APCo also proposed to share the off-system sales margins with customers with 40% going to reduce rates and 60% being retained by APCo. This proposed off-system sales fuel rate credit, which is estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in base rate revenues of $198 million. The major components of the $225 million base rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity.

In May 2006, the Virginia SCC issued an order, consistent with Virginia law, placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund. The $198 million base rate increase being collected, subject to refund, includes recovery of incremental E&R costs projected to be incurred during the rate year beginning October 2006. These incremental E&R costs can be deferred and recovery sought through the E&R surcharge mechanism previously discussed if not recovered through base rates. In October 2006, the Virginia SCC staff filed their 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. Management reserved a portion of the revenue subject to refund that in its opinion is not probable of recovery. APCo filed rebuttal testimony in November 2006. Hearings were held in December 2006. APCo expects a ruling during 2007.  Management is unable to predict the ultimate effect of this filing on future revenues, cash flows and financial condition.
 
West Virginia Rate Matters

APCo West Virginia Rate Case - Affecting APCo

In July 2006, the WVPSC approved a settlement agreement reached by APCo and WPCo and the WVPSC staff and intervenors in connection with a West Virginia rate case filed in 2005. The settlement agreement provided for an initial overall increase in rates of $40 million effective July 28, 2006 comprised of:

·	A $50 million increase in Expanded Net Energy Cost (ENEC) for fuel, purchased power expenses, off- system sales credits and other energy-related costs (the ENEC is an expanded form of a fuel clause mechanism which includes all energy-related costs);	
·	A $21 million special construction surcharge providing recovery of the costs of scrubbers and the new Wyoming-Jacksons Ferry 765 kV line to date;	
·	A $16 million general base rate reduction resulting predominantly from a reduction in the return on equity to 10.5% and a $9 million reduction in depreciation expense which affects cash flows but not earnings; and	
·	A $15 million credit to refund a portion of deferred prior over-recoveries of ENEC recorded in regulatory liabilities on APCo’s Consolidated Balance Sheets, which will impact cash flows but not earnings.	

In addition, the agreement provided a mechanism that allows APCo and WPCo to adjust their special construction surcharges annually for the timely recovery in each of the next three years of the incremental cost of ongoing environmental investments in scrubbers at APCo’s Mountaineer and John Amos power plants and the costs of the new Wyoming-Jacksons Ferry 765 kV line. APCo plans to file in March 2007 with the WVPSC for the first adjustment to their special construction surcharge, providing an incremental annual increase of $26 million to be effective July 1, 2007. APCo estimates annual increases in revenues of $13 million effective July 1, 2008 and $16 million effective July 1, 2009, subject to subsequent review by the WVPSC.

Under the settlement, the ENEC mechanism was reinstated effective July 1, 2006 with over/under recovery deferral accounting and annual ENEC proceedings to affect annual rate adjustments for changes in fuel, purchased power costs, off-system sales margins and other energy-related costs beginning in 2007. The settlement provides for the return to customers of the remaining portion of the prior ENEC regulatory liability plus interest at a LIBOR rate (London Interbank Offered Rate) on the unrefunded balance in future ENEC proceedings.

APCo IGCC - Affecting APCo

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer generating station in Mason County, WV. In January 2007, the WVPSC issued an order delaying the Commission’s deadline for issuing an order on the certificate to December 3, 2007. The order also cancels a previously-approved procedural schedule. Through December 31, 2006, APCo deferred pre-construction IGCC costs totaling $10 million.
 
Indiana Rate Matters

I&M Depreciation Study Filing - Affecting I&M

In December 2005, I&M filed a petition with the IURC seeking authorization to revise its book depreciation rates applicable to its electric utility plant in service effective January 1, 2006. An order issued by the IURC in October 2006 did not dispute our revised depreciation accounting rates but, nevertheless, denied I&M’s request to revise its book depreciation rates between base rate cases. In November 2006, I&M filed with the IURC a petition for reconsideration of the October order as well as a notice of appeal to the Indiana Court of Appeals. In January 2007, the IURC denied I&M’s petition for reconsideration.
 
In February 2007, I&M withdrew its appeal of the IURC order and filed a new request with the IURC for approval of the revised book depreciation rates effective January 1, 2007. The filing included a settlement agreement entered into with the Indiana Office of the Utility Consumer Counselor that would provide direct benefits to I&M's customers if new depreciation rates are approved by the IURC. The direct benefits would include a $5 million credit in fuel costs and an approximate $8 million smart metering pilot program. In addition, if the agreement is approved, I&M would initiate a general rate proceeding on or before July 1, 2007 and initiate two studies, one to investigate a general smart metering program and the other to study the market viability of demand side management programs.  Based on the depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. As proposed the book depreciation reduction would increase earnings but would not impact cash flows until rates are revised. I&M requested expeditious review and approval of its filing, but management cannot predict the outcome of the request.

Kentucky Rate Matters

KPCo Rate Filing - Affecting KPCo

In March 2006, the KPSC approved a settlement agreement in KPCo’s 2005 base rate case. The approved agreement provided for a $41 million annual increase in revenues effective March 30, 2006 and the retention of the existing environmental surcharge tariff. No return on equity was specified by the settlement terms except to note that KPCo will use a 10.5% return on equity to calculate the environmental surcharge tariff and AFUDC.

KPCo Environmental Surcharge Filing - Affecting KPCo

In July 2006, KPCo filed for approval of an amended environmental compliance plan and revised tariff to implement an adjusted environmental surcharge. KPCo requested recovery of approximately $2 million of additional revenue in 2007 and an additional $6 million in 2008 for a total of $8 million of additional revenue. In January 2007, the KPSC issued an order approving KPCo’s proposed plan and surcharge.

In November 2006, the Kentucky attorney general and the Kentucky Industrial Utility Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental Surcharge order. In its order, the KPSC approved KPCo’s recovery of its environmental costs at its Big Sandy Plant and its share of environmental costs it incurs as a result of the AEP Power Pool capacity settlement. The KPSC allowed KPCo to recover these FERC-approved allocated costs, via the environmental surcharge, since the KPSC’s first order in the environmental surcharge case in 1997. KPCo presently recovers $7 million a year in environmental surcharge revenues. At this time, management is unable to predict the outcome of this proceeding and its effect on KPCo’s current environmental surcharge revenues or on the January 2007 KPSC order increasing KPCo’s environmental rates.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP West companies

In 2002, PSO under recovered $44 million 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 proposed collection of those reallocated costs over eighteen months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduce its regulatory asset deferral by $2 million. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with their proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from their recommendation.
 
In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. The United States District Court for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling. The United States Court of Appeals for the Fifth Circuit, issued a decision in December 2006 regarding the TNC fuel proceeding that affirmed the United States District Court ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals other than the staff’s original recommendation that PSO be allowed to recover the $42 million over three years and will defend its position. Management believes that if the position taken by the federal courts in the Texas proceeding is applied to PSO’s case, then the OCC should be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party could file a complaint at the FERC alleging the allocation of off-system sales margins adopted by PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies.

In June 2005, the OCC issued an order directing its staff to conduct a prudence review of PSO’s fuel and purchased power practices for the year 2003. The OCC staff filed testimony finding no disallowances in the test year data. The Attorney General of Oklahoma filed testimony stating that they could not determine if PSO’s gas procurement activities were prudent, but did not include a recommended disallowance. However, an intervenor filed testimony in June 2006 proposing the disallowance of $22 million in fuel costs based on a historical review of potential hedging opportunities that he alleges existed during the year. A hearing was held in August 2006 and PSO expects a recommendation from the ALJ in 2007.  

In February 2006, a law was enacted requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served. PSO is subject to the required biennial reviews. In compliance with an OCC order, PSO is required to file its testimony by June 15, 2007. This proceeding will cover the year 2005.

Management cannot predict the outcome of the pending fuel and purchase power reviews or planned future reviews, but believes that PSO’s fuel and purchased power procurement practices and costs are prudent and properly incurred. If the OCC disagrees and disallows fuel or purchased power costs including the unrecovered 2002 reallocation of such costs incurred by PSO, it would have an adverse effect on future results of operations and cash flows.

PSO Rate Filing - Affecting PSO

In November 2006, PSO filed a request to increase base rates $50 million for Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007. PSO seeks a return on equity of 11.75%. PSO also proposed a formula rate plan that, if approved as filed, will permit PSO to defer any unrecovered costs as a result of a revenue deficiency that exceeds 50 basis points of the allowed return on equity for recovery within twelve-months beginning six months after the test year. The formula would enable PSO to recover on a timely basis the cost of its new generation, transmission and distribution construction (including carrying costs during construction), provide the opportunity to achieve the approved return on equity and avoid recording a large amount of AFUDC that would have been recorded during the construction time period. Hearings are scheduled to begin in May 2007.

Louisiana Rate Matters

SWEPCo Louisiana Fuel Inquiry - Affecting SWEPCo

In March 2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into SWEPCo’s fuel and purchased power procurement activities during the period January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s report, which concluded that SWEPCo’s activities were appropriate and did not identify any disallowances or areas for improvement.

SWEPCo Louisiana Compliance Filing - Affecting SWEPCo

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed updated 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, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, based on a proposed 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain ongoing operations and maintenance expense levels. SWEPCo filed rebuttal testimony in October 2006 strongly 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 will file testimony in the first quarter of 2007. Hearings are expected to occur in early 2007. A decision is not expected until mid or late 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ultimately ordered, it would adversely impact future results of operations and cash flows.

Michigan Rate Matters

Michigan Restructuring - Affecting I&M

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Effective on that date, the rates on I&M’s Michigan customers’ bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M’s total base rates in Michigan remain unchanged and reflect cost of service. As of December 31, 2006, none of I&M’s customers elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory. As a result, management concluded that as of December 31, 2006, the requirements to apply SFAS 71 continue to be met since I&M’s rates for generation in Michigan continue to be cost-based regulated.

FERC Rate Matters

RTO Formation/Integration Costs - Affecting APCo, CSPCo, I&M, KPCo and OPCo

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. The AEP East companies deferred unamortized RTO and PJM formation/integration costs were as follows:

 	 	December 31, 2006	 	December 31, 2005	 	
 	 	PJM-Billed Integration Costs	 	Non-PJM Billed Formation/ Integration Costs	 	PJM-Billed Integration Costs	 	Non-PJM Billed Formation/ Integration Costs	 	
Company	 	  (in millions)	 	
APCo	 	$	3.7	 	$	4.7	 	$	4.1	 	$	4.9	 	
CSPCo	 	 	1.5	 	 	1.9	 	 	1.7	 	 	1.9	 	
I&M	 	 	2.9	 	 	3.4	 	 	3.2	 	 	3.7	 	
KPCo	 	 	0.9	 	 	1.1	 	 	1.0	 	 	1.1	 	
OPCo	 	 	4.2	 	 	5.0	 	 	4.7	 	 	5.1	 	

In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs and related carrying costs not billed by PJM in monthly charges from November 1, 2005 through May 31, 2020. The rate, the result of a settlement, will be adjusted each year to collect $2 million on an annualized basis for 175 months. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is approximately 85% of the transmission load in the AEP zone. As a result, the AEP East companies will need to recover the 85% through their retail rates.

In May 2006, the FERC approved a settlement that provides for recovery over a ten-year period of the deferred PJM-billed integration costs, including related carrying charges, of AEP, Commonwealth Edison Company (ComEd) and The Dayton Power and Light Company from all present zones of the PJM region, except the Virginia Electric & Power Company (VEPCo) zone. The net result of the settlement is that the AEP East companies will recover approximately 50% of the deferred PJM-billed integration costs from third parties, and will need to recover the remaining 50% through retail rates.

As a result of recently approved rate increases, CSPCo, OPCo, KPCo and APCo recover the amortization of RTO formation/integration costs billed to the AEP East companies in Ohio, Kentucky, Virginia (subject to refund) and West Virginia. In Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded from recovering its share of the deferred RTO costs until that date or until it can file for a rate increase in Indiana. I&M has not yet filed for recovery in Michigan.

If the Virginia, Indiana or Michigan commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs, it could adversely impact future results of operations and cash flows. In the event of a disallowance, AEP would appeal that decision to the appropriate state or federal courts.

Transmission Rate Proceedings at the FERC - Affecting APCo, CSPCo, I&M, KPCo and OPCo

SECA Revenue Subject to Refund

The AEP East companies eliminated through-and-out transmission service (T&O) revenues in accordance with FERC orders, and collected SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues as follows:

 	 	Year Ended December 31,	 	
 	 	2006 (a)	 	2005	 	2004	 	
Company	 	(in millions)	 	
APCo	 	$	13.4	 	$	52.4	 	$	4.4	 	
CSPCo	 	 	7.9	 	 	28.4	 	 	2.5	 	
I&M	 	 	8.1	 	 	30.4	 	 	2.8	 	
KPCo	 	 	3.2	 	 	12.4	 	 	1.0	 	
OPCo	 	 	10.4	 	 	39.4	 	 	3.5	 	

(a)	Represents revenues through March 31, 2006, when SECA rates expired, and excludes all provisions for refund .	

Approximately $19 million of these recorded SECA revenues billed by PJM were never collected. The AEP East companies filed a motion with the FERC to force payment of these SECA billings.

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 was 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 the unpaid SECA rates must be paid in the recommended reduced amount.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund. The AEP East companies reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. It would also provide insignificant refunds of SECA rates paid by the AEP East companies. Based on the completed settlements and before the issuance of the ALJ’s initial decision, the AEP East companies initially provided a reserve for $22 million in net refunds.

AEP, together with Exelon and DP&L, filed an extensive post hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes that the FERC should reject the initial decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. However, the initial decision is adversely impacting settlement negotiations. As a consequence, an additional $15 million reserve was recorded in December 2006 .  

The AEP East companies provided for net refunds as shown in the following table:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in millions)	 	
APCo	 	$	11.0	 	$	1.0	 	$	-	 	
CSPCo	 	 	6.1	 	 	0.6	 	 	-	 	
I&M	 	 	6.4	 	 	0.6	 	 	-	 	
KPCo	 	 	2.6	 	 	0.2	 	 	-	 	
OPCo	 	 	8.3	 	 	0.8	 	 	-	 	

Although management believes it has meritorious arguments, they cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.

The FERC PJM Regional Transmission Rate Proceeding

At AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway.

Parties to the regional rate proceeding proposed the following rate regimes:

·	AEP/AP proposed a Highway/Byway rate design in which:	
 	·	The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP East companies from users in other zones of PJM.	
 	·	The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.	
·	Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues for AEP East companies than the AEP/AP proposal.	
·	In a competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues for AEP East companies than the AEP/AP proposal.	
·	In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues for AEP East companies than the AEP/AP proposal.	

All of these proposals were challenged by a majority of other transmission owners in the PJM region, who favor continuation of the existing PJM rate design. Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006. The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced. The ALJ found that the Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp rate proposed by the FERC staff to be just and reasonable alternatives and recommended that the FERC staff’s Postage Stamp rate proposal be adopted. The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination. Because the Postage Stamp rate was found to produce greater cost shifts than other proposals, the judge also recommended that the design be phased-in. Without a phase-in, the Postage Stamp method would produce more revenue for AEP East companies than the AEP/AP proposal. The phase-in of Postage Stamp rates would delay the full impact of that result until about 2012.

AEP filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. AEP argued that a phase-in should not be required. Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and a phase-in plan, the revenue collections curtailed by the phase-in should be deferred and paid later with interest. A FERC decision is likely before mid-2007.

To recover these lost T&O and SECA rates, the AEP East companies sought to increase their retail rates in most of their states. The status of such state retail rate proceedings is as follows:

·	In Kentucky, KPCo settled a rate case, which provided for the recovery of their share of the transmission revenue reduction in new rates effective March 30, 2006.	
·	In Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.	
·	In West Virginia, APCo settled a rate case, which provided for the recovery of their share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.	
·	In Virginia, APCo filed a request for revised rates, which includes recovery of their share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.	
·	In Indiana, I&M is precluded by a rate cap from raising their rates until July 1, 2007.	
·	In Michigan, I&M has not filed to seek recovery of the lost transmission revenues.	

The AEP East companies presently recover from retail customers approximately 85% of the reduction in transmission revenues of $128 million a year.

Once approved by the FERC, the favorable impacts of the new regional PJM rate design will flow directly to wholesale customers and to retail customers in West Virginia through the ENEC and to retail customers in Ohio upon PUCO approval of a filing the Ohio companies would make to reflect the new rates in the Transmission Cost Recovery Rider. In Kentucky, Indiana, Virginia and Michigan, the additional transmission revenues can be expected to reduce retail rates in future base rate proceedings.

Management is unable to predict whether the FERC will approve either the ALJ’s decision or another regional rate design. Management believes that the AEP/AP proposal or the Postage Stamp proposal combined with the retail rate recovery discussed above would be an effective replacement for the eliminated T&O and SECA rates. Future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues. The resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates on a timely basis especially in Indiana, where there is a rate freeze until June 30, 2007, and Michigan.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement which allowed increases in our wholesale transmission OATT rates in three steps: first, beginning retroactively on November 1, 2005, second, beginning on April 1, 2006 when the SECA revenues were eliminated and third, beginning on August 1, 2006 when the new Wyoming-Jacksons Ferry 765 kV line went into service. Wholesale transmission revenues increased approximately $23 million in 2006 due to this rate increase. Management estimates that this rate increase will increase wholesale transmission revenues by $35 million in 2007.
 
The AEP East companies’ wholesale transmission revenues approximate increases in 2006 and estimated increases in 2007 are shown in the following table:
 
 	 	Wholesale Transmission Revenues	 	
 	 	2006  	 	2007	 	
Company	 	(in millions)	 	
APCo	 	$	7.0	 	$	10.5	 	
CSPCo	 	 	5.3	 	 	7.9	 	
I&M	 	 	4.4	 	 	7.0	 	
KPCo	 	 	1.7	 	 	2.4	 	
OPCo	 	 	4.2	 	 	6.7	 	
Total	 	$	22.6	 	$	34.5	 	

Calpine Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From SPP - Affecting TNC, PSO and SWEPCo

In April 2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate schedule to charge SPP for reactive power from Calpine’s generating facility. The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCo and, until February 2007, a small portion of TNC operated in SPP. In September 2006, the FERC issued an order reversing an ALJ initial decision, granting Calpine’s request and requiring Calpine to make a compliance filing within 30 days. PSO’s, SWEPCo’s and TNC’s share of this SPP expense could be approximately 90% of the total amount billed by Calpine. Based on this information, in 2006 PSO and SWEPCo recorded a provision, including interest, of $4 million and $5 million, respectively, for the retroactive reactive power liability. AEP requested rehearing at the FERC.

Calpine issued invoices to AEP for service and interest charges from June 2003 through December 2006 totaling $10 million. AEP objected to these invoices, in part, on the basis that Calpine seeks to collect its entire revenue requirement from us, leaving us with the risk of collecting the portion that may be owed by other service providers in the AEP zone of SPP. Meanwhile, in December 2006, SPP filed a new rate schedule. If the new rate schedule is approved, it will be generally applicable throughout SPP for reactive power service. If the FERC accepts the new rate, on a going forward basis from March 2007, AEP will owe an immaterial amount to Calpine for its reactive power production capability. The new tariff compensates generators for the reactive service they actually provide rather than the capability they possess.

Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement - Affecting AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved the proposed methodology effective April 1, 2006 and beyond. The approved allocation methodology for the AEP East companies and AEP West companies is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies, which effectively allowed the AEP West companies to share in PJM and MISO regional margins in the East. In February 2006, AEP filed with the FERC to remove TCC and TNC from the SIA and CSW Operating Agreement because they are in the final stages of exiting the generation business and have already ceased serving retail load. The FERC approved the removal of TCC and TNC from the SIA effective April 1, 2006 and CSW Operating Agreement effective May 1, 2006. The total trading and marketing margins are unaffected by the allocation methodology. The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of expanded net energy fuel clause recovery mechanisms and related off-system sales sharing mechanisms by state.
 
         5.   EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Our regulated businesses’ financial statements are prepared in accordance with the provisions of SFAS 71, as discussed in the “Accounting for the Effects of Cost-Based Regulation” section of Note 1.

Regulatory assets and liabilities are comprised of the following items at December 31:

 	 	TCC	 	TNC	
 	 	2006	 	2005	 	Notes	 	2006	 	2005	 	Notes	
 	 	(in thousands)	
Regulatory Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SFAS 109 Regulatory Asset, Net (Note 13)	 	$	N/A	 	$	20,616	 	(b) (h) (i)	 	$	N/A	 	$	N/A	 	 	
SFAS 158 Regulatory Asset (Notes 2 and 9)	 	 	105,108	 	 	-	 	(a)	 	 	29,334	 	 	-	 	(a)	
Designated for Securitization	 	 	-	 	 	1,435,597	 	(d)	 	 	N/A	 	 	N/A	 	 	
Wholesale Capacity Auction True-up (Note 4)	 	 	-	 	 	76,464	 	(e)	 	 	N/A	 	 	N/A	 	 	
Refunded Excess Earnings (Note 4)	 	 	55,608	 	 	55,461	 	(l)	 	 	N/A	 	 	N/A	 	 	
Other	 	 	32,395	 	 	100,649	 	(c) (i)	 	 	9,068	 	 	9,787	 	(c) (i)	
Total Noncurrent Regulatory Assets	 	$	193,111	 	$	1,688,787	 	 	 	$	38,402	 	$	9,787	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset Removal Costs (Note 17)	 	$	246,115	 	$	231,990	 	(g)	 	$	87,313	 	$	82,639	 	(g)	
Deferred Investment Tax Credits	 	 	104,264	 	 	105,134	 	(a) (k)	 	 	16,157	 	 	17,427	 	(a) (j)	
SFAS 109 Regulatory Liability, Net (Note 13)	 	 	18,453	 	 	N/A	 	(b) (h) (i)	 	 	9,689	 	 	6,828	 	(b) (h) (i)	
CTC Refund	 	 	155,030	 	 	238,582	 	(e)	 	 	12,865	 	 	18,839	 	(f)	
Other	 	 	74,165	 	 	76,437	 	(c) (i)	 	 	13,405	 	 	13,999	 	(c) (i)	
Total Noncurrent Regulatory Liabilities	 	$	598,027	 	$	652,143	 	 	 	$	139,429	 	$	139,732	 	 	

(a)	Amount does not earn a return.	
(b)	Amount effectively earns a return.	
(c)	Amounts are both earning and not earning a return.	
(d)	Amount includes a carrying cost and was included in TCC’s True-up Proceeding and securitized in October 2006. The cost of the securitization bonds will be recovered over a fourteen-year period. Amount is included within Securitized Transition Assets on the Consolidated Balance Sheet for 2006. See “TCC Texas Restructuring” section of Note 4.	
(e)	Net amounts were ordered to be refunded through the CTC. TCC’s net refund began on an interim basis in October 2006. In a final order issued December 2006, the PUCT set the final net refund to be completed by June 2008. CTC refunds for TCC accrue interest until the refunds are completed. See “TCC’s 2006 CTC Proceeding” section of Note 4.	
(f)	The PUCT ordered TNC's CTC refund for the six-month period ending February 2007 and will accrue interest until completed. See “TNC’s True-up Proceeding” section of Note 4.	
(g)	The liability, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.	
(h)	SFAS 109 Regulatory Asset/Liability, Net is presented on the Balance Sheet at net presentation.	
(i)	Recovery/refund period - various periods.	
(j)	Recovery/refund period - up to 16 years.	
(k)	Recovery/refund period - up to 56 years.	
(l)	Recovery method and timing to be determined in future proceeding.	

N/A	= Not Applicable	

 	 	AEGCo	 	APCo	
 	 	2006	 	2005	 	Notes	 	2006	 	2005	 	Notes	
 	 	(in thousands)	
Regulatory Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Current Regulatory Assets -
   Under-recovered Fuel Costs - Virginia	 	$	N/A	 	$	N/A	 	 	 	$	29,526	 	$	30,697	 	(b) (j)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SFAS 109 Regulatory Asset, Net (Note 13)	 	$	N/A	 	$	N/A	 	 	 	$	365,462	 	$	337,544	 	(a) (h) (i)	
Transition Regulatory Assets - Virginia	 	 	N/A	 	 	N/A	 	 	 	 	16,978	 	 	21,223	 	(a) (l)	
SFAS 158 Regulatory Asset (Notes 2 and 9)	 	 	N/A	 	 	N/A	 	 	 	 	124,080	 	 	-	 	(a)	
Environmental and Reliability Costs - Virginia
   (Note 4)	 	 	N/A	 	 	N/A	 	 	 	 	58,375	 	 	24,430	 	(c) (i)	
Unamortized Loss on Reacquired Debt	 	 	4,021	 	 	4,258	 	(b) (p)	 	 	15,435	 	 	17,652	 	(b) (q)	
Other	 	 	1,417	 	 	1,314	 	(a) (i)	 	 	41,823	 	 	56,445	 	(a) (i)	
Total Noncurrent Regulatory Assets	 	$	5,438	 	$	5,572	 	 	 	$	622,153	 	$	457,294	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Current Regulatory Liabilities -
  Over-recovered Fuel Costs - West Virginia	 	$	N/A	 	$	N/A	 	 	 	$	11,196	 	$	-	 	(b) (f) (j)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset Removal Costs	 	$	30,896	 	$	27,640	 	(d)	 	$	200,582	 	$	86,315	 	(d)	
Deferred Investment Tax Credits	 	 	39,285	 	 	42,718	 	(c) (n)	 	 	21,164	 	 	25,723	 	(c) (m)	
SFAS 109 Regulatory Liability, Net (Note 13)	 	 	9,469	 	 	12,331	 	(a) (h) (i)	 	 	N/A	 	 	N/A	 	 	
Over-recovered ENEC Costs	 	 	N/A	 	 	N/A	 	 	 	 	41,395	 	 	52,399	 	(a) (f) (g)	
Other	 	 	-	 	 	-	 	 	 	 	46,583	 	 	36,793	 	(a) (i)	
Total Noncurrent Regulatory Liabilities	 	$	79,650	 	$	82,689	 	 	 	$	309,724	 	$	201,230	 	 	

 	 	CSPCo	 	I&M	
 	 	2006	 	2005	 	Notes	 	2006	 	2005	 	Notes	
 	 	(in thousands)	
Regulatory Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SFAS 109 Regulatory Asset, Net (Note 13)	 	$	17,646	 	$	17,723	 	(a) (h) (i)	 	$	111,035	 	$	118,743	 	(a) (h) (i)	
Transition Regulatory Assets (Note 4)	 	 	97,610	 	 	144,868	 	(a) (k)	 	 	N/A	 	 	N/A	 	 	
SFAS 158 Regulatory Asset (Notes 2 and 9)	 	 	94,924	 	 	-	 	(a)	 	 	101,673	 	 	-	 	(a)	
Cook Nuclear Plant Refueling Outage Levelization	 	 	N/A	 	 	N/A	 	 	 	 	46,864	 	 	22,971	 	(a) (g)	
Other	 	 	88,124	 	 	69,008	 	(a) (i)	 	 	55,233	 	 	80,972	 	(c) (i)	
Total Noncurrent Regulatory Assets	 	$	298,304	 	$	231,599	 	 	 	$	314,805	 	$	222,686	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset Removal Costs (Note 17)	 	$	121,773	 	$	117,942	 	(d)	 	$	293,961	 	$	280,819	 	(d)	
Deferred Investment Tax Credits	 	 	22,952	 	 	25,215	 	(a) (o)	 	 	67,324	 	 	75,077	 	(a) (n)	
Excess ARO for Nuclear Decommissioning (Note 10)	 	 	N/A	 	 	N/A	 	 	 	 	322,746	 	 	271,318	 	(e)	
Other	 	 	34,323	 	 	22,187	 	(c) (i)	 	 	69,371	 	 	82,801	 	(c) (i)	
Total Noncurrent Regulatory Liabilities	 	$	179,048	 	$	165,344	 	 	 	$	753,402	 	$	710,015	 	 	

(a)	Amount does not earn a return.	
(b)	Amount effectively earns a return.	
(c)	A portion of this amount effectively earns a return.	
(d)	The liability, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.	
(e)	This is the cumulative difference in the amount provided through rates and the amount as measured by applying SFAS 143. This amount earns a return, which accrues monthly, and will be paid when the nuclear plant is decommissioned.	
(f)	In July 2006, the WVPSC approved a settlement to activate the ENEC mechanism. See “APCo and WPCo West Virginia Rate Case” section of Note 4. The current portion is recorded in Other on our Consolidated Balance Sheets.	
(g)	Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.	
(h)	SFAS 109 Regulatory Asset/Liability, Net is presented on the Balance Sheet at net presentation.	
(i)	Recovery/refund period - various periods.	
(j)	Recovery/refund period - 1 year.	
(k)	Recovery/refund period - up to 2 years.	
(l)	Recovery/refund period - 4 years.	
(m)	Recovery/refund period - up to 13 years.	
(n)	Recovery/refund period - up to 16 years.	
(o)	Recovery/refund period - up to 18 years.	
(p)	Recovery/refund period - 8 to 19 years.	
(q)	Recovery/refund period - up to 26 years.	

N/A	= Not Applicable	

 	 	KPCo	 	OPCo	
 	 	2006	 	2005	 	Notes	 	2006	 	2005	 	Notes	
 	 	(in thousands)	
Regulatory Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SFAS 109 Regulatory Asset, Net (Note 13)	 	$	100,439	 	$	96,578	 	(a) (g) (h)	 	$	158,545	 	$	159,742	 	(a) (g) (h)	
Transition Regulatory Assets (Note 4)	 	 	N/A	 	 	N/A	 	 	 	 	70,397	 	 	139,632	 	(a) (i)	
SFAS 158 Regulatory Asset (Notes 2 and 9)	 	 	24,375	 	 	-	 	(a)	 	 	92,729	 	 	-	 	(a)	
Other	 	 	11,325	 	 	20,854	 	(c) (h)	 	 	92,509	 	 	98,633	 	(c) (h)	
Total Noncurrent Regulatory Assets	 	$	136,139	 	$	117,432	 	 	 	$	414,180	 	$	398,007	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset Removal Costs (Note 17)	 	$	31,165	 	$	30,291	 	(e)	 	$	111,319	 	$	110,098	 	(e)	
Deferred Investment Tax Credits	 	 	4,356	 	 	5,500	 	(a) (l)	 	 	6,447	 	 	9,416	 	(c) (l)	
Other	 	 	13,588	 	 	21,003	 	(h)	 	 	68,129	 	 	48,978	 	(c) (h)	
Total Noncurrent Regulatory Liabilities	 	$	49,109	 	$	56,794	 	 	 	$	185,895	 	$	168,492	 	 	

 	 	PSO	 	SWEPCo	
 	 	2006	 	2005	 	Notes	 	2006	 	2005	 	Notes	
 	 	(in thousands)	
Regulatory Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Current Regulatory Assets -
   Under-recovered Fuel Costs	 	$	7,557	 	$	108,732	 	(f) (i)	 	$	-	 	$	51,387	 	(f) (i)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SFAS 109 Regulatory Asset, Net (Note 13)	 	$	N/A	 	$	N/A	 	 	 	$	35,495	 	$	38,793	 	(b) (g) (h)	
SFAS 158 Regulatory Asset (Notes 2 and 9)	 	 	73,203	 	 	-	 	(a)	 	 	59,649	 	 	-	 	(a)	
Unrealized Loss on Forward Commitments	 	 	39,597	 	 	18,279	 	(a) (h)	 	 	31,093	 	 	13,922	 	(a) (h)	
Unamortized Loss on Reacquired Debt	 	 	10,451	 	 	12,456	 	(b) (j)	 	 	18,175	 	 	17,973	 	(b) (n)	
Other	 	 	19,654	 	 	19,988	 	(a) (h)	 	 	12,008	 	 	11,088	 	(d) (h)	
Total Noncurrent Regulatory Assets	 	$	142,905	 	$	50,723	 	 	 	$	156,420	 	$	81,776	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Current Regulatory Liabilities -
   Over-recovered Fuel Costs	 	$	N/A	 	$	N/A	 	 	 	$	26,012	 	$	3,181	 	(f) (i)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Asset Removal Costs (Note 17)	 	$	220,286	 	$	212,346	 	(e)	 	$	268,323	 	$	255,920	 	(e)	
Deferred Investment Tax Credits	 	 	26,242	 	 	27,273	 	(a) (m)	 	 	27,022	 	 	31,246	 	(a) (k)	
SFAS 109 Regulatory Liability, Net (Note 13)	 	 	10,706	 	 	12,089	 	(b) (g) (h)	 	 	N/A	 	 	N/A	 	 	
Unrealized Gain on Forward Commitments	 	 	58,350	 	 	32,932	 	(a) (h)	 	 	44,769	 	 	25,213	 	(a) (h)	
Other	 	 	-	 	 	-	 	 	 	 	6,660	 	 	7,687	 	(d) (h)	
Total Noncurrent Regulatory Liabilities	 	$	315,584	 	$	284,640	 	 	 	$	346,774	 	$	320,066	 	 	

(a)	Amount does not earn a return.	
(b)	Amount effectively earns a return.	
(c)	A portion of this amount effectively earns a return.	
(d)	Amounts are both earning and not earning a return.	
(e)	The liability, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.	
(f)	Over/Under-recovered fuel for SWEPCo’s Arkansas and Louisiana jurisdictions does not earn a return. Texas jurisdictional amounts for SWEPCo do earn a return. PSO fuel balances began earning a return in June 2005.	
(g)	SFAS 109 Regulatory Asset/Liability, Net is presented on the Balance Sheet at net presentation.	
(h)	Recovery/refund period - various periods.	
(i)	Recovery/refund period - 1 year.	
(j)	Recovery/refund period - up to 9 years.	
(k)	Recovery/refund period - up to 11 years.	
(l)	Recovery/refund period - up to 13 years.	
(m)	Recovery/refund period - up to 36 years.	
(n)	Recovery/refund period - up to 37 years.	

N/A	= Not Applicable	
 
Merger with CSW

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. The following table summarizes significant merger-related agreements.

Summary of key provisions of Merger Rate Agreements beginning in the third quarter of 2000:

State/Company	Ratemaking Provisions	
Texas - SWEPCo, TCC, TNC	Rate reductions of $221 million over 6 years. In 2006, TCC and TNC requested to have these rate reductions eliminated. See “TCC and TNC Energy Delivery Base Rate Filings” section of Note 4.	
Indiana - I&M	Rate reductions of $67 million over 8 years.	
Michigan - I&M	Customer billing credits of approximately $14 million over 8 years.	
Kentucky - KPCo	Rate reductions of approximately $28 million over 8 years.	
Louisiana - SWEPCo	Rate reductions to share merger savings estimated to be $18 million over 8 years.	

         6.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements.

Potential Losses and Insurance - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

The Registrant Subsidiaries maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from third parties and are in excess of retentions absorbed by the Registrant Subsidiaries. Coverage is generally provided by a combination of a South Carolina domiciled protected-cell captive insurance company together with and/or in addition to various industry mutual and commercial insurance carriers and various Lloyds of London syndicates.

See Note 10 for a discussion of nuclear exposures and related insurance.

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, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.
 
COMMITMENTS

Construction and Commitments   - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. The following table shows the estimated construction expenditures by company for 2007 including announced purchases of gas-fired generating units:

Company	 	(in millions)	 	
AEGCo	 	$	343	 	
APCo	 	 	664	 	
CSPCo	 	 	439	 	
I&M	 	 	252	 	
KPCo	 	 	71	 	
OPCo	 	 	832	 	
PSO	 	 	319	 	
SWEPCo	 	 	537	 	
TCC	 	 	241	 	
TNC	 	 	143	 	

In addition, AEGCo and CSPCo announced the purchase of gas-fired generating units for $325 million and $102 million, 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, weather, legal reviews and the ability to access capital.

Certain Registrant Subsidiaries entered into long-term contracts to acquire fuel for electric generation. The longest fuel contract extends to 2017 for APCo, 2015 for CSPCo, 2014 for I&M, 2009 for KPCo, 2021 for OPCo, 2007 for PSO and 2029 for SWEPCo. The contracts provide for periodic price adjustments and contain various clauses that would release the Registrant Subsidiary from its obligations under certain conditions.

The Registrant Subsidiaries purchase materials, supplies, services and property, plant and equipment under contract as part of their normal course of business. Certain supply contracts contain penalty provisions for early termination. Management does not expect to incur penalty payments under these provisions that would materially affect results of operations, cash flows or financial condition.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

Certain Registrant Subsidiaries have entered into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At December 31, 2006, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from March 2007 to June 2007.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of December 31, 2006, SWEPCo has collected approximately $29 million through a rider for final mine closure costs, which is recorded in Deferred Credits and Other on SWEPCo’s Consolidated Balance Sheets.

SWEPCo is the only customer of Sabine. Sabine charges SWEPCo all its costs which are included in the cost of fuel and passed through SWEPCo’s fuel clause.

Indemnifications and Other Guarantees

Contracts

All of the Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Prior to December 31, 2006, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except TCC. TCC sale agreements include indemnifications with a maximum exposure of $443 million related to the sale price of its generation assets. See “Texas Plants - South Texas Project” section of Note 8. There are no material liabilities recorded for any indemnifications.

AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Operating Lease

Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary has committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2006, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:
 
 	 	 Maximum
Potential Loss	 	
Company	 	(in millions)	 	
APCo	 	$	7	 	
CSPCo	 	 	4	 	
I&M	 	 	5	 	
KPCo	 	 	2	 	
OPCo	 	 	7	 	
PSO	 	 	5	 	
SWEPCo	 	 	6	 	
TCC	 	 	6	 	
TNC	 	 	3	 	

CONTINGENCIES

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA, certain special interest groups and a number of states allege that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The alleged modifications occurred at our generating units over a twenty-year period. A bench trial on the liability issues was held during July 2005. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

The Federal EPA and eight northeastern states each filed an additional complaint containing additional allegations against the Amos and Conesville plants. APCo and CSPCo filed an answer to the northeastern states’ complaint and the Federal EPA’s complaint, denying the allegations and stating their defenses. Cases are also pending that could affect CSPCo’s share of jointly-owned units at Beckjord (12.5% owned), Zimmer (25.4% owned), and Stuart (26% owned) Stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. The Federal EPA also proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded from NSR.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, AEP subsidiaries might have for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If AEP subsidiaries do not prevail, management believes AEP subsidiaries can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity. If any of the AEP subsidiaries are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a response to the complaint in May 2005. A trial in this matter is scheduled for the second quarter of 2007.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, cash flows or financial condition.

Carbon Dioxide (CO 2 ) Public Nuisance Claims - Affecting AEP East Companies and AEP West Companies

In 2004, eight states and the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO 2 emissions from the defendant’s power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The defendants’ motion to dismiss the lawsuits was granted in September 2005. The dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded. Management believes the actions are without merit and intends to defend against the claims.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances at disposal sites. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. At December 31, 2006, APCo and OPCo are each named as a Potentially Responsible Party (PRP) for one site and CSPCo and I&M are each named a PRP for two sites by the Federal EPA. There are nine additional sites for which APCo, CSPCo, I&M, KPCo, OPCo, and SWEPCo have received information requests which could lead to PRP designation. I&M, SWEPCo, TCC and TNC have also been named potentially liable at two sites under state law. In those instances where AEP subsidiaries have been named a PRP or defendant, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on results of operations.

The Registrant Subsidiaries evaluate the potential liability for each Superfund site separately, but several general statements can be made regarding their potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, present estimates do not anticipate material cleanup costs for identified sites for which certain Registrant Subsidiaries have been declared PRPs. If significant cleanup costs were attributed to those Registrant Subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be included in electricity prices.

TEM Litigation - Affecting OPCo

Juniper Capital L.P. (Juniper) constructed and financed AEP’s ownership interest in the nonregulated Plaquemine Cogeneration Facility (the Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP subleased the Facility to the Dow Chemical Company (Dow). AEP sold the Facility in November 2006.
 
Prior to the sale, Dow used a portion of the energy produced by the Facility and sold the excess energy. OPCo agreed to purchase up to approximately 800 MW of such excess energy from Dow for a twenty-year term. OPCo sold the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market until the sale of the Facility. With the sale of the Facility, OPCo terminated its purchase agreement with Dow.

OPCo agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA). Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In September 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleged that TEM breached the PPA, and sought a determination of its rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of OPCo breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In August 2005, a federal judge ruled that TEM had breached the contract and awarded damages to OPCo of $123 million plus prejudgment interest. Any eventual proceeds will be recorded as a gain when received.

In September 2005, TEM posted a $142 million letter of credit as security pending appeal of the judgment. Both parties filed Notices of Appeal with the United States Court of Appeals for the Second Circuit, which heard oral argument on the appeals in December 2006. Management cannot predict the ultimate outcome of this proceeding.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, disputed transportation costs for coal received between July 2000 and the present time. The joint plant remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded provisions for possible loss in 2004, 2005 and 2006. The provision was deferred as a regulatory asset under PSO’s fuel mechanism and immaterially affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.

Coal Transportation Rate Dispute - Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate, determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. At the end of 1991, PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board. In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim. PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court. In August 2006, PSO filed its response, to which BNSF filed its reply. Management continues to work toward mitigating the disputed amounts to the extent possible.

FERC Long-term Contracts - Affecting AEP East Companies and AEP West Companies

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in AEP’s favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the complaint, held that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required that changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. In December 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows. We have asserted claims against certain companies that sold power to us, which we resold to the Nevada utilities, seeking to recover a portion of any amounts we may owe to the Nevada utilities.

     7.   COMPANY-WIDE STAFFING AND BUDGET REVIEW

The following table shows the severance benefits expense recorded in 2005 (primarily in Other Operation and Maintenance) resulting from a company-wide staffing and budget review, including the allocation of approximately $19.2 million of severance benefits expense associated with AEPSC employees among the Registrant Subsidiaries. AEGCo has no employees, but received allocated expenses. Remaining accruals as of December 31, 2005, reflected primarily in Current Liabilities - Other, ranged from $8 thousand to $1.1 million, and were settled by June 30, 2006. Payments and accrual adjustments recorded during 2006 were immaterial.

 	 	Year Ended December 31,
2005	 	
Company	 	(in millions)	 	
AEGCo	 	$	0.3	 	
APCo	 	 	4.5	 	
CSPCo	 	 	2.6	 	
I&M	 	 	4.7	 	
KPCo	 	 	1.1	 	
OPCo	 	 	3.9	 	
PSO	 	 	1.4	 	
SWEPCo	 	 	1.8	 	
TCC	 	 	4.3	 	
TNC	 	 	1.3	 	

        8.   ACQUISITIONS, DISPOSITIONS, ASSET IMPAIRMENTS AND ASSETS HELD FOR SALE

ACQUISITIONS

Acquisitions Anticipated Being Completed During the First Half of 2007

Darby Electric Generating Station - Affecting CSPCo

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the first half of 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.

Lawrenceburg Generating Station - Affecting AEGCo

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2 million. The transaction is contingent on the receipt of various regulatory approvals and is expected to close in the second quarter of 2007. The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW.

2006

None

2005

Waterford Plant - Affecting CSPCo

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC, a subsidiary of PSEG, for the purchase of the Waterford Plant in Waterford, Ohio. The Waterford Plant is a natural gas, combined cycle power plant with a generating capacity of 821 MW. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million.

Monongahela Power Company - Affecting CSPCo

In June 2005, the PUCO ordered CSPCo to explore the purchase of the Ohio service territory of Monongahela Power Company (Monongahela Power), which includes approximately 29,000 customers. In August 2005, AEP agreed to terms of a transaction, which included the transfer of Monongahela Power’s Ohio customer base and the assets, at net book value, that serve those customers to CSPCo. This transaction was completed in December 2005 for approximately $46 million and the assumption of liabilities of approximately $2 million. In addition, CSPCo paid $10 million to compensate Monongahela Power for its termination of certain litigation in Ohio. Therefore, beginning January 1, 2006, CSPCo began serving customers in this additional portion of its service territory. CSPCo’s $10 million payment was recorded as a regulatory asset and will be recovered with a carrying cost from all of CSPCo’s customers over approximately 5 years. Also included in the transaction was a power purchase agreement under which Allegheny Power, Monongahela Power’s parent company, will provide the power requirements of the acquired customers through May 31, 2007.

Ceredo Generating Station - Affecting APCo

In August 2005, APCo signed a purchase and sale agreement with Reliant Energy for the purchase of the Ceredo Generating Station located near Ceredo, West Virginia. The Ceredo Generating Station is a natural gas, simple cycle power plant with a generating capacity of 505 MW. This transaction was completed in December 2005 for $100 million.

2004

None

DISPOSITIONS

2006

None

2005

Texas Plants - South Texas Project - Affecting TCC

In February 2004, TCC signed an agreement to sell its 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, TCC received notice from co-owners of their decisions to exercise their rights of first refusal with terms similar to the original agreement. In September 2004, TCC entered into sales agreements with two of its nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. The sale was completed for approximately $314 million and the assumption of liabilities of $22 million in May 2005 and did not have a significant effect on TCC’s results of operations. The plant did not meet the “component-of-an-entity” criteria because it did not have cash flows that could be clearly distinguished operationally. The plant also did not meet the “component-of-an-entity” criteria for financial reporting purposes because it did not operate individually, but rather as a part of the AEP System which included all of the generation facilities owned by the Registrant Subsidiaries.

2004

Texas Plants - TCC Generation Assets

In relation to the implementation of the Texas Restructuring Legislation, TCC signed an agreement in March 2004 to sell eight natural gas plants, one coal-fired plant and one hydro plant to a nonrelated joint venture. The sale was completed in July 2004 for approximately $428 million, net of adjustments. The sale did not have a significant effect on TCC’s 2004 results of operations.

ASSET IMPAIRMENTS

2006

None

2005

Conesville Units 1 and 2 - Affecting CSPCo

In the third quarter of 2005, following management’s extensive review of the commercial viability of CSPCo’s generation fleet, management committed to a plan to retire CSPCo’s Conesville Units 1 and 2 before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were considered retired as of the third quarter of 2005.

CSPCo recognized a pretax charge of approximately $39 million in 2005 related to its decision to retire the units. The impairment amount is classified in Asset Impairments and Other Related Charges on CSPCo’s 2005 Consolidated Statement of Income.

2004

None

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station - Affecting TCC

In January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004, TCC received notice from the nonaffiliated co-owners announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, TCC entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. Golden Spread challenged these agreements in State District Court in Dallas County. Golden Spread alleges that the Public Utilities Board of the City of Brownsville exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the nonaffiliated co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread in October 2005. TCC and the nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth District at Dallas.
 
In May 2006, the Court of Appeals for the Fifth District at Dallas reversed the trial court’s judgment in favor of Golden Spread and held that the City of Brownsville properly exercised its right of first refusal to acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the matter, which was denied. Golden Spread then appealed to the Supreme Court of Texas and on December 15, 2006, its Petition for review was denied. Various contract claims, between the parties, that were severed from the appeal on the right of first refusal are pending in the District Court of Dallas County.

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville. The sale did not have a significant effect on TCC’s results of operations nor does TCC expect the remaining litigation to have a significant effect on its results of operations.

TCC’s assets related to the Oklaunion Power Station are classified in Assets Held for Sale - Texas Generation Plant on TCC’s Consolidated Balance Sheets at December 31, 2006 and 2005. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by the Registrant Subsidiaries.

The Assets Held for Sale at December 31, 2006 and 2005 are as follows:

 	 	December 31,	 	
Texas Plants (TCC)	 	2006	 	2005	 	
Assets:	 	(in millions)	 	
Other Current Assets	 	$	1	 	$	1	 	
Property, Plant and Equipment, Net	 	 	43	 	 	43	 	
Total Assets Held for Sale - Texas Generation Plant	 	$	44	 	$	44	 	

         9.   BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other postretirement benefit plans sponsored by AEP to provide medical and life insurance benefits for retired employees.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” in 2004. The Medicare subsidy reduced the SFAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service by $202 million contributing to an actuarial gain in 2004. As a result, the tax-free subsidy reduced 2004’s net periodic postretirement benefit cost by a total of $29 million, including $12 million of amortization of the actuarial gain, $4 million of reduced service cost, and $13 million of reduced interest cost on the APBO. The following table provides the reduction in the net periodic postretirement cost for 2004:

	 	Postretirement Benefit Cost Reduction	 	
Company	 	(in thousands)	 	
APCo	 	$	5,208	 	
CSPCo	 	 	2,417	 	
I&M	 	 	3,647	 	
KPCo	 	 	690	 	
OPCo	 	 	4,106	 	
PSO	 	 	1,520	 	
SWEPCo	 	 	1,571	 	
TCC	 	 	1,849	 	
TNC	 	 	770	 	

In December 2006, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented SFAS 158. The effect of this standard on their financial statements was a pretax AOCI adjustment that was partially or fully offset by a SFAS 71 regulatory asset and as applicable a deferred income tax asset resulting in a net of tax AOCI equity reduction. The following table shows their amounts:
 
	 	Total
Adjustment	 	Regulatory
Asset	 	Deferred
Income
Tax	 	AOCI
Equity Reduction	 	
Company	 	(in thousands)	 	
APCo	 	$	204,456	 	$	124,080	 	$	28,132	 	$	52,244	 	
CSPCo	 	 	133,980	 	 	94,924	 	 	13,670	 	 	25,386	 	
I&M	 	 	111,040	 	 	101,673	 	 	3,278	 	 	6,089	 	
KPCo	 	 	24,375	 	 	24,375	 	 	-	 	 	-	 	
OPCo	 	 	191,229	 	 	92,729	 	 	34,475	 	 	64,025	 	
PSO	 	 	73,203	 	 	73,203	 	 	-	 	 	-	 	
SWEPCo	 	 	78,709	 	 	59,649	 	 	6,671	 	 	12,389	 	
TCC	 	 	105,108	 	 	105,108	 	 	-	 	 	-	 	
TNC	 	 	43,883	 	 	29,334	 	 	5,092	 	 	9,457	 	

The following tables provide a reconciliation of the changes in the AEP plans’ projected benefit obligations and fair value of assets over the two-year period ending at the plan’s measurement date of December 31, 2006, and their funded status as of December 31 for each year:

Projected Pension Obligations, Plan Assets, Funded Status as of December 31, 2006 and 2005

 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
 	 	2006	 	2005	 	2006	 	2005	 	
Change in Projected Benefit Obligation	 	(in millions)	 	
Projected Obligation at January 1	 	$	4,347	 	$	4,108	 	$	1,831	 	$	2,100	 	
Service Cost	 	 	97	 	 	93	 	 	39	 	 	42	 	
Interest Cost	 	 	231	 	 	228	 	 	102	 	 	107	 	
Participant Contributions	 	 	-	 	 	-	 	 	21	 	 	20	 	
Actuarial (Gain) Loss	 	 	(293	)	 	191	 	 	(55	)	 	(320	)	
Plan Amendments	 	 	2	 	 	-	 	 	-	 	 	-	 	
Benefit Payments	 	 	(276	)	 	(273	)	 	(112	)	 	(118	)	
Medicare Subsidy Accrued	 	 	-	 	 	-	 	 	(8	)	 	-	 	
Projected Obligation at December 31	 	$	4,108	 	$	4,347	 	$	1,818	 	$	1,831	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in Fair Value of Plan Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair Value of Plan Assets at January 1	 	$	4,143	 	$	3,555	 	$	1,172	 	$	1,093	 	
Actual Return on Plan Assets	 	 	470	 	 	224	 	 	127	 	 	70	 	
Company Contributions	 	 	9	 	 	637	 	 	94	 	 	107	 	
Participant Contributions	 	 	-	 	 	-	 	 	21	 	 	20	 	
Benefit Payments	 	 	(276	)	 	(273	)	 	(112	)	 	(118	)	
Fair Value of Plan Assets at December 31	 	$	4,346	 	$	4,143	 	$	1,302	 	$	1,172	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded Status	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded Status at December 31	 	$	238	 	$	(204	)	$	(516	)	$	(659	)	
Unrecognized Net Transition Obligation	 	 	-	 	 	-	 	 	-	 	 	152	 	
Unrecognized Prior Service Cost (Benefit)	 	 	-	 	 	(9	)	 	-	 	 	5	 	
Unrecognized Net Actuarial Loss	 	 	-	 	 	1,266	 	 	-	 	 	471	 	
Net Asset (Liability) Recognized	 	$	238	 	$	1,053	 	$	(516	)	$	(31	)	
 
Amounts Recognized on AEP’s Balance Sheets as of December 31, 2006 and 2005
 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
 	 	2006	 	2005	 	2006	 	2005	 	
 	 	(in millions)	 	
Employee Benefits and Pension Assets - Prepaid Benefit Costs	 	$	320	 	$	1,099	 	$	-	 	$	-	 	
Other Current Liabilities - Accrued Short-term   Benefit Liability	 	 	(8	)	 	-	 	 	(5	)	 	-	 	
Employee Benefits and Pension Obligations - Accrued
  Long-term Benefit Liability	 	 	(74	)	 	(46	)	 	(511	)	 	(31	)	
Funded Status	 	 	238	 	 	 	 	 	(516	)	 	 	 	
Regulatory Assets	 	 	582	 	 	N/A	 	 	293	 	 	N/A	 	
Deferred Income Taxes	 	 	60	 	 	10	 	 	66	 	 	N/A	 	
Additional Minimum Liability	 	 	N/A	 	 	(35	)	 	N/A	 	 	N/A	 	
Intangible Asset	 	 	N/A	 	 	6	 	 	N/A	 	 	N/A	 	
Accumulated Other Comprehensive Income (Loss), Net of tax	 	 	112	 	 	19	 	 	123	 	 	N/A	 	
Total	 	$	992	 	$	1,053	 	$	(34	)	$	(31	)	

N/A = Not Applicable

SFAS 158 Amounts Recognized in AEP’s Accumulated Other Comprehensive Income (AOCI) as of December 31, 2006
 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
Components	 	(in millions)	 	
Net Actuarial Loss	 	$	759	 	$	354	 	
Prior Service Cost (Credit)	 	 	(5	)	 	4	 	
Transition Obligation	 	 	-	 	 	124	 	
Pretax AOCI	 	$	754	 	$	482	 	
 	 	 	 	 	 	 	 	
Recorded as	 	 	 	 	 	 	 	
Regulatory Assets	 	$	582	 	$	293	 	
Deferred Income Taxes	 	 	60	 	 	66	 	
Net of tax AOCI	 	 	112	 	 	123	 	
Pretax AOCI	 	$	754	 	$	482	 	
 
The Registrant Subsidiaries, where applicable, recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of regulated operations that for ratemaking purposes will be deferred for future recovery.
 
Pension and Other Postretirement Plans’ Assets

The asset allocations for AEP’s pension plans at the end of 2006 and 2005, and the target allocation for 2007, by asset category, are as follows:
 
 	 	Target Allocation	 	Percentage of Plan Assets at Year End	 	
 	 	2007	 	2006	 	2005	 	
Asset Category	 	(in percentage)	 	
Equity Securities	 	 	65	 	 	63	 	 	62	 	
Real Estate	 	 	5	 	 	6	 	 	4	 	
Debt Securities	 	 	28	 	 	26	 	 	25	 	
Cash and Cash Equivalents	 	 	2	 	 	5	 	 	9	 	
Total	 	 	100	 	 	100	 	 	100	 	
 
The asset allocations for AEP’s other postretirement benefit plans at the end of 2006 and 2005, and target allocation for 2007, by asset category, are as follows:

 	 	Target Allocation	 	Percentage of Plan Assets at Year End	 	
 	 	2007	 	2006	 	2005	 	
Asset Category	 	(in percentage)	 	
Equity Securities	 	 	65	 	 	66	 	 	68	 	
Debt Securities	 	 	33	 	 	32	 	 	30	 	
Other	 	 	2	 	 	2	 	 	2	 	
Total	 	 	100	 	 	100	 	 	100	 	

AEP’s investment strategy for the employee benefit trust funds is to use a diversified portfolio of investments to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. To minimize risk, our employee benefit trust funds are broadly diversified among classes of assets, investment strategies and investment managers. We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation when considered appropriate. Our investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. Our investment policies prohibit investment in AEP securities, with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies. Because of the $320 million contribution at the end of 2005 the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2006.

The value of the pension plans’ assets increased to $4.3 billion at December 31, 2006 from $4.1 billion at December 31, 2005. The qualified plans paid $267 million in benefits to plan participants during 2006 (nonqualified plans paid $9 million in benefits). The value of AEP’s Postretirement Plans’ assets increased to $1.3 billion in December 31, 2006 from $1.2 billion at December 31, 2005. The Postretirement Plans paid $112 million in benefits to plan participants during 2006.

AEP bases the determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.

Accumulated Benefit Obligation

 	 	2006	 	2005	 	
 	 	(in millions)	 	
Qualified Pension Plans	 	$	3,861	 	$	4,053	 	
Nonqualified Pension Plans	 	 	78	 	 	81	 	
Total	 	$	3,939	 	$	4,134	 	

For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets of these plans at December 31, 2006 and 2005 were as follows:
 
 	 	Underfunded Pension Plans	 	
 	 	As of December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Projected Benefit Obligation	 	$	82	 	$	84	 	
 	 	 	 	 	 	 	 	
Accumulated Benefit Obligation	 	$	78	 	$	81	 	
Fair Value of Plan Assets	 	 	-	 	 	-	 	
Accumulated Benefit Obligation Exceeds the Fair Value of Plan Assets	 	$	
78	 	$	81	 	

AEP made a contribution of $626 million in 2005 to meet the goal of fully funding all qualified pension plans by the end of 2005.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31, used in the measurement of AEP’s benefit obligations are shown in the following tables:
 
 	 	  Pension Plans	 	 	 	Other Postretirement Benefit Plans	 	
 	 	  2006	 	 	 	2005	 	 	 	2006	 	 	 	2005	 	
 	 	  (in percentages)	 	
Discount Rate	 	 	5.75	 	 	 	 	 	5.50	 	 	 	 	 	5.85	 	 	 	 	5.65	 	
Rate of Compensation Increase	 	 	5.90	(a) 	 	 	 	 	5.90	(a) 	 	 	 	 	N/A	 	 	 	 	N/A	 	

(a)	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.	
 	 	
N/A	= Not Applicable	

To determine a discount rate, AEP uses a duration-based method by constructing a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s AA bond index with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2006, the rate of compensation increase assumed varies with the age of the employee, ranging from 5.0% per year to 11.5% per year, with an average increase of 5.9%.

Estimated Future Benefit Payments and Contributions

Information about the 2007 expected cash flows for the pension (qualified and nonqualified) and other postretirement benefit plans is as follows:

 	 		 	
 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
Employer Contributions	 	(in millions)	 	
Required Contributions (a)	 	$	8	 	 	N/A	 	
Additional Discretionary Contributions	 	 	- 	 	$	82 	 	

(a)	Contribution required to meet minimum funding requirement per the U.S. Department of Labor and to fund nonqualified benefit payments.	
 	 	
N/A	= Not Applicable	

The contribution to the pension plans is based on the minimum amount required by the U.S. Department of Labor and the amount to fund nonqualified benefit payments, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ periodic benefit cost for accounting purposes and is provided for in agreements with state regulatory authorities.

The table below reflects the total benefits expected to be paid from the plan or from the employer’s assets, including both the employer’s share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan. Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates, and variances in actuarial results. The estimated payments for AEP’s pension benefits and other postretirement benefits are as follows:

 	 	Pension Plans	 	Other Postretirement Benefit Plans	 	
 	 	Pension Payments	 	Benefit
Payments	 	Medicare Subsidy Receipts	 	
 	 	(in millions)	 	
2007	 	$	345	 	$	113	 	$	(9	)	
2008	 	 	354	 	 	121	 	 	(10	)	
2009	 	 	361	 	 	130	 	 	(11	)	
2010	 	 	366	 	 	139	 	 	(11	)	
2011	 	 	367	 	 	149	 	 	(12	)	
Years 2012 to 2016, in Total	 	 	1,821	 	 	839	 	 	(77	)	

Components of Net Periodic Benefit Cost

The following table provides the components of AEP’s net periodic benefit cost for the plans for fiscal years 2006, 2005 and 2004:

 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	2006	 	2005	 	2004	 	2006	 	2005	 	2004	 	
 	 	(in millions)	 	
Service Cost	 	$	97	 	$	93	 	$	86	 	$	39	 	$	42	 	$	41	 	
Interest Cost	 	 	231	 	 	228	 	 	228	 	 	102	 	 	107	 	 	117	 	
Expected Return on Plan Assets	 	 	(335	)	 	(314	)	 	(292	)	 	(94	)	 	(92	)	 	(81	)	
Amortization of Transition Obligation	 	 	-	 	 	-	 	 	2	 	 	27	 	 	27	 	 	28	 	
Amortization of Prior Service Cost (Credit)	 	 	(1	)	 	(1	)	 	(1	)	 	-	 	 	-	 	 	-	 	
Amortization of Net Actuarial Loss	 	 	79	 	 	55	 	 	17	 	 	22	 	 	25	 	 	36	 	
Net Periodic Benefit Cost	 	 	71	 	 	61	 	 	40	 	 	96	 	 	109	 	 	141	 	
Capitalized Portion	 	 	(21	)	 	(17	)	 	(10	)	 	(27	)	 	(33	)	 	(46	)	
Net Periodic Benefit Cost Recognized as   Expense	 	$	50	 	$	44	 	$	30	 	$	69	 	$	76	 	$	95	 	

Estimated amounts expected to be amortized to net periodic benefit costs from AEP’s pretax accumulated other comprehensive income during 2007 are shown in the following table:

 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	(in millions)	 	
Net Actuarial Loss	 	$	52	 	$	15	 	
Prior Service Cost (Credit)	 	 	(1	)	 	-	 	
Transition Obligation	 	 	-	 	 	27	 	
Total Estimated 2007 Pretax AOCI Amortization	 	$	51	 	$	42	 	

Net Benefit Cost by Registrant

The following table provides the net periodic benefit cost (credit) for the plans by Registrant Subsidiary for fiscal years 2006, 2005 and 2004:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	2006	 	2005	 	2004	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	5,876	 	$	7,391	 	$	1,272	 	$	17,953	 	$	20,005	 	$	25,847	 	
CSPCo	 	 	820	 	 	2,143	 	 	(1,626	)	 	7,222	 	 	8,202	 	 	11,050	 	
I&M	 	 	9,319	 	 	9,463	 	 	4,460	 	 	11,805	 	 	13,524	 	 	17,259	 	
KPCo	 	 	1,435	 	 	1,506	 	 	571	 	 	2,050	 	 	2,204	 	 	2,961	 	
OPCo	 	 	3,307	 	 	4,825	 	 	(415	)	 	13,582	 	 	15,442	 	 	20,975	 	
PSO	 	 	3,912	 	 	295	 	 	2,795	 	 	6,352	 	 	6,989	 	 	8,449	 	
SWEPCo	 	 	4,890	 	 	1,462	 	 	3,602	 	 	6,311	 	 	6,849	 	 	8,400	 	
TCC	 	 	3,091	 	 	(880	)	 	2,987	 	 	6,787	 	 	7,521	 	 	10,144	 	
TNC	 	 	1,303	 	 	158	 	 	1,351	 	 	2,861	 	 	3,291	 	 	4,280	 	

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1, used in the measurement of AEP’s benefit costs are shown in the following tables:
 
 	 	  Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	  2006	 	  2005	 	  2004	 	2006	 	  2005	 	  2004	 	
 	 	  (in percentages)	 	
Discount Rate	 	 	5.50	 	 	5.50	 	 	6.25	 	 	5.65	 	 	5.80	 	 	6.25	 	
Expected Return on Plan Assets	 	 	8.50	 	 	8.75	 	 	8.75	 	 	8.00	 	 	8.37	 	 	8.35	 	
Rate of Compensation Increase	 	 	5.90	 	 	3.70	 	 	3.70	 	 	N/A	 	 	N/A	 	 	N/A	 	

N/A = Not Applicable	

The expected return on plan assets for 2006 was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, and current prospects for economic growth.

The health care trend rate assumptions as of January 1, used for other postretirement benefit plans measurement purposes are shown below:

Health Care Trend Rates	 	2006	 	2005	 	
Initial	 	 	8.0	%	 	9.0	%	
Ultimate	 	 	5.0	%	 	5.0	%	
Year Ultimate Reached	 	 	2009	 	 	2009	 	

Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit health care plans. A 1% change in assumed health care cost trend rates would have the following effects:

 	 	1% Increase	 	1% Decrease	 	
 	 	(in millions)	 	
Effect on Total Service and Interest Cost  Components of Net Periodic Postretirement
   Health Care Benefit Cost	 	$	19	 	$	(16	)	
 	 	 	 	 	 	 	 	
Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation	 	 	193	 	 	(161	)	
 
Retirement Savings Plan

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in an AEP sponsored defined contribution retirement savings plans for substantially all employees who are not members of the United Mine Workers of America (UMWA). These plans offer participants an opportunity to contribute a portion of their pay, include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. The matching contributions to the plan are 75% of the first 6% of eligible compensation contributed by the employee.

The following table provides the cost for contributions to the retirement savings plans by the following Registrant Subsidiaries for fiscal years 2006, 2005 and 2004:
 
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	7,471	 	$	6,780	 	$	6,538	 	
CSPCo	 	 	3,224	 	 	2,929	 	 	2,723	 	
I&M	 	 	8,764	 	 	7,892	 	 	7,262	 	
KPCo	 	 	1,313	 	 	1,166	 	 	1,030	 	
OPCo	 	 	6,440	 	 	5,962	 	 	5,688	 	
PSO	 	 	3,312	 	 	2,915	 	 	2,731	 	
SWEPCo	 	 	4,284	 	 	3,935	 	 	3,571	 	
TCC	 	 	3,104	 	 	2,452	 	 	2,544	 	
TNC	 	 	1,075	 	 	1,022	 	 	1,126	 	
 
UMWA Benefits

APCo provides UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.

The health and welfare benefits are administered by APCo and benefits are paid from its general assets. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2006, 2005 and 2004.
 
        10.   NUCLEAR

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. A significant future financial commitment to safely dispose of SNF and to decommission and decontaminate the plant results from its ownership. Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. By agreement, I&M is partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S.

Decommissioning and Low Level Waste Accumulation Disposal

The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. 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. The wide range is caused by variables in assumptions. I&M recovers estimated Cook Plant decommissioning costs in its rates. The amount recovered in rates for decommissioning the Cook Plant was $30 million in 2006 and $27 million in 2005 and 2004. Decommissioning costs recovered from customers are deposited in external trusts.

I&M deposited an additional $4 million in 2006, 2005 and 2004 in its decommissioning trust for Cook Plant under funding provisions approved by regulatory commissions. At December 31, 2006, the total decommissioning trust fund balance for the Cook Plant was $974 million. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. Decommissioning costs for the Cook Plant including interest, unrealized gains and losses and expenses of the trust funds increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
 
SNF Disposal

Federal law provides for government responsibility for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. At December 31, 2006, fees and related interest of $247 million for fuel consumed prior to April 7, 1983 at the Cook Plant have been recorded as Long-term Debt and funds collected from customers towards payment of the pre-April 1983 fee and related earnings of $274 million are recorded as part of Spent Nuclear Fuel and Decommissioning Trust on I&M’s Consolidated Balance Sheet. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

Trust Assets for Decommissioning and SNF Disposal

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel at market value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. As discussed in the “Nuclear Trust Funds” section of Note 1, I&M records unrealized gains and losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. The gains, losses or other-than-temporary impairments shown below did not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdictions’ liabilities. Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of I&M’s nuclear trust fund investments at December 31:

 	 	2006	 	2005	 	
 	 	Estimated
Fair
Value	 	Gross
Unrealized
Gains	 	Other-Than-
Temporary
Impairments	 	Estimated
Fair
Value	 	Gross
Unrealized
Gains	 	Gross
Unrealized
Losses	 	
 	 	(in millions)	 	
Cash	 	$	24	 	$	-	 	$	-	 	$	21	 	$	-	 	$	-	 	
Debt Securities	 	 	750	 	 	18	 	 	(8	)	 	691	 	 	7	 	 	(7	)	
Equity Securities	 	 	474	 	 	192	 	 	(4	)	 	422	 	 	148	 	 	(3	)	
Spent Nuclear Fuel and  Decommissioning Trusts	 	$	1,248	 	$	210	 	$	(12	)	$	1,134	 	$	155	 	$	(10	)	

Proceeds from sales of I&M’s nuclear trust fund investments were $631 million, $557 million and $863 million in 2006, 2005 and 2004, respectively. Purchases of I&M’s nuclear trust fund investments were $692 million, $607 million and $901 million in 2006, 2005 and 2004, respectively.

Gross realized gains from the sales of I&M’s nuclear trust fund investments were $7 million, $4 million and $10 million in 2006, 2005 and 2004, respectively. Gross realized losses including other-than-temporary impairments in 2006 from the sales of I&M’s nuclear trust fund investments were $7 million, $16 million and $17 million in 2006, 2005 and 2004, respectively.

With the sale of STP in May 2005, TCC transferred the nuclear decommissioning liability and the related trust assets to the purchaser. Proceeds from sales of TCC’s nuclear trust fund investments were $150 million and $87 million in 2005 and 2004, respectively. Purchases of TCC’s nuclear trust fund investments were $154 million and $100 million in 2005 and 2004, respectively.

Gross realized gains from the sales of TCC’s nuclear trust fund investments were $9 million and $3 million in 2005 and 2004, respectively. Gross realized losses from the sales of TCC’s nuclear trust fund investments were $2 million and $1 million in 2005 and 2004, respectively.
 
The fair value of debt securities, summarized by contractual maturities, at December 31, 2006 for I&M is as follows:

 	 	Fair Value	 	
 	 	(in millions)	 	
 	 	  	 	
Within 1 year	 	$	50	 	
1 year - 5 years	 	 	188	 	
5 years - 10 years	 	 	215	 	
After 10 years	 	 	297	 	
Total	 	$	750	 	

Nuclear Incident Liability

I&M carries insurance coverage for property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion. I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M utilizes an industry mutual insurer for the placement of this insurance coverage. I&M’s participation in this mutual insurer requires a contingent financial obligation of up to $38 million which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $10.8 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $300 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $101 million on each licensed reactor in the U.S. payable in annual installments of $15 million. As a result, I&M could be assessed $202 million per nuclear incident payable in annual installments of $30 million. The number of incidents for which payments could be required is not limited. Under an industry-wide program insuring workers at nuclear facilities, I&M is also obligated for assessments of up to $6 million for potential claims until December 31, 2007.

In the event of an incident of a catastrophic nature, I&M is initially covered for the first $300 million through commercially available insurance. The next level of liability coverage of up to $10.8 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, results of operations, cash flows and financial condition could be adversely affected.

        11.   BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment. The one reportable segment is an integrated electricity generation, transmission and distribution business except AEGCo, which is an electricity generation business, and TCC and TNC, which are primarily transmission and distribution businesses. All of the Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

        12.   DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS

DERIVATIVES AND HEDGING

SFAS 133 requires recognition of all qualifying derivative instruments as either assets or liabilities in the statement of financial position at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the influence that imperfections in marketplace transparency may cause pricing to be less than or more than what the price should be based purely on supply and demand. Because energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.

Registrant Subsidiaries’ accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided in SFAS 133. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to MTM accounting treatment and are recognized on the accrual or settlement basis.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis in the Registrant Financial Statements. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the statements of income depending on the relevant facts and circumstances.

Depending on the exposure, the Registrant Subsidiaries designate a hedging instrument as a fair value hedge or cash flow hedge. For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), Registrant Subsidiaries recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in earnings. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) until the period the hedged item affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized immediately in earnings during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Fair Value Hedging Strategies

Certain Registrant Subsidiaries enter into interest rate derivative transactions in order to manage interest rate risk exposure. These interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Registrant Subsidiaries record gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as offsetting changes in the fair value of the debt being hedged, in Interest Expense on the statements of income. During 2006, 2005 and 2004, no Registrant Subsidiaries recognized hedge ineffectiveness related to these derivative transactions.

Cash Flow Hedging Strategies

At times certain Registrant Subsidiaries are exposed to foreign currency exchange rate risks because they may purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, the Registrant Subsidiaries may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The accumulated gains or losses related to our foreign currency hedges, which are immaterial, are reclassified from Accumulated Other Comprehensive Income (Loss) into Operating Expenses over the same period as the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships. We do not hedge all foreign currency exposure.

Certain Registrant Subsidiaries enter into interest rate derivative transactions in order to manage interest rate risk exposure. Certain Registrant Subsidiaries enter into forward starting interest rate swap or treasury lock contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. The anticipated debt offerings have a high probability of occurrence because the proceeds will be used to fund existing debt maturities as well as fund projected capital expenditures. Registrant Subsidiaries reclassify gains and losses on the hedges from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which the interest payments being hedged occur. During 2005 and 2006, certain Registrant Subsidiaries reclassified immaterial amounts into earnings due to hedge ineffectiveness. During 2004, certain Registrant Subsidiaries reclassified immaterial amounts to earnings because the original forecasted transaction did not occur within the originally specified time period.

Registrant Subsidiaries enter into, and designate as cash flow hedges, certain derivative transactions for the purchase and sale of electricity and natural gas in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We closely monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect margins for a portion of future electricity sales and fuel purchases. Realized gains and losses on these derivatives designated as cash flow hedges are included in Revenues or fuel expense, depending on the specific nature of the risk being hedged. We do not hedge all variable price risk exposure related to energy commodities. During 2006, 2005 and 2004, certain Registrant Subsidiaries recognized immaterial amounts in earnings related to hedge ineffectiveness.

The following table represents the activity in Accumulated Other Comprehensive Income (Loss) for derivative contracts that qualify as cash flow hedges for the years 2004, 2005 and 2006:

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	
 	 	(in thousands)	 	
Balance at December 31, 2003	 	$	(1,569	)	$	202	 	$	222	 	$	420	 	$	(103	)	
Effective portion of changes in fair value	 	 	(6,269	)	 	2,304	 	 	(3,141	)	 	918	 	 	2,830	 	
Reclasses from AOCI to net income	 	 	(1,486	)	 	(1,113	)	 	(1,157	)	 	(525	)	 	(1,486	)	
Balance at December 31, 2004	 	 	(9,324	)	 	1,393	 	 	(4,076	)	 	813	 	 	1,241	 	
Effective portion of changes in fair value	 	 	(4,515	)	 	(71	)	 	2,489	 	 	81	 	 	2,281	 	
Reclasses from AOCI to net income	 	 	(2,582	)	 	(2,181	)	 	(1,880	)	 	(1,088	)	 	(2,767	)	
Balance at December 31, 2005	 	 	(16,421	)	 	(859	)	 	(3,467	)	 	(194	)	 	755	 	
Effective portion of changes in fair value	 	 	10,365	 	 	3,438	 	 	(6,576	)	 	1,496	 	 	6,899	 	
Impact Due to Changes in SIA (a)	 	 	(442	)	 	(261	)	 	(267	)	 	(106	)	 	(337	)	
Reclasses from AOCI to net income	 	 	3,951	 	 	1,080	 	 	1,348	 	 	356	 	 	(55	)	
Balance at December 31, 2006	 	$	(2,547	)	$	3,398	 	$	(8,962	)	$	1,552	 	$	7,262	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
Balance at December 31, 2003	 	$	156	 	$	184	 	$	(1,828	)	$	(601	)	
Effective portion of changes in fair value	 	 	713	 	 	(450	)	 	866	 	 	373	 	
Reclasses from AOCI to net income	 	 	(469	)	 	(554	)	 	1,619	 	 	513	 	
Balance at December 31, 2004	 	 	400	 	 	(820	)	 	657	 	 	285	 	
Effective portion of changes in fair value	 	 	(1,168	)	 	(4,817	)	 	(635	)	 	(290	)	
Reclasses from AOCI to net income	 	 	(344	)	 	(215	)	 	(246	)	 	(106	)	
Balance at December 31, 2005	 	 	(1,112	)	 	(5,852	)	 	(224	)	 	(111	)	
Effective portion of changes in fair value	 	 	(728	)	 	(1,833	)	 	-	 	 	(703	)	
Impact Due to Changes in SIA (a)	 	 	506	 	 	592	 	 	218	 	 	98	 	
Reclasses from AOCI to net income	 	 	264	 	 	683	 	 	6	 	 	14	 	
Balance at December 31, 2006	 	$	(1,070	)	$	(6,410	)	$	-	 	$	(702	)	

(a)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4.	
 
The following table approximates net loss (gain) from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2006 that are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from AOCI to Net Income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is forty-two months.

Company	 	(in thousands)	 	
APCo	 	$	3,709	 	
CSPCo	 	 	3,357	 	
I&M	 	 	2,521	 	
KPCo	 	 	1,340	 	
OPCo	 	 	4,791	 	
PSO	 	 	(183	)	
SWEPCo	 	 	(755	)	
TCC	 	 	-	 	
TNC	 	 	-	 	

FINANCIAL INSTRUMENTS

The fair values of Long-term Debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of significant financial instruments for Registrant Subsidiaries at December 31, 2006 and 2005 are summarized in the following tables.

 	 	2006	 	2005	 	
 	 	Book Value	 	Fair Value	 	Book Value	 	Fair Value	 	
Company	 	(in thousands)	 	
AEGCo	 	  	 	  	 	  	 	  	 	
Long-term Debt	 	$	44,837	 	$	45,928	 	$	44,828	 	$	45,216	 	
APCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	2,598,664	 	 	2,577,506	 	 	2,151,378	 	 	2,134,973	 	
CSPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	1,197,322	 	 	1,211,176	 	 	1,196,920	 	 	1,232,553	 	
I&M	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	1,555,135	 	 	1,549,985	 	 	1,444,940	 	 	1,456,000	 	
KPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	446,968	 	 	440,839	 	 	486,990	 	 	484,834	 	
OPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	2,401,741	 	 	2,417,050	 	 	2,199,670	 	 	2,250,708	 	
PSO	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	669,998	 	 	670,531	 	 	571,071	 	 	568,998	 	
SWEPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	729,006	 	 	718,902	 	 	744,641	 	 	744,915	 	
TCC	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	3,015,614	 	 	3,040,398	 	 	1,853,496	 	 	1,916,511	 	
TNC	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term Debt	 	 	276,936	 	 	277,842	 	 	276,845	 	 	281,047	 	

        13.   INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes before extraordinary loss and cumulative effect of accounting changes as reported are as follows:

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
Year Ended December 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Income Tax Expense (Credit):	 	  	 	  	 	  	 	  	 	  	 	
Current	 	$	9,244	 	$	88,750	 	$	114,007	 	$	70,231	 	$	17,203	 	
Deferred	 	 	(6,730	)	 	17,225	 	 	(10,900	)	 	13,626	 	 	2,596	 	
Deferred Investment Tax Credits	 	 	(3,433	)	 	(4,559	)	 	(2,264	)	 	(7,752	)	 	(1,144	)	
Total Income Tax	 	$	(919	)	$	101,416	 	$	100,843	 	$	76,105	 	$	18,655	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
Year Ended December 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Income Tax Expense (Credit):	 	  	 	  	 	  	 	  	 	  	 	
Current	 	$	165,290	 	$	40,690	 	$	71,589	 	$	(680	)	$	5,751	 	
Deferred	 	 	(43,997	)	 	(23,672	)	 	(23,667	)	 	24,200	 	 	(227	)	
Deferred Investment Tax Credits	 	 	(2,969	)	 	(1,031	)	 	(4,225	)	 	(870	)	 	(1,270	)	
Total Income Tax	 	$	118,324	 	$	15,987	 	$	43,697	 	$	22,650	 	$	4,254	 	

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
Year Ended December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Income Tax Expense (Credit):	 	  	 	  	 	  	 	  	 	  	 	
Current	 	$	5,089	 	$	(1,915	)	$	44,968	 	$	62,082	 	$	2,803	 	
Deferred	 	 	(1,666	)	 	72,763	 	 	19,209	 	 	26,873	 	 	10,555	 	
Deferred Investment Tax Credits	 	 	(3,532	)	 	(4,659	)	 	(2,717	)	 	(7,725	)	 	(1,222	)	
Total Income Tax	 	$	(109	)	$	66,189	 	$	61,460	 	$	81,230	 	$	12,136	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
Year Ended December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Income Tax Expense (Credit):	 	  	 	  	 	  	 	  	 	  	 	
Current	 	$	68,508	 	$	(14,510	)	$	44,156	 	$	106,437	 	$	24,426	 	
Deferred	 	 	59,593	 	 	46,342	 	 	(4,942	)	 	(91,387	)	 	(4,578	)	
Deferred Investment Tax Credits	 	 	(3,123	)	 	(1,347	)	 	(4,292	)	 	(2,609	)	 	(1,271	)	
Total Income Tax	 	$	124,978	 	$	30,485	 	$	34,922	 	$	12,441	 	$	18,577	 	

 	 	AEGCo	 	  APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
Year Ended December 31, 2004	 	  	 	  	 	  	 	  	 	  	 	
Income Tax Expense (Credit):	 	  	 	  	 	  	 	  	 	  	 	
Current	 	$	5,442	 	$	37,689	 	$	57,140	 	$	84,639	 	$	(2,870	)	
Deferred	 	 	(2,219	)	 	47,585	 	 	13,395	 	 	(5,548	)	 	12,774	 	
Deferred Investment Tax Credits	 	 	(3,339	)	 	(163	)	 	(2,864	)	 	(7,476	)	 	(1,233	)	
Total Income Tax	 	$	(116	)	$	85,111	 	$	67,671	 	$	71,615	 	$	8,671	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
Year Ended December 31, 2004	 	  	 	  	 	  	 	  	 	  	 	
Income Tax Expense (Credit):	 	  	 	  	 	  	 	  	 	  	 	
Current	 	$	75,883	 	$	(12,434	)	$	26,271	 	$	123,304	 	$	19,565	 	
Deferred	 	 	23,329	 	 	22,034	 	 	12,782	 	 	16,490	 	 	4,236	 	
Deferred Investment Tax Credits	 	 	(3,102	)	 	(1,791	)	 	(4,326	)	 	(4,736	)	 	(1,292	)	
Total Income Tax	 	$	96,110	 	$	7,809	 	$	34,727	 	$	135,058	 	$	22,509	 	

Shown below is a reconciliation for each Registrant Subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory rate and the amount of income taxes reported.

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
Year Ended December 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Net Income	 	$	10,914	 	$	181,449	 	$	185,579	 	$	121,168	 	$	35,035	 	
Cumulative Effect of Accounting Changes	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Income Taxes	 	 	(919	)	 	101,416	 	 	100,843	 	 	76,105	 	 	18,655	 	
Pretax Income	 	$	9,995	 	$	282,865	 	$	286,422	 	$	197,273	 	$	53,690	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax on Pretax Income at Statutory Rate (35%)	 	$	3,498	 	$	99,003	 	$	100,248	 	$	69,046	 	$	18,791	 	
Increase (Decrease) in Income Tax resulting from the following items:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	120	 	 	10,325	 	 	1,395	 	 	20,834	 	 	1,669	 	
Nuclear Fuel Disposal Costs	 	 	-	 	 	-	 	 	-	 	 	(5,538	)	 	-	 	
Allowance for Funds Used During  Construction	 	 	(1,075	)	 	(7,379	)	 	(789	)	 	(5,149	)	 	(606	)	
Rockport Plant Unit 2 Investment  Tax Credit	 	 	374	 	 	-	 	 	-	 	 	397	 	 	-	 	
Removal Costs	 	 	(17	)	 	(3,339	)	 	(544	)	 	(5,968	)	 	(1,361	)	
Investment Tax Credits, Net	 	 	(3,433	)	 	(4,559	)	 	(2,264	)	 	(7,752	)	 	(1,144	)	
State and Local Income Taxes	 	 	634	 	 	12,678	 	 	(53	)	 	4,559	 	 	1,070	 	
Other	 	 	(1,020	)	 	(5,313	)	 	2,850	 	 	5,676	 	 	236	 	
Total Income Taxes	 	$	(919	)	$	101,416	 	$	100,843	 	$	76,105	 	$	18,655	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	N.M.	 	 	35.9	%	 	35.2	%	 	38.6	%	 	34.7	%	

N.M. = Not Meaningful	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
Year Ended December 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Net Income	 	$	228,643	 	$	36,860	 	$	91,723	 	$	41,569	 	$	14,943	 	
Cumulative Effect of Accounting Changes	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Extraordinary Loss	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Income Taxes	 	 	118,324	 	 	15,987	 	 	43,697	 	 	22,650	 	 	4,254	 	
Pretax Income	 	$	346,967	 	$	52,847	 	$	135,420	 	$	64,219	 	$	19,197	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax on Pretax Income at Statutory Rate (35%)	 	$	121,438	 	$	18,496	 	$	47,397	 	$	22,477	 	$	6,719	 	
Increase (Decrease) in Income Tax  resulting from the following items:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	4,397	 	 	(593	)	 	(85	)	 	(453	)	 	(500	)	
Depletion	 	 	-	 	 	-	 	 	(3,150	)	 	-	 	 	-	 	
Investment Tax Credits, Net	 	 	(2,969	)	 	(1,031	)	 	(4,225	)	 	(870	)	 	(1,270	)	
State and Local Income Taxes	 	 	270	 	 	260	 	 	3,764	 	 	3,782	 	 	(759	)	
Other	 	 	(4,812	)	 	(1,145	)	 	(4	)	 	(2,286	)	 	64	 	
Total Income Taxes	 	$	118,324	 	$	15,987	 	$	43,697	 	$	22,650	 	$	4,254	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	34.1	%	 	30.3	%	 	32.3	%	 	35.3	%	 	22.2	%	
 
 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
Year Ended December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Net Income	 	$	8,695	 	$	133,576	 	$	136,960	 	$	146,852	 	$	20,809	 	
Cumulative Effect of Accounting Changes	 	 	-	 	 	2,256	 	 	839	 	 	-	 	 	-	 	
Income Taxes	 	 	(109	)	 	66,189	 	 	61,460	 	 	81,230	 	 	12,136	 	
Pretax Income	 	$	8,586	 	$	202,021	 	$	199,259	 	$	228,082	 	$	32,945	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax on Pretax Income at Statutory Rate (35%)	 	$	3,005	 	$	70,707	 	$	69,741	 	$	79,829	 	$	11,531	 	
Increase (Decrease) in Income Tax resulting from the following items:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	757	 	 	11,257	 	 	1,614	 	 	19,492	 	 	1,644	 	
Nuclear Fuel Disposal Costs	 	 	-	 	 	-	 	 	-	 	 	(3,413	)	 	-	 	
Allowance for Funds Used During Construction	 	 	(1,097	)	 	(4,786	)	 	(679	)	 	(3,819	)	 	(614	)	
Rockport Plant Unit 2 Investment Tax Credit	 	 	374	 	 	-	 	 	-	 	 	397	 	 	-	 	
Removal Costs	 	 	-	 	 	(4,275	)	 	(357	)	 	(5,476	)	 	(995	)	
Investment Tax Credits, Net	 	 	(3,532	)	 	(4,659	)	 	(2,717	)	 	(7,725	)	 	(1,222	)	
State and Local Income Taxes	 	 	723	 	 	2,223	 	 	448	 	 	6,598	 	 	778	 	
Other	 	 	(339	)	 	(4,278	)	 	(6,590	)	 	(4,653	)	 	1,014	 	
Total Income Taxes	 	$	(109	)	$	66,189	 	$	61,460	 	$	81,230	 	$	12,136	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	N.M.	 	 	32.8	%	 	30.8	%	 	35.6	%	 	36.8	%	

N.M. = Not Meaningful	

 	 	OPCo  	 	PSO  	 	SWEPCo  	 	TCC  	 	TNC  	 	
 	 	(in thousands)	 	
Year Ended December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Net Income (Loss)	 	$	245,844	 	$	57,893	 	$	73,938	 	$	(173,779	)	$	33,004	 	
Extraordinary Loss	 	 	-	 	 	-	 	 	-	 	 	224,551	 	 	-	 	
Cumulative Effect of Accounting Changes	 	 	4,575	 	 	-	 	 	1,252	 	 	-	 	 	8,472	 	
Income Taxes	 	 	124,978	 	 	30,485	 	 	34,922	 	 	12,441	 	 	18,577	 	
Pretax Income	 	$	375,397	 	$	88,378	 	$	110,112	 	$	63,213	 	$	60,053	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax on Pretax Income at  Statutory Rate (35%)	 	$	131,389	 	$	30,932	 	$	38,539	 	$	22,125	 	$	21,019	 	
Increase (Decrease) in Income Tax resulting from  the following items:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	5,195	 	 	(775	)	 	(211	)	 	(519	)	 	(513	)	
Depletion	 	 	-	 	 	-	 	 	(3,150	)	 	-	 	 	-	 	
Investment Tax Credits, Net	 	 	(3,123	)	 	(1,347	)	 	(4,292	)	 	(2,609	)	 	(1,271	)	
State and Local Income Taxes	 	 	5,437	 	 	(1,387	)	 	1,831	 	 	300	 	 	718	 	
Other	 	 	(13,920	)	 	3,062	 	 	2,205	 	 	(6,856	) (a)	 	(1,376	)	
Total Income Taxes	 	$	124,978	 	$	30,485	 	$	34,922	 	$	12,441	 	$	18,577	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	33.3	%	 	34.5	%	 	31.7	%	 	19.7	%	 	30.9	%	

(a)  Includes $(3,900) of consolidated tax savings from parent.	
 
 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
Year Ended December 31, 2004	 	  	 	  	 	  	 	  	 	  	 	
Net Income	 	$	7,842	 	$	153,115	 	$	140,258	 	$	133,222	 	$	25,905	 	
Income Taxes	 	 	(116	)	 	85,111	 	 	67,671	 	 	71,615	 	 	8,671	 	
Pretax Income	 	$	7,726	 	$	238,226	 	$	207,929	 	$	204,837	 	$	34,576	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax on Pretax Income at  Statutory Rate (35%)	 	$	2,704	 	$	83,379	 	$	72,775	 	$	71,693	 	$	12,102	 	
Increase (Decrease) in Income Tax resulting from the following items:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	808	 	 	10,719	 	 	2,570	 	 	19,023	 	 	1,466	 	
Nuclear Fuel Disposal Costs	 	 	-	 	 	-	 	 	-	 	 	(3,338	)	 	-	 	
Allowance for Funds Used During  Construction	 	 	(1,060	)	 	(3,948	)	 	(515	)	 	(3,160	)	 	(603	)	
Rockport Plant Unit 2 Investment Tax Credit	 	 	374	 	 	-	 	 	-	 	 	397	 	 	-	 	
Removal Costs	 	 	-	 	 	(1,632	)	 	(336	)	 	(2,974	)	 	(1,497	)	
Investment Tax Credits, Net	 	 	(3,339	)	 	(163	)	 	(2,864	)	 	(7,476	)	 	(1,233	)	
State and Local Income Taxes	 	 	933	 	 	6,629	 	 	159	 	 	7,102	 	 	(197	)	
Other	 	 	(536	)	 	(9,873	)	 	(4,118	)	 	(9,652	)	 	(1,367	)	
Total Income Taxes	 	$	(116	)	$	85,111	 	$	67,671	 	$	71,615	 	$	8,671	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	N.M.	 	 	35.7	%	 	32.5	%	 	35.0	%	 	25.1	%	

N.M. = Not Meaningful	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
Year Ended December 31, 2004	 	  	 	  	 	  	 	  	 	  	 	
Net Income	 	$	210,116	 	$	37,542	 	$	89,457	 	$	174,122	 	$	47,659	 	
Extraordinary Loss	 	 	-	 	 	-	 	 	-	 	 	120,534	 	 	-	 	
Income Taxes	 	 	96,110	 	 	7,809	 	 	34,727	 	 	135,058	 	 	22,509	 	
Pretax Income	 	$	306,226	 	$	45,351	 	$	124,184	 	$	429,714	 	$	70,168	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax on Pretax Income at  Statutory Rate (35%)	 	$	107,179	 	$	15,873	 	$	43,464	 	$	150,400	 	$	24,559	 	
Increase (Decrease) in Income Tax resulting from the following items:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation	 	 	4,977	 	 	(937	)	 	(1,622	)	 	(812	)	 	(739	)	
Depletion	 	 	-	 	 	-	 	 	(2,100	)	 	-	 	 	-	 	
Investment Tax Credits, Net	 	 	(3,102	)	 	(1,791	)	 	(4,326	)	 	(4,736	)	 	(1,292	)	
State and Local Income Taxes	 	 	305	 	 	1,882	 	 	4,736	 	 	543	 	 	2,762	 	
Other	 	 	(13,249	)	 	(7,218	)	 	(5,425	)	 	(10,337	)	 	(2,781	)	
Total Income Taxes	 	$	96,110	 	$	7,809	 	$	34,727	 	$	135,058	 	$	22,509	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective Income Tax Rate	 	 	31.4	%	 	17.2	%	 	28.0	%	 	31.4	%	 	32.1	%	
 
The following tables show the elements of the net deferred tax liability and the significant temporary differences for each Registrant Subsidiary:

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
As of December 31, 2006	 	  	 	 	 	  	 	  	 	  	 	
Deferred Tax Assets	 	$	56,758	 	$	359,085	 	$	117,884	 	$	696,709	 	$	38,454	 	
Deferred Tax Liabilities	 	 	(76,507	)	 	(1,316,314	)	 	(593,772	)	 	(1,031,709	)	 	(280,587	)	
Net Deferred Tax Liabilities	 	$	(19,749	)	$	(957,229	)	$	(475,888	)	$	(335,000	)	$	(242,133	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property Related Temporary Differences	 	$	(51,683	)	$	(742,711	)	$	(381,832	)	$	(1,550	)	$	(180,662	)	
Amounts Due From Customers For   Future Federal Income Taxes	 	 	4,036	 	 	(101,554	)	 	(5,745	)	 	(23,938	)	 	(24,888	)	
Deferred State Income Taxes	 	 	(2,060	)	 	(97,887	)	 	(8,559	)	 	(42,329	)	 	(29,331	)	
Transition Regulatory Assets	 	 	-	 	 	(5,942	)	 	(34,179	)	 	-	 	 	-	 	
Deferred Income Taxes on Other Comprehensive Loss	 	 	-	 	 	29,503	 	 	11,840	 	 	8,104	 	 	(836	)	
Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2	 	 	30,068	 	 	-	 	 	-	 	 	20,670	 	 	-	 	
Accrued Nuclear Decommissioning Expense	 	 	-	 	 	-	 	 	-	 	 	(246,533	)	 	-	 	
Deferred Fuel and Purchased Power	 	 	-	 	 	7,117	 	 	(39	)	 	(146	)	 	(410	)	
Accrued Pensions	 	 	-	 	 	(17,769	)	 	(16,161	)	 	(7,618	)	 	(1,665	)	
Nuclear Fuel	 	 	-	 	 	-	 	 	-	 	 	(16,403	)	 	-	 	
All Other, Net	 	 	(110	)	 	(27,986	) 	 	(41,213	)	 	(25,257	)	 	(4,341	) 	
Net Deferred Tax Liabilities	 	$	(19,749	)	$	(957,229	)	$	(475,888	)	$	(335,000	)	$	(242,133	)	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
As of December 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Deferred Tax Assets	 	$	215,890	 	$	107,723	 	$	109,860	 	$	235,109	 	$	44,915	 	
Deferred Tax Liabilities	 	 	(1,127,111	)	 	(521,920	)	 	(484,408	)	 	(1,269,232	)	 	(168,963	)	
Net Deferred Tax Liabilities	 	$	(911,221	)	$	(414,197	)	$	(374,548	)	$	(1,034,123	)	$	(124,048	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property Related Temporary Differences	 	$	(789,303	)	$	(351,461	)	$	(319,240	)	$	(251,645	)	$	(124,197	)	
Amounts Due From Customers For Future Federal Income Taxes	 	 	(51,673	)	 	3,747	 	 	(1,382	)	 	6,477	 	 	3,392	 	
Deferred State Income Taxes	 	 	(33,053	)	 	(55,256	)	 	(38,073	)	 	(2,248	)	 	(1,471	)	
Transition Regulatory Assets	 	 	(25,273	)	 	-	 	 	-	 	 	19,239	 	 	-	 	
Accrued Nuclear Decommissioning  Expense	 	 	-	 	 	-	 	 	-	 	 	(928	)	 	-	 	
Deferred Income Taxes on Other  Comprehensive Loss	 	 	30,565	 	 	576	 	 	10,337	 	 	-	 	 	5,470	 	
Deferred Fuel and Purchased Power	 	 	-	 	 	(2,644	)	 	(6,501	)	 	31,774	 	 	3,525	 	
Accrued Pensions	 	 	(30,668	)	 	(14,182	)	 	(11,676	)	 	(15,494	)	 	(10,131	)	
Provision for Refund	 	 	2,690	 	 	67	 	 	415	 	 	50	 	 	77	 	
Regulatory Assets	 	 	(34,821	)	 	(30,392	)	 	(21,293	)	 	(15,795	) 	 	(13,009	)	
Securitized Transition Assets	 	 	-	 	 	-	 	 	-	 	 	(809,065	)	 	-	 	
All Other, Net	 	 	20,315	 	 	35,348	 	 	12,865	 	 	3,512	 	 	12,296	 	
Net Deferred Tax Liabilities	 	$	(911,221	)	$	(414,197	)	$	(374,548	)	$	(1,034,123	)	$	(124,048	)	

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
As of December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Deferred Tax Assets	 	$	61,315	 	$	221,910	 	$	76,785	 	$	614,838	 	$	26,806	 	
Deferred Tax Liabilities	 	 	(84,932	)	 	(1,174,407	)	 	(575,017	)	 	(950,102	)	 	(261,525	)	
Net Deferred Tax Liabilities	 	$	(23,617	)	$	(952,497	)	$	(498,232	)	$	(335,264	)	$	(234,719	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property Related Temporary Differences	 	$	(56,297	)	$	(695,698	)	$	(391,117	)	$	(42,401	)	$	(175,512	)	
Amounts Due From Customers For  Future Federal Income Taxes	 	 	5,711	 	 	(93,171	)	 	(6,053	)	 	(28,714	)	 	(24,720	)	
Deferred State Income Taxes	 	 	(3,987	)	 	(108,455	)	 	(9,409	)	 	(36,352	)	 	(25,950	)	
Transition Regulatory Assets	 	 	-	 	 	(7,428	)	 	(50,719	)	 	-	 	 	-	 	
Deferred Income Taxes on Other  Comprehensive Loss	 	 	-	 	 	8,944	 	 	473	 	 	1,922	 	 	120	 	
Net Deferred Gain on Sale and  Leaseback-Rockport Plant Unit 2	 	 	32,018	 	 	-	 	 	-	 	 	21,303	 	 	-	 	
Accrued Nuclear Decommissioning  Expense	 	 	-	 	 	-	 	 	-	 	 	(214,126	)	 	-	 	
Deferred Fuel and Purchased Power	 	 	-	 	 	7,471	 	 	(39	)	 	(1,200	)	 	(1,080	)	
Accrued Pensions	 	 	-	 	 	(48,649	)	 	(40,460	)	 	(28,443	)	 	(6,488	)	
Nuclear Fuel	 	 	-	 	 	-	 	 	-	 	 	(8,040	)	 	-	 	
All Other, Net	 	 	(1,062	)	 	(15,511	)	 	(908	)	 	787	 	 	(1,089	)	
Net Deferred Tax Liabilities	 	$	(23,617	)	$	(952,497	)	$	(498,232	)	$	(335,264	)	$	(234,719	)	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
As of December 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Deferred Tax Assets	 	$	138,836	 	$	50,570	 	$	67,226	 	$	146,877	 	$	37,158	 	
Deferred Tax Liabilities	 	 	(1,126,222	)	 	(486,952	)	 	(476,739	)	 	(1,195,249	)	 	(169,493	)	
Net Deferred Tax Liabilities	 	$	(987,386	)	$	(436,382	)	$	(409,513	)	$	(1,048,372	)	$	(132,335	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property Related Temporary Differences	 	$	(789,885	)	$	(336,743	)	$	(321,810	)	$	(240,361	)	$	(121,192	)	
Amounts Due From Customers For  Future Federal Income Taxes	 	 	
(51,780	
)	 	
4,231	 	 	(961	)	 	
7,216	 	 	
3,892	 	
Deferred State Income Taxes	 	 	(41,366	)	 	(59,574	)	 	(45,218	)	 	(43,427	)	 	(7,316	)	
Transition Regulatory Assets	 	 	(49,505	)	 	-	 	 	14	 	 	(68,076	)	 	-	 	
Accrued Nuclear Decommissioning  Expense	 	 	
-	 	 	
-	 	 	-	 	 	(1,983	)	 	-	 	
Deferred Income Taxes on Other  Comprehensive Loss	 	 	
(406	
)	 	
681	 	 	3,300	 	 	620	 	 	271	 	
Deferred Fuel and Purchased Power	 	 	-	 	 	(37,984	)	 	(26,449	)	 	(1,738	)	 	(8,554	)	
Accrued Pensions	 	 	(52,450	)	 	(32,387	)	 	(29,041	)	 	(41,894	)	 	(17,698	)	
Provision for Refund	 	 	-	 	 	67	 	 	843	 	 	40,111	 	 	11,671	 	
Regulatory Assets	 	 	(4,981	)	 	(3,665	)	 	(496	)	 	(464,080	)	 	(2,915	)	
Securitized Transition Assets	 	 	-	 	 	-	 	 	-	 	 	(231,587	)	 	-	 	
All Other, Net	 	 	2,987	 	 	28,992	 	 	10,305	 	 	(3,173	)	 	9,506	 	
Net Deferred Tax Liabilities	 	$	(987,386	)	$	(436,382	)	$	(409,513	)	$	(1,048,372	)	$	(132,335	)	

Registrant Subsidiaries join in the filing of a consolidated federal income tax return with the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the System companies allocates the benefit of current tax losses to the System companies giving rise to such losses in determining their current tax expense. The tax benefit of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

The IRS and other taxing authorities routinely examine the Registrant Subsidiaries tax returns. Management believes that the Registrant Subsidiaries have filed tax returns with positions that may be challenged by these tax authorities. Registrant Subsidiaries have settled with the IRS all issues from the audits of our consolidated federal income tax returns for years prior to1997. Management has reached a negotiated settlement of all outstanding proposed IRS adjustments for years 1997 through 1999 and through June 2000 for the CSW pre-merger tax period and anticipates payment for the agreed adjustments to occur during 2007. Returns for the years 2000 through 2003 are presently being audited by the IRS.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. As of December 31, 2006, Registrant Subsidiaries have total provisions for uncertain tax positions of approximately $16 million, excluding AEGCo. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

In 2005, the Energy Tax Incentives Act of 2005 was signed into law. This act created a limited amount of tax credits for the building of Integrated Gasification Combined Cycle (IGCC) plants. The credit is 20% of the eligible property in the construction of new plant or 20% of the total cost of repowering of an existing plant using IGCC technology. In the case of a newly constructed IGCC, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment. AEP announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits. AEP filed applications for the Mountaineer and Great Bend projects with the DOE and the IRS. Both projects were certified by the DOE and qualified by the IRS. However, neither project was awarded credits during this round of credit awards. AEP will continue to pursue credits for the next round of credits in 2009.

The Energy Tax Incentives Act of 2005 also changed the tax depreciation life for transmission assets from 20 years to 15 years. This act also allows for the accelerated amortization of atmospheric pollution control equipment placed in service after April 11, 2005 and installed on plants placed in service on or after January 1, 1976. This provision allows for tax amortization of the equipment over eighty-four months in lieu of taking a depreciation deduction over 20-years. This act also allows for the transfer (“poured-over”) of funds held in nonqualifying nuclear decommissioning trusts into qualified nuclear decommissioning trusts. The tax deduction may be claimed, as the nonqualified funds are poured-over; the funds are poured-over during the remaining life of the plant. The earnings on funds held in a qualified nuclear decommissioning fund are taxed at a 20% federal rate as opposed to a 35% federal tax rate for nonqualified funds. The tax law changes discussed in this paragraph have not materially affected AEP’s results of operations, cash flows, or financial condition.

After Hurricanes Katrina, Rita and Wilma in 2005, a series of tax acts were placed into law to aid in the recovery of the Gulf coast region. The Katrina Emergency Tax Relief Act of 2005 (enacted September 23, 2005) and the Gulf Opportunity Zone Act of 2005 (enacted December 21, 2005) contained a number of provisions to aid businesses and individuals impacted by these hurricanes. The application of these tax acts has not materially affected our results of operations, cash flows, or financial condition.
 
On June 30, 2005, the Governor of Ohio signed Ohio House Bill 66 into law enacting sweeping tax changes impacting all companies doing business in Ohio. Most of the significant tax changes will be phased in over a five-year period, while some of the less significant changes became fully effective July 1, 2005. Changes to the Ohio franchise tax, nonutility property taxes, and the new commercial activity tax are subject to phase-in. The Ohio franchise tax will fully phase-out over a five-year period beginning with a 20% reduction in state franchise tax for taxable income accrued during 2005. In 2005, AEP reversed deferred state income tax liabilities that are not expected to reverse during the phase-out as follows in thousands:

Company	 	  Other Regulatory Liabilities (a)	 	  SFAS 109 Regulatory Asset, Net (b)	 	 
State Income Tax Expense (c)	 	  Deferred State Income Tax Liabilities (d)	 	
APCo	 	$	-	 	$	10,945	 	$	2,769	 	$	13,714	 	
CSPCo	 	 	15,104	 	 	-	 	 	-	 	 	15,104	 	
I&M	 	 	-	 	 	5,195	 	 	-	 	 	5,195	 	
KPCo	 	 	-	 	 	3,648	 	 	-	 	 	3,648	 	
OPCo	 	 	41,864	 	 	-	 	 	-	 	 	41,864	 	
PSO	 	 	-	 	 	-	 	 	706	 	 	706	 	
SWEPCo	 	 	-	 	 	582	 	 	119	 	 	701	 	
TCC	 	 	-	 	 	1,156	 	 	365	 	 	1,521	 	
TNC	 	 	-	 	 	120	 	 	75	 	 	195	 	

(a)	The reversal of deferred state income taxes for the Ohio companies was recorded as a regulatory liability pending rate-making treatment in Ohio. See "Ormet" section of Note 4.  	
(b)	Deferred state income tax adjustments related to those companies in which state income taxes flow through for rate-making purposes reduced the regulatory asset associated with the deferred state income tax liabilities.	
(c)	These amounts were recorded as a reduction to Income Tax Expense.	
(d)	Total deferred state income tax liabilities that reversed during 2005 related to Ohio law change.	

In November 2006, the PUCO ordered OPCo and CSPCo to amortize $41,864 and $15,104, respectively, to income as an offset to power supply contract losses incurred by Ohio Power and Columbus Southern Power for sales to Ormet.

The new legislation also imposes a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts. The new tax is being phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate. The increase in Taxes Other than Income Taxes for 2006 and 2005 were approximately $2 million and $1 million for CSPCo and $2 million and $1 million for OPCo, respectively.

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, management reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006 the following adjustments were recorded (in thousands):
 
Company	 	  Decrease in SFAS 109 Regulatory Asset, Net	 	 
Decrease in State Income Tax Expense	 	  Decrease in Deferred State Income Tax Liabilities	 	
TCC	 	$	36,315	 	$	-	 	$	36,315	 	
TNC	 	 	4,801	 	 	1,265	 	 	6,066	 	
PSO	 	 	-	 	 	3,273	 	 	3,273	 	
SWEPCo	 	 	4,438	 	 	501	 	 	4,939	 	
 
The Tax Increase Prevention and Reconciliation Act of 2005 (TIPRA 2005) was passed May 17, 2006. The majority of the provisions in TIPRA 2005 were directed toward individual income tax relief including the extension of reduced tax rates for dividends and capital gains through 2010. Management believes the application of this act will not materially affect the Registrant Subsidiaries’ results of operations, cash flows, or financial condition.

The President signed the Pension Protection Act of 2006 (PPA 2006) into law on August 17, 2006. This law is directed toward strengthening qualified retirement plans and adding new restrictions on charitable contributions. Specifically, PPA 2006 concentrates on the funding of defined benefit plans and the health of the Pension Benefit Guaranty Corporation. PPA 2006 imposes new minimum funding rules for multiemployer plans as well as increasing the deduction limitation for contributions to multiemployer defined benefit plans. Due to the significant funding of the AEP pension plans in 2005, the Act will not materially affect the Registrant Subsidiaries’ results of operations, cash flows, or financial condition.

On December 20, 2006, the Tax Relief and Health Care Act of 2006 (TRHCA 2006) was signed into law. The primary purpose of the bill was to extend expiring tax provisions for individuals and business taxpayers and provide increased tax flexibility around medical benefits. In addition to extending the lower capital gains and dividend tax rates for individuals, TRHCA 2006 extended the research credit and for 2007 provides a new alternative formula for deterring the research credit. The application of TRHCA 2006 is not expected to materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.  

         14.   LEASES

Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
Year Ended December 31, 2006	 	(in thousands)	 	
Net Lease Expense on Operating Leases	 	$	72,205	 	$	12,657	 	$	5,093	 	$	97,750	 	$	2,079	 	
Amortization of Capital Leases	 	 	310	 	 	5,825	 	 	3,221	 	 	6,533	 	 	1,207	 	
Interest on Capital Leases	 	 	702	 	 	873	 	 	429	 	 	2,807	 	 	116	 	
Total Lease Rental Costs	 	$	73,217	 	$	19,355	 	$	8,743	 	$	107,090	 	$	3,402	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Year Ended December 31, 2006	 	(in thousands)	 	
Net Lease Expense on Operating Leases	 	$	20,985	 	$	6,901	 	$	6,808	 	$	6,091	 	$	2,812	 	
Amortization of Capital Leases	 	 	7,946	 	 	1,155	 	 	6,504	 	 	1,024	 	 	397	 	
Interest on Capital Leases	 	 	2,155	 	 	232	 	 	3,689	 	 	223	 	 	82	 	
Total Lease Rental Costs	 	$	31,086	 	$	8,288	 	$	17,001	 	$	7,338	 	$	3,291	 	

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
Year Ended December 31, 2005	 	(in thousands)	 	
Net Lease Expense on Operating Leases	 	$	72,301	 	$	8,539	 	$	6,194	 	$	93,993	 	$	1,735	 	
Amortization of Capital Leases	 	 	284	 	 	6,273	 	 	3,313	 	 	6,681	 	 	1,519	 	
Interest on Capital Leases	 	 	709	 	 	449	 	 	540	 	 	2,442	 	 	34	 	
Total Lease Rental Costs	 	$	73,294	 	$	15,261	 	$	10,047	 	$	103,116	 	$	3,288	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Year Ended December 31, 2005	 	(in thousands)	 	
Net Lease Expense on Operating Leases	 	$	10,528	 	$	5,658	 	$	5,867	 	$	5,594	 	$	2,275	 	
Amortization of Capital Leases	 	 	7,940	 	 	668	 	 	6,200	 	 	478	 	 	249	 	
Interest on Capital Leases	 	 	2,275	 	 	93	 	 	2,738	 	 	60	 	 	34	 	
Total Lease Rental Costs	 	$	20,743	 	$	6,419	 	$	14,805	 	$	6,132	 	$	2,558	 	

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
Year Ended December 31, 2004	 	(in thousands)	 	
Net Lease Expense on Operating Leases	 	$	69,974	 	$	6,832	 	$	5,313	 	$	107,637	 	$	1,416	 	
Amortization of Capital Leases	 	 	92	 	 	7,906	 	 	3,933	 	 	6,825	 	 	1,605	 	
Interest on Capital Leases	 	 	7	 	 	1,260	 	 	705	 	 	1,403	 	 	258	 	
Total Lease Rental Costs	 	$	70,073	 	$	15,998	 	$	9,951	 	$	115,865	 	$	3,279	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Year Ended December 31, 2004	 	(in thousands)	 	
Net Lease Expense on Operating Leases	 	$	14,390	 	$	3,697	 	$	4,877	 	$	3,949	 	$	1,458	 	
Amortization of Capital Leases	 	 	8,232	 	 	520	 	 	3,543	 	 	437	 	 	216	 	
Interest on Capital Leases	 	 	2,259	 	 	53	 	 	2,054	 	 	66	 	 	27	 	
Total Lease Rental Costs	 	$	24,881	 	$	4,270	 	$	10,474	 	$	4,452	 	$	1,701	 	

The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrant Subsidiaries’ balance sheets. Capital lease obligations are included in Current Liabilities - Other and Noncurrent Liabilities - Deferred Credits and Other on the Registrant Subsidiaries’ balance sheets.

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
As of December 31, 2006	 	(in thousands)	 	
Property, Plant and Equipment  Under Capital Leases:	 	  	 	  	 	  	 	  	 	  	 	
Production	 	$	12,272	 	$	1,264	 	$	7,104	 	$	18,480	 	$	436	 	
Distribution	 	 	-	 	 	-	 	 	-	 	 	14,589	 	 	-	 	
Other	 	 	428	 	 	30,578	 	 	13,009	 	 	40,227	 	 	6,723	 	
Construction Work in Progress	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Total Property, Plant and Equipment	 	 	12,700	 	 	31,842	 	 	20,113	 	 	73,296	 	 	7,159	 	
Accumulated Amortization	 	 	699	 	 	20,011	 	 	11,660	 	 	30,240	 	 	4,512	 	
Net Property, Plant and Equipment Under Capital Leases	 	$	12,001	 	$	11,831	 	$	8,453	 	$	43,056	 	$	2,647	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncurrent Liability	 	$	11,675	 	$	7,699	 	$	5,731	 	$	27,073	 	$	1,493	 	
Liability Due Within One Year	 	 	326	 	 	4,160	 	 	2,741	 	 	15,983	 	 	1,154	 	
Total Obligations Under  Capital Leases  	 	$	12,001	 	$	11,859	 	$	8,472	 	$	43,056	 	$	2,647	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
As of December 31, 2006	 	(in thousands)	 	
Property, Plant and Equipment  Under Capital Leases:  	 	  	 	  	 	  	 	  	 	  	 	
Production	 	$	39,807	 	$	-	 	$	14,270	 	$	-	 	$	-	 	
Distribution	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Other	 	 	31,590	 	 	6,387	 	 	82,209	 	 	5,480	 	 	2,110	 	
Construction Work in Progress	 	 	-	 	 	-	 	 	29,777	 	 	-	 	 	-	 	
Total Property, Plant and Equipment	 	 	71,397	 	 	6,387	 	 	126,256	 	 	5,480	 	 	2,110	 	
Accumulated Amortization	 	 	38,102	 	 	1,571	 	 	41,894	 	 	1,306	 	 	467	 	
Net Property, Plant and Equipment Under Capital Leases	 	$	33,295	 	$	4,816	 	$	84,362	 	$	4,174	 	$	1,643	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncurrent Liability	 	$	25,996	 	$	3,332	 	$	72,061	 	$	2,739	 	$	1,137	 	
Liability Due Within One Year	 	 	8,970	 	 	1,484	 	 	12,654	 	 	1,358	 	 	506	 	
Total Obligations Under  Capital Leases	 	$	34,966	 	$	4,816	 	$	84,715	 	$	4,097	 	$	1,643	 	

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
As of December 31, 2005	 	(in thousands)	 	
Property, Plant and Equipment  Under Capital Leases:  	 	  	 	  	 	  	 	  	 	  	 	
Production	 	$	12,316	 	$	1,275	 	$	7,104	 	$	18,964	 	$	436	 	
Distribution	 	 	-	 	 	-	 	 	-	 	 	14,589	 	 	-	 	
Other	 	 	349	 	 	36,792	 	 	16,059	 	 	38,568	 	 	9,128	 	
Total Property, Plant and Equipment	 	 	12,665	 	 	38,067	 	 	23,163	 	 	72,121	 	 	9,564	 	
Accumulated Amortization	 	 	438	 	 	23,185	 	 	13,609	 	 	28,145	 	 	6,396	 	
Net Property, Plant and  Equipment Under Capital Leases	 	$	12,227	 	$	14,882	 	$	9,554	 	$	43,976	 	$	3,168	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncurrent Liability	 	$	11,930	 	$	9,292	 	$	6,545	 	$	38,645	 	$	2,030	 	
Liability Due Within One Year	 	 	297	 	 	5,600	 	 	3,031	 	 	5,331	 	 	1,138	 	
Total Obligations Under  Capital Leases	 	$	12,227	 	$	14,892	 	$	9,576	 	$	43,976	 	$	3,168	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
As of December 31, 2005	 	(in thousands)	 	
Property, Plant and Equipment  Under Capital Leases :	 	  	 	  	 	  	 	  	 	  	 	
Production	 	$	40,554	 	$	-	 	$	14,270	 	$	-	 	$	-	 	
Distribution	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
Other	 	 	37,867	 	 	3,378	 	 	65,014	 	 	2,072	 	 	1,045	 	
Total Property, Plant and Equipment	 	 	78,421	 	 	3,378	 	 	79,284	 	 	2,072	 	 	1,045	 	
Accumulated Amortization	 	 	39,912	 	 	844	 	 	36,803	 	 	694	 	 	321	 	
Net Property, Plant and  Equipment Under Capital Leases	 	$	38,509	 	$	2,534	 	$	42,481	 	$	1,378	 	$	724	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations Under Capital Leases:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncurrent Liability	 	$	30,750	 	$	1,778	 	$	37,055	 	$	888	 	$	506	 	
Liability Due Within One Year	 	 	9,174	 	 	756	 	 	5,490	 	 	490	 	 	218	 	
Total Obligations Under  Capital Leases  	 	$	39,924	 	$	2,534	 	$	42,545	 	$	1,378	 	$	724	 	

Future minimum lease payments consisted of the following at December 31, 2006:

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
Capital Leases	 	(in thousands)	 	
2007	 	$	1,011	 	$	4,793	 	$	3,180	 	$	17,135	 	$	1,232	 	
2008	 	 	1,001	 	 	4,268	 	 	2,931	 	 	7,416	 	 	809	 	
2009	 	 	988	 	 	2,094	 	 	1,830	 	 	5,687	 	 	395	 	
2010	 	 	970	 	 	1,557	 	 	1,276	 	 	2,819	 	 	260	 	
2011	 	 	935	 	 	219	 	 	118	 	 	1,875	 	 	97	 	
Later Years	 	 	16,101	 	 	311	 	 	68	 	 	19,205	 	 	83	 	
Total Future Minimum Lease Payments	 	 	21,006	 	 	13,242	 	 	9,403	 	 	54,137	 	 	2,876	 	
Less Estimated Interest Element	 	 	9,005	 	 	1,383	 	 	931	 	 	11,081	 	 	229	 	
Estimated Present Value of Future Minimum Lease Payments	 	$	12,001	 	$	11,859	 	$	8,472	 	$	43,056	 	$	2,647	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Capital Leases	 	(in thousands)	 	
2007	 	$	9,277	 	$	1,728	 	$	13,528	 	$	1,574	 	$	593	 	
2008	 	 	7,173	 	 	1,540	 	 	13,855	 	 	1,488	 	 	565	 	
2009	 	 	5,069	 	 	1,172	 	 	13,610	 	 	1,009	 	 	399	 	
2010	 	 	4,046	 	 	722	 	 	9,380	 	 	394	 	 	206	 	
2011	 	 	1,822	 	 	153	 	 	8,134	 	 	62	 	 	64	 	
Later Years	 	 	20,885	 	 	62	 	 	61,201	 	 	15	 	 	-	 	
Total Future Minimum Lease Payments	 	 	48,272	 	 	5,377	 	 	119,708	 	 	4,542	 	 	1,827	 	
Less Estimated Interest Element	 	 	13,306	 	 	561	 	 	34,993	 	 	445	 	 	184	 	
Estimated Present Value of Future Minimum Lease Payments	 	$	34,966	 	$	4,816	 	$	84,715	 	$	4,097	 	$	1,643	 	

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
Noncancelable Operating Leases	 	(in thousands)	 	
2007	 	$	77,338	 	$	12,436	 	$	5,288	 	$	98,894	 	$	2,069	 	
2008	 	 	77,334	 	 	11,020	 	 	4,665	 	 	98,311	 	 	1,693	 	
2009	 	 	77,331	 	 	8,788	 	 	4,175	 	 	96,614	 	 	1,459	 	
2010	 	 	77,178	 	 	7,685	 	 	3,379	 	 	93,040	 	 	1,348	 	
2011	 	 	76,731	 	 	5,832	 	 	2,286	 	 	91,809	 	 	996	 	
Later Years	 	 	814,478	 	 	14,725	 	 	4,500	 	 	873,750	 	 	2,334	 	
Total Future Minimum  Lease Payments	 	$	1,200,390	 	$	60,486	 	$	24,293	 	$	1,352,418	 	$	9,899	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Noncancelable Operating Leases	 	(in thousands)	 	
2007	 	$	21,269	 	$	6,779	 	$	7,373	 	$	6,243	 	$	2,685	 	
2008	 	 	19,287	 	 	4,730	 	 	6,665	 	 	5,165	 	 	2,444	 	
2009	 	 	18,107	 	 	4,052	 	 	5,614	 	 	4,557	 	 	2,449	 	
2010	 	 	16,576	 	 	4,208	 	 	3,935	 	 	4,363	 	 	2,061	 	
2011	 	 	15,070	 	 	2,475	 	 	2,813	 	 	2,227	 	 	1,097	 	
Later Years	 	 	71,018	 	 	5,834	 	 	6,102	 	 	3,086	 	 	1,974	 	
Total Future Minimum  Lease Payments	 	$	161,327	 	$	28,078	 	$	32,502	 	$	25,641	 	$	12,710	 	

Rockport Lease

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale and leaseback transaction for each respective company as of December 31, 2006 are as follows:

 	 	AEGCo	 	I&M	 	
 	 	(in millions)	 	
2007	 	$	74	 	$	74	 	
2008	 	 	74	 	 	74	 	
2009	 	 	74	 	 	74	 	
2010	 	 	74	 	 	74	 	
2011	 	 	74	 	 	74	 	
Later Years	 	 	812	 	 	812	 	
Total Future Minimum Lease Payments	 	$	1,182	 	$	1,182	 	

Sabine Dragline Lease

In December 2006, Sabine Mining Company (Sabine), an entity consolidated under FIN 46, entered into a capital lease agreement with a nonaffiliated company to finance the purchase of a $51 million electric dragline for Sabine’s mining operations. The initial capital outlay for the dragline was $26 million with an additional estimated $25 million of transportation, assembly and upgrade costs to be incurred prior to the completion date of mid-2008. These additional costs will be added to SWEPCo’s consolidated lease assets and capital lease obligations as they are incurred. Sabine will pay interim rent on a quarterly basis starting in March 2007 and continue through the completion date of mid-2008. Once the dragline is fully assembled, Sabine will pay capital and interest payments on the outstanding lease obligation. At December 31, 2006, the capital lease asset is included in Construction Work in Progress and the capital lease obligation is included in Noncurrent Liabilities - Deferred Credits and Other on SWEPCo’s 2006 Consolidated Balance Sheet. SWEPCo calculated future payments using both interim rent prior to completion and capital and interest from completion until the maturity of the lease solely using the initial capital outlay of $26 million.
 
15.   FINANCING ACTIVITIES

Preferred Stock

 	 	 	 	 	 	 	 	Shares  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Outstanding at	 	Call Price at	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Par  	 	Authorized  	 	December 31,  	 	December 31,  	 	 	 	 	 	 	 	December 31,	 	
Company	 	Value  	 	Shares  	 	2006  	 	2006 (a)  	 	Series  	 	Redemption  	 	2006  	 	2005  	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(in thousands)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APCo	 	$	0	(b)	 	8,000,000	 	 	177,634	 	$	110.00	 	 	4.50%	 	 	Any time	 	$	17,763	 	$	17,784	 	
CSPCo	 	 	25	 	 	7,000,000	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
CSPCo	 	 	100	 	 	2,500,000	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
I&M	 	 	25	 	 	11,200,000	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
I&M	 	 	100	 	 	(c)	 	 	55,357	 	 	106.125	 	 	4.125%	 	 	Any time	 	 	5,535	 	 	5,537	 	
I&M	 	 	100	 	 	(c)	 	 	14,412	 	 	102.00	 	 	4.56%	 	 	Any time	 	 	1,441	 	 	1,441	 	
I&M	 	 	100	 	 	(c)	 	 	11,055	 	 	102.728	 	 	4.12%	 	 	Any time	 	 	1,106	 	 	1,106	 	
OPCo	 	 	25	 	 	4,000,000	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	
OPCo	 	 	100	 	 	(d)	 	 	14,595	 	 	103.00	 	 	4.08%	 	 	Any time	 	 	1,460	 	 	1,460	 	
OPCo	 	 	100	 	 	(d)	 	 	22,824	 	 	103.20	 	 	4.20%	 	 	Any time	 	 	2,282	 	 	2,282	 	
OPCo	 	 	100	 	 	(d)	 	 	31,512	 	 	104.00	 	 	4.40%	 	 	Any time	 	 	3,151	 	 	3,151	 	
OPCo	 	 	100	 	 	(d)	 	 	97,373	 	 	110.00	 	 	4.50%	 	 	Any time	 	 	9,737	 	 	9,746	 	
PSO	 	 	100	 	 	(e)	 	 	44,548	 	 	105.75	 	 	4.00%	 	 	Any time	 	 	4,455	 	 	4,455	 	
PSO	 	 	100	 	 	(e)	 	 	8,069	 	 	103.19	 	 	4.24%	 	 	Any time	 	 	807	 	 	807	 	
SWEPCo	 	 	100	 	 	(f)	 	 	7,386	 	 	103.90	 	 	4.28%	 	 	Any time	 	 	740	 	 	740	 	
SWEPCo	 	 	100	 	 	(f)	 	 	1,907	 	 	102.75	 	 	4.65%	 	 	Any time	 	 	190	 	 	190	 	
SWEPCo	 	 	100	 	 	(f)	 	 	37,673	 	 	109.00	 	 	5.00%	 	 	Any time	 	 	3,767	 	 	3,770	 	
TCC	 	 	100	 	 	(g)	 	 	41,912	 	 	105.75	 	 	4.00%	 	 	Any time	 	 	4,191	 	 	4,192	 	
TCC	 	 	100	 	 	(g)	 	 	17,301	 	 	103.75	 	 	4.20%	 	 	Any time	 	 	1,730	 	 	1,748	 	
TNC	 	 	100	 	 	810,000	 	 	23,486	 	 	107.00	 	 	4.40%	 	 	Any time	 	 	2,349	 	 	2,357	 	

(a)	The cumulative preferred stock is callable at the price indicated plus accrued dividends.	
(b)	Stated value is $100 per share.	
(c)	I&M has 2,250,000 authorized $100 par value per share shares in total.	
(d)	OPCo has 3,762,403 authorized $100 par value per share shares in total.	
(e)	PSO has 700,000 authorized shares in total.	
(f)	SWEPCo has 1,860,000 authorized shares in total.	
(g)	TCC has 3,035,000 authorized shares in total.	

 	 	 	 	 	 	 	Number of Shares Redeemed for the
Year Ended December 31,	 	
 	Company	 	 	Series	 	 	2006	 	 	2005	 	 	2004	 	
 	APCo	 	 	4.50%	 	 	202	 	 	-	 	 	3	 	
 	APCo	 	 	5.90%	 	 	-	 	 	-	 	 	22,100	 	
 	APCo	 	 	5.92%	 	 	-	 	 	-	 	 	31,500	 	
 	I&M	 	 	4.12%	 	 	12	 	 	-	 	 	175	 	
 	I&M	 	 	5.90%	 	 	-	 	 	132,000	 	 	20,000	 	
 	I&M	 	 	6.25%	 	 	-	 	 	192,500	 	 	-	 	
 	I&M	 	 	6.30%	 	 	-	 	 	132,450	 	 	-	 	
 	I&M	 	 	6.875%	 	 	-	 	 	157,500	 	 	-	 	
 	OPCo	 	 	4.50%	 	 	89	 	 	20	 	 	41	 	
 	OPCo	 	 	5.90%	 	 	-	 	 	50,000	 	 	22,500	 	
 	PSO	 	 	4.00%	 	 	-	 	 	-	 	 	50	 	
 	SWEPCo	 	 	5.00%	 	 	30	 	 	-	 	 	-	 	
 	TCC	 	 	4.00%	 	 	10	 	 	-	 	 	5	 	
 	TCC	 	 	4.20%	 	 	175	 	 	-	 	 	-	 	
 	TNC	 	 	4.40%	 	 	80	 	 	-	 	 	4	 	

Long-term Debt

There are certain limitations on establishing liens against the Registrant Subsidiaries’ assets under their respective indentures. None of the long-term debt obligations of the Registrant Subsidiaries have been guaranteed or secured by AEP or any of its affiliates.

The following details long-term debt outstanding as of December 31, 2006 and 2005:

 	 	 	 	Interest Rates at	 	 	 	
 	 	 	 	December 31,	 	December 31,	 	
Type of Debt	 	Maturity	 	2006	 	2005	 	2006	 	2005	 	
AEGCo	 	 	 	 	 	 	 	(in thousands)	 	
Pollution Control Bonds, City of Rockport, 
   Series 1995 A and B (a) (b)	 	2025	 	4.15%	 	4.05%	 	$	45,000	 	$	45,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(163	)	 	(172	)	
Total Pollution Control Bonds - AEGCo	 	 	 	 	 	 	 	 	44,837	 	 	44,828	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total AEGCo Long-term Debt	 	 	 	 	 	 	 	 	44,837	 	 	44,828	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	-	 	 	44,828	 	
Long-Term Debt	 	 	 	 	 	 	 	$	44,837	 	$	-	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, Russell Co., Series I (a)	 	2007	 	-	 	2.70%	 	$	-	 	$	17,500	 	
Pollution Control Bonds, Putnam Co., Series E (a)	 	2019	 	-	 	2.80%	 	 	-	 	 	30,000	 	
Pollution Control Bonds, Putnam Co., Series E (a)	 	2019	 	3.50%	 	-	 	 	30,000	 	 	-	 	
Pollution Control Bonds, Putnam Co., Series F (a)	 	2019	 	3.60%	 	3.10%	 	 	40,000	 	 	40,000	 	
Pollution Control Bonds, Russell Co., Series J (a)	 	2021	 	3.70%	 	-	 	 	17,500	 	 	-	 	
Pollution Control Bonds, Russell Co., Series H (a)	 	2021	 	5.00%	 	5.00%	 	 	19,500	 	 	19,500	 	
Pollution Control Bonds, Mason Co., Series L (a)	 	2022	 	5.50%	 	5.50%	 	 	100,000	 	 	100,000	 	
Pollution Control Bonds, Mason Co., Series K (a)	 	2024	 	6.05%	 	6.05%	 	 	30,000	 	 	30,000	 	
Pollution Control Bonds, West Virginia Econ. Dev. Auth, 
  Series 2006 A (a)	 	2036	 	3.70%	 	-	 	 	50,275	 	 	-	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(215	)	 	(229	)	
Total Pollution Control Bonds - APCo	 	 	 	 	 	 	 	 	287,060	 	 	236,771	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series F	 	2007	 	4.3148%	 	4.3148%	 	 	200,000	 	 	200,000	 	
Senior Unsecured Floating Rate Notes, Series C	 	2007	 	5.6938%	 	4.85%	 	 	125,000	 	 	125,000	 	
Senior Unsecured Notes, Series G	 	2008	 	3.60%	 	3.60%	 	 	200,000	 	 	200,000	 	
Senior Unsecured Notes, Series C	 	2009	 	6.60%	 	6.60%	 	 	150,000	 	 	150,000	 	
Senior Unsecured Notes, Series J	 	2010	 	4.40%	 	4.40%	 	 	150,000	 	 	150,000	 	
Senior Unsecured Notes, Series M	 	2011	 	5.55%	 	-	 	 	250,000	 	 	-	 	
Senior Unsecured Notes, Series I	 	2015	 	4.95%	 	4.95%	 	 	200,000	 	 	200,000	 	
Senior Unsecured Notes, Series K	 	2017	 	5.00%	 	5.00%	 	 	250,000	 	 	250,000	 	
Senior Unsecured Notes, Series H	 	2033	 	5.95%	 	5.95%	 	 	200,000	 	 	200,000	 	
Senior Unsecured Notes, Series L	 	2035	 	5.80%	 	5.80%	 	 	250,000	 	 	250,000	 	
Senior Unsecured Notes, Series N	 	2036	 	6.375%	 	-	 	 	250,000	 	 	-	 	
MTM of Fair Value Hedge	 	 	 	 	 	 	 	 	(1,171	)	 	(1,360	)	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(14,718	)	 	(11,524	)	
Total Senior Unsecured Notes - APCo	 	 	 	 	 	 	 	 	2,209,111	 	 	1,712,116	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Mortgage Bonds, 6.80% Series (d)	 	2006	 	-	 	6.80%	 	 	-	 	 	100,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	-	 	 	(13	)	
Total First Mortgage Bonds - APCo	 	 	 	 	 	 	 	 	-	 	 	99,987	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2010	 	4.708%	 	4.708%	 	 	100,000	 	 	100,000	 	
Total Notes Payable - Affiliated - APCo	 	 	 	 	 	 	 	 	100,000	 	 	100,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Long-term Debt	 	2026	 	13.718%	 	13.718%	 	 	2,493	 	 	2,504	 	
Total Other Long-term Debt - APCo	 	 	 	 	 	 	 	 	2,493	 	 	2,504	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total APCo Long-term Debt	 	 	 	 	 	 	 	 	2,598,664	 	 	2,151,378	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	324,191	 	 	146,999	 	
Long-term Debt	 	 	 	 	 	 	 	$	2,274,473	 	$	2,004,379	 	
 
CSPCo	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, State of Ohio Air Quality 
   Series 2005 D (a)	 	2038	 	3.53%	 	3.20%	 	$	48,550	 	$	48,550	 	
Pollution Control Bonds, State of Ohio Air Quality  
  Series 2005 C (a)	 	2038	 	3.75%	 	3.35%	 	 	43,695	 	 	43,695	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(158	)	 	(163	)	
Total Pollution Control Bonds - CSPCo	 	 	 	 	 	 	 	 	92,087	 	 	92,082	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Medium Term Notes, Series A	 	2008	 	6.51%	 	6.51%	 	 	52,000	 	 	52,000	 	
Senior Unsecured Medium Term Notes, Series B	 	2008	 	6.55%	 	6.55%	 	 	60,000	 	 	60,000	 	
Senior Unsecured Notes, Series E	 	2010	 	4.40%	 	4.40%	 	 	150,000	 	 	150,000	 	
Senior Unsecured Notes, Series C	 	2013	 	5.50%	 	5.50%	 	 	250,000	 	 	250,000	 	
Senior Unsecured Notes, Series B	 	2033	 	6.60%	 	6.60%	 	 	250,000	 	 	250,000	 	
Senior Unsecured Notes, Series F	 	2035	 	5.85%	 	5.85%	 	 	250,000	 	 	250,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(6,765	)	 	(7,162	)	
Total Senior Unsecured Notes - CSPCo	 	 	 	 	 	 	 	 	1,005,235	 	 	1,004,838	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2010	 	4.64%	 	4.64%	 	 	100,000	 	 	100,000	 	
Total Notes Payable - Affiliated - CSPCo	 	 	 	 	 	 	 	 	100,000	 	 	100,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total CSPCo Long-term Debt	 	 	 	 	 	 	 	 	1,197,322	 	 	1,196,920	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	-	 	 	-	 	
Long-Term Debt	 	 	 	 	 	 	 	$	1,197,322	 	$	1,196,920	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
I&M	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, City of Sullivan, Series D (a)	 	2009	 	3.70%	 	3.229%	 	$	45,000	 	$	45,000	 	
Pollution Control Bonds, City of Lawrenceburg, Series F (a)	 	2019	 	-	 	2.625%	 	 	-	 	 	25,000	 	
Pollution Control Bonds, City of Lawrenceburg, Series F (a)	 	2019	 	3.55%	 	-	 	 	25,000	 	 	-	 	
Pollution Control Bonds, City of Lawrenceburg, Series G (a)	 	2021	 	3.50%	 	3.20%	 	 	52,000	 	 	52,000	 	
Pollution Control Bonds, City of Rockport, Series C (a)	 	2025	 	-	 	2.625%	 	 	-	 	 	40,000	 	
Pollution Control Bonds, City of Rockport, Series C (a)	 	2025	 	3.74%	 	-	 	 	40,000	 	 	-	 	
Pollution Control Bonds, City of Rockport, Series B (a)	 	2025	 	3.60%	 	3.20%	 	 	50,000	 	 	50,000	 	
Pollution Control Bonds, City of Rockport, 
  Series 2002A (a) (c)	 	2025	 	4.90%	 	4.90%	 	 	50,000	 	 	50,000	 	
Pollution Control Bonds, City of Rockport, Series 1995A (a)	 	2025	 	-	 	6.55%	 	 	-	 	 	50,000	 	
Pollution Control Bonds, City of Rockport, Series 2006A (a)	 	2025	 	3.90%	 	-	 	 	50,000	 	 	-	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(695	)	 	(733	)	
Total Pollution Control Bonds - I&M	 	 	 	 	 	 	 	 	311,305	 	 	311,267	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series C	 	2006	 	-	 	6.125%	 	 	-	 	 	300,000	 	
Senior Unsecured Notes, Series A	 	2008	 	6.45%	 	6.45%	 	 	50,000	 	 	50,000	 	
Senior Unsecured Notes, Series E	 	2012	 	6.375%	 	6.375%	 	 	100,000	 	 	100,000	 	
Senior Unsecured Notes, Series F	 	2014	 	5.05%	 	5.05%	 	 	175,000	 	 	175,000	 	
Senior Unsecured Notes, Series G	 	2015	 	5.65%	 	5.65%	 	 	125,000	 	 	125,000	 	
Senior Unsecured Notes, Series D	 	2032	 	6.00%	 	6.00%	 	 	150,000	 	 	150,000	 	
Senior Unsecured Notes, Series H	 	2037	 	6.05%	 	-	 	 	400,000	 	 	-	 	
MTM of Fair Value Hedge	 	 	 	 	 	 	 	 	-	 	 	(530	)	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(3,254	)	 	(1,602	)	
Total Senior Unsecured Notes - I&M	 	 	 	 	 	 	 	 	996,746	 	 	897,868	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Spent Nuclear Fuel Liability (e)	 	 	 	 	 	 	 	 	247,084	 	 	235,805	 	
Total Spent Nuclear Fuel Liability - I&M	 	 	 	 	 	 	 	 	247,084	 	 	235,805	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total I&M Long-term Debt	 	 	 	 	 	 	 	 	1,555,135	 	 	1,444,940	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	50,000	 	 	364,469	 	
Long-term Debt	 	 	 	 	 	 	 	$	1,505,135	 	$	1,080,471	 	
 
KPCo	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series B	 	2007	 	4.3148%	 	4.3148%	 	 	80,400	 	 	80,400	 	
Senior Unsecured Notes, Series C	 	2007	 	4.368%	 	4.368%	 	 	69,564	 	 	69,564	 	
Senior Unsecured Notes, Series A	 	2007	 	5.50%	 	5.50%	 	 	125,000	 	 	125,000	 	
Senior Unsecured Medium Term Notes, Series A	 	2007	 	6.91%	 	6.91%	 	 	48,000	 	 	48,000	 	
Senior Unsecured Medium Term Notes, Series A	 	2008	 	6.45%	 	6.45%	 	 	30,000	 	 	30,000	 	
Senior Unsecured Notes, Series D	 	2032	 	5.625%	 	5.625%	 	 	75,000	 	 	75,000	 	
MTM of Fair Value Hedge	 	 	 	 	 	 	 	 	(916	)	 	(800	)	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(80	)	 	(174	)	
Total Senior Unsecured Notes - KPCo	 	 	 	 	 	 	 	 	426,968	 	 	426,990	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2006	 	-	 	6.501%	 	 	-	 	 	40,000	 	
Notes Payable - Affiliated	 	2015	 	5.25%	 	5.25%	 	 	20,000	 	 	20,000	 	
Total Notes Payable - Affiliated - KPCo	 	 	 	 	 	 	 	 	20,000	 	 	60,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total KPCo Long-term Debt	 	 	 	 	 	 	 	 	446,968	 	 	486,990	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	322,048	 	 	39,771	 	
Long-term Debt	 	 	 	 	 	 	 	$	124,920	 	$	447,219	 	
 	 	 	 	 	 	 	 	 	 	
OPCo	 	 	 	 	 	 	 	(in thousands)	 	
Pollution Control Bonds, Marshall Co., WV, Series C (a)	 	2014	 	3.60%	 	3.35%	 	$	50,000	 	$	50,000	 	
Pollution Control Bonds, Mason Co., WV, Series C (a)	 	2016	 	3.60%	 	3.36%	 	 	50,000	 	 	50,000	 	
Pollution Control Bonds, Marshall Co., WV, Series F (a)	 	2022	 	3.60%	 	3.35%	 	 	35,000	 	 	35,000	 	
Pollution Control Bonds, Marshall Co., WV, Series E (a)	 	2022	 	3.75%	 	3.45%	 	 	50,000	 	 	50,000	 	
Pollution Control Bonds, JMG Air Quality   Revenue Bonds, 
  1997 Series A (a)	 	2022	 	5.5625%	 	5.5625%	 	 	19,565	 	 	19,565	 	
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 
   1997 Series B (a)	 	2023	 	5.5625%	 	5.5625%	 	 	19,565	 	 	19,565	 	
Pollution Control Bonds, Ohio Air Quality Revenue Bonds, 
  1 999 Series C (a)	 	2026	 	5.15%	 	5.15%	 	 	50,000	 	 	50,000	 	
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 
   2005 Series B (a)	 	2028	 	3.70%	 	3.10%	 	 	54,500	 	 	54,500	 	
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 
   2005 Series C (a)	 	2028	 	3.80%	 	3.15%	 	 	54,500	 	 	54,500	 	
Pollution Control Bonds, JMG Air Quality Revenue Bonds,
  2005 Series D (a)	 	2028	 	3.70%	 	3.16%	 	 	54,500	 	 	54,500	 	
Pollution Control Bonds, JMG Air Quality Revenue Bonds, 
   Series 2005 A (a)	 	2029	 	3.70%	 	3.15%	 	 	54,500	 	 	54,500	 	
Pollution Control Bonds, West Virginia Econ. Dev. Auth., 
   Series 2006A (a)	 	2036	 	3.85%	 	-	 	 	65,000	 	 	-	 	
Total Pollution Control Bonds - OPCo	 	 	 	 	 	 	 	 	557,130	 	 	492,130	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Medium Notes, Series A	 	2008	 	6.24%	 	6.24%	 	 	37,225	 	 	37,225	 	
Senior Unsecured Notes, Series J	 	2010	 	5.30%	 	5.30%	 	 	200,000	 	 	200,000	 	
Senior Unsecured Notes, Series D	 	2013	 	5.50%	 	5.50%	 	 	250,000	 	 	250,000	 	
Senior Unsecured Notes, Series H	 	2014	 	4.85%	 	4.85%	 	 	225,000	 	 	225,000	 	
Senior Unsecured Notes, Series K	 	2016	 	6.00%	 	-	 	 	350,000	 	 	-	 	
Senior Unsecured Notes, Series I	 	2033	 	6.375%	 	6.375%	 	 	225,000	 	 	225,000	 	
Senior Unsecured Notes, Series E	 	2033	 	6.60%	 	6.60%	 	 	250,000	 	 	250,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(5,932	)	 	(5,356	)	
Total Senior Unsecured Notes - OPCo	 	 	 	 	 	 	 	 	1,531,293	 	 	1,181,869	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2006	 	-	 	3.32%	 	 	-	 	 	200,000	 	
Notes Payable - Affiliated	 	2015	 	5.25%	 	5.25%	 	 	200,000	 	 	200,000	 	
Total Notes Payable - Affiliated - OPCo	 	 	 	 	 	 	 	 	200,000	 	 	400,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Nonaffiliated, JMG Funding Corp., Series B  	 	2008	 	6.81%	 	6.81%	 	 	7,318	 	 	13,171	 	
Notes Payable - Nonaffiliated, JMG Funding Corp., Series D	 	2009	 	6.27%	 	6.27%	 	 	25,000	 	 	31,500	 	
Notes Payable - Nonaffiliated, JMG Funding Corp., Series F	 	2009	 	7.21%	 	7.21%	 	 	11,000	 	 	11,000	 	
Notes Payable - Nonaffiliated, JMG Funding Corp., Series E	 	2009	 	7.49%	 	7.49%	 	 	70,000	 	 	70,000	 	
Total Notes Payable - Nonaffiliated - OPCo	 	 	 	 	 	 	 	 	113,318	 	 	125,671	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total OPCo Long-term Debt	 	 	 	 	 	 	 	 	2,401,741	 	 	2,199,670	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	17,854	 	 	212,354	 	
Long-term Debt	 	 	 	 	 	 	 	$	2,383,887	 	$	1,987,316	 	
 
PSO	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, Oklahoma Development Finance Auth., 
  Series 2004 (a)	 	2014	 	3.60%	 	3.15%	 	$	33,700	 	$	33,700	 	
Pollution Control Bonds, Red River Auth. of Texas,  Series 1996 (a)	 	2020	 	6.00%	 	6.00%	 	 	12,660	 	 	12,660	 	
Total Pollution Control Bonds - PSO	 	 	 	 	 	 	 	 	46,360	 	 	46,360	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series D	 	2009	 	4.70%	 	4.70%	 	 	50,000	 	 	50,000	 	
Senior Unsecured Notes, Series C	 	2010	 	4.85%	 	4.85%	 	 	150,000	 	 	150,000	 	
Senior Unsecured Notes, Series E	 	2011	 	4.70%	 	4.70%	 	 	75,000	 	 	75,000	 	
Senior Unsecured Notes, Series F	 	2016	 	6.15%	 	-	 	 	150,000	 	 	-	 	
Senior Unsecured Notes, Series B	 	2032	 	6.00%	 	6.00%	 	 	200,000	 	 	200,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(1,362	)	 	(289	)	
Total Senior Unsecured Notes - PSO	 	 	 	 	 	 	 	 	623,638	 	 	474,711	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2006	 	-	 	3.35%	 	 	-	 	 	50,000	 	
Total Notes Payable - Affiliated - PSO	 	 	 	 	 	 	 	 	-	 	 	50,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total PSO Long-term Debt	 	 	 	 	 	 	 	 	669,998	 	 	571,071	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	-	 	 	50,000	 	
Long-term Debt	 	 	 	 	 	 	 	$	669,998	 	$	521,071	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SWEPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, Titus Co., Series 2004 (a)	 	2011	 	3.60%	 	3.10%	 	$	41,135	 	$	41,135	 	
Pollution Control Bonds, Series 1996 Sabine River (a)	 	2018	 	-	 	6.10%	 	 	-	 	 	81,700	 	
Pollution Control Bonds, Sabine River Auth. of Texas, 
   Series 2006 (a)	 	2018	 	3.88%	 	-	 	 	81,700	 	 	 	 	
Pollution Control Bonds, Parish of DeSoto, Series 2004 (a)	 	2019	 	3.65%	 	3.40%	 	 	53,500	 	 	53,500	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	1,360	 	 	1,342	 	
Total Pollution Control Bonds - SWEPCo	 	 	 	 	 	 	 	 	177,695	 	 	177,677	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series D	 	2015	 	4.90%	 	4.90%	 	 	150,000	 	 	150,000	 	
Senior Unsecured Notes, Series C	 	2015	 	5.38%	 	5.375%	 	 	100,000	 	 	100,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(178	)	 	(199	)	
Total Senior Unsecured Notes - SWEPCo	 	 	 	 	 	 	 	 	249,822	 	 	249,801	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Mortgage Bonds, Series 1976A Siloam Springs (d)	 	2006	 	-	 	6.20%	 	 	-	 	 	5,070	 	
First Mortgage Bonds, Series 1976B Siloam Springs (d)	 	2006	 	-	 	6.20%	 	 	-	 	 	1,000	 	
First Mortgage Bonds, Series X (d)	 	2007	 	7.00%	 	7.00%	 	 	90,000	 	 	90,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(48	)	 	(119	)	
Total First Mortgage Bonds - SWEPCo	 	 	 	 	 	 	 	 	89,952	 	 	95,951	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2010	 	4.45%	 	4.45%	 	 	50,000	 	 	50,000	 	
Total Notes Payable - Affiliated - SWEPCo	 	 	 	 	 	 	 	 	50,000	 	 	50,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Nonaffiliated, Sabine Mines	 	2007	 	6.36%	 	6.36%	 	 	4,000	 	 	4,000	 	
Notes Payable - Nonaffiliated, Sabine Mines	 	2008	 	5.93675%	 	5.12688%	 	 	4,500	 	 	7,500	 	
Notes Payable - Nonaffiliated, Dolet Hills Lignite Co., LLC	 	2011	 	4.47%	 	4.47%	 	 	19,998	 	 	26,683	 	
Notes Payable - Nonaffiliated, Sabine Mines	 	2012	 	7.03%	 	7.03%	 	 	20,000	 	 	20,000	 	
Total Notes Payable - Nonaffiliated - SWEPCo	 	 	 	 	 	 	 	 	48,498	 	 	58,183	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable to Trust, 5.25% TPS Flexible	 	2043	 	5.25%	 	5.25%	 	 	113,403	 	 	113,403	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(364	)	 	(374	)	
Total Notes Payable to Trust - SWEPCo	 	 	 	 	 	 	 	 	113,039	 	 	113,029	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total SWEPCo Long-term Debt	 	 	 	 	 	 	 	 	729,006	 	 	744,641	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	102,312	 	 	15,755	 	
Long-term Debt	 	 	 	 	 	 	 	$	626,694	 	$	728,886	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TCC	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1, 
  Series 2001A (a)	 	2006	 	-	 	4.55%	 	$	-	 	$	100,635	 	
Pollution Control Bonds, Guadalupe-Blanco River Auth., 
  Series 2005 (a)	 	2015	 	3.75%	 	3.35%	 	 	40,890	 	 	40,890	 	
Pollution Control Bonds, Red River Auth. of  Texas,  Series 1996(a)	 	2020	 	6.00%	 	6.00%	 	 	6,330	 	 	6,330	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1,
  Series 2005C-1 (a)	 	2028	 	3.65%	 	3.30%	 	 	60,000	 	 	60,000	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1,
  Series 2005C-2 (a)	 	2028	 	3.60%	 	3.45%	 	 	60,265	 	 	60,265	 	
Pollution Control Bonds, Matagorda Co. Navigation D istrict #1,
  Series 2005B (a)	 	2030	 	-	 	3.15%	 	 	-	 	 	50,000	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1,
  Series 2005B (a)	 	2030	 	4.55%	 	-	 	 	50,000	 	 	-	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1,
  Series 2005A (a)	 	2030	 	-	 	3.30%	 	 	-	 	 	111,700	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1,
  Series 2005A (a)	 	2030	 	4.40%	 	-	 	 	111,700	 	 	-	 	
Pollution Control Bonds, Matagorda Co. Navigation  District #1,
  Series 1996 (a)	 	2030	 	6.125%	 	6.125%	 	 	60,000	 	 	60,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(208	)	 	(217	)	
Total Pollution Control Bonds - TCC	 	 	 	 	 	 	 	 	388,977	 	 	489,603	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series A	 	2013	 	-	 	5.50%	 	 	-	 	 	275,000	 	
Senior Unsecured Notes, Series B	 	2033	 	6.65%	 	6.65%	 	 	275,000	 	 	275,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(1,170	)	 	(1,958	)	
Total Senior Unsecured Notes - TCC	 	 	 	 	 	 	 	 	273,830	 	 	548,042	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Mortgage Bonds, Series GG (d)	 	2008	 	7.125%	 	7.125%	 	 	18,581	 	 	18,581	 	
Total First Mortgage Bonds - TCC	 	 	 	 	 	 	 	 	18,581	 	 	18,581	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable - Affiliated	 	2007	 	-	 	4.58%	 	 	-	 	 	150,000	 	
Total Notes Payable - Affiliated - TCC	 	 	 	 	 	 	 	 	-	 	 	150,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Securitization Bonds, Class 2002 A-2	 	2008 (f)	 	5.01%	 	5.01%	 	 	81,649	 	 	133,914	 	
Securitization Bonds, Class 2006 A-1 (g)	 	2010 (f)	 	4.98%	 	-	 	 	217,000	 	 	-	 	
Securitization Bonds, Class 2002 A-3	 	2010 (f)	 	5.56%	 	5.56%	 	 	107,094	 	 	107,094	 	
Securitization Bonds, Class 2006 A-2 (g)	 	2013 (f)	 	4.98%	 	-	 	 	341,000	 	 	-	 	
Securitization Bonds, Class 2002 A-4	 	2013 (f)	 	5.96%	 	5.96%	 	 	214,927	 	 	214,927	 	
Securitization Bonds, Class 2006 A-3 (g)	 	2015 (f)	 	5.09%	 	-	 	 	250,000	 	 	-	 	
Securitization Bonds, Class 2002 A-5	 	2016 (f)	 	6.25%	 	6.25%	 	 	191,857	 	 	191,857	 	
Securitization Bonds, Class 2006 A-4 (g)	 	2018 (f)	 	5.17%	 	-	 	 	437,000	 	 	-	 	
Securitization Bonds, Class 2006 A-5 (g)	 	2020 (f)	 	5.3063%	 	-	 	 	494,700	 	 	-	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(1,001	)	 	(522	)	
Total Securitization Bonds - TCC	 	 	 	 	 	 	 	 	2,334,226	 	 	647,270	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total TCC Long-term Debt	 	 	 	 	 	 	 	 	3,015,614	 	 	1,853,496	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	78,227	 	 	152,900	 	
Long-term Debt	 	 	 	 	 	 	 	$	2,937,387	 	$	1,700,596	 	
 	 	 	 	 	 	 	 	 	 	
TNC	 	 	 	 	 	 	 	 	 	
Pollution Control Bonds, Red River Auth. of Texas,  Series 1996 (a)	 	2020	 	6.00%	 	6.00%	 	$	44,310	 	$	44,310	 	
Total Pollution Control Bonds - TNC	 	 	 	 	 	 	 	 	44,310	 	 	44,310	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Unsecured Notes, Series A	 	2013	 	5.50%	 	5.50%	 	 	225,000	 	 	225,000	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	(525	)	 	(615	)	
Total Senior Unsecured Notes - TNC	 	 	 	 	 	 	 	 	224,475	 	 	224,385	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Mortgage Bonds, Series P (d)	 	2007	 	7.75%	 	7.75%	 	 	8,151	 	 	8,151	 	
Unamortized Premium (Discount)	 	 	 	 	 	 	 	 	-	 	 	(1	)	
Total First Mortgage Bonds - TNC	 	 	 	 	 	 	 	 	8,151	 	 	8,150	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total TNC Long-term Debt	 	 	 	 	 	 	 	 	276,936	 	 	276,845	 	
Less: Long-term Debt Due Within One Year	 	 	 	 	 	 	 	 	8,151	 	 	-	 	
Long-term Debt	 	 	 	 	 	 	 	$	268,785	 	$	276,845	 	

(a)	Under the terms of the pollution control bonds, each Registrant Subsidiary is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Interest payments range from monthly to semi-annually.	
(b)	The fixed rate bonds of AEGCo due in 2025 are subject to mandatory tender for purchase on July 15, 2011. Consequently, the fixed rate bonds have been classified for repayment purposes in 2011.	
(c)	I&M’s pollution control bonds for City of Rockport, Series 2002A maturing in 2025 provides for bonds to be tendered in 2007. Therefore, these pollution control bonds have been classified for payment in 2007.	
(d)	First mortgage bonds are secured by the first mortgage liens on Electric Property, Plant and Equipment. Certain supplemental indentures to the first mortgage liens contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually. TCC’s first mortgage bonds were defeased in 2004 and TNC’s first mortgage bonds were defeased in 2005.	
(e)	Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets of $274 million and $264 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheets at December 31, 2006 and 2005, respectively.	
(f)	This date represents the scheduled final payment date for this class of TCC’s securitization bonds. The contractual maturity date is one to two years later. These bonds have been classified for repayment purposes based on the scheduled final payment date.	
(g)	In October 2006, AEP Texas Central Transition Funding II LLC (TFII), a subsidiary of TCC, issued $1.7 billion in securitization bonds.  TFII is the sole owner of the transition charges and the orginal transition property.  The holders of the securititization bonds do not have recourse to any assets or revenues of TCC.  The creditors of TCC do not have recourse to any assets or revenues of TFII, including, without limitation, the orginal transition property.	
 
At December 31, 2006 future annual long-term debt payments are as follows:

 	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
2007	 	$	-	 	$	324,191	 	$	-	 	$	50,000	 	$	322,048	 	
2008	 	 	-	 	 	199,665	 	 	112,000	 	 	50,000	 	 	30,000	 	
2009	 	 	-	 	 	150,017	 	 	-	 	 	45,000	 	 	-	 	
2010	 	 	-	 	 	250,019	 	 	250,000	 	 	-	 	 	-	 	
2011	 	 	45,000	 	 	250,022	 	 	-	 	 	-	 	 	-	 	
Later Years	 	 	-	 	 	1,439,683	 	 	842,245	 	 	1,414,083	 	 	95,000	 	
Total Principal Amount	 	 	45,000	 	 	2,613,597	 	 	1,204,245	 	 	1,559,083	 	 	447,048	 	
Unamortized Discount	 	 	(163	)	 	(14,933	)	 	(6,923	)	 	(3,948	)	 	(80	)	
Total	 	$	44,837	 	$	2,598,664	 	$	1,197,322	 	$	1,555,135	 	$	446,968	 	

 	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
 	 	  	 	  	 	  	 	  	 	  	 	
2007	 	$	17,854	 	$	-	 	$	102,312	 	$	78,227	 	$	8,151	 	
2008	 	 	55,188	 	 	-	 	 	5,906	 	 	143,419	 	 	-	 	
2009	 	 	77,500	 	 	50,000	 	 	4,406	 	 	137,141	 	 	-	 	
2010	 	 	200,000	 	 	150,000	 	 	54,406	 	 	147,833	 	 	-	 	
2011	 	 	-	 	 	75,000	 	 	42,603	 	 	159,443	 	 	-	 	
Later Years	 	 	2,057,131	 	 	396,360	 	 	518,603	 	 	2,351,930	 	 	269,310	 	
Total Principal Amount	 	 	2,407,673	 	 	671,360	 	 	728,236	 	 	3,017,993	 	 	277,461	 	
Unamortized Premium/(Discount)	 	 	(5,932	)	 	(1,362	)	 	770	 	 	(2,379	)	 	(525	)	
Total	 	$	2,401,741	 	$	669,998	 	$	729,006	 	$	3,015,614	 	$	276,936	 	

In January 2007, SWEPCo issued a 5.55%, $250 million Senior Unsecured Note due in January 2017.

In January 2007, SWEPCo retired $548 thousand of 4.47% notes.

In January 2007, TCC retired $32.1 million of 5.01% securitization bonds.

Dividend Restrictions

Under the Federal Power Act, the Registrants Subsidiaries can only pay dividends out of retained or current earnings unless they obtain prior FERC approval.

Trust Preferred Securities

SWEPCo has a wholly-owned business trust that issued trust preferred securities. Effective July 1, 2003, the trust was deconsolidated due to the implementation of FIN 46. The SWEPCo trust, which holds mandatorily redeemable trust preferred securities, is reported as two components on the Consolidated Balance Sheets. The investment in the trust, which was $3 million as of December 31, 2006 and 2005, is reported as Deferred Charges and Other within Other Noncurrent Assets. The Junior Subordinated Debentures, in the amount of $113 million as of December 31, 2006 and 2005, are reported as Notes Payable to Trust within Long-term Debt - Nonaffiliated.

The business trust is treated as a nonconsolidated subsidiary of its parent company. The only asset of the business trust is the subordinated debentures issued by its parent company as specified above. In addition to the obligations under the subordinated debentures, the parent company has also agreed to a security obligation, which represents a full and unconditional guarantee of its capital trust obligation.
 
Lines of Credit and Short-term Debt - AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. The AEP System corporate borrowing program operates in accordance with the terms and conditions approved in a regulatory order. The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of December 31, 2006 and 2005 are included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized limits for the years ended December 31, 2006 and 2005 are described in the following tables:

Year Ended December 31, 2006:	 	
 	 	
 	 	Maximum Borrowings from Utility Money Pool	 	Maximum Loans to Utility Money Pool	 	Average Borrowings from Utility Money Pool	 	Average Loans to Utility Money Pool	 	Loans (Borrowings) to/from Utility Money Pool as of December 31, 2006	 	Authorized
Short-Term Borrowing Limit	 	
Company	 	(in thousands)	 	
AEGCo	 	$	79,828	 	$	2,247	 	$	21,940	 	$	2,247	 	$	(53,646	)	$	125,000	 	
APCo	 	 	283,872	 	 	314,064	 	 	169,937	 	 	149,103	 	 	(34,975	)	 	600,000	 	
CSPCo	 	 	48,337	 	 	95,977	 	 	14,703	 	 	45,886	 	 	(696	)	 	350,000	 	
I&M	 	 	128,071	 	 	322,067	 	 	62,659	 	 	292,504	 	 	(91,173	)	 	500,000	 	
KPCo	 	 	46,156	 	 	11,993	 	 	25,994	 	 	4,384	 	 	(30,636	)	 	200,000	 	
OPCo	 	 	351,302	 	 	40,382	 	 	102,302	 	 	15,845	 	 	(181,281	)	 	600,000	 	
PSO	 	 	167,456	 	 	146,657	 	 	94,328	 	 	58,541	 	 	(76,323	)	 	300,000	 	
SWEPCo	 	 	189,021	 	 	24,209	 	 	66,848	 	 	9,411	 	 	(188,965	)	 	350,000	 	
TCC	 	 	117,429	 	 	818,415	 	 	44,416	 	 	199,100	 	 	394,004	 	 	600,000	 	
TNC	 	 	23,660	 	 	34,574	 	 	7,988	 	 	8,381	 	 	(235	)	 	250,000	 	

Year Ended December 31, 2005:

 	 	Maximum Borrowings from Utility Money Pool	 	Maximum Loans to Utility Money Pool	 	Average Borrowings from Utility Money Pool	 	Average Loans to Utility Money Pool	 	Loans (Borrowings) to/from Utility Money Pool as of December 31, 2005	 	Authorized
Short-Term Borrowing Limit	 	
Company	 	(in thousands)	 	
AEGCo	 	$	45,694	 	$	9,305	 	$	15,551	 	$	4,272	 	$	(35,131	)	$	125,000	 	
APCo	 	 	242,718	 	 	321,977	 	 	134,079	 	 	44,622	 	 	(194,133	)	 	600,000	 	
CSPCo	 	 	180,397	 	 	181,238	 	 	143,885	 	 	94,083	 	 	(17,609	)	 	350,000	 	
I&M	 	 	203,248	 	 	11,768	 	 	87,208	 	 	5,797	 	 	(93,702	)	 	500,000	 	
KPCo	 	 	9,964	 	 	35,779	 	 	2,969	 	 	12,653	 	 	(6,040	)	 	200,000	 	
OPCo	 	 	162,907	 	 	182,495	 	 	64,142	 	 	75,186	 	 	(70,071	)	 	600,000	 	
PSO	 	 	101,962	 	 	66,159	 	 	30,205	 	 	32,632	 	 	(75,883	)	 	300,000	 	
SWEPCo	 	 	55,756	 	 	188,215	 	 	17,657	 	 	34,490	 	 	(28,210	)	 	350,000	 	
TCC	 	 	320,508	 	 	120,937	 	 	109,463	 	 	39,060	 	 	(82,080	)	 	600,000	 	
TNC	 	 	13,606	 	 	119,569	 	 	10,930	 	 	58,067	 	 	34,286	 	 	250,000	 	

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the years ended December 31, 2006, 2005 and 2004 were as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Maximum Interest Rate	 	5.41%	 	4.49%	 	2.24%	 	
Minimum Interest Rate	 	3.32%	 	1.63%	 	0.89%	 	
 
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2006, 2005 and 2004 are summarized for all Registrant Subsidiaries in the following table:

 	 	Average Interest Rate for Funds
Borrowed from the Utility Money Pool for
Year Ended December 31,	 	 	 	Average Interest Rate for Funds
Loaned to the Utility Money Pool for
Year Ended December 31,	 	
Company	 	2006	 	2005	 	2004	 	 	 	2006	 	2005	 	2004	 	
 	 	(in percentage)	 	
AEGCo	 	4.79	 	3.27	 	1.47	 	 	 	5.11	 	3.17	 	1.91	 	
APCo	 	4.63	 	3.40	 	1.68	 	 	 	4.93	 	3.15	 	1.48	 	
CSPCo	 	4.76	 	3.95	 	1.50	 	 	 	4.37	 	3.03	 	1.69	 	
I&M	 	4.80	 	3.43	 	1.45	 	 	 	3.84	 	2.12	 	1.93	 	
KPCo	 	4.74	 	3.70	 	1.59	 	 	 	4.97	 	2.70	 	1.61	 	
OPCo	 	4.74	 	3.86	 	1.29	 	 	 	5.12	 	2.57	 	1.46	 	
PSO	 	5.02	 	3.37	 	1.38	 	 	 	4.35	 	3.56	 	1.80	 	
SWEPCo	 	4.79	 	4.10	 	1.37	 	 	 	4.45	 	2.62	 	1.67	 	
TCC	 	4.79	 	3.18	 	1.40	 	 	 	4.24	 	2.43	 	1.47	 	
TNC	 	4.60	 	4.41	 	1.09	 	 	 	4.56	 	3.29	 	1.56	 	

Interest expense related to the Utility Money Pool is included in Interest Expense in each of the Registrant Subsidiaries’ Financial Statements. The Registrant Subsidiaries incurred interest expense for amounts borrowed from the Utility Money Pool as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
AEGCo	 	$	1,046	 	$	418	 	$	338	 	
APCo	 	 	2,656	 	 	2,830	 	 	1,136	 	
CSPCo	 	 	284	 	 	280	 	 	32	 	
I&M	 	 	2,772	 	 	2,854	 	 	1,127	 	
KPCo	 	 	1,065	 	 	18	 	 	65	 	
OPCo	 	 	4,473	 	 	1,056	 	 	51	 	
PSO	 	 	3,037	 	 	637	 	 	486	 	
SWEPCo	 	 	3,234	 	 	293	 	 	219	 	
TCC	 	 	724	 	 	3,272	 	 	177	 	
TNC	 	 	274	 	 	8	 	 	8	 	

Interest income related to the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ Financial Statements. Interest income earned from amounts advanced to the Utility Money Pool by Registrant Subsidiary were:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
AEGCo	 	$	-	 	$	24	 	$	1	 	
APCo	 	 	5,007	 	 	543	 	 	24	 	
CSPCo	 	 	1,231	 	 	2,757	 	 	1,076	 	
I&M	 	 	967	 	 	6	 	 	84	 	
KPCo	 	 	30	 	 	287	 	 	177	 	
OPCo	 	 	63	 	 	1,129	 	 	1,965	 	
PSO	 	 	941	 	 	431	 	 	76	 	
SWEPCo	 	 	216	 	 	649	 	 	649	 	
TCC	 	 	5,591	 	 	66	 	 	1,445	 	
TNC	 	 	112	 	 	1,897	 	 	587	 	
 
In the third quarter of 2006, TNC created a new wholly-owned subsidiary, AEP Texas North Generation Company, LLC (TNGC). Following the creation of this subsidiary, TNC transferred all of its mothballed generation assets and related liabilities to this new subsidiary, effectively completing the business separation requirement of the Texas Restructuring Legislation. Subsequently, TNGC became a participant in the Nonutility Money Pool. As of December 31, 2006, TNGC had $13.8 million in loans to the Nonutility Money Pool. For the year ended December 31, 2006, TNGC paid an immaterial amount of interest expense for borrowings from the Nonutility Money Pool and earned $233 thousand in interest income for loans to the Nonutility Money Pool. For the year ended December 31, 2006, the average interest rate for funds either borrowed from or loaned to the Nonutility Money Pool by TNGC was 5.36%.

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

 	 	 	 	At December 31, 2006	 	 	At December 31, 2005	 	
 	 	Type of Debt	 	Outstanding
Amount	 	Interest
Rate	 	 	Outstanding
Amount	 	Interest
Rate	 	
Company	 	 	 	(in millions)	 	 	 	 	 	(in millions)	 	 	 	 	
OPCo	 	Commercial Paper - JMG (a)	 	$	1	 	 	5.56	%	 	$	10	 	 	4.47	%	
SWEPCo	 	Line of Credit - Sabine	 	 	17	 	 	6.38	%	 	 	1	 	 	5.31	%	

(a)	This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility. This commercial paper does not reduce our available liquidity.	

Sale of Receivables - AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires from affiliated utility subsidiaries to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,” allowing the receivables to be taken off of AEP Credit’s balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and is not required to consolidate these entities in accordance with GAAP. AEP Credit continues to service the receivables. This off-balance sheet transaction was entered into to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies’ receivables, and accelerate AEP Credit’s cash collections.

AEP Credit’s sale of receivables agreement expires on August 24, 2007. AEP intends to extend or replace the sale of receivables agreement. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2006, $536 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent receivables purchased by AEP Credit from certain Registrant Subsidiaries. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo’s accounts receivable are sold to AEP Credit.
 
Comparative accounts receivable information for AEP Credit is as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
 	 	($ in millions)	 	
Proceeds from Sale of Accounts Receivable	 	$	6,849	 	$	5,925	 	$	5,163	 	
Loss on Sale of Accounts Receivable	 	$	31	 	$	18	 	$	7	 	
Average Variable Discount Rate	 	 	5.02	% 	 	3.23	% 	 	1.50	% 	

 	 	December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Accounts Receivable Retained Interest and Pledged as Collateral  Less
  Uncollectible Accounts	 	$	87	 	 	106	 	
Deferred Revenue from Servicing Accounts Receivable	 	 	1	 	 	1	 	
Retained Interest if 10% Adverse Change in Uncollectible Accounts	 	 	85	 	 	103	 	
Retained Interest if 20% Adverse Change in Uncollectible Accounts	 	 	83	 	 	101	 	

Historical loss and delinquency amounts for the AEP System’s customer accounts receivable managed portfolio is as follows:
 
 	 	Face Value
December 31,	 	
 	 	2006	 	2005	 	
 	 	(in millions)	 	
Customer Accounts Receivable Retained	 	$	676	 	$	826	 	
Accrued Unbilled Revenues Retained	 	 	350	 	 	374	 	
Miscellaneous Accounts Receivable Retained	 	 	44	 	 	51	 	
Allowance for Uncollectible Accounts Retained	 	 	(30	)	 	(31	)	
Total Net Balance Sheet Accounts Receivable	 	 	1,040	 	 	1,220	 	
Customer Accounts Receivable Securitized	 	 	536	 	 	516	 	
Total Accounts Receivable Managed	 	$	1,576	 	$	1,736	 	
 	 	 	 	 	 	 	 	
Net Uncollectible Accounts Written Off	 	$	31	 	$	74	 	

Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous accounts receivable have been fully retained and not securitized.

Delinquent customer accounts receivable for the electric utility affiliates that AEP Credit currently factors were $29 million and $30 million at December 31, 2006 and 2005, respectively. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

Under the factoring arrangement, participating Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company’s receivables and administrative costs. The costs of factoring customer accounts receivable are reported in Other Operation of the participant’s Statements of Income.
 
The amount of factored accounts receivable and accrued unbilled revenues for each Registrant Subsidiary was as follows:

 	 	As of December 31,	 	
 	 	2006	 	2005	 	
Company	 	(in millions)	 	
APCo	 	$	102.1	 	$	77.1	 	
CSPCo	 	 	142.5	 	 	124.4	 	
I&M	 	 	94.5	 	 	102.7	 	
KPCo	 	 	44.0	 	 	38.7	 	
OPCo	 	 	140.2	 	 	122.1	 	
PSO	 	 	119.4	 	 	146.5	 	
SWEPCo	 	 	102.7	 	 	100.4	 	

The fees paid by the Registrant Subsidiaries to AEP Credit for factoring customer accounts receivable were:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in millions)	 	
APCo	 	$	6.3	 	$	5.1	 	$	3.9	 	
CSPCo	 	 	13.7	 	 	7.4	 	 	10.2	 	
I&M	 	 	9.2	 	 	7.4	 	 	6.5	 	
KPCo	 	 	3.4	 	 	2.9	 	 	2.6	 	
OPCo	 	 	11.1	 	 	6.1	 	 	7.7	 	
PSO	 	 	16.3	 	 	11.1	 	 	8.9	 	
SWEPCo	 	 	10.5	 	 	8.3	 	 	5.8	 	

        16.   RELATED PARTY TRANSACTIONS

For other related party transactions, also see “Lines of Credit - AEP System” and “Sale of Receivables-AEP Credit” sections of Note 15.

AEP System Power Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (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,” which is calculated monthly on the basis of each company’s maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement, which provides, among other things, for the transfer of SO 2 allowances associated with the transactions under the Interconnection Agreement.

Power, gas and risk management activities are conducted by the AEP Power Pool and profits/losses are shared among the parties under the System Integration Agreement. Risk management activities involve the purchase and sale of electricity and gas under physical forward contracts at fixed and variable prices. In addition, the risk management of electricity, and to a lesser extent gas contracts, includes exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System’s traditional marketing area and are typically settled by entering into offsetting contracts. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity and gas options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System’s traditional marketing area.

CSW Operating Agreement

PSO, SWEPCo, TCC, TNC 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 the AEP West companies to maintain adequate annual planning reserve margins and requires the operating companies that have capacity in excess of the required margins to make such capacity available for sale to other operating companies as capacity commitments. Parties are compensated for energy delivered to 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 are generally shared based on the amount of energy each AEP West company contributes that is sold to third parties.

In February 2006, AEP filed with the FERC a proposed amendment to the CSW Operating Agreement to remove TCC and TNC as parties to the agreement. Pursuant to Texas electric restructuring law, those companies exited the generation and load-servicing businesses. AEP made a similar filing to remove those two companies as parties to the System Integration Agreement. The filings were approved effective May 1, 2006 and April 1, 2006, respectively.

System Integration Agreement

AEP’s System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP’s East companies and West companies zones. 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 within each zone.

In November 2005, AEP filed with the FERC a proposed amendment to the System Integration Agreement to change the method of allocating profits from off-system electricity sales between the East and West zones. The proposed method causes such profits to be allocated generally on the basis of the zone in which the underlying transactions occur or originate. The filing was made in accordance with a provision of the agreement that called for a re-evaluation of the allocation method effective January 1, 2006 and was approved as filed effective April 1, 2006.

Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any Registrant Subsidiary is primarily sold to customers (or in the case of the ERCOT area of Texas, REPs) by such Registrant Subsidiary at rates approved (other than in Ohio, Virginia and the ERCOT area of Texas) 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 transition to the use of market rates for generation (see Note 4). In the ERCOT area of Texas, such rates are market-based.

Under both the Interconnection Agreement and CSW Operating Agreement, power generated that is not needed to serve the native load of any Registrant Subsidiary is sold in the wholesale market by AEPSC on behalf of the generating subsidiary.

Affiliated Revenues and Purchases

The following table shows the revenues derived from sales to the pools, direct sales to affiliates, natural gas contracts with AEPES, and other revenues for the years ended December 31, 2006, 2005 and 2004:

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	AEGCo	 	
Related Party Revenues	 	(in thousands)	 	
2006	 	  	 	  	 	  	 	  	 	  	 	  	 	
Sales to East System Pool	 	$	163,633	 	$	76,938	 	$	285,048	 	$	57,921	 	$	610,865	 	$	-	 	
Direct Sales to East Affiliates	 	 	70,402	 	 	-	 	 	-	 	 	-	 	 	65,386	 	 	309,604	 	
Direct Sales to West Affiliates	 	 	20,009	 	 	12,117	 	 	12,538	 	 	4,801	 	 	15,306	 	 	-	 	
Natural Gas Contracts with AEPES	 	 	(19,998	)	 	(9,705	)	 	(9,296	)	 	(4,698	)	 	(17,219	)	 	-	 	
Other	 	 	4,546	 	 	6,376	 	 	2,743	 	 	263	 	 	11,005	 	 	-	 	
Total Revenues	 	$	238,592	 	$	85,726	 	$	291,033	 	$	58,287	 	$	685,343	 	$	309,604	 	

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	AEGCo	 	
Related Party Revenues	 	(in thousands)	 	
2005	 	  	 	  	 	  	 	  	 	  	 	  	 	
Sales to East System Pool	 	$	162,014	 	$	70,165	 	$	314,677	 	$	49,791	 	$	542,364	 	$	-	 	
Direct Sales to East Affiliates	 	 	70,130	 	 	-	 	 	-	 	 	-	 	 	64,449	 	 	270,545	 	
Direct Sales to West Affiliates	 	 	25,776	 	 	14,162	 	 	14,998	 	 	6,122	 	 	19,562	 	 	-	 	
Natural Gas Contracts with AEPES	 	 	60,793	 	 	34,324	 	 	33,461	 	 	14,586	 	 	46,751	 	 	-	 	
Other	 	 	3,620	 	 	5,759	 	 	2,896	 	 	304	 	 	8,726	 	 	-	 	
Total Revenues	 	$	322,333	 	$	124,410	 	$	366,032	 	$	70,803	 	$	681,852	 	$	270,545	 	

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	AEGCo	 	
Related Party Revenues	 	(in thousands)	 	
2004	 	  	 	  	 	  	 	  	 	  	 	  	 	
Sales to East System Pool	 	$	138,566	 	$	69,309	 	$	250,356	 	$	36,853	 	$	487,794	 	$	-	 	
Direct Sales to East Affiliates	 	 	62,018	 	 	-	 	 	-	 	 	-	 	 	55,017	 	 	241,578	 	
Direct Sales to West Affiliates	 	 	22,238	 	 	13,322	 	 	14,682	 	 	5,206	 	 	17,899	 	 	-	 	
Natural Gas Contracts with AEPES	 	 	25,733	 	 	15,732	 	 	17,886	 	 	6,306	 	 	22,971	 	 	-	 	
Other	 	 	3,573	 	 	6,384	 	 	3,386	 	 	352	 	 	10,676	 	 	-	 	
Total Revenues	 	$	252,128	 	$	104,747	 	$	286,310	 	$	48,717	 	$	594,357	 	$	241,578	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Related Party Revenues	 	(in thousands)	 	
2006	 	  	 	  	 	  	 	  	 	
Direct Sales to East Affiliates	 	$	227	 	$	220	 	$	-	 	$	-	 	
Direct Sales to West Affiliates	 	 	47,184	 	 	37,284	 	 	-	 	 	17	 	
Other	 	 	4,582	 	 	4,941	 	 	6,403	 	 	33,208	 	
Total Revenues	 	$	51,993	 	$	42,445	 	$	6,403	 	$	33,225	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Related Party Revenues	 	(in thousands)	 	
2005	 	  	 	  	 	  	 	  	 	
Direct Sales to West Affiliates	 	$	33,992	 	$	61,555	 	$	-	 	$	98	 	
Other	 	 	5,686	 	 	3,853	 	 	14,973	 	 	47,066	 	
Total Revenues	 	$	39,678	 	$	65,408	 	$	14,973	 	$	47,164	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Related Party Revenues	 	(in thousands)	 	
2004	 	  	 	  	 	  	 	  	 	
Sales to West System Pool	 	$	103	 	$	521	 	$	-	 	$	159	 	
Direct Sales to East Affiliates	 	 	2,652	 	 	1,878	 	 	188	 	 	78	 	
Direct Sales to West Affiliates	 	 	3,203	 	 	63,141	 	 	3,027	 	 	71	 	
Other	 	 	4,732	 	 	5,650	 	 	43,824	 	 	51,372	 	
Total Revenues	 	$	10,690	 	$	71,190	 	$	47,039	 	$	51,680	 	

The following table shows the purchased power expense incurred from purchases from the pools and affiliates for the years ended December 31, 2006, 2005, and 2004:

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	
Related Party Purchases	 	(in thousands)	 	
2006	 	  	 	  	 	  	 	  	 	  	 	
Purchases from East System Pool	 	$	492,619	 	$	365,425	 	$	126,345	 	$	99,166	 	$	108,151	 	
Direct Purchases from East Affiliates	 	 	-	 	 	-	 	 	216,723	 	 	92,881	 	 	-	 	
Direct Purchases from West Affiliates	 	 	137	 	 	85	 	 	88	 	 	33	 	 	104	 	
Gas Purchases from AEPES	 	 	-	 	 	-	 	 	-	 	 	-	 	 	5,396	 	
Total Purchases	 	$	492,756	 	$	365,510	 	$	343,156	 	$	192,080	 	$	113,651	 	

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	
Related Party Purchases	 	(in thousands)	 	
2005	 	  	 	  	 	  	 	  	 	  	 	
Purchases from East System Pool	 	$	453,600	 	$	362,959	 	$	116,735	 	$	95,187	 	$	104,777	 	
Direct Purchases from East Affiliates	 	 	-	 	 	-	 	 	189,382	 	 	81,163	 	 	12,113	 	
Total Purchases	 	$	453,600	 	$	362,959	 	$	306,117	 	$	176,350	 	$	116,890	 	

 	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	OPCo	 	
Related Party Purchases	 	(in thousands)	 	
2004	 	  	 	  	 	  	 	  	 	  	 	
Purchases from East System Pool	 	$	370,038	 	$	346,463	 	$	102,760	 	$	68,072	 	$	84,042	 	
Direct Purchases from East Affiliates	 	 	-	 	 	-	 	 	169,103	 	 	72,475	 	 	4,334	 	
Direct Purchases from West Affiliates	 	 	915	 	 	539	 	 	589	 	 	211	 	 	979	 	
Total Purchases	 	$	370,953	 	$	347,002	 	$	272,452	 	$	140,758	 	$	89,355	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Related Party Purchases	 	(in thousands)	 	
2006	 	  	 	  	 	  	 	  	 	
Purchases from West System Pool	 	$	-	 	$	-	 	$	-	 	$	4	 	
Direct Purchases from East Affiliates	 	 	37,504	 	 	27,257	 	 	-	 	 	11	 	
Direct Purchases from West Affiliates	 	 	31,902	 	 	47,201	 	 	-	 	 	5,933	 	
Total Purchases	 	$	69,406	 	$	74,458	 	$	-	 	$	5,948	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Related Party Purchases	 	(in thousands)	 	
2005	 	  	 	  	 	  	 	  	 	
Purchases from East System Pool	 	$	43,516	 	$	36,573	 	$	-	 	$	-	 	
Direct Purchases from East Affiliates	 	 	281	 	 	278	 	 	-	 	 	-	 	
Direct Purchases from West Affiliates	 	 	61,564	 	 	34,060	 	 	-	 	 	23	 	
Total Purchases	 	$	105,361	 	$	70,911	 	$	-	 	$	23	 	

 	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
Related Party Purchases	 	(in thousands)	 	
2004	 	  	 	  	 	  	 	  	 	
Purchases from East System Pool	 	$	66	 	$	177	 	$	-	 	$	-	 	
Purchases from West System Pool	 	 	49	 	 	191	 	 	-	 	 	568	 	
Direct Purchases from East Affiliates	 	 	45,689	 	 	24,988	 	 	1,984	 	 	1,278	 	
Direct Purchases from West Affiliates	 	 	58,197	 	 	3,698	 	 	4,156	 	 	3,365	 	
Total Purchases	 	$	104,001	 	$	29,054	 	$	6,140	 	$	5,211	 	

The above summarized related party revenues and expenses are reported as consolidated and are presented as Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates on the income statements of each AEP Power Pool member. Since all of the above pool members are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.

AEP System Transmission Pool

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP’s East companies and AEP West companies zones. Similar to the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the Transmission Equalization Agreement (TEA) and the Transmission Coordination Agreement (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 AEP System dispatch costs.	
 
The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TEA, dated April 1, 1984, as amended, defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kV and above) and certain facilities operated at lower voltages (138 kV and above). Like the Interconnection Agreement, this sharing is based upon each company’s “member-load-ratio.”

The following table shows the net charges (credits) allocated among the parties to the TEA during the years ended December 31, 2006, 2005 and 2004:

 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	(16,000	)	$	8,900	 	$	(500	)	
CSPCo	 	 	46,200	 	 	34,600	 	 	37,700	 	
I&M	 	 	(37,300	)	 	(47,000	)	 	(40,800	)	
KPCo	 	 	(2,000	)	 	(3,500	)	 	(6,100	)	
OPCo	 	 	9,100	 	 	7,000	 	 	9,700	 	

The net charges (credits) shown above are recorded in Other Operation on the Registrant Subsidiaries’ income statements.

PSO, SWEPCo, TCC, TNC and AEPSC are parties to the TCA, originally dated January 1, 1997. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the AEP West companies, including the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and 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 delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. Prior to September 2005, TCA also provided for the allocation among the AEP West companies of revenues collected for transmission and ancillary services provided under the OATT. Since then, these allocations have been governed 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 charges (credits) allocated among 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, 2006, 2005 and 2004:

 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
PSO	 	$	1,800	 	$	3,500	 	$	8,100	 	
SWEPCo	 	 	(1,900	)	 	5,200	 	 	13,800	 	
TCC	 	 	1,100	 	 	(3,800	)	 	(12,200	)	
TNC	 	 	(1,000	)	 	(4,900	)	 	(9,700	)	

The net charges (credits) shown above are recorded in the Other Operation on the Registrant Subsidiaries’ income statements.

CSPCo coal purchases from AEP Coal, Inc.

During 2004, CSPCo purchased approximately 330,000 tons of coal from AEP Coal. The coal was delivered (at CSPCo’s expense) to the Conesville Plant for a price of $26.15 per ton. During 2004, CSPCo’s purchases from AEP Coal totaled $9.5 million. These purchases were recorded in Fuel on CSPCo’s Consolidated Balance Sheets.

AEP Coal and CSPCo were parties to a 1998 coal transloading agreement, dated June 12, 1998. Pursuant to the agreement, in 2004 AEP Coal transferred coal from railcars into trucks at AEP Coal’s Muskie Transloading Facility and delivered the coal via trucks to either CSPCo’s Conesville Preparation Plant or one of CSPCo’s power plants for a rate of $1.25 per ton. During 2004, CSPCo paid AEP Coal $1 million. These transloading costs were recorded in Fuel on CSPCo’s Consolidated Balance Sheets.

As a result of management’s decision to exit our non-core businesses, AEP Coal, Inc. (AEP Coal) was sold in April 2004.

Coal Transactions with AEP Coal Marketing

AEP Coal Marketing, a wholly-owned subsidiary of AEP, enters into sale and purchase transactions with certain operating companies. The transactions are executed on a spot basis and are performed at cost for the operating companies’ fuel requirements. During 2005 and 2004, the only transactions were immaterial purchases by I&M and OPCo from AEP Coal Marketing. There were no transactions in 2006.

Natural Gas Contracts with DETM

Effective October 31, 2003, AEPES assigned to AEPSC, as agent for the AEP East companies, approximately $97 million (negative value) associated with its natural gas contracts with DETM. The assignment was executed in order to consolidate DETM positions within AEP. In the future, PSO and SWEPCo may also be allocated a portion of the DETM assignment based on the SIA methodology of sharing trading and marketing margins between the AEP East companies and PSO and SWEPCo. Concurrently, in order to ensure that there would be no financial impact to the AEP East companies, PSO or SWEPCo as a result of the assignment, AEPES and AEPSC entered into agreements requiring AEPES to reimburse AEPSC for any related cash settlements and all income related to the assigned contracts. There is no impact to the AEP consolidated financial statements. The following table represents Registrant Subsidiaries’ risk management liabilities related to DETM at December 31:

 	 	2006	 	2005	 	
Company	 	(in thousands)	 	
APCo	 	$	(11,224	)	$	(12,318	)	
CSPCo	 	 	(7,154	)	 	(7,142	)	
I&M	 	 	(7,517	)	 	(7,294	)	
KPCo	 	 	(2,692	)	 	(2,932	)	
OPCo	 	 	(8,503	)	 	(9,810	)	

Fuel Agreement between OPCo and AEPES

OPCo and National Power Cooperative, Inc (NPC) have an agreement whereby OPCo operates a 500 MW gas plant owned by NPC (Mone Plant). AEPES entered into a fuel management agreement with those two parties to manage and procure fuel for the Mone Plant. The gas purchased by AEPES and used in generation is first sold to OPCo then allocated to the AEP East companies, who purchased 100% of the available generating capacity from the plant through May 2006. The agreement was renewed and extends through May 2007. The related purchases of gas managed by AEPES were as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	1,660	 	$	3,905	 	$	1,230	 	
CSPCo	 	 	1,016	 	 	2,113	 	 	732	 	
I&M	 	 	1,065	 	 	2,255	 	 	805	 	
KPCo	 	 	398	 	 	924	 	 	286	 	
OPCo	 	 	1,257	 	 	2,916	 	 	1,281	 	

These purchases are reflected in Purchased Electricity for Resale on the Registrant Subsidiaries’ income statements.
 
Unit Power Agreements

A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, 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) for such amounts, as when added to amounts received by AEGCo from any other sources, 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 the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant 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 power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same 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 ends in December 2022. See Affiliated Revenues and Purchases section of this note.

Jointly-Owned Electric Utility Plants

APCo and OPCo jointly own two power plants. The costs of operating these facilities are apportioned between owners based on ownership interests. Each company’s share of these costs is included in the appropriate expense accounts on its respective Consolidated Statements of Income. Each company’s investment in these plants is included in Property, Plant and Equipment on its respective Consolidated Balance Sheets.

AEGCo and I&M jointly own one generating unit and jointly lease the other generating unit of the Rockport Plant. The costs of operating this facility are equally apportioned between AEGCo and I&M since each company has a 50% interest. Each company’s share of costs is included in the appropriate expense accounts on its respective income statements. Each company’s investment in these plants is included in Property, Plant and Equipment on its respective balance sheets.

PSO, TCC and TNC jointly own the Oklaunion power plant along with two nonaffiliated companies. The costs of operating the facility are apportioned between owners based on ownership interests. Each company’s share of these costs is included in the appropriate expense accounts on its respective income statement. PSO’s and TNC’s investment in this plant is included in Property, Plant and Equipment on its respective balance sheets, while TCC’s share is included in Assets Held For Sale - Texas Generation Plant. TCC sold its share to one of the nonaffiliated owners in February 2007.

Cook Coal Terminal

In 2006, 2005 and 2004, Cook Coal Terminal, a division of OPCo, performed coal transloading services at cost for APCo and I&M. OPCo included revenues for these services in Other-Affiliated and expenses in Other Operation on its Consolidated Statements of Income. The coal transloading revenues were as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	899	 	$	1,770	 	$	730	 	
I&M	 	 	15,869	 	 	13,653	 	 	14,275	 	

APCo and I&M recorded the cost of the transloading services in Fuel on their respective Consolidated Balance Sheets.

In addition, Cook Coal Terminal provided coal transloading services for OVEC in 2006 and 2005. OPCo recorded revenue as Other - Nonaffiliated on its Consolidated Statements of Income in the amounts of $172 thousand and $513 thousand in 2006 and 2005, respectively. OVEC is 43.47% owned by AEP and CSPCo.
 
In 2006, 2005 and 2004, Cook Coal Terminal also performed railcar maintenance services at cost for APCo, I&M, PSO and SWEPCo. OPCo includes revenues for these services in Sales to AEP Affiliates and expenses in Other Operation on its Consolidated Statements of Income. The railcar maintenance revenues were as follows:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	278	 	$	-	 	$	-	 	
I&M	 	 	2,491	 	 	2,816	 	 	2,634	 	
PSO	 	 	905	 	 	117	 	 	-	 	
SWEPCo	 	 	433	 	 	163	 	 	-	 	

APCo, I&M, PSO and SWEPCo record the cost of the railcar maintenance services in Fuel on their respective balance sheets.

SWEPCo Railcar Facility

SWEPCo operates a railcar maintenance facility in Alliance, Nebraska. The facility performs maintenance on its own railcars as well as railcars belonging to I&M, PSO and third parties. SWEPCo billed I&M $1,224 thousand and $453 thousand for railcar services provided in 2006 and 2005, respectively, and billed PSO $905 thousand and $964 thousand in 2006 and 2005, respectively. These billings, for SWEPCo, and costs, for I&M and PSO, are recorded in Fuel on the Registrant Subsidiaries’ respective balance sheets.

I&M Barging and Other Services

I&M provides barging and other transportation services to affiliates. I&M records revenues from barging services as Other - Affiliated on its Consolidated Statements of Income. The affiliates record costs paid to I&M for barging services as fuel expense or operation expense. The amount of affiliated revenues and affiliated expenses were:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in millions)	 	
I&M - revenues	 	$	47.9	 	$	43.1	 	$	38.2	 	
AEGCo - expense	 	 	14.9	 	 	11.4	 	 	9.5	 	
APCo - expense	 	 	14.5	 	 	18.5	 	 	13.0	 	
KPCo - expense	 	 	0.1	 	 	0.1	 	 	0.1	 	
OPCo - expense	 	 	2.1	 	 	2.5	 	 	4.9	 	
MEMCO - expense (Nonutility subsidiary of AEP)	 	 	16.3	 	 	10.6	 	 	10.7	 	

Services Provided by MEMCO

AEP MEMCO LLC (MEMCO) provides services for barge towing and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation. For the years ended December 31, 2006, 2005 and 2004, I&M recorded $16.0 million, $14.1 million and $12.6 million, respectively.
 
Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers on its balance sheet the cost of performing the services, then transfers the cost to the Registrant Subsidiary and is reimbursed. The Registrant Subsidiaries recorded these billings as capital or maintenance expense depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the Registrant Subsidiaries:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
CSPCo	 	$	617	 	$	790	 	$	544	 	
I&M	 	 	1,826	 	 	3,620	 	 	2,134	 	
KPCo	 	 	181	 	 	285	 	 	182	 	
OPCo	 	 	2,831	 	 	2,684	 	 	2,731	 	
PSO	 	 	801	 	 	21	 	 	4	 	
SWEPCo	 	 	2	 	 	-	 	 	90	 	

In addition, APCo billed OVEC and IKEC a total of $951 thousand, $957 thousand and $1,343 thousand for 2006, 2005 and 2004, respectively.

Affiliate Railcar Agreement

The Registrant Subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The Registrant Subsidiaries record these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on their balance sheets and such costs are recoverable from customers. The following table shows the net effect of the railcar agreement on the Registrant Subsidiaries’ respective 2006 balance sheets:

 	 	Billing Company	 	
 	 	AEP Transportation (a) 	 	APCo	 	I&M	 	OPCo	 	PSO	 	SWEPCo	 	Total	 	
Billed Company	 	(in thousands)	 	
APCo	 	$	1	 	$	-	 	$	289	 	$	1,786	 	$	46	 	$	65	 	$	2,187	 	
I&M	 	 	310	 	 	176	 	 	-	 	 	1,016	 	 	487	 	 	735	 	 	2,724	 	
KPCo	 	 	-	 	 	384	 	 	-	 	 	233	 	 	-	 	 	-	 	 	617	 	
OPCo	 	 	-	 	 	231	 	 	700	 	 	-	 	 	-	 	 	-	 	 	931	 	
PSO	 	 	321	 	 	145	 	 	962	 	 	105	 	 	-	 	 	382	 	 	1,915	 	
SWEPCo	 	 	883	 	 	20	 	 	2,194	 	 	845	 	 	456	 	 	-	 	 	4,398	 	
Total	 	$	1,515	 	$	956	 	$	4,145	 	$	3,985	 	$	989	 	$	1,182	 	$	12,772	 	

 (a)  AEP Transportation is a 100%-owned nonutility subsidiary of AEP, Inc.	
 
I&M Urea Transloading

I&M provides urea transloading services to APCo, KPCo, and OPCo. Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System. I&M records revenues from urea transloading services as Other - Affiliated on its Consolidated Statements of Income. The affiliates record costs paid to I&M for barging services as Fuel and Other Consumables Used for Electric Generation on their respective statements of income. The amount of affiliated revenues and affiliated expenses were:
 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
I&M - revenues	 	$	853	 	$	1,412	 	$	896	 	
APCo - expense	 	 	413	 	 	644	 	 	428	 	
KPCo - expense	 	 	68	 	 	133	 	 	86	 	
OPCo - expense	 	 	372	 	 	635	 	 	382	 	

In addition, I&M provided transloading services to OVEC. I&M recorded the revenue, which totaled $121 thousand, $215 thousand and $128 thousand for 2006, 2005 and 2004, respectively, in Other - Nonaffiliated on its Consolidated Statements of Income.

Gas Purchases from HPL

Prior to its sale in January 2005, HPL acquired physical gas in the spot market. The gas was then purchased by TCC and TNC at cost for their fuel requirements. These purchases are included in Fuel from Affiliates for Electricity Generation on TCC’s and TNC’s respective income statements. The purchases from HPL were as follows:

 	 	Year Ended December 31,	 	
 	 	2005	 	2004	 	
  Company	 	  (in thousands)	 	
TCC	 	$	-	 	$	129,682	 	
TNC	 	 	42	 	 	45,767	 	

OPCo Indemnification Agreement with AEP Resources

OPCo had an indemnification agreement with AEP Resources (AEPR), a nonutility subsidiary of AEP, whereby AEPR held OPCo harmless from market exposure related to OPCo’s Power Purchase and Sale Agreement dated November 15, 2000 with Dow Chemical Company. In 2006, 2005 and 2004, AEPR paid OPCo $14.9 million, $29.6 million and $21.5 million, respectively, which is reported in OPCo’s Other Operation on its Consolidated Statements of Income. As a result of the sale of the Plaquemine Cogeneration Facility and subsequent termination of OPCo’s Power Purchase and Sale Agreement in November 2006, no indemnification payments are expected in 2007.

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC, which is 43.47% owned by AEP and CSPCo, for the years ended December 31, 2006, 2005 and 2004 were:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	82,422	 	$	77,337	 	$	62,101	 	
CSPCo	 	 	22,821	 	 	20,602	 	 	16,724	 	
I&M	 	 	38,961	 	 	30,961	 	 	27,474	 	
OPCo	 	 	78,579	 	 	66,680	 	 	55,052	 	

The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale in the Registrant Subsidiaries’ respective Consolidated Statements of Income.
 
AEP Power Pool Purchases from OVEC

Under a new agreement in 2006, the AEP Power Pool began purchasing power from OVEC as part of wholesale marketing and risk management activity. These purchases are reflected in Electric Generation, Transmission and Distribution revenues in the Registrant Subsidiaries’ respective Consolidated Statements of Income. The agreement expired in December 2006. The following table shows the amounts recorded by the Registrant Subsidiaries in 2006:

 	 	Year Ended	 	
 	 	December 31, 2006	 	
Company	 	(in thousands)	 	
APCo	 	$	11,284	 	
CSPCo	 	 	6,915	 	
I&M	 	 	7,189	 	
KPCo	 	 	2,706	 	
OPCo	 	 	8,576	 	

Purchased Power from Sweeny

On behalf of the AEP West companies, CSPCo entered into a ten year Power Purchase Agreement (PPA) with Sweeny, which is 50% owned by AEP. The PPA is for unit contingent power up to a maximum of 315 MW from January 1, 2005 through December 31, 2014. The delivery point for the power under the PPA is in TCC’s system. The power is sold in ERCOT. Prior to May 1, 2006, the purchase of Sweeny power and its sale to nonaffiliates were shared among the AEP West companies under the CSW Operating Agreement. After May 1, 2006, the purchases and sales are shared between PSO and SWEPCo. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 4 and “CSW Operating Agreement” section of this note. The purchases from Sweeny were:

 	 	Year Ended December 31,	 	
 	 	2006	 	2005	 	
Company	 	(in thousands)	 	
PSO	 	$	53,354	 	$	57,742	 	
SWEPCo	 	 	62,794	 	 	50,618	 	
TCC	 	 	703	 	 	4,560	 	
TNC	 	 	4,229	 	 	27,804	 	

The amounts shown above are recorded in Purchased Electricity for Resale on the Registrant Subsidiaries’ respective income statements.

OPCo Coal Transfers

In 2006, OPCo sold 115,877 tons of coal from its Mitchell plant inventory to APCo for $4.8 million. The coal was sold at cost, based on a weighted average cost method of carrying inventory. APCo paid for the cost of transporting the coal from OPCo’s facility to its delivery points at APCo’s Amos plant and Sporn plant. The amount above was transferred from Fuel on OPCo’s Consolidated Balance Sheet to APCo’s Consolidated Balance Sheet at the time of the sale.

In 2005, OPCo sold 142,226 tons of coal from its Mitchell plant inventory to APCo for $6.0 million. The coal was sold at cost, based on a weighted average cost method of carrying inventory. APCo paid for the cost of transporting the coal from OPCo’s facility to its delivery point at APCo’s Amos plant. The amount above was transferred from Fuel on OPCo’s Consolidated Balance Sheet to APCo’s Consolidated Balance Sheet at the time of the sale.

In 2005, OPCo also sold 30,844 tons of coal from its Gavin plant inventory to OVEC for $1 million. The coal was sold at cost, based on a weighted average cost method of carrying inventory. OVEC paid for the cost of transporting the coal from OPCo’s facility to its delivery point at OVEC’s Kyger Creek plant. The coal inventory was removed from Fuel on OPCo’s Consolidated Balance Sheet at the time of the sale.

Sales of Property

The Registrant Subsidiaries had sales of electric property individually amounting to $100,000 or more, for the years ended December 31, 2006, 2005 and 2004 as shown in the following table:

 	 	2006	 	
 	 	(in thousands)	 	
APCo to OPCo	 	$	1,037	 	
CSPCo to OPCo	 	 	592	 	
I&M to CSPCo	 	 	173	 	
I&M to SWEPCo	 	 	111	 	
I&M to WPCo	 	 	201	 	
KPCo to APCo	 	 	191	 	
OPCo to APCo	 	 	3,822	 	
OPCo to KPCo	 	 	1,324	 	
OPCo to PSO	 	 	760	 	

 	 	2005	 	
 	 	(in thousands)	 	
APCo to I&M	 	$	554	 	
APCo to OPCo	 	 	637	 	
I&M to APCo	 	 	1,135	 	
I&M to OPCo	 	 	3,423	 	
KPCo to OPCo	 	 	101	 	
OPCo to APCo	 	 	1,057	 	
OPCo to I&M	 	 	2,142	 	
 	
 	 	 	2004	 	
 	 	(in thousands)  	 	
APCo to OPCo	 	$	2,992	 	
I&M to APCo	 	 	1,630	 	

In addition, the Registrant Subsidiaries had aggregate affiliated sales and purchases of meters and transformers for the years ended December 31, 2006, 2005 and 2004 as shown in the following table:

2006

 	 	Purchaser	 	
 	 	APCo	 	CSPCo	 	I&M	 	KGPCo	 	KPCo	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	 WPCo 	 	 TOTAL 	 	
Seller	 	(in thousands)	 	
APCo	 	$	-	 	$	17	 	$	187	 	$	676	 	$	3,206	 	$	2,019	 	$	157	 	$	669	 	$	1,631	 	$	-	 	$	459	 	$	9,021	 	
CSPCo	 	 	87	 	 	-	 	 	2	 	 	2	 	 	1	 	 	661	 	 	17	 	 	-	 	 	-	 	 	-	 	 	-	 	 	770	 	
I&M	 	 	86	 	 	44	 	 	-	 	 	-	 	 	18	 	 	2,052	 	 	25	 	 	158	 	 	2	 	 	-	 	 	10	 	 	2,395	 	
KGPCo	 	 	179	 	 	-	 	 	-	 	 	-	 	 	-	 	 	1	 	 	-	 	 	-	 	 	179	 	 	-	 	 	-	 	 	359	 	
KPCo	 	 	2,178	 	 	75	 	 	40	 	 	11	 	 	-	 	 	254	 	 	28	 	 	-	 	 	3	 	 	-	 	 	9	 	 	2,598	 	
OPCo	 	 	1,750	 	 	2,545	 	 	910	 	 	-	 	 	504	 	 	-	 	 	330	 	 	211	 	 	1	 	 	-	 	 	391	 	 	6,642	 	
PSO	 	 	1	 	 	1	 	 	26	 	 	-	 	 	-	 	 	1	 	 	-	 	 	129	 	 	30	 	 	2	 	 	-	 	 	190	 	
SWEPCo	 	 	16	 	 	-	 	 	-	 	 	-	 	 	-	 	 	12	 	 	95	 	 	-	 	 	37	 	 	-	 	 	-	 	 	160	 	
TCC	 	 	12	 	 	-	 	 	-	 	 	36	 	 	-	 	 	18	 	 	10	 	 	50	 	 	-	 	 	1,266	 	 	-	 	 	1,392	 	
TNC	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	17	 	 	4	 	 	209	 	 	-	 	 	-	 	 	230	 	
WPCo	 	 	7	 	 	28	 	 	21	 	 	-	 	 	3	 	 	247	 	 	8	 	 	-	 	 	-	 	 	-	 	 	-	 	 	314	 	
Total	 	$	4,316	 	$	2,710	 	$	1,186	 	$	725	 	$	3,732	 	$	5,265	 	$	687	 	$	1,221	 	$	2,092	 	$	1,268	 	$	869	 	$	24,071	 	
 
2005

 	 	Purchaser	 	
 	 	APCo	 	CSPCo	 	I&M	 	KGPCo	 	KPCo	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	 WPCo 	 	 TOTAL 	 	
Seller	 	(in thousands)	 	
APCo	 	$	-	 	$	9	 	$	1,847	 	$	371	 	$	1,577	 	$	677	 	$	208	 	$	210	 	$	357	 	$	-	 	$	717	 	$	5,973	 	
CSPCo	 	 	36	 	 	-	 	 	23	 	 	-	 	 	8	 	 	605	 	 	47	 	 	29	 	 	-	 	 	-	 	 	-	 	 	748	 	
I&M	 	 	59	 	 	8	 	 	-	 	 	4	 	 	22	 	 	2,903	 	 	-	 	 	3	 	 	-	 	 	-	 	 	19	 	 	3,018	 	
KGPCo	 	 	270	 	 	-	 	 	4	 	 	-	 	 	-	 	 	19	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	293	 	
KPCo	 	 	381	 	 	1	 	 	-	 	 	1	 	 	-	 	 	135	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	518	 	
OPCo	 	 	1,246	 	 	1,901	 	 	2,504	 	 	28	 	 	304	 	 	-	 	 	182	 	 	94	 	 	69	 	 	-	 	 	335	 	 	6,663	 	
PSO	 	 	12	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	52	 	 	8	 	 	3	 	 	-	 	 	75	 	
SWEPCo	 	 	10	 	 	-	 	 	-	 	 	-	 	 	-	 	 	4	 	 	67	 	 	-	 	 	40	 	 	3	 	 	-	 	 	124	 	
TCC	 	 	164	 	 	-	 	 	2	 	 	-	 	 	-	 	 	29	 	 	2	 	 	130	 	 	-	 	 	1,642	 	 	-	 	 	1,969	 	
TNC	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	17	 	 	317	 	 	-	 	 	-	 	 	334	 	
WPCo	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	196	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	196	 	
Total	 	$	2,178	 	$	1,919	 	$	4,380	 	$	404	 	$	1,911	 	$	4,568	 	$	506	 	$	535	 	$	791	 	$	1,648	 	$	1,071	 	$	19,911	 	

2004

 	 	Purchaser	 	
 	 	APCo	 	CSPCo	 	I&M	 	KGPCo	 	KPCo	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	 WPCo 	 	 TOTAL 	 	
Seller	 	(in thousands)	 	
APCo	 	$	-	 	$	12	 	$	138	 	$	314	 	$	687	 	$	284	 	$	3	 	$	-	 	$	48	 	$	-	 	$	5	 	$	1,491	 	
CSPCo	 	 	31	 	 	-	 	 	19	 	 	-	 	 	4	 	 	554	 	 	-	 	 	14	 	 	-	 	 	-	 	 	-	 	 	622	 	
I&M	 	 	21	 	 	12	 	 	-	 	 	-	 	 	16	 	 	1,208	 	 	-	 	 	-	 	 	-	 	 	-	 	 	8	 	 	1,265	 	
KGPCo	 	 	102	 	 	-	 	 	-	 	 	-	 	 	-	 	 	5	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	107	 	
KPCo	 	 	200	 	 	1	 	 	2	 	 	7	 	 	-	 	 	120	 	 	-	 	 	-	 	 	-	 	 	-	 	 	10	 	 	340	 	
OPCo	 	 	627	 	 	1,229	 	 	1,176	 	 	1	 	 	206	 	 	-	 	 	-	 	 	34	 	 	18	 	 	-	 	 	190	 	 	3,481	 	
PSO	 	 	40	 	 	-	 	 	-	 	 	-	 	 	-	 	 	6	 	 	-	 	 	74	 	 	10	 	 	1	 	 	-	 	 	131	 	
SWEPCo	 	 	1	 	 	31	 	 	40	 	 	-	 	 	5	 	 	1	 	 	49	 	 	-	 	 	124	 	 	12	 	 	-	 	 	263	 	
TCC	 	 	6	 	 	-	 	 	20	 	 	-	 	 	-	 	 	67	 	 	1	 	 	26	 	 	-	 	 	810	 	 	-	 	 	930	 	
TNC	 	 	20	 	 	-	 	 	-	 	 	-	 	 	-	 	 	8	 	 	9	 	 	7	 	 	227	 	 	-	 	 	-	 	 	271	 	
WPCo	 	 	-	 	 	-	 	 	8	 	 	-	 	 	-	 	 	122	 	 	-	 	 	-	 	 	-	 	 	-	 	 	-	 	 	130	 	
Total	 	$	1,048	 	$	1,285	 	$	1,403	 	$	322	 	$	918	 	$	2,375	 	$	62	 	$	155	 	$	427	 	$	823	 	$	213	 	$	9,031	 	

The amounts above are recorded in Property, Plant and Equipment. Transfers are performed at cost.

Global Borrowing Notes

AEP issued long-term debt, portions of which were loaned to the Registrant Subsidiaries. The debt is reflected in Long-term Debt - Affiliated on the Registrant Subsidiaries’ respective balance sheets. AEP pays the interest on the global notes, but the Registrant Subsidiaries accrue interest for their respective share of the global borrowing and remit the interest to AEP. The accrued interest is reflected in either Accrued Interest or Other in the Current Liabilities section of the Registrant Subsidiaries’ respective balance sheets. APCo, CSPCo, KPCo, OPCo, PSO, SWEPCo and TCC participated in the global borrowing arrangement during the reporting periods.

AEPSC

AEPSC provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered and are recoverable from customers. During 2005 and 2004, AEPSC and its billings were subject to regulation by the SEC under the PUHCA of 1935. Effective February 8, 2006, the PUHCA of 2005 was enacted, which repealed the PUHCA of 1935 and transferred the regulatory responsibility from the SEC to the FERC.

Intercompany Billings

The Registrant Subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable bases of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital. Billings between Registrant Subsidiaries are capitalized or expensed depending on the nature of the services rendered.

         17.   PROPERTY, PLANT AND EQUIPMENT

Depreciation, Depletion and Amortization

We provide for depreciation of property, plant and equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following table provides the annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries:

TCC

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Transmission	 	$	904,527	 	$	208,121	 	1.6	%	40-71	 	$ 	-	 	$	-	 	N.M.	 	N.M.	
Distribution	 	 	1,579,498	 	 	331,297	 	3.3	%	15-62	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	165,979	 	 	362	 	N.M.	 	N.M.	 	 	-	 	 	-	 	N.M.	 	N.M.	
Other	 	 	217,050	 	 	89,448	 	6.8	%	N.M.	 	 	2,978	 	 	1,011	 	N.M.	 	N.M.	
Total	 	$	2,867,054	 	$	629,228	 	 	 	 	 	$	2,978	 	$	1,011	 	 	 	 	

2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Transmission	 	$	 817,351	 	$ 	 204,426	 	2.1	%	40-71	 	$ 	-	 	$	-	 	N.M.	 	N.M.	
Distribution	 	 	 1,476,683	 	 	332,143	 	3.4	%	15-62	 	 	-	 	 	 -	 	N.M.	 	N.M.	
CWIP	 	 	 129,800	 	 	 1,147	 	N.M.	 	N.M.	 	 	-	 	 	 -	 	N.M.	 	N.M.	
Other	 	 	 229,893	 	 	 97,196	 	6.5	%	N.M.	 	 	 3,468	 	 	 1,166	 	2.9	%	N.M.	
Total	 	$	 2,653,727	 	$	 634,912	 	 	 	 	 	$	 3,468	 	$	 1,166	 	 	 	 	

2004	 	Regulated	 	Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
Transmission	 	2.3	%	35-60	 	N.M.	 	N.M.	 	
Distribution	 	3.4	%	25-60	 	N.M.	 	N.M.	 	
Other	 	6.5	%	N.M.	 	2.9	%	N.M.	 	
 
TNC

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	-	 	$	-	 	N.M.	 	N.M.	 	$	290,485	 	$	112,591	 	9.2	%	20-49	
Transmission	 	 	327,845	 	 	100,822	 	2.9	%	40-75	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	512,265	 	 	151,805	 	3.2	%	19-55	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	36,579	 	 	(1,457	)	N.M.	 	N.M.	 	 	2,268	 	 	-	 	N.M.	 	N.M.	
Other	 	 	99,411	 	 	64,713	 	9.3	%	N.M.	 	 	60,040	 	 	58,487	 	N.M.	 	N.M.	
Total	 	$	976,100	 	$	315,883	 	 	 	 	 	$	352,793	 	$	171,078	 	 	 	 	

2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	-	 	$	-	 	N.M.	 	N.M.	 	$	 288,934	 	$	 117,963	 	2.6	%	20-49	
Transmission	 	 	289,029	 	 	 98,630	 	3.0	%	40-75	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	492,878	 	 	 144,465	 	3.2	%	19-55	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	 42,929	 	 	(327	)	N.M.	 	N.M.	 	 	3,495	 	 	-	 	N.M.	 	N.M.	
Other	 	 	109,264	 	 	60,376	 	9.7	%	N.M.	 	 	58,585	 	 	57,412	 	4.9	%	N.M.	
Total	 	$	934,100	 	$	303,144	 	 	 	 	 	$	351,014	 	$	 175,375	 	 	 	 	

2004	 	Regulated	 	Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
Production	 	N.M.	 	N.M.	 	 2.6	% 	20-49	 	
Transmission	 	3.0	%	40-75	 	N.M.	 	N.M.	 	
Distribution	 	3.2	%	19-55	 	N.M.	 	N.M.	 	
Other	 	8.4	%	N.M.	 	4.9	%	N.M.	 	
 
APCo

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	1,320,507	 	$	697,275	 	2.6	%	40-121	 	$	1,524,296	 	$	604,290	 	2.6	%	40-121	
Transmission	 	 	1,620,512	 	 	457,129	 	1.8	%	25-87	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	2,237,887	 	 	562,672	 	3.3	%	11-52	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	500,641	 	 	(7,263	)	N.M.	 	N.M.	 	 	456,985	 	 	(5,054	)	N.M.	 	N.M.	
Other	 	 	305,811	 	 	154,829	 	7.7	%	24-55	 	 	33,639	 	 	12,412	 	N.M.	 	N.M.	
Total	 	$	5,985,358	 	$	1,864,642	 	 	 	 	 	$	2,014,920	 	$	611,648	 	 	 	 	

2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	 1,140,438	 	$	 515,967	 	2.9	%	40-120	 	$	 1,657,719	 	$	 748,739	 	2.9	%	40-120	
Transmission	 	 	 1,266,855	 	 	 481,978	 	2.2	%	35-65	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	 2,141,153	 	 	 655,856	 	3.2	%	10-60	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	 481,579	 	 	(4,844	)	N.M.	 	N.M.	 	 	 166,059	 	 	(5,210	) 	N.M.	 	N.M.	
Other	 	 	289,924	 	 	 119,178	 	9.3	%	N.M.	 	 	 33,234	 	 	13,191	 	3.2	%	N.M.	
Total	 	$	 5,319,949	 	$	 1,768,135	 	 	 	 	 	$	 1,857,012	 	$	756,720	 	 	 	 	

2004	 	Regulated	 	 Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
 	 	 	 	(in years)	 	 	 	(in years)	 	
Production	 	2.8	%	40-120	 	2.8	%	40-120	 	
Transmission	 	2.2	%	35-65	 	N.M.	 	N.M.	 	
Distribution	 	3.3	%	10-60	 	N.M.	 	N.M.	 	
Other	 	9.4	%	N.M.	 	3.2	%	N.M.	 	
 
CSPCo

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	-	 	$	-	 	N.M.	 	N.M.	 	$	1,896,073	 	$	812,541	 	3.1	%	40-59	
Transmission	 	 	479,119	 	 	202,585	 	2.3	%	33-50	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	1,475,758	 	 	514,042	 	3.5	%	12-56	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	77,484	 	 	(4,749	) 	N.M.	 	N.M.	 	 	216,654	 	 	704	 	N.M.	 	N.M.	
Other	 	 	168,911	 	 	83,782	 	8.7	%	N.M.	 	 	22,192	 	 	2,138	 	N.M.	 	N.M.	
Total	 	$	2,201,272	 	$	795,660	 	 	 	 	 	$	2,134,919	 	$	815,383	 	 	 	 	

2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	 -	 	$	-	 	N.M.	 	N.M.	 	$	 1,874,652	 	$	 759,789	 	3.1	%	40-59	
Transmission	 	 	457,937	 	 	 192,282	 	2.3	%	33-50	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	 1,380,722	 	 	 475,669	 	3.6	%	12-56	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	 69,800	 	 	(3,781	) 	N.M.	 	N.M.	 	 	 59,446	 	 	 63	 	N.M.	 	N.M.	
Other	 	 	 161,205	 	 	 73,505	 	10.2	%	N.M.	 	 	22,891	 	 	3,331	 	N.M.	 	N.M.	
Total	 	$	 2,069,664	 	$	 737,675	 	 	 	 	 	$	1,956,989	 	$	 763,183	 	 	 	 	

2004	 	Regulated	 	Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
 	 	 	 	(in years)	 	 	 	(in years)	 	
Production	 	 	N.M.	 	 	N.M.	 	 	2.9	%	 	40-50	 	
Transmission	 	 	2.3	%	 	33-50	 	 	N.M.	 	 	N.M.	 	
Distribution	 	 	3.6	%	 	12-56	 	 	N.M.	 	 	N.M.	 	
Other	 	 	10.3	%	 	N.M.	 	 	N.M.	 	 	N.M.	 	
 
OPCo

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	-	 	$	-	 	N.M.	 	N.M.	 	$	4,413,340	 	$	1,925,883	 	2.8	%	35-61	
Transmission	 	 	1,030,934	 	 	420,748	 	2.3	%	27-70	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	1,322,103	 	 	356,629	 	3.9	%	12-55	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	82,615	 	 	(1,115	) 	N.M.	 	N.M.	 	 	1,257,016	 	 	6,666	 	N.M.	 	N.M.	
Other	 	 	238,456	 	 	117,946	 	9.2	%	N.M.	 	 	61,181	 	 	9,827	 	N.M.	 	N.M.	
Total	 	$	2,674,108	 	$	894,208	 	 	 	 	 	$	5,731,537	 	$	1,942,376	 	 	 	 	

2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	-	 	$	-	 	N.M.	 	N.M.	 	$	4,278,553	 	$	 1,876,732	 	2.8	%	35-61	
Transmission	 	 	1,002,255	 	 	403,260	 	2.3	%	27-70	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	 1,258,518	 	 	 338,652	 	3.9	%	12-55	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	 66,103	 	 	(1,361	) 	N.M.	 	N.M.	 	 	 624,065	 	 	 1,494	 	N.M.	 	N.M.	
Other	 	 	234,569	 	 	 110,743	 	10.7	%	N.M.	 	 	59,225	 	 	9,379	 	3.0	%	N.M.	
Total	 	$	2,561,445	 	$	851,294	 	 	 	 	 	$	4,961,843	 	$	1,887,605	 	 	 	 	

2004	 	Regulated	 	Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
 	 	 	 	(in years)	 	 	 	(in years)	 	
Production	 	N.M.	 	N.M.	 	2.8	%	35-42	 	
Transmission	 	2.3	%	27-70	 	N.M.	 	N.M.	 	
Distribution	 	4.0	%	12-55	 	N.M.	 	N.M.	 	
Other	 	10.1	%	N.M.	 	3.0	%	N.M.	 	
 
SWEPCo

2006	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	949,867	 	$	596,453	 	3.1	%	30-57	 	$	626,333	 	$	393,295	 	3.1	%	30-57	
Transmission	 	 	668,008	 	 	213,618	 	2.5	%	40-55	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	1,228,948	 	 	375,659	 	3.1	%	16-65	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	169,700	 	 	(5,709	) 	N.M.	 	N.M.	 	 	89,962	 	 	(403	) 	N.M.	 	N.M.	
Other	 	 	361,138	 	 	119,361	 	8.6	%	N.M.	 	 	234,291	 	 	141,871	 	N.M.	 	N.M.	
Total	 	$	3,377,661	 	$	1,299,382	 	 	 	 	 	$	950,586	 	$	534,763	 	 	 	 	

2005	 	Regulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	912,044	 	$	577,611	 	3.1	%	30-57	 	$	601,392	 	$	483,743	 	3.1	%	30-57	
Transmission	 	 	645,297	 	 	201,521	 	2.5	%	40-55	 	 	-	 	 	-	 	N.M.	 	N.M.	
Distribution	 	 	 1,153,026	 	 	 339,258	 	3.1	%	16-65	 	 	-	 	 	-	 	N.M.	 	N.M.	
CWIP	 	 	 81,437	 	 	(73	) 	N.M.	 	N.M.	 	 	22,738	 	 	 667	 	N.M.	 	N.M.	
Other	 	 	362,572	 	 	 134,575	 	8.6	%	N.M.	 	 	228,133	 	 	38,914	 	N.M.	 	N.M.	
Total	 	$	 3,154,376	 	$	 1,252,892	 	 	 	 	 	$	852,263	 	$	523,324	 	 	 	 	

2004	 	Regulated	 	Nonregulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
 	 	 	 	(in years)	 	 	 	(in years)	 	
Production	 	3.3	%	30-57	 	 3.3	%	30-57	 	
Transmission	 	2.8	%	40-55	 	 N.M.	 	N.M.	 	
Distribution	 	3.6	%	16-65	 	 N.M.	 	N.M.	 	
Other	 	6.9	%	N.M.	 	N.M.	 	N.M.	 	

 	 	AEGCo	 	KPCo	
 	 	 	 	 	
2006	 	Regulated	 	Regulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	686,776	 	$	395,736	 	3.6	%	31	 	$	478,955	 	$	161,172	 	3.8	%	40-50	
Transmission	 	 	-	 	 	-	 	N.M.	 	N.M.	 	 	394,419	 	 	124,709	 	1.7	%	25-75	
Distribution	 	 	-	 	 	-	 	N.M.	 	N.M.	 	 	481,083	 	 	138,578	 	3.4	%	11-75	
CWIP	 	 	15,198	 	 	942	 	N.M.	 	N.M.	 	 	29,587	 	 	(1,785	)	N.M.	 	N.M.	
Other	 	 	2,415	 	 	1,744	 	11.5	%	N.M.	 	 	55,544	 	 	19,918	 	9.6	%	N.M.	
Total	 	$	704,389	 	$	398,422	 	 	 	 	 	$	1,439,588	 	$	442,592	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Nonregulated	 	Nonregulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Other	 	$	45	 	$	-	 	N.M.	 	N.M.	 	$	5,545	 	$	186	 	N.M	 	N.M.	

2005	 	Regulated	 	Regulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	 684,721	 	$	 379,641	 	3.5	%	31	 	$	 472,575	 	$	 151,389	 	3.8	%	40-50	
Transmission	 	 	-	 	 	-	 	N.M.	 	N.M.	 	 	386,945	 	 	119,048	 	1.7	%	25-75	
Distribution	 	 	-	 	 	-	 	N.M.	 	N.M.	 	 	456,063	 	 	136,106	 	3.5	%	11-75	
CWIP	 	 	 12,252	 	 	 2,226	 	N.M.	 	N.M.	 	 	 35,461	 	 	(1,126	) 	N.M.	 	N.M.	
Other	 	 	 2,251	 	 	 1,058	 	16.0	%	N.M.	 	 	 57,776	 	 	 20,241	 	9.4	%	N.M.	
Total	 	$	 699,224	 	$	 382,925	 	 	 	 	 	$	 1,408,820	 	$	 425,658	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Nonregulated	 	Nonregulated	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Other	 	$	118	 	$	-	 	N.M.	 	N.M.	 	$	5,606	 	$	159	 	2.0	%	N.M.	

2004	 	AEGCo
Regulated	 	KPCo
Regulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
 	 	 	 	(in years)	 	 	 	(in years)	 	
Production	 	3.5	%	31	 	3.8	%	40-50	 	
Transmission	 	N.M.	 	N.M.	 	1.7	%	25-75	 	
Distribution	 	N.M.	 	N.M.	 	3.5	%	11-75	 	
Other	 	16.4	% 	N.M.	 	9.2	%	N.M.	 	

 	 	I&M	 	PSO	
 	 	 	 	 	
2006	 	Regulated	 	Regulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	3,363,813	 	$	1,948,199	 	3.6	%	40-119	 	$	1,091,910	 	$	638,599	 	2.7	%	30-57	
Transmission	 	 	1,047,264	 	 	420,256	 	1.9	%	30-65	 	 	503,638	 	 	158,115	 	2.0	%	40-75	
Distribution	 	 	1,102,033	 	 	355,059	 	4.0	%	12-65	 	 	1,215,236	 	 	269,306	 	3.0	%	25-65	
CWIP	 	 	183,893	 	 	(11,627	)	N.M.	 	N.M.	 	 	141,283	 	 	(8,252	)	N.M.	 	N.M.	
Other	 	 	373,983	 	 	94,183	 	10.2	%	N.M.	 	 	229,759	 	 	129,339	 	6.7	%	N.M.	
Total	 	$	6,070,986	 	$	2,806,070	 	 	 	 	 	$	3,181,826	 	$	1,187,107	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Nonregulated	 	Nonregulated	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Other	 	$	155,744	 	$	108,061	 	N.M.	 	N.M.	 	$	4,468	 	$	-	 	N.M.	 	N.M.	

2005	 	Regulated	 	Regulated	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Production	 	$	 3,128,078	 	$	 1,901,698	 	3.8	%	40-119	 	$	 1,072,928	 	$	 639,256	 	2.7	%	30-57	
Transmission	 	 	 1,028,496	 	 	 401,024	 	1.9	%	30-65	 	 	 479,272	 	 	 153,998	 	2.1	%	40-75	
Distribution	 	 	 1,029,498	 	 	 335,642	 	4.1	%	12-65	 	 	 1,140,535	 	 	 262,763	 	3.1	%	25-65	
CWIP	 	 	 311,080	 	 	(1,544	) 	N.M.	 	N.M.	 	 	 90,455	 	 	(7,798	) 	N.M.	 	N.M.	
Other	 	 	309,217	 	 	 79,741	 	11.7	%	N.M.	 	 	 207,211	 	 	 127,639	 	7.4	%	N.M.	
Total	 	$	5,806,369	 	$	 2,716,561	 	 	 	 	 	$	 2,990,401	 	$	 1,175,858	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Nonregulated	 	Nonregulated	
Functional Class of Property	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Property, Plant and Equipment	 	Accumulated Depreciation	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	
 	 	(in thousands)	 	 	 	(in years)	 	(in thousands)	 	 	 	(in years)	
Other	 	$	155,913	 	$	105,997	 	3.4	%	N.M.	 	$	4,594	 	$	-	 	N.M.	 	N.M.	

2004	 	I&M
Regulated	 	PSO
Regulated	 	
 	 	 	 	 	 	 	 	 	 	
Functional Class of Property	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	Annual Composite Depreciation Rate	 	Depreciable Life Ranges	 	
 	 	 	 	(in years)	 	 	 	(in years)	 	
Production	 	 3.7	%	40-119	 	 2.7	%	30-57	 	
Transmission	 	 1.9	%	30-65	 	 2.3	%	40-75	 	
Distribution	 	 4.1	%	12-65	 	 3.3	%	25-65	 	
Other	 	 11.2	%	N.M.	 	 7.9	%	N.M.	 	

N.M. = Not Meaningful

We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense. Average amortization rates for coal rights and mine development costs related to SWEPCo were $0.66, $0.66 and $0.65 per ton in 2006, 2005 and 2004, respectively.

For cost-based rate-regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to accumulated depreciation. Actual removal costs incurred are charged to accumulated depreciation. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from accumulated depreciation and reflected as a regulatory liability. For nonregulated operations, non-ARO removal cost is expensed as incurred (see “Accounting for Asset Retirement Obligations” section of this note).

Accounting for Asset Retirement Obligations (ARO)

The Registrant Subsidiaries implemented SFAS 143 effective January 1, 2003. SFAS 143 requires entities to record a liability at fair value for any legal obligations for future asset retirements when the related assets are acquired or constructed. Upon establishment of a legal liability, SFAS 143 requires a corresponding ARO asset to be established, which will be depreciated over its useful life. ARO accounting is followed for regulated and nonregulated property that has a legal obligation related to asset retirement. Upon settlement of an ARO, the Registrant Subsidiaries recognize any difference between the ARO liability and actual costs as income or expense.

The Registrant Subsidiaries adopted FIN 47 during the fourth quarter of 2005. FIN 47 interprets the application of SFAS 143. It clarifies that conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Entities are required to record a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO.

The Registrant Subsidiaries completed a review of their FIN 47 conditional ARO and concluded that legal liabilities exist for asbestos removal and disposal in general buildings and generating plants. In 2005, the Registrant Subsidiaries recorded conditional ARO in accordance with FIN 47. The cumulative effect of certain retirement costs for asbestos removal related to regulated operations was generally charged to a regulatory liability and reflected in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets of certain Registrant Subsidiaries. The Registrant Subsidiaries with nonregulated generation operations recorded an unfavorable cumulative effect related to asbestos removal for those operations. This adjustment is reflected in Cumulative Effect of Accounting Change, Net of Tax on certain Registrant Subsidiaries’ 2005 statements of income.

The following table shows the liability for conditional ARO and cumulative effect recorded in 2005 for FIN 47 by Registrant Subsidiary:

 	 	Liability	 	Cumulative Effect	 	
 	 	Recorded	 	Pretax	 	Net of Tax	 	
Company	 	  	 	(in thousands)	 	
AEGCo	 	$	56	 	$	-	 	$	-	 	
APCo	 	 	8,972	 	 	(3,470	)	 	(2,256	)	
CSPCo	 	 	1,981	 	 	(1,292	)	 	(839	)	
I&M	 	 	5,801	 	 	-	 	 	-	 	
KPCo	 	 	1,190	 	 	-	 	 	-	 	
OPCo	 	 	9,513	 	 	(7,039	)	 	(4,575	)	
PSO	 	 	6,056	 	 	-	 	 	-	 	
SWEPCo	 	 	6,702	 	 	(1,926	)	 	(1,252	)	
TCC	 	 	1,165	 	 	-	 	 	-	 	
TNC	 	 	13,514	 	 	(13,034	)	 	(8,472	)	

As of December 31, 2006 and 2005, I&M’s ARO liability was $803 million and $731 million for nuclear decommissioning of the Cook Plant. These liabilities are reflected in Asset Retirement Obligations on I&M’s Consolidated Balance Sheets. As of December 31, 2006 and 2005, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $974 million and $870 million, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s Consolidated Balance Sheets.

The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets, as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

Pro forma net income related to the application of FIN 47 is not presented for the year ended December 31, 2004 because it is not materially different from reported net income for 2004.

The following is a summary by Registrant Subsidiary of the pro forma liability for conditional ARO calculated as if FIN 47 had been adopted as of January 1, 2004:

 	 	December 31,	 	
 	 	2004	 	
Company	 	(in thousands)	 	
AEGCo	 	$	53	 	
APCo	 	 	8,434	 	
CSPCo	 	 	1,862	 	
I&M	 	 	5,453	 	
KPCo	 	 	1,119	 	
OPCo	 	 	8,943	 	
PSO	 	 	5,693	 	
SWEPCo	 	 	6,757	 	
TCC	 	 	1,085	 	
TNC	 	 	12,704	 	

The following is a reconciliation of the 2006 and 2005 aggregate carrying amounts of ARO by Registrant Subsidiary:

 	 	ARO at
January 1,
2006	 	Accretion Expense	 	Liabilities Incurred	 	Liabilities Settled	 	Revisions in Cash Flow
Estimates	 	ARO at December 31, 2006	 	
Company	 	 (in thousands)	 	
AEGCo (a) (e)	 	$	1,370	 	$	107	 	$	-	 	$	(173	)	$	-	 	$	1,304	 	
APCo (a) (e)	 	 	35,496	 	 	2,620	 	 	307	 	 	(1,422	)	 	505	 	 	37,506	 	
CSPCo (a) (e)	 	 	17,844	 	 	1,310	 	 	304	 	 	(891	)	 	1,036	 	 	19,603	 	
I&M (a) (b) (e)	 	 	737,959	 	 	48,806	 	 	-	 	 	(507	)	 	23,595	 	 	809,853	 	
KPCo (e)	 	 	1,190	 	 	74	 	 	-	 	 	(89	)	 	-	 	 	1,175	 	
OPCo (a) (e)	 	 	65,557	 	 	4,949	 	 	-	 	 	(2,295	)	 	3,108	 	 	71,319	 	
PSO (e)	 	 	6,056	 	 	382	 	 	-	 	 	(188	)	 	187	 	 	6,437	 	
SWEPCo (a) (c) (e) (f)	 	 	43,077	 	 	2,437	 	 	8,362	 	 	(6,581	)	 	723	 	 	48,018	 	
TCC (e)	 	 	1,165	 	 	74	 	 	-	 	 	-	 	 	-	 	 	1,239	 	
TNC (e)	 	 	13,514	 	 	862	 	 	-	 	 	(33	)	 	525	 	 	14,868	 	

 	 	ARO at
January 1,
2005,
Including
Held for Sale	 	Accretion Expense	 	Liabilities Incurred	 	Liabilities Settled	 	Revisions in Cash Flow
Estimates	 	ARO at December 31, 2005	 	
Company	 	  (in thousands)	 	
AEGCo (a)(e)	 	$	1,216	 	$	98	 	$	56	 	$	-	 	$	-	 	$	1,370	 	
APCo (a)(e)	 	 	24,626	 	 	1,928	 	 	8,972	 	 	(32	)	 	2	 	 	35,496	 	
CSPCo (a)(e)	 	 	11,585	 	 	864	 	 	1,981	 	 	(9	)	 	3,423	 	 	17,844	 	
I&M (a)(b)(e)	 	 	711,769	 	 	47,368	 	 	5,801	 	 	-	 	 	(26,979	)	 	737,959	 	
KPCo (e)	 	 	-	 	 	-	 	 	1,190	 	 	-	 	 	-	 	 	1,190	 	
OPCo (a)(e)	 	 	45,606	 	 	3,665	 	 	9,513	 	 	-	 	 	6,773	 	 	65,557	 	
PSO (e)	 	 	-	 	 	-	 	 	6,056	 	 	-	 	 	-	 	 	6,056	 	
SWEPCo (a)(c)(e)(f)	 	 	27,361	 	 	1,491	 	 	18,071	 	 	(3,449	)	 	(397	)	 	43,077	 	
TCC (d)(e)	 	 	248,872	 	 	7,549	 	 	1,165	 	 	(256,421	)	 	-	 	 	1,165	 	
TNC (e)	 	 	-	 	 	-	 	 	13,514	 	 	-	 	 	-	 	 	13,514	 	
 
(a)	Includes ARO related to ash ponds.	
(b)	Includes ARO related to nuclear decommissioning costs for the Cook Plant ($803 million and $731 million at December 31, 2006 and 2005, respectively).	
(c)	Includes ARO related to Sabine Mining Company and Dolet Hills Lignite Company, LLC.	
(d)	Includes ARO related to nuclear decommissioning costs for TCC’s share of STP. STP was sold in May 2005 (see Note 8).	
(e)	Includes ARO related to asbestos removal.	
(f)	The current portion of SWEPCo’s ARO, totaling $1 million and $2 million, at December 31, 2006 and 2005, respectively, is included in Other in the Current Liabilities section of SWEPCo’s Consolidated Balance Sheets.	

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The amounts of AFUDC included in Allowance For Equity Funds Used During Construction on the Registrant Subsidiaries’ Consolidated Statements of Income for 2006, 2005 and 2004 were as follows:

 	 	2006	 	2005	 	2004	 	
Company	 	(in millions)	 	
AEGCo	 	$	-	 	$	0.1	 	$	-	 	
APCo	 	 	12.0	 	 	8.0	 	 	6.6	 	
CSPCo	 	 	1.9	 	 	1.6	 	 	1.1	 	
I&M	 	 	7.9	 	 	4.5	 	 	2.3	 	
KPCo	 	 	0.2	 	 	0.3	 	 	0.3	 	
OPCo	 	 	2.6	 	 	1.4	 	 	1.5	 	
PSO	 	 	0.7	 	 	0.9	 	 	0.3	 	
SWEPCo	 	 	1.3	 	 	2.4	 	 	0.8	 	
TCC	 	 	2.7	 	 	1.0	 	 	1.2	 	
TNC	 	 	0.9	 	 	0.7	 	 	0.4	 	
 
The amounts of interest capitalized included in Interest Expense on the Registrant Subsidiaries’ Consolidated Statements of Income for 2006, 2005 and 2004 were as follows:

 	 	2006	 	2005	 	2004	 	
Company	 	(in millions)	 	
AEGCo	 	$	0.4	 	$	0.2	 	$	-	 	
APCo	 	 	17.7	 	 	8.7	 	 	8.1	 	
CSPCo	 	 	6.0	 	 	1.5	 	 	5.0	 	
I&M	 	 	7.5	 	 	4.3	 	 	1.8	 	
KPCo	 	 	0.7	 	 	0.3	 	 	0.2	 	
OPCo	 	 	42.7	 	 	16.4	 	 	4.8	 	
PSO	 	 	1.5	 	 	0.6	 	 	0.3	 	
SWEPCo	 	 	2.2	 	 	1.2	 	 	0.3	 	
TCC	 	 	2.6	 	 	1.5	 	 	0.7	 	
TNC	 	 	0.6	 	 	0.4	 	 	0.2	 	

Jointly-owned Electric Utility Plant

CSPCo, PSO, SWEPCo, TCC and TNC have generating units that are jointly-owned with affiliated and nonaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly-owned facilities in the same proportion as its ownership interest. Each Registrant Subsidiary’s proportionate share of the operating costs associated with such facilities is included in its statements of operations and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:
 
 	 	 	 	 	Company’s Share at December 31, 2006	 	
 	Fuel
Type	 	Percent of Ownership	 	Utility Plant in Service	 	Construction Work in
Progress (i)	 	Accumulated
Depreciation	 	
 	 	 	 	 	(in thousands)	 	
CSPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal	 	12.5	%	$	15,702	 	$	280	 	$	7,560	 	
Conesville Generating Station (Unit No. 4) (b)	Coal	 	43.5	 	 	85,253	 	 	31,691	 	 	49,150	 	
J.M. Stuart Generating Station (c)	Coal	 	26.0	 	 	284,142	 	 	101,769	 	 	127,591	 	
Wm. H. Zimmer Generating Station (a)	Coal	 	25.4	 	 	751,148	 	 	4,797	 	 	302,053	 	
Transmission	N/A	 	(d)	 	 	62,876	 	 	86	 	 	42,433	 	
Total	 	 	 	 	$	1,199,121	 	$	138,623	 	$ 	528,787	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
PSO	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oklaunion Generating Station (Unit No. 1) (e)	Coal	 	15.6	%	$	86,676	 	$	543	 	$	55,951	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SWEPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite	 	40.2	%	$	240,471	 	$	5,248	 	$	166,938	 	
Flint Creek Generating Station (Unit No. 1) (g)	Coal	 	50.0	 	 	96,799	 	 	1,637	 	 	57,303	 	
Pirkey Generating Station (Unit No. 1) (g)	Lignite	 	85.9	 	 	481,093	 	 	4,847	 	 	310,271	 	
Total	 	 	 	 	$	818,363	 	$	11,732	 	$	534,512	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TCC (h)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oklaunion Generating Station (Unit No. 1) (e)	Coal	 	7.8	%	$	39,660	 	$	-	 	$	19,671	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TNC	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oklaunion Generating Station (Unit No. 1) (e)	Coal	 	54.7	%	$	290,485	 	$	2,164	 	$	124,459	 	
 
 	 	 	 	 	Company’s Share at December 31, 2005	 	
 	Fuel
Type	 	Percent of Ownership	 	Utility Plant in Service	 	Construction Work in Progress (i)	 	Accumulated
Depreciation	 	
 	 	 	 	 	(in thousands)	 	
CSPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
W.C. Beckjord Generating Station (Unit No. 6) (a)	Coal	 	12.5	%	$	15,681	 	$	52	 	$	7,274	 	
Conesville Generating Station (Unit No. 4) (b)	Coal	 	43.5	 	 	85,162	 	 	7,583	 	 	48,086	 	
J.M. Stuart Generating Station (c)	Coal	 	26.0	 	 	266,136	 	 	35,461	 	 	120,770	 	
Wm. H. Zimmer Generating Station (a)	Coal	 	25.4	 	 	749,112	 	 	2,295	 	 	280,310	 	
Transmission	N/A	 	(d)	 	 	62,553	 	 	1,344	 	 	41,109	 	
Total	 	 	 	 	$	1,178,644	 	$	46,735	 	$ 	497,549	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
PSO	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oklaunion Generating Station (Unit No. 1) (e)	Coal	 	15.6	%	$	86,051	 	$	700	 	$	54,401	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SWEPCo	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dolet Hills Generating Station (Unit No. 1) (f)	Lignite	 	40.2	%	$	237,941	 	$	3,829	 	$	159,774	 	
Flint Creek Generating Station (Unit No. 1) (g)	Coal	 	50.0	 	 	94,261	 	 	2,494	 	 	55,378	 	
Pirkey Generating Station (Unit No. 1) (g)	Lignite	 	85.9	 	 	459,513	 	 	10,447	 	 	297,590	 	
Total	 	 	 	 	$	791,715	 	$	16,770	 	$	512,742	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TCC (h)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oklaunion Generating Station (Unit No. 1) (e)	Coal	 	7.8	%	$	39,656	 	$	321	 	$	19,765	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TNC	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oklaunion Generating Station (Unit No. 1) (e)	Coal	 	54.7	%	$	288,934	 	$	2,165	 	$	117,963	 	

(a)	Operated by Duke Energy Corporation, a nonaffiliated company.	
(b)	Operated by CSPCo.	
(c)	Operated by The Dayton Power & Light Company, a nonaffiliated company.	
(d)	Varying percentages of ownership.	
(e)	Operated by PSO.	
(f)	Operated by Cleco Corporation, a nonaffiliated company.	
(g)	Operated by SWEPCo.	
(h)	Included in Assets Held for Sale - Texas Generation Plant on TCC’s Consolidated Balance Sheets.	
(i)	Primarily relates to environmental upgrades, including the installation of flue gas desulfurization projects at Conesville Generating Station and J.M. Stuart Generating Station.	
 	 	
N/A	= Not Applicable	

         18.   UNAUDITED QUARTERLY FINANCIAL INFORMATION

The unaudited quarterly financial information for each Registrant Subsidiary is provided below. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors.

Quarterly Periods Ended:	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
March 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Operating Revenues	 	$	78,151	 	$	634,441	 	$	428,768	 	$	515,779	 	$	151,847	 	
Operating Income	 	 	4,220	 	 	138,473	 	 	92,497	 	 	103,438	 	 	22,524	 	
Net Income	 	 	2,928	 	 	73,594	 	 	51,337	 	 	57,878	 	 	9,830	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
June 30, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	77,195	 	$	514,588	 	$	417,109	 	$	469,454	 	$	135,303	 	
Operating Income	 	 	2,998	 	 	30,601	 	 	61,331	 	 	57,461	 	 	13,554	 	
Net Income	 	 	2,220	 	 	9,647	 	 	32,262	 	 	28,525	 	 	5,051	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	74,756	 	$	648,601	 	$	539,898	 	$	525,535	 	$	152,319	 	
Operating Income	 	 	3,110	 	 	89,716	 	 	140,636	 	 	66,401	 	 	21,846	 	
Net Income	 	 	2,219	 	 	30,536	 	 	84,021	 	 	34,561	 	 	9,869	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	79,712	 	$	596,398	 	$	420,960	 	$	466,179	 	$	146,398	 	
Operating Income	 	 	2,590	 	 	106,853	 	 	43,186	 	 	24,891	 	 	23,701	 	
Net Income	 	 	3,547	 	 	67,672	 	 	17,959	 	 	204	 	 	10,285	 	
 
Quarterly Periods Ended:	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
March 31, 2006	 	  	 	  	 	  	 	  	 	  	 	
Operating Revenues	 	$	702,606	 	$	354,729	 	$	305,132	 	$	135,288	 	$	74,666	 	
Operating Income (Loss)	 	 	157,063	 	 	(1,163	)	 	38,960	 	 	11,468	 	 	8,635	 	
Net Income (Loss)	 	 	95,032	 	 	(5,357	)	 	17,872	 	 	3,773	 	 	3,834	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
June 30, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	616,007	 	$	347,046	 	$	359,484	 	$	161,489	 	$	82,998	 	
Operating Income	 	 	53,069	 	 	30,024	 	 	54,932	 	 	33,411	 	 	184	 	
Net Income (Loss)	 	 	23,399	 	 	14,638	 	 	28,312	 	 	16,975	 	 	(592	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	764,908	 	$	458,441	 	$	456,700	 	$	173,923	 	$	87,762	 	
Operating Income	 	 	145,100	 	 	77,577	 	 	91,273	 	 	35,771	 	 	16,368	 	
Net Income	 	 	83,342	 	 	42,023	 	 	49,706	 	 	17,235	 	 	8,446	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	641,354	 	$	281,568	 	$	310,523	 	$	193,964	 	$	84,044	 	
Operating Income (Loss)	 	 	70,059	 	 	(15,445	)	 	4,453	 	 	48,447	 	 	10,100	 	
Net Income (Loss)	 	 	26,870	 	 	(14,444	)	 	(4,167	)	 	3,586	 	 	3,255	 	

Quarterly Periods Ended:	 	AEGCo	 	APCo	 	CSPCo	 	I&M	 	KPCo	 	
 	 	(in thousands)	 	
March 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Operating Revenues	 	$	66,546	 	$	557,695	 	$	367,133	 	$	457,559	 	$	128,060	 	
Operating Income	 	 	3,195	 	 	92,359	 	 	78,667	 	 	72,890	 	 	21,083	 	
Income Before Cumulative Effect of Accounting Changes	 	 	
2,516	 	 	
46,672	 	 	47,468	 	 	
39,669	 	 	9,885	 	
Net Income	 	 	2,516	 	 	46,672	 	 	47,468	 	 	39,669	 	 	9,885	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
June 30, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	65,082	 	$	497,102	 	$	359,990	 	$	457,560	 	$	122,709	 	
Operating Income	 	 	2,340	 	 	53,752	 	 	63,558	 	 	69,589	 	 	9,743	 	
Income Before Cumulative Effect of  Accounting Changes	 	 	
2,073	 	 	24,213	 	 	
34,651	 	 	35,593	 	 	2,446	 	
Net Income	 	 	2,073	 	 	24,213	 	 	34,651	 	 	35,593	 	 	2,446	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	69,640	 	$	570,122	 	$	454,568	 	$	515,079	 	$	143,996	 	
Operating Income	 	 	2,913	 	 	79,477	 	 	65,604	 	 	100,754	 	 	18,223	 	
Income Before Cumulative Effect of  Accounting Changes	 	 	2,239	 	 	37,372	 	 	34,225	 	 	53,012	 	 	7,727	 	
Net Income	 	 	2,239	 	 	37,372	 	 	34,225	 	 	53,012	 	 	7,727	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	69,487	 	$	551,354	 	$	360,641	 	$	462,404	 	$	136,578	 	
Operating Income	 	 	2,453	 	 	57,800	 	 	35,051	 	 	43,427	 	 	11,782	 	
Income Before Cumulative Effect of  Accounting Changes	 	 	1,867	 	 	
27,575	 	 	21,455	 	 	18,578	 	 	751	 	
Net Income	 	 	1,867	 	 	25,319	 	 	20,616	 	 	18,578	 	 	751	 	

Quarterly Periods Ended:	 	OPCo	 	PSO	 	SWEPCo	 	TCC	 	TNC	 	
 	 	(in thousands)	 	
March 31, 2005	 	  	 	  	 	  	 	  	 	  	 	
Operating Revenues	 	$	655,154	 	$	253,082	 	$	247,211	 	$	201,357	 	$	118,907	 	
Operating Income	 	 	151,434	 	 	7,113	 	 	29,163	 	 	30,284	 	 	15,815	 	
Income Before Cumulative Effect of  Accounting Changes	 	 	99,483	 	 	505	 	 	12,205	 	 	1,137	 	 	7,394	 	
Net Income	 	 	99,483	 	 	505	 	 	12,205	 	 	1,137	 	 	7,394	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
June 30, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	650,999	 	$	286,602	 	$	332,851	 	$	202,326	 	$	114,704	 	
Operating Income	 	 	123,901	 	 	32,435	 	 	37,363	 	 	42,922	 	 	20,162	 	
Income Before Cumulative Effect of  Accounting Changes	 	 	71,481	 	 	18,570	 	 	19,304	 	 	28,368	 	 	12,004	 	
Net Income	 	 	71,481	 	 	18,570	 	 	19,304	 	 	28,368	 	 	12,004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
September 30, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	687,140	 	$	432,633	 	$	474,283	 	$	203,365	 	$	126,097	 	
Operating Income	 	 	99,437	 	 	85,387	 	 	88,135	 	 	63,399	 	 	36,924	 	
Income Before Cumulative Effect of  Accounting Changes	 	 	56,408	 	 	48,654	 	 	49,731	 	 	40,476	 	 	22,304	 	
Net Income	 	 	56,408	 	 	48,654	 	 	49,731	 	 	40,476	 	 	22,304	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	$	641,256	 	$	331,761	 	$	351,034	 	$	186,198	 	$	99,180	 	
Operating Income (Loss)	 	 	50,715	 	 	(6,919	)	 	5,876	 	 	40,676	 	 	3,798	 	
Income (Loss) Before Extraordinary Item  and Cumulative
  Effect of Accounting  Changes	 	 	23,047	 	 	(9,836	)	 	(6,050	)	 	(19,209	)	 	(226	)	
Extraordinary Loss on Stranded Cost  Recovery, Net of Tax (a)	 	 	-	 	 	-	 	 	-	 	 	(224,551	)	 	-	 	
Net Income (Loss)	 	 	18,472	 	 	(9,836	)	 	(7,302	)	 	(243,760	)	 	(8,698	)	

(a)	See “Extraordinary Items” section of Note 2 and “TCC Texas Restructuring” section of Note 4 for discussions of the extraordinary loss booked in the fourth quarter of 2005.	

For each of the Registrant Subsidiaries, (excluding TCC for 2005) there were no significant, nonrecurring events in the fourth quarter of 2006 or 2005.

 
COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the registrants’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and results of operations and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, (iii) footnotes and (iv) the schedules of each individual registrant.

Source of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities. Proceeds are loaned to the Registrant Subsidiaries through intercompany notes. AEP and its Registrant Subsidiaries also operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity for certain electric subsidiaries. The Registrant Subsidiaries generally use short-term funding sources (the money pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leaseback, leasing arrangements and additional capital contributions from AEP.

Dividend Restrictions

Under regulatory orders, the Registrant Subsidiaries can only pay dividends out of retained or current earnings.

Sale of Receivables Through AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires from affiliated utility subsidiaries to the commercial paper conduits and banks and receives cash. AEP does not have an ownership interest in the commercial paper conduits and is not required to consolidate these entities in accordance with GAAP. AEP Credit continues to service the receivables. This off-balance sheet transaction was entered to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s sale of receivables agreement expires August 24, 2007. AEP intends to extend or replace the sale of receivables agreement. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2006, $536 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent receivables purchased by AEP Credit from certain Registrant Subsidiaries. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.
 
Budgeted Capital Expenditures

Construction expenditures for the Registrant Subsidiaries for 2007 are:
 	 	Projected Construction Expenditures	 	
Company	 	(in millions)	 	
AEGCo	 	$	18	 	
APCo	 	 	664	 	
CSPCo	 	 	337	 	
I&M	 	 	252	 	
KPCo	 	 	71	 	
OPCo	 	 	832	 	
PSO	 	 	319	 	
SWEPCo	 	 	537	 	
TCC	 	 	241	 	
TNC	 	 	143	 	
 
In addition, AEGCo and CSPCo announced the purchase of gas-fired generating units for $325 million and $102 million, respectively. 
 
Significant Factors

Ohio New Generation

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 629 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases. In Phase 1, the Ohio companies would recover approximately $24 million in pre-construction costs during 2006. In Phase 2, the Ohio companies would recover construction-financing costs through regulatory authorization until the plant is placed in service. The proposed recoveries in Phases 1 and 2 will be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008, under their RSPs. In Phase 3, which begins when the plant enters commercial operation and runs through the operating life of the plant, the Ohio companies would recover or refund in distribution rates any difference between the Ohio companies’ market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power costs. Through December 31, 2006, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $6 million of those costs. The PUCO indicated that if the Ohio companies have not commenced continuous construction of the IGCC plant by 2010, all charges collected for pre-construction costs, which are assignable to other jurisdictions, must be refunded to Ohio ratepayers with interest.

SECA Revenue Subject to Refund

The AEP East companies eliminated through-and-out transmission service (T&O) revenues in accordance with FERC orders and implemented SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. 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 was 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.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund. The AEP East companies have reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. The AEP East companies have provided a reserve for $37 million in net refunds.
 
AEP, together with Exelon and the Dayton Power and Light Company, filed an extensive post hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes that the FERC should reject the initial decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. However, the initial decision is adversely impacting settlement negotiations. Although management believes it has meritorious arguments, they cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.

Pension and Postretirement Benefit Plans

In September 2006, the FASB issued SFAS 158 related to phase one of its pension and postretirement benefit accounting project. The new standard requires the recognition of a liability for pension and postretirement benefit plans, thereby eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net actuarial gains and losses. The adoption during the fourth quarter of 2006 resulted in a negative impact on certain Registrant Subsidiaries’ common equity at December 31, 2006 due to the recognition of an accumulated other comprehensive income reduction for those jurisdictions where we could not record a regulatory asset.

AEP maintains qualified, defined benefit pension plans (Qualified Plans), which cover a substantial majority of nonunion and certain union employees, and unfunded, nonqualified supplemental plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans collectively the Pension Plans. Additionally, AEP entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits as a part of the nonqualified, supplemental plans. AEP also sponsors other postretirement benefit plans to provide medical and life insurance benefits for retired employees (Postretirement Plans). The Qualified Plans and Postretirement Plans are collectively “the Plans.”

The following table shows the net periodic benefit cost and assumed rate of return on Plan assets for AEP’s Pension Plans and Postretirement Plans:
 	 	2006	 	  2005	 	2004	 	
Net Periodic Benefit Cost	 	(in millions)	 	
Pension Plans	 	$	71	 	$	61	 	$	40	 	
Postretirement Plans	 	 	96	 	 	109	 	 	141	 	
Assumed Rate of Return	 	 	 	 	 	 	 	 	 	 	
Pension Plans	 	 	8.50	%	 	8.75	%	 	8.75	% 	
Postretirement Plans	 	 	8.00	%	 	8.37	%	 	8.35	%	

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Plans’ assets. In developing the expected long-term rate of return assumption, AEP evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. AEP also considered historical returns of the investment markets as well as its ten-year average return, for the period ended December 2006, of approximately 9.43%. AEP anticipates that the investment managers employed for the Pension Plans will continue to generate long-term returns averaging 8.50%.
 
The expected long-term rate of return on the Plans’ assets is based on AEP’s targeted asset allocation and its expected investment returns for each investment category. AEP’s assumptions are summarized in the following table:
 	 	Pension	 	Other Postretirement
Benefit Plans	 	 	 	
 	 	2006
Actual
Asset Allocation	 	2007
Target
Asset
Allocation	 	2006
Actual
Asset
Allocation	 	2007
Target
Asset
Allocation	 	Assumed/
Expected
Long-term
Rate of
Return	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Equity	 	 	63	%  	 	65	%  	 	66	%  	 	65	%  	 	10.00	%  	
Real Estate	 	 	6	%	 	5	%	 	-	%	 	-	%	 	8.25	%	
Fixed Income	 	 	26	%	 	28	%	 	32	%	 	33	%	 	5.25	%	
Cash and Cash Equivalents	 	 	5	%	 	2	%	 	2	%	 	2	%	 	4.25	%	
Total	 	 	100	%	 	100	%	 	100	%	 	100	%	 	 	 	

 	Pension	 	Other Postretirement
Benefit Plans	 	
Overall Expected Return  (weighted average)	8.50	%	8.00	%	

AEP regularly reviews the actual asset allocation and periodically rebalances the investments to its targeted allocation. AEP believes that 8.50% and 8.00% for the Pension Plans and Postretirement Plans, respectively, are reasonable long-term rate of return on the Plans’ assets despite the recent market volatility. The Plans’ assets had an actual gain of 12.78% and 7.76% for the twelve months ended December 31, 2006 and 2005, respectively. AEP will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

AEP bases its determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2006, AEP had cumulative gains of approximately $187 million, which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial gains result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with SFAS No. 87, “Employers’ Accounting for Pensions.”

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s AA bond index was constructed but with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2006 under this method was 5.75% for the Pension Plans and 5.85% for the Postretirement Plans. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 8.50%, a discount rate of 5.75% and various other assumptions, AEP estimates that the pension costs for all pension plans will approximate $40 million, $14 million and $5 million in 2007, 2008 and 2009, respectively. Based on an expected rate of return on the OPEB plans’ assets of 8.00%, a discount rate of 5.85% and various other assumptions, AEP estimates Postretirement Plan costs will approximate $85 million, $81 million and $78 million in 2007, 2008 and 2009, respectively. Future actual cost will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 50 basis point change to selective actuarial assumptions are in “Pension and Other Postretirement Benefits” within the “Critical Accounting Estimates” section of this Combined Management’s Discussion and Analysis of Registrant Subsidiaries.

The value of AEP’s Pension Plans’ assets increased to $4.3 billion at December 31, 2006 from $4.1 billion at December 31, 2005 primarily due to investment returns on the assets. The Qualified Plans paid $267 million in benefits to plan participants during 2006 (nonqualified plans paid $9 million in benefits). The value of AEP’s Postretirement Plans’ assets increased to $1.3 billion at December 31, 2006 from $1.2 billion at December 31, 2005. The Postretirement Plans paid $112 million in benefits to plan participants during 2006.

AEP’s nonqualified pension plans are unfunded, and are therefore considered underfunded for accounting purposes. For the nonqualified pension plans, the accumulated benefit obligation in excess of plan assets was $78 million and $81 million at December 31, 2006 and 2005, respectively. AEP made a contribution of $626 million in 2005 to meet its goal of fully funding all Qualified Plans by the end of 2005. AEP’s Qualified Plans remained fully funded as of December 31, 2006.

Certain pension plans AEP sponsors and maintains contain a cash balance benefit feature. In recent years, cash balance benefit features have become a focus of scrutiny, as government regulators and courts consider how the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended, and other relevant federal employment laws apply to plans with such a cash balance plan feature. AEP believes that its defined benefit pension plans comply with the applicable requirements of such laws.

The Pension Protection Act of 2006 did not materially impact AEP’s plans.

Litigation

See discussion of the Environmental Litigation under “Environmental Matters.”

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, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities, which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.

Environmental Matters

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

·	Requirements under the Clean Air Act (CAA) to reduce emissions of sulfur dioxide (SO 2 ), nitrogen oxide (NO x ), particulate matter (PM) and mercury from fossil fuel-fired power plants; and	
·	Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain power plants.	

In addition, the Registrant Subsidiaries are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of I&M’s nuclear units. Management also monitors possible future requirements to reduce carbon dioxide (CO 2 ) emissions to address concerns about global climate change. All of these matters are discussed below.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality, and control mobile and stationary sources of air emissions. The major CAA programs affecting power plants are briefly described below. The states implement and administer many of these programs and could impose additional or more stringent requirements.

National Ambient Air Quality Standards: The CAA requires the Federal EPA to periodically review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin. These concentration levels are known as “national ambient air quality standards” or NAAQS.

Each state identifies those areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. In addition, as the Federal EPA reviews the NAAQS, the attainment status of areas can change, and states may be required to develop new SIPs. The Federal EPA recently proposed a new PM NAAQS and is conducting periodic reviews for additional criteria pollutants.

In 1997, the Federal EPA established new NAAQS that required further reductions in SO 2 and NO x emissions. In 2005, the Federal EPA issued a final model federal rule, the Clean Air Interstate Rule (CAIR), that assists states developing new SIPs to meet the new NAAQS. CAIR reduces regional emissions of SO 2 and NO x from power plants in the Eastern U.S. (29 states and the District of Columbia). CAIR requires power plants within these states to reduce emissions of SO 2 by 50 percent by 2010, and by 65 percent by 2015. NO x emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015. Reductions of both SO 2 and NO x would be achieved through a cap-and-trade program. The Federal EPA affirmed certain aspects of the final CAIR after reconsideration. The rule has been challenged in the courts. States were required to develop and submit SIPs to implement CAIR by November 2006. Nearly all of the states in which the Registrant Subsidiaries’ power plants are located will be covered by CAIR. Oklahoma is not affected, while Texas and Arkansas will be covered only by certain parts of CAIR. A SIP that complies with CAIR will also establish compliance with other CAA requirements, including certain visibility goals.

Hazardous Air Pollutants: As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In 2005, the Federal EPA issued a final Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants. The Federal EPA issued a model federal rule based on a cap-and-trade program for mercury emissions from existing coal-fired power plants that would reduce mercury emissions to 38 tons per year from all existing plants in 2010, and to 15 tons per year in 2018. The national cap of 38 tons per year in 2010 is intended to reflect the level of reduction in mercury emissions that will be achieved as a result of installing controls to reduce SO 2 and NO x emissions in order to comply with CAIR. The Federal EPA affirmed certain aspects of the final CAMR after reconsideration, and the rule has been challenged in the courts. States were required to develop and submit their SIPs to implement CAMR by November 2006.

The Acid Rain Program: The 1990 Amendments to the CAA included a cap-and-trade emission reduction program for SO 2 emissions from power plants, implemented in two phases. By 2000, the program established a nationwide cap on power plant SO 2 emissions of 8.9 million tons per year. The 1990 Amendments also contained requirements for power plants to reduce NOx emissions through the use of available combustion controls.

The success of the SO 2 cap-and-trade program encouraged the Federal EPA and states to use it as a model for other emission reduction programs, including CAIR and CAMR. The Registrant Subsidiaries continue to meet their obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets. CAIR uses the SO 2 allowances originally allocated through the Acid Rain Program as the basis for its SO 2 cap-and-trade system.

Regional Haze : The CAA also establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (the “Regional Haze” program). In 2005, the Federal EPA issued its final Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology (BART) requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. The final rule contains a demonstration that CAIR will result in more visibility improvements than BART for power plants subject to it. Thus, states are allowed to substitute CAIR requirements in their Regional Haze SIPs for controls that would otherwise be required by BART. For BART-eligible facilities located in states not subject to CAIR requirements for SO 2 and NO x , some additional controls will be required. The courts upheld the final rule.
 
Estimated Air Quality Environmental Investments

The CAIR and CAMR programs described above will require significant additional investments, some of which are estimable. However, many of the rules described above have been challenged in the courts and are not incorporated into SIPs. As a result, these rules may be further modified. Management’s estimates are subject to significant uncertainties, and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: the timing of implementation; required levels of reductions; methods for allocation of allowances; and selected compliance alternatives. In short, management cannot estimate compliance costs with certainty, and the actual costs to comply could differ significantly from the estimates discussed below.

APCo, CSPCo, KPCo and OPCo installed a total of 9,700 MW of selective catalytic reduction (SCR) technology to control NO x emissions at their power plants over the past several years to comply with NO x requirements in various SIPs. The Registrant Subsidiaries comply with Acid Rain Program SO 2 requirements by installing scrubbers, using alternate fuels and using SO 2 allowances. They receive allowances through Acid Rain Program allocations and purchase them at the annual Federal EPA auction or in the market. Decreasing allowance allocations, diminishing SO 2 allowance banks, and increasing allowance costs will require installation of additional controls on the Registrant Subsidiaries’ power plants. In addition under CAIR and CAMR, the Registrant Subsidiaries will be required to install additional controls by 2010. The Registrant Subsidiaries plan to install additional scrubbers on 7,300 MW for SO 2 control and additional SCRs on 1,900 MW for NO x control to comply with current CAIR and CAMR requirements. In January 2007, the scrubber on Unit 2 of Mitchell Plant went into service leaving 6,500 MW of scrubbers to be completed. From 2007 to 2011, the following table shows the total estimated costs for environmental investment and additional scrubbers and other SO 2 equipment by Registrant Subsidiary:

 	 	Total
Environmental	 	Cost of Additional Scrubbers and
SO 2 Equipment	 	
Company	 	(in millions)	 	
APCo	 	$	739	 	$	494	 	
CSPCo	 	 	299	 	 	187	 	
OPCo	 	 	746	 	 	502	 	
PSO	 	 	263	 	 	221	 	
SWEPCo	 	 	66	 	 	9	 	

The Registrant Subsidiaries will also incur additional operation and maintenance expenses in future years due to the costs associated with the maintenance of additional controls, disposal of byproducts and purchase of reagents.

Assuming that the CAIR and CAMR programs are implemented consistent with the provisions of the final federal rules, the Registrant Subsidiaries expect to incur additional costs for pollution control technology retrofits totaling approximately $2.6 billion between 2012 and 2020. However, this estimate is highly uncertain due to the uncertainty associated with: (1) the states’ implementation of these regulatory programs, including the potential for SIPs that impose standards more stringent than CAIR or CAMR; (2) the actual performance of the pollution control technologies installed on each unit; (3) changes in costs for new pollution controls; (4) new generating technology developments; and (5) other factors. Associated operational and maintenance expenses will also increase during those years. Management cannot estimate these additional operational and maintenance costs due to the uncertainties described above, but they are expected to be significant.

The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through regulated rates (in regulated jurisdictions). The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, those costs could adversely affect future results of operations, cash flows and possibly financial condition.

Clean Water Act Regulation

In 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water. The standards vary based on the water bodies from which the plants draw their cooling water. These rules will result in additional capital and operating expenses, which the Federal EPA estimated could be $193 million for the Registrant Subsidiaries’ plants. Any capital costs incurred to meet these standards had been expected to be incurred between 2008 and 2010. The Registrant Subsidiaries undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates. In addition, a recent court decision introduced additional uncertainty to these costs and their timing. The following table shows the investment amount per Registrant Subsidiary.

 	 	Estimated Compliance Investments	 	
Company	 	(in millions)	 	
APCo	 	$	21	 	
CSPCo	 	 	19	 	
I&M	 	 	118	 	
OPCo	 	 	31	 	

The rule was challenged in the courts by states, advocacy organizations and industry. On January 25, 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA. Among other things, the restoration option, the cost-benefit and other tests and certain alternative technology options in the 2004 rule have been remanded. Management cannot predict how or when the Federal EPA will respond to the remand, or what effect the remand may have on similar requirements adopted by the states. The Registrant Subsidiaries may seek further review or relief from the schedules included in the final rule and their plant’s permits, in order to allow time for the Federal EPA’s response to the remand.

Potential Regulation of CO 2 Emissions

At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in 1997, more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly CO 2 , which many scientists believe are contributing to global climate change. The U.S. signed the Kyoto Protocol in 1998, but the treaty was not submitted to the Senate for its advice and consent. In 2001, President Bush announced his opposition to the treaty. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries in February 2005. Members of Congress introduced several bills seeking regulation of greenhouse gas emissions, including CO 2 emissions from power plants, but none have passed. The AEP System participate in a number of voluntary programs to monitor, mitigate, and reduce greenhouse gas emissions.

The Federal EPA stated that it does not have authority under the CAA to regulate greenhouse gas emissions that may affect global climate trends. This decision was upheld by an appellate court. The U.S. Supreme Court reviewed the appellate decision and is expected to issue its decision in 2007.

The Registrant Subsidiaries will seek recovery of expenditures for potential regulation of CO 2 emissions from customers through regulated rates (in regulated jurisdictions). The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions.

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M and OPCo modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. A separate lawsuit, initiated by certain special interest groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and thereafter against nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at the Registrant Subsidiaries’ power plants occurred over a twenty-year period. A bench trial on the liability issues was held during 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions. Similarly, courts that considered whether the activities at issue increased emissions from the power plants have reached different results. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Federal EPA filed a petition for rehearing in that case, which the Court denied. The Federal EPA also recently proposed a rule that would define “emissions increases” in a way that would excluded most of the challenged activities from NSR.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, the Registrant Subsidiaries might have for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues to be determined by the court. If the Registrant Subsidiaries do not prevail, management believes the Registrant Subsidiaries can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity. If the Registrant Subsidiaries are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Other Environmental Concerns

Management performs environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. In addition to the matters discussed above, the Registrant Subsidiaries manage other environmental concerns that are not believed to be material or potentially material at this time. If they become significant or if any new matters arise that could be material, they could have a material adverse effect on results of operations, cash flows and possibly financial condition.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:

·	it requires assumptions to be made that were uncertain at the time the estimate was made; and	
·	changes in the estimate or different estimates that could have been selected could have a material effect on results of operations or financial condition.	

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosure relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions.

The sections that follow present information about the Registrant Subsidiaries’ most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required: The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (I&M, KPCo, PSO, AEGCo and a portion of APCo, CSPCo, OPCo, SWEPCo, TCC and TNC) reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.
 
The Registrant Subsidiaries recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation by matching the timing of expense recognition with the recovery of such expense in regulated revenues. Likewise, they match income with the regulated revenues from their customers in the same accounting period. Regulatory liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used: When regulatory assets are probable of recovery through regulated rates, the Registrant Subsidiaries record them as assets on the balance sheet. Regulatory assets are tested for probability of recovery whenever new events occur, for example, changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate of return earned on invested capital and the timing and amount of assets to be recovered through regulated rates. If it is determined that recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on the results of operations. Refer to Note 5 of the Notes to Financial Statements of Registrant Subsidiaries for further detail related to regulatory assets and liabilities.

Revenue Recognition - Unbilled Revenues

Nature of Estimates Required:   The Registrant Subsidiaries record revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings.
 
Incremental unbilled electric utility revenues included in Revenue for the years ended December 31 were as follows:

 	 	2006	 	2005	 	2004	 	
Company	 	(in thousands)	 	
APCo	 	$	711	 	$	14,024	 	$	18,206	 	
CSPCo	 	 	4,545	 	 	(5,404	)	 	283	 	
I&M	 	 	1,166	 	 	1,783	 	 	(2,942	)	
KPCo	 	 	1,021	 	 	1,105	 	 	3,833	 	
OPCo	 	 	(3,312	)	 	14,689	 	 	(2,793	)	
PSO	 	 	157	 	 	494	 	 	2,789	 	
SWEPCo	 	 	(4,875	)	 	606	 	 	1,814	 	
TCC	 	 	(14,262	)	 	(164	)	 	(1,579	)	
TNC	 	 	(2,740	)	 	1,250	 	 	(1,160	)	

Assumptions and Approach Used: The Registrant Subsidiaries calculate the monthly estimate for unbilled revenues as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to the occurrence of problems in meter readings, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWH to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWH. The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

Effect if Different Assumptions Used:   Significant fluctuations in energy demand for the unbilled period, weather impact, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the Accrued Unbilled Revenues on the Balance Sheets.

Revenue Recognition - Accounting for Derivative Instruments

Nature of Estimates Required: Management considers fair value techniques, valuation adjustments related to credit and liquidity, and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used:   APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based on exchange prices and broker quotes. If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data, and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing future bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. Credit adjustments are based on estimated defaults by counterparties that are calculated using historical default probabilities for companies with similar credit ratings. APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC evaluate the probability of the occurrence of the forecasted transaction within the specified time period as provided for in the original documentation related to hedge accounting.

Effect if Different Assumptions Used: There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

The probability that hedged forecasted transactions will occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding accounting for derivative instruments, see sections labeled Credit Risk and VaR Associated with Risk Management Contracts within “Quantitative and Qualitative Disclosures About Risk Management Activities.”

Long-Lived Assets

Nature of Estimates Required: In accordance with the requirements of SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Registrant Subsidiaries evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable or the assets meet the held for sale criteria under SFAS 144. The evaluations of long-lived held and used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses. If the carrying amount is not recoverable, the subsidiary records an impairment to the extent that the fair value of the asset is less than its book value. For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. For nonregulated assets, any impairment charge is recorded as a charge against earnings.
 
Assumptions and Approach Used: The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, the Registrant Subsidiaries estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used: In connection with the evaluation of long-lived assets in accordance with the requirements of SFAS 144, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques. In cases of impairment as described in Note 8 of the Notes to Financial Statements of Registrant Subsidiaries, the best estimate of fair value was made using valuation methods based on the most current information at that time. Certain Registrant Subsidiaries have been divesting certain generation assets and their sales values can vary from the recorded fair value as described in Note 8 of the Notes to Financial Statements of Registrant Subsidiaries. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

Nature of Estimates Required: APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC sponsor pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. These benefits are accounted for under SFAS 87, “Employers’ Accounting For Pensions”, SFAS 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” and SFAS 158. See Note 9 of the Notes to Financial Statements of Registrant Subsidiaries for more information regarding costs and assumptions for employee retirement and postretirement benefits. The measurement of pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.

Assumptions and Approach Used: The critical assumptions used in developing the required estimates include the following key factors:

·	Discount rate	
·	Expected return on plan assets	
·	Health care cost trend rate	
·	Rate of compensation increase	
·	Cash balance crediting rate	

Other assumptions, such as retirement, mortality, and turnover, are evaluated periodically and updated to reflect actual experience.
 
Effect if Different Assumptions Used: The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants. If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:
 	 	Pension Plans	 	Other Postretirement
Benefits Plans	 	
 	 	+0.5%	 	-0.5%	 	+0.5%	 	-0.5%	 	
 	 	(in millions)	 	
Effect on December 31, 2006 Benefit Obligations:	 	  	 	  	 	  	 	  	 	
Discount Rate	 	$	(178.2	)	$	192.7	 	$	(114.1	)	$	121.4	 	
Compensation Increase Rate	 	 	27.2	 	 	(25.5	)	 	3.3	 	 	(3.2	)	
Cash Balance Crediting Rate	 	 	13.4	 	 	16.7	 	 	N/A	 	 	N/A	 	
Health Care Cost Trend Rate	 	 	N/A	 	 	N/A	 	 	91.7	 	 	(83.7	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect on 2006 Periodic Cost:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount Rate	 	 	(13.0	)	 	13.6	 	 	(10.4	)	 	10.6	 	
Compensation Increase Rate	 	 	5.9	 	 	(5.6	)	 	0.6	 	 	(0.6	)	
Cash Balance Crediting Rate	 	 	6.7	 	 	(1.9	)	 	N/A	 	 	N/A	 	
Health Care Cost Trend Rate	 	 	N/A	 	 	N/A	 	 	15.2	 	 	(14.7	)	
Expected Return on Plan Assets	 	 	(19.7	)	 	19.7	 	 	(5.6	)	 	5.7	 	

N/A = Not Applicable	

New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption. SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. Management expects that the adoption of this standard will impact MTM valuations of certain contracts, but are unable to quantify the effect at this time. Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. The Registrant Subsidiaries will adopt SFAS 157 effective January 1, 2008.

In July 2006, the FASB issued FIN 48. It clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. FIN 48 is effective for fiscal years beginning after December 15, 2006. Management estimates the effect of this interpretation on each of the Registrant Subsidiaries’ financial statements will be an unfavorable adjustment to retained earnings of less than $1 million except for the following:
Company	 	  (in millions)	 	
APCo	 	$	7	 	
OPCo	 	 	3	 	
TCC	 	 	2	 	

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. In the event we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted. The statement is applied prospectively upon adoption. We will adopt SFAS 159 effective January 1, 2008.

EXHIBIT 23
 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-00973 and 333-133548 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 adoption of new accounting pronouncements in 2004 and 2006) and financial statement schedule of Public Service Company of Oklahoma appearing in and incorporated by reference in the Annual Report on Form 10-K of Public Service Company of Oklahoma for the year ended December 31, 2006.

 
/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 28, 2007

 
EXHIBIT 24

 
POWER OF ATTORNEY
 	
Annual Report on Form 10-K for the Fiscal Year Ended	
December 31, 2006	

The undersigned directors of the following companies (each respectively the "Company")
 
Company
 	 
State of Incorporation
 	
AEP Texas Central Company	Texas	
AEP Texas North Company	Texas	
Public Service Company of Oklahoma	Oklahoma	
Southwestern Electric Power Company	Delaware	

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 31st day of January, 2007.

/s/ Nicholas K. Akins  	/s/ Holly K. Koeppel  	
Nicholas K. Akins	Holly K. Koeppel	
 	 	
/s/ Carl L. English  	/s/ Michael G. Morris  	
Carl L. English	Michael G. Morris	
 	 	
/s/ Thomas M. Hagan  	/s/ Stephen P. Smith  	
Thomas M. Hagan	Stephen P. Smith	
 	 	
/s/ John B. Keane  	/s/ Susan Tomasky  	
John B. Keane	Susan Tomasky	
 	 	
 	/s/ Dennis E. Welch  	
 	Dennis E. Welch	

  
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:	

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;

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) ) 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.	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	

 	c.	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, 2007                                             By:   /s/ Michael G. Morris  
   Michael G. Morris
   Chief Executive Officer
  
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:	

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;

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) ) 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.	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	

 	c.	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, 2007                                       By:   /s/ Holly K. Koeppel  
    Holly K. Koeppel
    Chief Financial Officer
  
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.
  
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.