Aep Texas Central (ATXCH) 10-Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended September 30, 2005

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address of Principal Executive Offices, and Telephone Number	Identification No.
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)	72-0323455
All Registrants	1 Riverside Plaza, Columbus, Ohio 43215-2373
	Telephone (614) 716-1000

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  ___

Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes   X	No  ___

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 accelerated filers (as defined in Rule 12b-2 of the Exchange Act).
Yes  ___	No   X

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act.)
Yes  ___	No  X

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

	Number of Shares of Common Stock Outstanding at October 31, 2005
American Electric Power Company, Inc.	393,684,291
AEP Generating Company	1,000
AEP Texas Central Company	2,211,678
AEP Texas North Company	5,488,560
Appalachian Power Company	13,499,500
Columbus Southern Power Company	16,410,426
Indiana Michigan Power Company	1,400,000
Kentucky Power Company	1,009,000
Ohio Power Company	27,952,473
Public Service Company of Oklahoma	9,013,000
Southwestern Electric Power Company	7,536,640

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2005

Glossary of Terms
Forward-Looking Information
Part I. FINANCIAL INFORMATION
	Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative   Disclosures About Risk Management Activities:
	American Electric Power Company, Inc. and Subsidiary Companies:
		Management’s Financial Discussion and Analysis of Results of Operations
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements
		Condensed Notes to Condensed Consolidated Financial Statements
	AEP Generating Company:
		Management’s Narrative Financial Discussion and Analysis
		Condensed Financial Statements
	AEP Texas Central Company and Subsidiary:
		Management’s Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements
	AEP Texas North Company:
		Management’s Narrative Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Financial Statements
	Appalachian Power Company and Subsidiaries:
		Management’s Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements
	Columbus Southern Power Company and Subsidiaries:
		Management’s Narrative Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements
	Indiana Michigan Power Company and Subsidiaries:
		Management’s Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements
	Kentucky Power Company:
		Management’s Narrative Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Financial Statements
	Ohio Power Company Consolidated:
		Management’s Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements

	Public Service Company of Oklahoma:
		Management’s Narrative Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Financial Statements
	Southwestern Electric Power Company Consolidated:
		Management’s Financial Discussion and Analysis
		Quantitative and Qualitative Disclosures About Risk Management Activities
		Condensed Consolidated Financial Statements
	Condensed Notes to Financial Statements of Registrant Subsidiaries
	Combined Management’s Discussion and Analysis of Registrant Subsidiaries
	Item 4.		Controls and Procedures
Part II. OTHER INFORMATION
	Item 1.		Legal Proceedings
	Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds
	Item 5.		Other Information
	Item 6.		Exhibits:
				Exhibit 12
				Exhibit 31(a)
				Exhibit 31(b)
				Exhibit 31(c)
				Exhibit 31(d)
				Exhibit 32(a)
				Exhibit 32(b)
SIGNATURE

This combined Form 10-Q is separately filed by 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. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

GLOSSARY OF TERMS

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

  Term   Meaning

AEGCo	AEP Generating Company, an electric utility subsidiary of AEP.
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.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
ARO	Asset Retirement Obligations.
CAA	Clean Air Act.
COLI	Corporate owned, life insurance program.
Cook Plant	The 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.).
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.
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.”
GAAP	Generally Accepted Accounting Principles.
HPL	Houston Pipeline Company.
IGCC	Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPP	Independent Power Producers.
IURC	Indiana Utility Regulatory Commission.
JMG	JMG Funding LP.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KPSC	Kentucky Public Service Commission.
KWH	Kilowatthour.
LIG	Louisiana Intrastate Gas, a former AEP subsidiary.
ME SWEPCo	Mutual Energy SWEPCo L.P., a Texas retail electric provider.
MISO	Midwest Independent Transmission System Operator.
MLR	Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
MWH	Megawatthour.
NOx	Nitrogen oxide.
Nonutility Money Pool	AEP System’s Nonutility Money Pool.
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.
PJM	Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO	Public Utilities Commission of Ohio.
PUCT	The 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.
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 109	Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.
SFAS 133	Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging   Activities.
SIA	System Integration Agreement.
SNF	Spent Nuclear Fuel.
SO2	Sulfur Dioxide.
SPP	Southwest Power Pool.
STP	South Texas Project Nuclear Generating Plant.
Sweeny	Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation   facility, owned 50% by AEP.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC	AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor	Maturity of a contract.
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.
TVA	Tennessee Valley Authority.
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.
Zimmer Plant	William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by CSPCo.

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 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.

· New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon 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.).

· Our ability to constrain operation and maintenance costs.

· Our ability to sell assets at acceptable prices and other acceptable terms, including rights to share in earnings derived from the assets subsequent to their   sale.

· The economic climate and growth in our service territory and changes in market demand and demographic patterns.

· Inflationary 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 and number of participants in the energy trading market.

· Changes in the financial markets, particularly those affecting the availability of capital and our ability to refinance existing debt at attractive rates.

· 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 membership in regional transmission structures.

· 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.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Utility Operations Segment Results

Net income from our Utility Operations was $352 million for the third quarter of 2005, representing a decrease of $7 million when compared with net income from our Utility Operations for the third quarter of 2004. The decrease was primarily due to a $26 million after-tax impairment related to our commitment to a plan to retire two units at CSPCo’s Conesville Plant. Strong retail and wholesale sales due to warmer weather, customer growth and higher wholesale prices, net of increased fuel costs and higher operating expenses, partially offset the Conesville impairment.

Acquisition

In August 2005, we announced an agreement to purchase the Ceredo Generating Station for approximately $100 million. The Ceredo Generating Station is a natural-gas-fired plant with capacity of 505 megawatts located near Ceredo, West Virginia. This purchase is part of our broad strategy to meet the growing capacity needs of our customer base and reduce reliance on the marketplace. We expect this acquisition to close in the latter part of 2005 or first quarter of 2006.

Dividend Increase

On October 26, 2005, our Board of Directors approved a six percent increase in our quarterly dividend to $0.37 per share from $0.35 per share. We also announced criteria that will be used to make future dividend recommendations to the Board.

Regulatory Activity

West Virginia

In August 2005, APCo and WPCo jointly filed with the Public Service Commission of West Virginia for a $183 million revenue increase. The companies proposed the requested increase to be phased-in over four years. The primary reasons for the request include increasing costs for coal, purchased power and environmental improvement construction projects. A final order is expected in June 2006.

Kentucky

In September 2005, KPCo filed with the Kentucky Public Service Commission for a $65 million revenue increase. The primary reason for the request is to recover increasing costs associated with providing safe and reliable electric service to customers. A final order is expected in April 2006.

Texas

In September 2005, we filed rebuttal testimony in our stranded cost recovery proceeding addressing the issues raised by the various intervenors and PUCT staff. The issues raised were similar to those raised in other nonaffiliated utilities’ True-up Proceedings. Texas Restructuring Legislation provides for a PUCT decision within 150 days after filing. Hearings concluded in October 2005 and a final order is expected in the fourth quarter of 2005.

Fuel Costs

Market prices for coal, natural gas and oil increased dramatically during 2004 and have continued to increase in 2005. These increasing fuel costs are the result of increasing worldwide demand, supply interruptions and uncertainty, anticipation and ultimate promulgation of clean air rules and transportation constraints, as well as other market factors. We manage price and performance risk, particularly for coal, through a portfolio of contracts of varying durations and other fuel procurement and management activities. We have fuel recovery mechanisms for about 45% of our fuel costs in our various jurisdictions. Additionally, about 25% of our fuel is used for off-system sales where prices for our power should allow us to recover our cost of fuel. Accordingly, we should recover approximately 70% of fuel cost increases. The remaining 30% of our fuel costs relate primarily to Ohio and West Virginia customers, where we do not currently have fuel cost recovery mechanisms. Such percentages are subject to change over time based on fuel cost impacts, fuel caps and freezes and changes to the recovery mechanisms at jurisdictions in our individual operating companies. In August 2005, APCo filed in West Virginia to reinstate the suspended fuel cost recovery mechanism.  In addition, our Ohio companies will be increasing their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans.

During the third quarter of 2005 as compared to the same period in 2004, higher coal costs reduced gross margins by approximately $22 million and our year-to-date reduction in gross margins related to fuel costs is approximately $119 million. Several major events have impacted fuel costs in 2005. In January, deliveries of coal were restricted due to flooding and restricted shipping on the Ohio River at the Belleville Lock and Dam. Central Appalachian coal deliveries were also affected early in the year by rail transportation limitations resulting in performance issues among coal suppliers, the railroad, and AEP. Some of the suppliers in this region continue to experience performance related issues. The Union Pacific Railroad claimed, in mid-May, a force majeure event due to severe track damage impacting the delivery of Powder River Basin (PRB) coal, which has reduced, and will continue to reduce, PRB coal deliveries by roughly 15% through at least November 2005. Since PRB supplies tend to be lower priced than our average, our delivered coal costs are unfavorably impacted.

Environmental

In June 2005, we revised our environmental investment program that extends through 2010 to a projected investment level of $4.1 billion, from our previous estimate of $3.7 billion. The increase is attributable to continued refinement of our forecast and the ongoing development of estimates for our remaining scrubber program. There could be additional changes in our investment program estimates as we further evaluate and monitor the impact of the Clean Air Interstate Rule and Clean Air Mercury Rule.

In June 2005, we announced five additional locations where we will invest in equipment to continue to improve the environmental performance of our coal-fired power plants including sites in West Virginia, Ohio, Kentucky and Texas. We plan to complete these projects between 2007 and 2010 and are included in both our previous and revised projected investment level discussed above.

Nuclear Licenses

In August 2005, the Nuclear Regulatory Commission approved the renewal of operating licenses for the two generating units at our Cook Plant. The licenses will now expire in 2034 for Unit 1 and 2037 for Unit 2. Based on this renewal, we adjusted our asset retirement obligation liability and related plant asset. We are evaluating the effect of relicensing on current depreciation rates and decommissioning funding. If any changes are necessary, we will need IURC and MPSC approval.

Energy Policy Act of 2005

In August 2005, the President signed the Energy Policy Act of 2005 into law. The Energy Policy Act of 2005 repeals PUHCA, effective February 8, 2006. We believe adoption of the Energy Policy Act of 2005 will end the litigation challenging our merger with CSW. The Energy Policy Act of 2005 provides for tax credits for the development of certain clean coal and emissions technologies and provides federal tax relief in support of our commitment to build IGCC generating units.

Additional Information

For additional information on our strategic outlook, see “Management’s Financial Discussion and Analysis of Results of Operations,” including “Business Strategy,” in our 2004 Annual Report. Also see the remainder of our “Management’s Financial Discussion and Analysis of Results of Operations” in this Form 10-Q, along with the Condensed Notes to Condensed Consolidated Financial Statements.

RESULTS OF OPERATIONS

Segments

As outlined in our 2004 Annual Report, our business strategy and the core of our business are to focus on domestic electric utility operations. Our previous decision that we no longer sought business interests outside of the footprint of our domestic core utility assets led us to embark on a divestiture of such noncore assets. Major asset divestitures included the sale in 2004 of two generating plants in the UK, LIG and Jefferson Island Storage & Hub, and the sale in January 2005 of a 98% interest in the HPL assets. Consequently, our Investments segments generally are of significance only to previous periods.

Our on-going segments and their related business activities are as follows:

Utility Operations

· Domestic generation of electricity for sale to retail and wholesale customers.

· Domestic electricity transmission and distribution.

Investments - Other

·	Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.
	Four IPPs were sold during 2004.

AEP Consolidated Results

Our consolidated Net Income for the three and nine months periods ended September 30, 2005 and 2004 was as follows (Earnings and Weighted Average Shares Outstanding in millions):

	Three Months Ended September 30,												Nine Months Ended September 30,
	2005						2004						2005						2004
	Earnings			EPS			Earnings			EPS			Earnings			EPS			Earnings			EPS
Utility Operations	$	352		$	0.91		$	359		$	0.91		$	952		$	2.45		$	847		$	2.14
Investments - Other		28			0.07			89			0.22			32			0.08			89			0.22
All Other(a)		(5	)		(0.01	)		(9	)		(0.02	)		(45	)		(0.12	)		(43	)		(0.11	)
Investments - Gas Operations (b)		(10	)		(0.03	)		(27	)		(0.07	)		(2	)		-			(41	)		(0.10	)
Income Before Discontinued Operations		365			0.94			412			1.04			937			2.41			852			2.15
Investments - Gas Operations		-			-			(3	)		-			-			-			(2	)		-
Investments - UK Operations		2			-			120			0.30			(3	)		(0.01	)		56			0.14
Investments - Other		20			0.05			1			-			29			0.08			6			0.01
Discontinued Operations, Net of Tax		22			0.05			118			0.30			26			0.07			60			0.15
Net Income	$	387		$	0.99		$	530		$	1.34		$	963		$	2.48		$	912		$	2.30
Weighted Average Basic Shares Outstanding					389						396						389						396

(a) All Other includes the parent company’s interest income and expense, as well as other nonallocated costs. 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.

(b) We sold 98% of our remaining gas operations in January 2005.

Third Quarter of 2005 Compared to Third Quarter of 2004

Income Before Discontinued Operations decreased $47 million to $365 million in the third quarter of 2005 compared to the third quarter of 2004.

For the third quarter of 2005, our Utility Operations earnings decreased $7 million from the third quarter of the previous year primarily due to higher fuel and operating costs and an impairment related to our commitment to a plan to retire two units at our Conesville Plant, partially offset by load and customer growth in all sectors, an increase in off-system sales volumes and margins and Ohio and Texas carrying cost accruals.

Losses before discontinued operations from our Gas Operations for the third quarter of 2005 decreased $17 million from the third quarter of 2004 due to the January 2005 sale of a 98% controlling interest in HPL resulting in decreased operations, maintenance and interest expenses.

Income before discontinued operations from our Investments - Other decreased $61 million from the third quarter of 2004 primarily due to the prior year gain on the sales of our South Coast Power Limited equity investment and three IPPs.

Average basic shares outstanding decreased to 389 million in 2005 from 396 million in 2004 primarily due to the common stock share repurchase program, which began in March 2005 and ended in May 2005.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Income Before Discontinued Operations increased $85 million to $937 million for the nine months ended September 30, 2005.

For the nine months ended September 30, 2005, our Utility Operations earnings increased $105 million from the same nine month period of the previous year driven primarily by favorable weather and load growth, the Centrica earnings sharing payments received in March 2005 and Ohio and Texas carrying cost accruals. These favorable changes are partially offset by higher fuel costs.

The income before discontinued operations from our Investments - Other decreased $57 million in 2005. This decrease is primarily due to the prior year gain on the sales of our South Coast Power Limited equity investment and three IPPs.

Losses before discontinued operations from our Gas Operations decreased $39 million from the same nine month period of the previous year reflecting favorable results for one month of HPL’s operations in 2005 compared with a loss for the nine months of HPL’s operations in the prior year. We sold a 98% controlling interest in HPL in January 2005, resulting in decreased operations, maintenance and depreciation expenses as well as decreased interest charges.

Average basic shares outstanding decreased to 389 million in 2005 from 396 million in 2004 primarily due to the common stock share repurchase program, which began in March 2005 and ended in May 2005.

Our results of operations by operating segment are discussed below.

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 our Utility Operations segment results on a gross margin basis is most appropriate. Gross margins represent utility operating revenues less the related direct costs of fuel and purchased power.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(in millions)
Revenues	$	3,214	$	2,950	$	8,496	$	8,097
Fuel and Purchased Power		1,197		1,032		3,058		2,631
Gross Margin		2,017		1,918		5,438		5,466
Depreciation and Amortization		328		322		963		940
Other Operating Expenses		1,052		922		2,866		2,804
Operating Income		637		674		1,609		1,722
Other Income (Expense), Net		49		9		253		35
Interest Expense and Preferred Stock Dividend Requirements		145		152		445		479
Income Taxes		189		172		465		431
Income Before Discontinued Operations	$	352	$	359	$	952	$	847

Summary of Selected Sales Data

For Utility Operations

For the Three and Nine Months Ended September 30, 2005 and 2004

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Energy Summary	(in millions of KWH)
Retail:
Residential		14,152		12,002		37,332		35,169
Commercial		10,900		10,070		29,205		28,240
Industrial		13,380		13,052		39,633		38,227
Miscellaneous		683		857		1,967		2,406
Total Retail		39,115		35,981		108,137		104,042
Texas Retail and Other		114		280		504		802
Total		39,229		36,261		108,641		104,844
Wholesale		14,198		17,629		38,971		45,124
Texas Wires Delivery		8,093		7,691		20,348		19,431

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact weather has on results of operations. Cooling degree days and heating degree days in our service territory for the quarter and year-to-date periods ended September 30, 2005 and 2004 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Weather Summary	(in degree days)
Eastern Region
Actual - Heating		1		1		1,940		2,033
Normal - Heating(a)		7		7		1,995		1,993
Actual - Cooling		835		553		1,122		869
Normal - Cooling(a)		674		679		955		960
Western Region (b)
Actual - Heating		0		0		795		913
Normal - Heating(a)		2		2		1,007		1,013
Actual - Cooling		1,523		1,178		2,225		1,867
Normal - Cooling(a)		1,397		1,398		2,059		2,058

(a) Normal Heating/Cooling represents the 30-year average of degree days.

(b) Western Region statistics represent PSO/SWEPCo customer base only.

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005

Income Before Discontinued Operations

(in millions)

Third Quarter of 2004			$	359
Changes in Gross Margin:
Retail Margins	120
Texas Supply	(61	)
Transmission Revenues	(20	)
Off-system Sales	69
Other Revenues	(9	)
Total Change in Gross Margin				99
Changes in Operating Expenses and Other:
Maintenance and Other Operation	(67	)
Asset Impairments and Other Related Charges	(39	)
Depreciation and Amortization	(6	)
Taxes Other Than Income Taxes	(24	)
Other Income (Expense), Net	40
Interest Expense	7
Total Change in Operating Expenses and Other				(89	)
Income Taxes				(17	)
Third Quarter of 2005			$	352

Income from Utility Operations decreased $7 million in 2005 compared to 2004.

The major components of our change in gross margin were as follows:

· Retail Margins in our utility business were $120 million higher than last year. The primary driver of this increase was a 12% increase in volume attributable to load growth in residential and commercial classes as well as favorable weather in 2005. This retail margin increase was partially offset by higher delivered fuel costs of approximately $22 million, which primarily relates to our utilities in the East with inactive fuel clauses.

· Our Texas Supply business had a $61 million decrease in gross margin as a result of the sale of a majority of our nonnuclear Texas generation assets in the third quarter of 2004 and STP in May 2005.

· Transmission Revenues decreased $20 million primarily due to the loss of through and out rates as mandated by the FERC partially offset by the addition of SECA rates.

· Margins from Off-system Sales for 2005 were $69 million higher than 2004 primarily due to an increase in volume, favorable price margins and favorable optimization activity.

Utility Operating Expenses and Other changed between years as follows:

· Maintenance and Other Operation expenses increased $67 million. Approximately $22 million of the increase is due to timing of maintenance projects experienced in the third quarter of 2005 as compared to the same period in 2004. Additionally, in 2005 we incurred $13 million of maintenance costs related to major storms. Also, $32 million of the increase relates to increased generation expense, including environmental consumables and allowances, due to strong retail and wholesale sales and capacity requirements in 2005.

· Asset Impairments and Other Related Charges were $39 million in 2005 due to our commitment to a plan in September to retire two units at our Conesville Plant. In September, we formally requested permission from PJM to retire the two units effective December 29, 2005. We received preliminary approval on October 21, 2005.

· Taxes Other Than Income Taxes increased $24 million primarily due to a $15 million increase in property taxes related to increased property values.

· $15 million related to the recognition of carrying costs by TCC on its net stranded generation costs and its capacity auction true-up asset.

· $10 million 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.

· $17 million related to increased interest income and increased AFUDC due to extensive construction activities occurring in 2005.

See “Income Taxes” section below for discussion of fluctuations related to income taxes.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to Nine Months Ended September 30, 2005

Income Before Discontinued Operations

(in millions)

Nine Months Ended September 30, 2004			$	847
Changes in Gross Margin:
Retail Margins	59
Texas Supply	(117	)
Transmission Revenues	(71	)
Off-system Sales	103
Other Revenues	(2	)
Total Change in Gross Margin				(28	)
Changes in Operating Expenses and Other:
Asset Impairments and Other Related Charges	(39	)
Depreciation and Amortization	(23	)
Taxes Other Than Income Taxes	(23	)
Other Income (Expense), Net	218
Interest Expense	34
Total Change in Operating Expenses and Other				167
Income Taxes				(34	)
Nine Months Ended September 30, 2005			$	952

Income from Utility Operations increased $105 million to $952 million in 2005. The key driver of the increase was a $218 million increase in Other Income (Expense), Net, partially offset by a $28 million decrease in gross margin, a $39 million increase in asset impairments and a $34 million increase in income taxes.

The major components of our change in gross margin were as follows:

· Overall Retail Margins in our utility business were $59 million higher than last year. The primary driver of this increase was continued customer growth and usage in our residential and commercial classes. This load growth was partially offset by higher delivered fuel costs of approximately $119 million, of which the majority relates to our East companies with inactive fuel clauses.

· Our Texas Supply business had a $117 million decrease in gross margin due to the sale of a majority of our nonnuclear Texas generation assets in the third quarter of 2004 and STP in May 2005.

· Transmission Revenues decreased $71 million primarily due to the loss of through and out rates as mandated by the FERC partially offset by the addition of SECA rates.

· Margins from Off-system Sales for 2005 were $103 million higher than 2004 primarily due to increased volume and favorable price margins.

Utility Operating Expenses and Other changed between years as follows:

· Asset Impairments and Other Related Charges increased $39 million due to our commitment to a plan in September to retire two units at our Conesville Plant.  In September, we formally requested permission from PJM to retire the two units effective December 29, 2005.  We received preliminary approval on October 21, 2005.

· Other Income (Expense), Net increased $218 million primarily due to the following:

· $112 million resulting from the receipt of 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. Agreement was reached with Centrica in March 2005 resolving disputes on how such amounts are to be calculated.

· $41 million 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.

· $32 million related to increased interest income and increased AFUDC due to extensive construction activities occurring in 2005.

· $30 million related to the recognition of carrying costs by TCC on its net stranded generation costs and its capacity auction true-up asset.

· Interest Expense decreased $34 million due to the refinancing of higher coupon debt and the retirement of debt in 2004 and in the first nine months of 2005.

See “Income Taxes” section below for discussion of fluctuations related to income taxes.

Investments - Other

Third Quarter of 2005 Compared to Third Quarter of 2004

Income before discontinued operations from our Investments - Other segment decreased by $61 million in 2005 primarily due tothe gain recorded in 2004 related to the third quarter sale of three of our IPP investments and our 50 percent interest in South Coast Power Limited.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Income before discontinued operations from our Investments - Other segment decreased by $57 million in 2005 primarily due tothe gain recorded in 2004 related to the third quarter sale of three of our IPP investments and our 50 percent interest in South Coast Power Limited.

Other

Parent

Third Quarter of 2005 Compared to Third Quarter of 2004

Our parent company’s loss for the third quarter of 2005 decreased $4 million in comparison to the third quarter of 2004 due to lower interest expense in 2005 primarily related to the $550 million senior unsecured notes redemption in April 2005.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Our parent company’s loss for the nine months ended September 30, 2005 increased $2 million in comparison to the nine months ended September 30, 2004 due to lower interest income related to the repayment of intercompany debt associated with the sale of HPL, partially offset by lower interest expense due to lower short-term debt borrowings in 2005 and savings from the redemption of $550 million senior unsecured notes in April 2005.

Investments - Gas Operations and UK Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Our $10 million net loss from Gas Operations before discontinued operations compares with a $27 million loss recorded in the third quarter of 2004. The improvement is due to the sale of a 98% controlling interest in HPL in January 2005, offset in part by the settlement of the Bank of Montreal litigation matter (see “Significant Matters”“Litigation” section of Management’s Financial Discussion and Analysis of Results of Operations).

Income included in discontinued operations from our Investments - UK Operations segment was $2 million in 2005 as compared to income of $120 million in 2004 due to the gain on the sale of substantially all operations and assets within our Investments - UK Operations segment recognized in July 2004.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Our $2 million net loss from Gas Operations before discontinued operations compares with a $41 million loss recorded in the nine months ended September 30, 2004. Due to the sale of a 98% controlling interest in HPL in January 2005, current year results include only one month of HPL’s operations compared to nine months of HPL’s operations in the prior year.

Losses included in discontinued operations from our Investments - UK Operations segment were $3 million in 2005 as compared to income of $56 million in 2004 due to the gain related to the sale of substantially all operations and assets within our Investments - UK Operations segment in July 2004. The current period amount represents purchase price true-up adjustments made during the first quarter of 2005 related to the 2004 sale.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 34.9% and 33.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, energy production credits, amortization of investment tax credits and state income taxes.

The effective tax rates for the nine months ended September 30, 2005 and 2004 were 33.3% and 34.1%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, energy production credits, amortization of investment tax credits and state income taxes.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

Capitalization ($ in millions)

	September 30, 2005				December 31, 2004
Common Shareholders’ Equity	$	8,985	43.2	%	$	8,515	40.6	%
Cumulative Preferred Stock		61	0.3			61	0.3
Cumulative Preferred Stock (Subject to Mandatory Redemption)		-	-			66	0.3
Long-term Debt, including amounts due within one year		11,742	56.4			12,287	58.7
Short-term Debt		15	0.1			23	0.1
Total Capitalization	$	20,803	100.0	%	$	20,952	100.0	%

In March 2005, we repurchased 12.5 million shares of our outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share. The 12.5 million shares repurchased under the program were subject to a contingent purchase price adjustment based on the actual purchase prices paid for the common stock during the program period. Based on this adjustment, our actual stock purchase price averaged $34.18 per share.

In April 2005, we redeemed $550 million of parent company senior unsecured notes.

In August 2005, we issued 8.4 million shares of common stock as part of the settlement of forward purchase contracts embedded in equity units issued in June 2002. The senior notes associated with the equity units were remarketed in June 2005 with the proceeds held by a trustee for settlement of the forward purchase contracts on behalf of the original equity unit holders. With the issuance of the shares of common stock, we received $345 million from the trustee on behalf of the holders.

As a consequence of the capital changes during the first nine months of 2005, our ratio of debt to total capital decreased from 59.1% to 56.5% (preferred stock subject to mandatory redemption is included in the debt component of the ratio).

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability. We are committed to preserving an adequate liquidity position through the effective management of external financing commitments, appropriate balances of cash and other temporary investments on hand, our operational cash management and our investing activities.

Credit Facilities

We manage our liquidity, in part, by maintaining adequate external financing commitments. We had an available liquidity position, at September 30, 2005, of approximately $3.4 billion as illustrated in the table below.

	Amount			Maturity
	(in millions)
Commercial Paper Backup:
Revolving Credit Facility	$	1,000			May 2007
Revolving Credit Facility		1,500			March 2010
Letter of Credit Facility		200			September 2006
Total		2,700
Cash and Cash Equivalents		849
Total Liquidity Sources		3,549
Less: AEP Commercial Paper Outstanding		-	(a)
Letters of Credit Outstanding		150
Net Available Liquidity at September 30, 2005	$	3,399

(a) Amount does not include JMG commercial paper outstanding in the amount of $15 million. This commercial paper is specifically associated with the Gavin scrubber and does not reduce AEP’s available liquidity. The JMG commercial paper is supported by a separate letter of credit facility not included above.

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 September 30, 2005, this percentage was 53.5%. Nonperformance of these covenants could result in an event of default under these credit agreements. At September 30, 2005, 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 amounts outstanding thereunder payable.

Our $1 billion revolving credit facility, which matures in May 2007, generally prohibits new borrowings if we experience a material adverse change in our business or operations. We may, however, make new borrowings under this facility if we experience a material adverse change so long as the proceeds of such borrowings are used to repay outstanding commercial paper. Under the $1.5 billion revolving credit facility, which matures in March 2010, we may borrow despite a material adverse change.

Under an SEC order, we and our utility subsidiaries cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% (25% for TCC) of its capital. In addition, this order restricts us and our 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 September 30, 2005, we were in compliance with this order. The Energy Policy Act of 2005 repeals PUHCA effective February 8, 2006. With repeal, compliance with this order will no longer be necessary. However, new regulatory requirements of the FERC could replace or modify this order.

Nonutility Money Pool borrowings, Utility Money Pool borrowings and external borrowings may not exceed SEC or state commission authorized limits. At September 30, 2005, we had not exceeded the SEC or state commission authorized limits.

Credit Ratings

Moody’s upgraded our short-term and long-term ratings during September 2005. We are currently on a stable outlook by Moody’s.

Our current ratings by the major agencies are as follows:

	Moody’s	S&P	Fitch
Short-term Debt	P-2	A-2	F-2
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

Our cash flows are a major factor in managing and maintaining our liquidity strength.

	Nine Months Ended September 30,
	2005			2004
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	320		$	778
Cash Flows From (Used For):
Operating Activities		1,587			2,278
Investing Activities		12			(33	)
Financing Activities		(1,070	)		(2,089	)
Net Increase in Cash and Cash Equivalents		529			156
Cash and Cash Equivalents at End of Period	$	849		$	934
Other Temporary Cash Investments	$	73		$	529

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provide necessary working capital and help us 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 our other subsidiaries that are not participants in the Nonutility Money Pool. As of September 30, 2005, we had credit facilities totaling $2.5 billion to support our commercial paper program. At September 30, 2005, we had no outstanding short-term borrowings supported by the revolving credit facilities. JMG had commercial paper outstanding in the amount of $15 million. This commercial paper is specifically associated with the Gavin scrubber and is not supported by our credit facilities. The maximum amount of commercial paper outstanding during the nine months ended September 30, 2005 was $25 million. The weighted-average interest rate for our commercial paper during the first nine months of 2005 was 2.5%.

We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding alternatives are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements.

In addition to our Cash and Cash Equivalents, we have Other Temporary Cash Investments on hand that we use to manage and maintain our liquidity.

Operating Activities

	Nine Months Ended September 30,
	2005			2004
	(in millions)
Net Income	$	963		$	912
Plus: (Income) From Discontinued Operations		(26	)		(60	)
Income from Continuing Operations		937			852
Noncash Items Included in Earnings		1,039			1,267
Changes in Assets and Liabilities		(389	)		159
Net Cash Flows From Operating Activities	$	1,587		$	2,278

The key drivers of the decrease in cash from operations for the first nine months of 2005 are the Pension Contributions of $306 million and an increase in our under-recovered fuel of $183 million.

2005 Operating Cash Flow

Net Cash Flows From Operating Activities were approximately $1.6 billion for the first nine months of 2005. We produced Income from Continuing Operations of $937 million during the period. Income from Continuing Operations for the period included noncash expense items primarily for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. We made contributions of $306 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 these asset and liability accounts relates to a number of items; the most significant are a $204 million cash increase from Accounts Payable and an increase in the balance of Taxes Accrued of $118 million. Cash increased related to Accounts Payable due to higher fuel and allowance acquisition costs not paid at September 30, 2005. Taxes Accrued increased due to the difference between the recording of the current federal income tax liability, the timing of required estimated payments and the receipt of a prior year federal income tax refund. Our consolidated tax group paid a total of $217 million in federal income taxes, net of refunds, during the first nine months of 2005.

2004 Operating Cash Flow

Net Cash Flows From Operating Activities were approximately $2.3 billion for the first nine months of 2004. We produced Income from Continuing Operations of $852 million during the period. Income from Continuing Operations for the period included noncash items of $1.1 billion for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. There was a current period favorable impact for a net $89 million balance sheet change for risk management contracts that were marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The most significant change in other activity in the asset and liability accounts was an increase in Taxes Accrued of $388 million. 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

	Nine Months Ended September 30,
	2005			2004
	(in millions)
Construction Expenditures	$	(1,610	)	$	(1,047	)
Acquisition of Waterford Plant		(218	)		-
Change in Other Temporary Cash Investments, Net		99			28
Investment in Discontinued Operations, Net		-			(59	)
Purchases of Investments		(3,342	)		(425	)
Proceeds from the Sale of Investments		3,445			274
Proceeds from Sale of Assets		1,599			1,202
Other		39			(6	)
Net Cash Flows From (Used For) Investing Activities	$	12		$	(33	)

Net Cash Flows From Investing Activities were $12 million in 2005 primarily due to proceeds from the sale of HPL and STP in 2005 significantly offset by our Construction Expenditures. Our Construction Expenditures include planned environmental, transmission and distribution investments. Our remaining Construction Expenditures for 2005 are estimated to be approximately $900 million.

We purchase auction rate securities and variable rate demand notes with cash available for short-term investment. During the first nine months of 2005, we purchased $3.3 billion of investments and received $3.4 billion of proceeds from their sale, which included the sale of our investments held at December 31, 2004, as reflected above in the Change in Other Temporary Cash Investments, Net line.

Net Cash Flows Used For Investing Activities were $33 million in 2004 primarily due to Construction Expenditures being offset by proceeds from the sales of the Pushan Power Plant in China and LIG Pipeline Company. The sales were part of our announced plan to divest noncore investments and assets.

We forecast $3.3 billion of construction expenditures for 2006. 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.

Financing Activities

	Nine Months Ended September 30,
	2005			2004
	(in millions)
Issuance of Common Stock	$	393		$	13
Repurchase of Common Stock		(427	)		-
Issuance/Retirement of Debt, net		(562	)		(1,683	)
Retirement of Preferred Stock		(66	)		(4	)
Dividends Paid on Common Stock		(408	)		(415	)
Net Cash Flows Used For Financing Activities	$	(1,070	)	$	(2,089	)

Net Cash Flows Used For Financing Activities in 2005 were approximately $1.1 billion. During the first nine months of 2005, we repurchased common stock and reduced outstanding long-term debt using the proceeds from the sale of HPL and from the conversion of the equity units to common stock. Our subsidiaries retired $66 million of cumulative preferred stock.

Net Cash Flows Used For Financing Activities were approximately $2.1 billion in 2004. During 2004, we retired debt using proceeds from the sale of assets and cash from operating activities.

In October 2005, CSPCo issued $250 million of 5.85% Senior Notes, Series F, due in October 2035.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current policy restricts 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. Our off-balance sheet arrangements have not changed significantly from year-end. For complete information on each of these off-balance sheet arrangements see the “Minority Interest and Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2004 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements discussed in “Cash Flow”“Financing Activities” above.

SIGNIFICANT MATTERS

Texas Regulatory Activity

Texas Restructuring

The principal remaining component of the stranded cost recovery process in Texas is the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items including carrying costs in TCC’s true-up filing under the Texas Restructuring Legislation. The PUCT approved TCC’s request to file its True-up Proceeding after the sales of its interest in STP, with only the ownership interest in Oklaunion remaining to be settled. On May 19, 2005, the sales of TCC’s interest in STP closed. On May 27, 2005, TCC filed its true-up request seeking recovery of $2.4 billion of net stranded costs and other true-up items which it believes the Texas Restructuring Legislation allows. TCC’s request includes unrecorded equity carrying costs through May 27, 2005 and amounts for stranded costs that we have previously written off (principally, a $238 million provision for a probable depreciation adjustment recorded in December 2004 based on a methodology approved by the PUCT in a nonaffiliated utility’s true-up order). The PUCT hearing concluded on October 4, 2005. It is anticipated that the PUCT will issue a final order in the fourth quarter of 2005.

TCC continues to accrue carrying costs on its net true-up regulatory asset at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on an assumed cost-of-money benefit for accumulated deferred federal income taxes retroactively applied to January 1, 2004. In the first nine months of 2005, TCC began to accrue carrying costs based on this order. Through September 30, 2005, TCC has computed carrying costs of $509 million, of which TCC has recognized $332 million to-date. The equity component of the carrying costs, which totals $177 million through September 30, 2005, will be recognized in income as collected.

In TCC’s True-up Proceeding, parties have recommended that the PUCT reduce TCC’s carrying cost rate to an amount that ranged from 7.5% to the combined rate that was settled upon in TCC’s wires rate proceeding which included a cost of debt of 5.7%. If the PUCT ultimately determines that a lower rate should be used by TCC to calculate carrying costs on its stranded cost balance, a portion of carrying costs previously recorded would have to be reversed and it would have an adverse impact on future results of operations and cash flows. Based upon a range of debt rates from 7.5% to 5.7%, through September 30, 2005, such reversal would range from $28 million to $107 million, of which $6 million to $22 million would apply to amounts accrued in 2005.

When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in its regulated transmission and distribution (T&D) rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

We believe that our filed request for recovery of $2.4 billion of net stranded costs and other true-up items, inclusive of carrying costs, is recoverable under the Texas Restructuring Legislation and that our $1.6 billion recorded net true-up regulatory asset, inclusive of carrying costs at September 30, 2005, is probable of recovery at this time. However, other parties have contended that all or material amounts of our net stranded costs and/or wholesale capacity auction true-up amounts should not be recovered. To the extent decisions of the PUCT in TCC’s True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated utilities, additional provisions for material disallowances and reductions of the net true-up regulatory asset, including recorded carrying costs, are possible. Such disallowances would have a material adverse effect on future results of operations, cash flows and possibly financial condition.

Ohio Regulatory Activity

Ohio Restructuring

On January 26, 2005, the PUCO approved Rate Stabilization Plans (RSP) for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for possible additional annual generation rate increases of up to an average of 4% per year based on the Ohio Companies supporting the need for additional revenues for specified costs. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. Pretax earnings increased by $6 million for CSPCo and $35 million for OPCo in the first nine months of 2005 as a result of implementing this provision of the RSP.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding its approval of the RSP. On March 23, 2005, the PUCO denied all applications for rehearing. In the second quarter of 2005, two intervenors filed separate appeals to the Ohio Supreme Court. One of those appeals has been withdrawn. If the RSP order is determined on appeal to be illegal under the restructuring legislation, it would have an adverse effect on results of operations, cash flows and possibly financial condition. Although we believe that the RSP plan is legal and we intend to defend vigorously the PUCO’s order, we cannot predict the ultimate outcome of the pending litigation.

Integrated Gasification Combined Cycle (IGCC) Power Plant

On March 18, 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new approximately 600 MW IGCC power plant using clean-coal technology. The application proposes 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 from 2007 through mid-2010 when the plant is projected to be placed in commercial operation. 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 RSP. 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. As of September 30, 2005, we have deferred $6 million of pre-construction IGCC costs. These costs primarily relate to an agreement with GE Energy and Bechtel Corporation to begin the front-end engineering design process.

Monongahela Power Company

In June 2005, the PUCO ordered CSPCo to explore the purchase of the Ohio service territory of Monongahela Power, which includes approximately 29,000 customers. On August 2, 2005, we agreed to terms of a transaction, which includes the transfer to CSPCo of Monongahela Power’s Ohio customer base and the assets that serve those customers for an estimated sales price of approximately $45 million. The net assets are being acquired at net book value. The sale price will be adjusted based on book values of the acquired assets and certain related liabilities at the closing date. In addition, CSPCo will pay $10 million to compensate Monongahela Power for its termination of certain generation cost recovery litigation in Ohio. CSPCo is proposing that the $10 million payment will be recorded as a regulatory asset and recovered with a carrying cost from large commercial and industrial customers in the Monongahela Power Ohio service territory over approximately 5 years.

Also included in the proposed transaction is 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. CSPCo is proposing that beginning June 1, 2007, it will acquire power on the market to meet the needs of the acquired customers through December 31, 2008 (the end of the RSP period). CSPCo has proposed a generation surcharge to be applied to all of its customers to recover the difference between the cost of power included in its generation rates and the higher Allegheny and subsequent market-based purchased power cost to meet the power requirements of the customers acquired from Monongahela Power through the end of the RSP period. CSPCo is proposing to institute a true-up mechanism with over/under-recovery deferral accounting for any difference between the surcharge recoveries and the actual cost differential. CSPCo has also requested permission to defer with a carrying cost incremental costs associated with the transaction for future recovery in the next CSPCo distribution rate case. Hearings at the PUCO were held in September 2005. If the transaction is approved by the PUCO, we expect to close the proposed transaction in December 2005.

Oklahoma Regulatory Activity

PSO Rate Review

PSO has been involved in a commission staff-initiated base rate review before the OCC which began in 2003. In March 2005, a settlement was negotiated and approved by the ALJ. The settlement provides for a $7 million annual base revenue reduction, offset by a $6 million reduction in annual depreciation expense and recovery through fuel revenues of certain transmission expenses previously recovered in base rates. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. The settlement also provides for recovery over 24 months of $9 million of deferred fuel costs associated with a renegotiated coal transportation contract and the continuation of a $12 million vegetation management rider, both of which are earnings neutral. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC issued an order approving the stipulation on May 2, 2005, and new base rates were implemented in June 2005. We anticipate that this order will favorably impact results of operations and cash flows beginning in 2006.

PSO Fuel and Purchased Power and its Potential Impact on the AEP East Companies

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 offered to the OCC to collect those reallocated costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. Subsequently, the OCC expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices and off-system sales margin sharing between AEP East and AEP West companies for the year 2002. On July 25, 2005, the OCC Staff and two intervenors filed testimony in which they quantified an alleged improper allocation of off-system sales margins between AEP East and AEP West companies. Their overall recommendations would result in an increase in off-system sales margins and thus, a reduction in PSO’s recoverable fuel costs through June 2005 of an amount between $38 million and $47 million. PSO does not agree with the intervenors’ and the OCC Staff’s recommendations and will defend vigorously its position. In addition, PSO believes the amounts of such alleged improper allocations are significantly overstated.

As noted in the 2004 Annual Report, 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. On September 29, 2005, the United States District Court, Western District of Texas, issued an order in the TNC fuel proceeding, preempting the PUCT from deciding this same allocation issue in Texas. Based on the position taken by the Federal court in Texas, it would appear that OCC would be preempted from disallowing PSO’s fuel costs in Oklahoma based on an alleged improper off-system sales margin allocation under a FERC jurisdictional allocation agreement. If the OCC or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between the AEP East and AEP West companies.

On June 10, 2005, the OCC decided to have its staff conduct a prudence review of PSO’s fuel and purchased power practices for 2003.

Management is unable to predict the ultimate effect of these proceedings on revenues, results of operations, cash flows and financial condition.

Virginia and West Virginia Regulatory Activity

APCo Virginia Environmental and Reliability Costs

In April 2004, the Virginia Electric Restructuring Act was amended to include a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and T&D system reliability (E&R) costs prudently incurred after July 1, 2004. On July 1, 2005, APCo filed a request with the Virginia SCC seeking approval for the recovery of $62 million in incremental E&R costs through June 30, 2006. The $62 million request represents i) expected costs of environmental controls on coal-fired generators to meet the first phase of the Clean Air Interstate Rule and Clean Air Mercury Rule finalized earlier this year, ii) recovery of the incremental cost of the Jacksons Ferry-Wyoming 765 kilovolt transmission line construction and iii) other incremental T&D system reliability costs from July 1, 2004 to June 30, 2006.

In the filing, APCo requested that a twelve-month E&R recovery factor be applied to electric service bills on an interim basis beginning August 1, 2005. The recovery factor would have been applied as a 9.18% surcharge to customer bills. APCo had proposed to practice over/under-recovery deferral accounting for the difference between the actual incremental costs incurred and revenue recovered.

Through September 30, 2005, APCo has incurred approximately $13 million of actual incremental E&R costs and has deferred $7 million of such costs for future recovery. APCo did not record $2 million of equity carrying costs that are not recognized until collected.  Additionally, E&R costs of $4 million represented previously capitalized interest that was duplicative of the carrying costs.

On October 14, 2005, the Virginia SCC denied APCo’s request to place in effect, on an interim basis subject to refund, its proposed cost recovery surcharge. Under this order, an E&R surcharge will not become effective until the Virginia SCC issues an order following the February 7, 2006 public hearing in this case. The Virginia SCC also ruled in this order that it does not have the authority under applicable Virginia law to approve the recovery of projected E&R costs before their actual incurrence and adjudication, which effectively eliminated projected costs requested in this filing. However, according to this order, APCo may update its request to reflect additional incurred costs and/or present additional evidence. If the Virginia SCC denies recovery of any portion of the net incremental actual amounts deferred to date, it would adversely affect future results of operations and cash flows.

APCo and WPCo West Virginia Rate Case

On August 26, 2005, APCo and WPCo collectively filed an application with the Public Service Commission of West Virginia seeking an initial increase in their retail rates of approximately $82 million. The initial increase included approval to reactivate and modify the suspended Expanded Net Energy Cost (ENEC) Recovery Mechanism which accounted for $72 million of the initial increase and approval to implement a system reliability tracker which accounted for $10 million. ENEC includes fuel and purchased power costs, as well as other energy-related items including off-system sales margins and transmission items. In addition, APCo and WPCo requested a series of supplemental annual increases related to the recovery of the cost of significant environmental and transmission expenditures. The first proposed supplemental increase of $9 million would go in effect on the same date as the initial rate increase, and the remaining proposed supplemental increases of $44 million, $10 million and $38 million would go in effect on January 1, 2007, 2008 and 2009, respectively. It is expected that the proposed rates will become effective on June 23, 2006 under West Virginia law. APCo has a regulatory liability of $52 million of pre-suspension, previously over-recovered ENEC costs which it is proposing to apply plus a carrying cost in the future to any under-recoveries of ENEC costs through the reactivated ENEC Recovery Mechanism. Management is unable to predict the ultimate effect of this filing on future revenues, results of operations, cash flows and financial condition.

Kentucky Regulatory Activity

KPCo Rate Filing

On September 26, 2005, KPCo filed a request with the Kentucky Public Service Commission to increase base rates by approximately $65 million to recover increasing costs. A final order is expected in April 2006. We are unable to predict the ultimate effect of this filing on future revenues, results of operations, cash flows and financial condition.

FERC Order on Regional Through and Out Rates

A load-based transitional transmission rate mechanism, SECA, became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. SECA transition rates are in effect through March 31, 2006. The FERC has set the SECA rate issue for hearing and indicated that the SECA rates are being recovered subject to refund. We recognized net SECA revenues of $36 million and $93 million in the third quarter and first nine months of 2005, respectively. In addition, we recognized $11 million of net SECA revenues in December 2004. Intervenors in that proceeding are objecting to the SECA rates and our method of determining those rates. Management is unable to determine the probable outcome of the FERC’s SECA rate proceeding.

In a March 31, 2005 FERC filing, we proposed an increase in the revenue requirements and rates for transmission service, and certain ancillary services in the AEP zone of PJM. The customers receiving these services are the AEP East companies, municipal and cooperative wholesale entities and retail customers that exercise retail choice that have load delivery points in the AEP zone of PJM. As proposed, the transmission service rates will increase in two steps, first to reflect an increase in the revenue requirements, and then to reflect the loss of revenues from the discontinuance of SECA transition rates on April 1, 2006. On May 31, 2005, the FERC accepted the filing, set the issues for hearing, and suspended the effective date of the first increase in OATT rates until November 1, 2005, subject to refund with interest if lower rates are eventually approved. The FERC accepted the two-step increase concept, such that the transmission rates will automatically increase on April 1, 2006, if the SECA revenues cease to be collected, and to the extent that replacement rates are not established. In a separate proceeding, at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present regime may need to be replaced through establishment of regional rates that would compensate AEP, among others, for the regional service provided by high voltage facilities they own that benefit customers throughout PJM. On September 30, 2005, AEP and a nonaffiliated utility (Allegheny Power) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime.

As of September 30, 2005, SECA transition rates have not fully compensated the AEP East companies for their lost T&O revenues. Management is unable to predict whether SECA rates and, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone will be sufficient to replace the SECA transition rate revenues. In addition, we are unable to predict whether the effect of the loss of transmission revenues will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If, (i) the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, (ii) AEP zonal transmission rates are not sufficiently increased by the FERC after March 31, 2006 to replace the lost T&O/SECA revenues, (iii) the FERC’s review of our current SECA rate results in a rate reduction which is subject to refund, or (iv) any increase in the AEP East companies’ transmission costs from the loss of transmission revenues are not fully recovered in retail and wholesale rates on a timely basis, and (v) if the FERC does not approve a new rate within PJM, future results of operations, cash flows and financial condition would be adversely affected.

Litigation

We continue to be involved in various litigation described in the “Significant Factors - Litigation” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2004 Annual Report. The 2004 Annual Report should be read in conjunction with this report in order to understand other litigation that did not have significant changes in status since the issuance of our 2004 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition. Other matters described in the 2004 Annual Report that did not have significant changes during the first nine months of 2005, that should be read in order to gain a full understanding of our current litigation include: (1) Coal Transportation Dispute, (2) Shareholders’ Litigation, (3) Potential Uninsured Losses, (4) Enron Bankruptcy, (5) Natural Gas Markets Lawsuits and (6) Cornerstone Lawsuit. Additionally, refer to the Commitments and Contingencies footnote in our Condensed Notes to Condensed Consolidated Financial Statements for further discussion of these matters.

New Source Review Litigation

See discussion of New Source Review Litigation within “Significant Factors - Environmental Matters.”

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and filed a petition for review of this Initial Decision, which the SEC has granted.

We believe the repeal of PUHCA will end litigation challenging our merger with CSW. All parties to the proceeding have filed motions with the SEC supporting dismissal of the proceeding upon repeal of the PUHCA in February 2006.

Bank of Montreal Claim

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals with us. In April 2003, we filed a lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had acted contrary to the appropriate trading contract and industry practice in terminating the contract and calculating termination and liquidation amounts. We claimed that BOM owed us at least $41 million related to previously recorded receivables on which we held approximately $20 million of credit collateral. In September 2005, we reached a settlement, subject to a confidentiality clause, with BOM without material impact on results of operations or financial condition.

TEM Litigation

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to us. We have subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 220 MW through May 31, 2006 and 270 MW thereafter). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.) (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000, (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

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.) has provided a limited guaranty.

On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the New York federal court that the PPA was terminated and (iii) would be pursuing against TEM, and SUEZ-TRACTEBEL S.A. under the guaranty, damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that TEM had breached the contract and awarded damages to us of $123 million plus pre-judgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. We asked the court to modify the judgment to (i) award a termination payment to us under the terms of the PPA; (ii) grant our attorneys’ fees; and (iii) render judgment against SUEZ-TRACTEBEL, S.A. on the guaranty. TEM sought reduction of the damages awarded by the court for replacement electric power products made available by OPCo under the PPA.

In September 2005, TEM posted a letter of credit for $142 million as security pending appeal of the judgment. Both parties have filed Notices of Appeal with the United States Court of Appeals for the Second Circuit. If the PPA is deemed terminated or found to be unenforceable by the court ultimately deciding the case, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM.

Texas Commercial Energy, LLP Lawsuit

In July 2003, Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas against us and four of our subsidiaries, ERCOT and a number of nonaffiliated energy companies including TXU, CenterPoint, Texas Genco, Reliant, TECO and Tractebel. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to their fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs.  In June 2004, the Court dismissed all claims against the AEP companies. TCE appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. The Fifth Circuit issued its decision in June 2005 and affirmed the lower Court’s decision. TCE filed a Petition for Writ of Certiorari with the United States Supreme Court on October 14, 2005. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit against the same defendants and others. Trial is scheduled in the Utility Choice/Cirro Energy case for April 2006. On October 18, 2005, the U.S. District Court heard oral argument on our Motion to Dismiss. We intend to continue to defend vigorously against the allegations in these cases.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005.

On July 19, 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. On April 11, 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 and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 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 references 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, financial condition or cash flows.

Spent Nuclear Fuel Litigation

As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, we, along with a number of nonaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, we filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In January 2003, the U.S. Court of Federal Claims ruled in our favor on the issue of liability. The case was tried in March 2004 on the issue of damages owed to us by the DOE. In May 2004, the U.S. Court of Federal Claims ruled against us and denied damages, ruling that pre-breach and post-breach damages are not recoverable in a partial breach case. In July 2004, we appealed this ruling to the U.S. Court of Appeals for the Federal Circuit. In September 2005, the U.S. Court of Appeals ruled that the trial court erred in ruling that pre-breach damages in a partial breach case are per se not recoverable, but denied us our pre-breach damages on the facts alleged. The Court of Appeals also ruled that the trial court did not err in determining that post-breach damages are not recoverable in a partial breach case, but determined that we may recover our post-breach damages in later suits as the costs are incurred.

Ontario Litigation

In June 2005, we were named as one of 21 defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. We have not been served with the lawsuit. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operation, have emitted NO_x, SO₂ and particulate matter that have harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $50 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. We believe we have meritorious defenses to this action and intend to defend vigorously against it.

Environmental Matters

As discussed in our 2004 Annual Report, there are emerging environmental control requirements that we expect will result in substantial capital investments and operational costs. The sources of these future requirements include:

· Legislative and regulatory proposals to adopt stringent controls on SO₂, NO_x and mercury emissions from coal-fired power plants,

· Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and

· Possible future requirements to reduce carbon dioxide emissions to address concerns about global climate change.

This discussion updates certain events occurring in 2005. You should also read the “Significant Factors - Environmental Matters” section within Management’s Financial Discussion and Analysis of Results of Operations in our 2004 Annual Report for a description of all environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) the Comprehensive Environmental Response Compensation and Liability Act (Superfund) and state remediation, (4) global climate change, (5) costs for spent nuclear fuel disposal and decommissioning, and (6) Clean Water Act regulation.

Future Reduction Requirements for SO₂ , NO_x and Mercury

Regulatory Emissions Reductions

In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO₂, NO_x and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

· The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO₂ and NO_x emissions across the Eastern United States (29 states and the District of Columbia) and make progress toward attainment of the new fine particulate matter and ground-level ozone national ambient air quality standards. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program.

· The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.

On March 14, 2005, the Administrator of the Federal EPA signed the final CAIR. The rule includes both a seasonal and annual NO_x control program as well as an annual SO₂ control program. All of the states in which our generating facilities are located will be subject to the seasonal and annual NO_x control programs and the annual SO₂ control program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the annual programs only. Arkansas will be subject to the seasonal NO_x control program only. Oklahoma is not affected by CAIR. In addition, the compliance deadline for Phase I for the NO_x control program has been accelerated to 2009, and will replace any obligations imposed by the NO_x State Implementation Plan (SIP) Call in 2009. On August 24, 2005, the Administrator of the Federal EPA published a proposed rule that includes a federal implementation plan (FIP) to reduce transport of fine particulate matter and ozone, modeled on the final CAIR, and proposes to deny the Section 126 petition filed by the State of North Carolina to require reductions of NO_x and SO₂ from specific facilities in thirteen states, including several AEP facilities. The proposed rule denies North Carolina’s petition for action based on its ozone non-attainment area, since the Federal EPA’s modeling predicts that this area will be in attainment with the 8-hour standard in 2010. The Federal EPA also proposes to deny the petition based on North Carolina’s PM_2.5 non-attainment areas, based on the reductions prescribed by the FIP, or to withdraw its Section 126 findings with respect to any state that submits a SIP implementing the CAIR requirements.

On March 15, 2005, the Administrator of the Federal EPA signed a final Clean Air Mercury Rule (CAMR) that will permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. The final CAMR imposes a national cap on mercury emissions from coal-fired power plants of 38 tons by 2010 and 15 tons by 2018. On October 21, 2005, the Federal EPA announced its decision to reconsider several issues in connection with the CAMR, including the legal basis for its decision to withdraw the December 2000 finding under Section 112 of the CAA and the impacts associated with the implementation of an emissions cap and trading program.

In April 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include "Best Available Retrofit Technology" (BART) requirements for individual facilities in their SIPs to address regional haze. The requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. On June 15, 2005, the Federal EPA issued its final "Clean Air Visibility Rule" (CAVR). The record for the final rule contains an analysis that demonstrates that for electric generating units subject to CAIR, CAIR will result in more visibility improvements than BART would provide. Therefore, states that adopt the CAIR are allowed to substitute CAIR for controls otherwise required by BART. On July 20, 2005, the Federal EPA also issued a proposed rule detailing the requirements for an emissions trading program that can satisfy the BART requirements for the regional haze program.

The changes in the Federal EPA’s final CAIR, CAMR and CAVR have not caused us to significantly revise our estimates of the capital investments necessary to achieve compliance with these requirements. However, the final rules give states substantial discretion in developing their rules to implement these programs and states will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. In addition, the CAIR, CAMR and CAVR have been challenged in the United States Court of Appeals for the District of Columbia. As a result, the ultimate requirements may not be known for several years and may depart significantly from the rules described here. If the final rules are remanded by the court, if states elect not to participate in the federal cap-and-trade programs, and/or if states elect to impose additional requirements on individual units that are already subject to the CAIR, CAVR and/or CAMR, our costs could increase significantly. The cost of compliance could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.

New Source Review (NSR) Litigation

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review 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 court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded.

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.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV were already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern states each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. The Northeastern states’ complaint has been assigned to the same judge in the U.S. District Court for the Southern District of Ohio. AEP filed an answer to the Northeastern states’ complaint and to the Federal EPA’s complaint, denying the allegations and stating its defenses.

On June 24, 2005, the United States Court of Appeals for the District of Columbia Circuit issued a decision affirming in part the new source review reform regulations adopted by the Federal EPA in December 2002. The court upheld the Federal EPA’s decision to apply an actual-to-future actual emissions, and includes tests utilizing a five-year look back period to establish actual baseline emissions for utilities and a ten-year period for other sources. This excludes increased emissions unrelated to a physical change from the projected emissions and includes emissions associated with demand growth. The court vacated the Federal EPA’s adoption of a broad pollution control project exclusion that includes projects that result in a significant collateral emissions increase, and the “clean unit” applicability test, and remanded certain recordkeeping requirements to the Federal EPA.

On August 30, 2005, the United States Court of Appeals for the Fourth Circuit denied the petitions for rehearing filed by the United States and other appellants in the Duke Energy case. On October 13, 2005, the Administrator of the Federal EPA signed a proposed rule that would adopt a test for determining when an emissions increase results from a change at an existing electric utility generating unit under the federal NSR programs that would be consistent with the test adopted and applied by the Fourth Circuit in the Duke Energy case. This would be based on maximum hourly emissions before and after the change. The Federal EPA is also seeking comments on two alternative formulations of the emission increase test.  We have filed a Motion in the NSR litigation that asks the Court, among other things, to dismiss the NSR cases on due process grounds based on the statements and admissions the Federal EPA made in promulgating the proposed rule.

We are unable to estimate the loss or range of loss related to any contingent liability 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 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.

Emergency Release Reporting

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances that cross property boundaries of the releasing facility.

On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to the alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. I&M and the Federal EPA signed a Final Consent Agreement and Final Order related to the Administrative Complaint effective June 30, 2005. I&M paid a $15 thousand penalty and will invest in a supplemental environmental project at the Cook Plant.

On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant SCR system. The Federal EPA indicated its intent to seek civil penalties. OPCo and the Federal EPA signed a Final Consent Agreement and Final Order related to the Administrative Complaint effective September 30, 2005. OPCo paid a $16 thousand penalty and will invest in a supplemental environmental project at the Gavin Plant.

Carbon Dioxide Public Nuisance Claims

In July 2004, attorneys general from eight states and the corporation counsel for the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions alleged that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. A notice of appeal to the Second Circuit Court of Appeals has been filed on behalf of all plaintiffs. A briefing schedule has not been established.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

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 has certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Investment-Gas Operations segment continues to hold forward gas contracts that were not sold with the gas pipeline and storage assets. These contracts are primarily financial derivatives with some physical contracts which will gradually wind down and completely expire in 2011. Our risk objective is to keep these positions risk neutral through maturity.

We have established 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 daily, weekly, and 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 of the 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 have embraced the disclosure standards. The following tables provide information on our risk management activities:

Mark-to-Market Risk Management Contract Net Assets (Liabilities)

This table provides detail on changes in our MTM asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in millions)

	Utility Operations			Investments-Gas Operations		Investments-UK Operations			Total
Total MTM Risk Management Contract Net Assets   (Liabilities) at December 31, 2004	$	277		$	-	$	(12	)	$	265
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(93	)		18		12			(63	)
Fair Value of New Contracts When Entered During the Period (b)		2			-		-			2
Net Option Premiums Paid/(Received) (c)		(4	)		-		-			(4	)
Change in Fair Value Due to Valuation Methodology Changes		-			-		-			-
Changes in Fair Value of Risk Management Contracts (d)		59			1		-			60
Changes in Fair Value of Risk Management Contracts Allocated to   Regulated Jurisdictions (e)		19			-		-			19
Total MTM Risk Management Contract Net Assets   (Liabilities) at September 30, 2005	$	260		$	19	$	-			279
Net Cash Flow and Fair Value Hedge Contracts (f)										(64	)
Ending Net Risk Management Assets at September 30, 2005									$	215

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized gains from risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed in detail within the following pages.

Detail on MTM Risk Management Contract Net Assets (Liabilities)

As of September 30, 2005

(in millions)

	Utility Operations			Investments-Gas Operations			Total
Current Assets	$	919		$	390		$	1,309
Noncurrent Assets		641			274			915
Total Assets		1,560			664			2,224
Current Liabilities		(845	)		(362	)		(1,207	)
Noncurrent Liabilities		(455	)		(283	)		(738	)
Total Liabilities		(1,300	)		(645	)		(1,945	)
Total Net Assets (Liabilities),excluding Hedges	$	260		$	19		$	279

Reconciliation of MTM Risk Management Contracts to

Total MTM Risk Management Contract Net Assets (Liabilities)

As of September 30, 2005

(in millions)

	MTM Risk Management Contracts (a)			PLUS: Hedges			Total (b)
Current Assets	$	1,309		$	9		$	1,318
Noncurrent Assets		915			3			918
Total MTM Derivative Contract Assets		2,224			12			2,236
Current Liabilities		(1,207	)		(73	)		(1,280	)
Noncurrent Liabilities		(738	)		(3	)		(741	)
Total MTM Derivative Contract Liabilities		(1,945	)		(76	)		(2,021	)
Total MTM Derivative Contract Net Assets	$	279		$	(64	)	$	215

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets (liabilities) provides two fundamental pieces of information.

· The source of 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, giving 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 September 30, 2005

(in millions)

	Remainder 2005			2006			2007			2008			2009			After 2009 (c)			Total (d)
Utility Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	(18	)	$	68		$	(4	)	$	2		$	-		$	-		$	48
Prices Provided by Other External Sources - OTC Broker Quotes (a)		75			33			97			30			3			-			238
Prices Based on Models and Other Valuation Methods (b)		(10	)		(57	)		(33	)		16			33			25			(26	)
Total	$	47		$	44		$	60		$	48		$	36		$	25		$	260
Investments - Gas Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	9		$	(16	)	$	10		$	-		$	-		$	-		$	3
Prices Provided by Other External Sources - OTC Broker Quotes (a)		30			6			(7	)		-			-			-			29
Prices Based on Models and Other Valuation Methods (b)		(3	)		(2	)		-			(2	)		(4	)		(2	)		(13	)
Total	$	36		$	(12	)	$	3		$	(2	)	$	(4	)	$	(2	)	$	19
Total:
Prices Actively Quoted - Exchange Traded Contracts	$	(9	)	$	52		$	6		$	2		$	-		$	-		$	51
Prices Provided by Other External Sources - OTC Broker Quotes (a)		105			39			90			30			3			-			267
Prices Based on Models and Other Valuation Methods (b)		(13	)		(59	)		(33	)		14			29			23			(39	)
Total	$	83		$	32		$	63		$	46		$	32		$	23		$	279

(a)	Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party on-line 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.
(c)	There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $26 million of this mark-to-market value is in 2010.
(d)	Amounts exclude Cash Flow and Fair Value Hedges.

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 September 30, 2005

Commodity	Transaction Class	Market/Region	Tenor
			(in months)
Natural Gas	Futures	NYMEX/Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	27
	Swaps	Gas East - Northeast, Mid-continent,
		Gulf Coast, Texas	27
	Swaps	Gas West - Rocky Mountains, West Coast	27
	Exchange Option Volatility	NYMEX/Henry Hub	12
Power	Futures	Power East - PJM	39
	Physical Forwards	Power East - MISO Cin Hub	27
	Physical Forwards	Power East - PJM West	39
	Physical Forwards	Power East - AEP Dayton (PJM)	15
	Physical Forwards	Power East - NEPOOL	39
	Physical Forwards	Power East - NYPP	39
	Physical Forwards	Power East - ERCOT	39
	Physical Forwards	Power East - Com Ed	9
	Physical Forwards	Power East - Entergy	15
	Physical Forwards	Power West - Palo Verde, Mead	51
	Physical Forwards	Power West - North Path 15, South Path 15	51
	Physical Forwards	Power West - Mid Columbia	51
	Peak Power Volatility (Options)	Cinergy, PJM	12
Emissions	Credits	SO2,NOx	39
Coal	Physical Forwards	PRB, NYMEX, CSX	27

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

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

We employ the use of interest rate forward and swap transactions in order to manage interest rate risk related to existing debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The tables below provide detail on designated, effective cash flow hedges included in our Condensed Consolidated Balance Sheets. The data in the first table indicates the magnitude of cash flow hedges that we have in place. 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. This table further indicates what portions of designated, effective hedges are expected to be reclassified into net income in the next 12 months. The second table provides the nature of changes from December 31, 2004 to September 30, 2005.

Information on energy commodity risk management activities is presented separately from interest rate risk management activities.

Cash Flow Hedges included in Accumulated Other Comprehensive Income (Loss)

On the Condensed Consolidated Balance Sheet as of September 30, 2005

(in millions)

	Accumulated Other Comprehensive Income (Loss) After Tax (a)			After Tax Portion Expected to be Reclassified to Earnings During the Next 12 Months (b)
Power and Gas	$	(42	)	$	(42	)
Interest Rate		(25	)		(3	)
Total	$	(67	)	$	(45	)

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2005

(in millions)

	Power and Gas			Interest Rate			Total
Beginning Balance, December 31, 2004	$	23		$	(23	)	$	-
Changes in Fair Value (c)		(41	)		(5	)		(46	)
Reclassifications from AOCI to Net Income (d)		(24	)		3			(21	)
Ending Balance, September 30, 2005	$	(42	)	$	(25	)	$	(67	)

(a)	“Accumulated Other Comprehensive Income (Loss) After Tax” - Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders’ equity on the balance sheet.
(b)	“After Tax Portion Expected to be Reclassified to Earnings During the Next 12 Months” - Amount of gains or losses (realized or unrealized) from derivatives used as hedging instruments that have been deferred and are expected to be reclassified into net income during the next 12 months at the time the hedged transaction affects net income.
(c)	“Changes in Fair Value” - Changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(d)	“Reclassifications from AOCI to Net Income” - Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into Net Income during the reporting period. Amounts are reported net of related income taxes.

Credit Risk

We limit credit risk 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 has met our internal credit rating criteria will we extend unsecured credit. We use Moody’s, S&P and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. Our analysis, in conjunction with the rating agencies’ information, is used 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. At September 30, 2005, our credit exposure net of collateral to sub investment grade counterparties was approximately 13.22%, expressed in terms of net MTM assets and net receivables. As of September 30, 2005, 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	$	1,149	$	359	$	790		3	$	342
Split Rating		25		9		16		1		15
Noninvestment Grade		316		222		94		3		81
No External Ratings:
Internal Investment Grade		113		1		112		1		51
Internal Noninvestment Grade		48		1		47		2		35
Total	$	1,651	$	592	$	1,059		10	$	524

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 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2007. This table presents 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 for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information

Estimated Next Three Years

As of September 30, 2005

	Remainder 2005	2006	2007
Estimated Plant Output Hedged	94%	89%	90%

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates 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 September 30, 2005, 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 year-to-date:

VaR Model

Nine Months Ended September 30, 2005				Twelve Months Ended December 31, 2004
(in millions)				(in millions)
End	High	Average	Low	End	High	Average	Low
$4	$5	$2	$1	$3	$19	$5	$1

Our VaR model results are adjusted using standard statistical treatments to calculate the CCRO VaR reporting metrics listed below.

CCRO VaR Metrics

(in millions)

	September 30, 2005		Average for Year-to-Date 2005		High for Year-to-Date 2005		Low for Year-to-Date 2005
95% Confidence Level, Ten-Day Holding Period	$	15	$	9	$	20	$	5
99% Confidence Level, One-Day Holding Period	$	6	$	4	$	8	$	2

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 $593 million at September 30, 2005 and $601 million at December 31, 2004. 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.

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, emissions and to a lesser degree other commodities. As a result, we are subject to price risk. The amount of risk taken is controlled by risk management operations and our Chief Risk Officer and risk management staff. When risk management activities exceed certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(in millions, except per-share amounts)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2005			2004			2005			2004
REVENUES
Utility Operations	$	3,132		$	2,920		$	8,318		$	8,009
Gas Operations		73			760			449			2,191
Other		95			101			289			356
TOTAL		3,300			3,781			9,056			10,556
EXPENSES
Fuel for Electric Generation		1,011			782			2,554			2,210
Purchased Electricity for Resale		181			274			494			444
Purchased Gas for Resale		5			725			255			2,011
Maintenance and Other Operation		906			847			2,569			2,689
Asset Impairments and Other Related Charges		39			-			39			-
Depreciation and Amortization		336			333			988			972
Taxes Other Than Income Taxes		205			181			566			555
TOTAL		2,683			3,142			7,465			8,881
OPERATING INCOME		617			639			1,591			1,675
Other Income		139			208			484			329
Other Expense		(24	)		(36	)		(130	)		(110	)
Investment Value Losses		(7	)		-			(7	)		(2	)
INTEREST AND OTHER CHARGES
Interest Expense		163			193			524			591
Preferred Stock Dividend Requirements of Subsidiaries		1			2			6			5
TOTAL		164			195			530			596
INCOME BEFORE INCOME TAXES		561			616			1,408			1,296
Income Taxes		196			204			471			444
INCOME BEFORE DISCONTINUED OPERATIONS		365			412			937			852
DISCONTINUED OPERATIONS, Net of Tax		22			118			26			60
NET INCOME	$	387		$	530		$	963		$	912
WEIGHTED AVERAGE NUMBER OF BASIC SHARES   OUTSTANDING		389			396			389			396
BASIC EARNINGS PER SHARE
Income Before Discontinued Operations	$	0.94		$	1.04		$	2.41		$	2.15
Discontinued Operations		0.05			0.30			0.07			0.15
TOTAL BASIC EARNINGS PER SHARE	$	0.99		$	1.34		$	2.48		$	2.30
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES   OUTSTANDING		390			397			390			396
DILUTED EARNINGS PER SHARE
Income Before Discontinued Operations	$	0.94		$	1.04		$	2.40		$	2.15
Discontinued Operations		0.05			0.30			0.07			0.15
TOTAL DILUTED EARNINGS PER SHARE	$	0.99		$	1.34		$	2.47		$	2.30
CASH DIVIDENDS PAID PER SHARE	$	0.35		$	0.35		$	1.05		$	1.05

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(in millions)

(Unaudited)

	2005			2004
CURRENT ASSETS
Cash and Cash Equivalents	$	849		$	320
Other Temporary Cash Investments		73			275
Accounts Receivable:
Customers		829			930
Accrued Unbilled Revenues		369			592
Miscellaneous		45			79
Allowance for Uncollectible Accounts		(33	)		(77	)
Total Accounts Receivable		1,210			1,524
Fuel, Materials and Supplies		649			852
Risk Management Assets		1,318			737
Margin Deposits		357			113
Other		214			200
TOTAL		4,670			4,021
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		16,487			15,969
Transmission		6,400			6,293
Distribution		10,564			10,280
Other (including gas, coal mining and nuclear fuel)		3,072			3,585
Construction Work in Progress		1,676			1,159
Total		38,199			37,286
Accumulated Depreciation and Amortization		14,684			14,485
TOTAL - NET		23,515			22,801
OTHER NONCURRENT ASSETS
Regulatory Assets		3,852			3,601
Securitized Transition Assets		608			642
Spent Nuclear Fuel and Decommissioning Trusts		1,120			1,053
Investments in Power and Distribution Projects		105			154
Goodwill		76			76
Long-term Risk Management Assets		918			470
Prepaid Pension Obligations		382			386
Other		663			831
TOTAL		7,724			7,213
Assets Held for Sale		47			628
TOTAL ASSETS	$	35,956		$	34,663

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2005 and December 31, 2004

(Unaudited)

			2005			2004
CURRENT LIABILITIES			(in millions)
Accounts Payable			$	1,112		$	1,051
Short-term Debt				15			23
Long-term Debt Due Within One Year (a)				717			1,279
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption				-			66
Risk Management Liabilities				1,280			608
Accrued Taxes				729			611
Accrued Interest				160			180
Customer Deposits				725			414
Other				674			775
TOTAL				5,412			5,007
NONCURRENT LIABILITIES
Long-term Debt (a)				11,025			11,008
Long-term Risk Management Liabilities				741			329
Deferred Income Taxes				4,674			4,819
Regulatory Liabilities and Deferred Investment Tax Credits				2,847			2,540
Asset Retirement Obligations				847			827
Employee Benefits and Pension Obligations				461			730
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2				159			166
Deferred Credits and Other				742			411
TOTAL				21,496			20,830
Liabilities Held for Sale				2			250
TOTAL LIABILITIES				26,910			26,087
Cumulative Preferred Stock Not Subject to Mandatory Redemption				61			61
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDERS’ EQUITY
Common Stock Par Value $6.50:
	2005	2004
Shares Authorized	600,000,000	600,000,000
Shares Issued	414,959,884	404,858,145
(21,499,992 and 8,999,992 shares were held in treasury at September 30, 2005 and  December 31, 2004,   respectively)				2,697			2,632
Paid-in Capital				4,121			4,203
Retained Earnings				2,579			2,024
Accumulated Other Comprehensive Income (Loss)				(412	)		(344	)
TOTAL				8,985			8,515
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	35,956		$	34,663

(a) See Accompanying Schedule.

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(in millions)

(Unaudited)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	963		$	912
Less: Income from Discontinued Operations		(26	)		(60	)
Income from Continuing Operations		937			852
Adjustments for Noncash Items:
Depreciation and Amortization		988			972
Accretion of Asset Retirement Obligations		50			47
Deferred Income Taxes		(33	)		88
Deferred Investment Tax Credits		(23	)		(21	)
Asset Impairments, Investment Value Losses and Other Related Charges		46			2
Carrying Costs		(83	)		(2	)
Amortization of Deferred Property Taxes		94			92
Mark-to-Market of Risk Management Contracts		-			89
Pension Contributions		(306	)		(27	)
Over/Under Fuel Recovery		(183	)		78
Gain on Sales of Assets		(172	)		(156	)
Change in Other Noncurrent Assets		(99	)		(101	)
Change in Other Noncurrent Liabilities		(21	)		27
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		5			367
Fuel, Materials and Supplies		54			(18	)
Accounts Payable		204			(289	)
Taxes Accrued		118			388
Customer Deposits		311			19
Interest Accrued		(25	)		(25	)
Other Current Assets		(246	)		(107	)
Other Current Liabilities		(29	)		3
Net Cash Flows From Operating Activities		1,587			2,278
INVESTING ACTIVITIES
Acquisition of Waterford Plant		(218	)		-
Construction Expenditures		(1,610	)		(1,047	)
Change in Other Temporary Cash Investments, Net		99			28
Investment in Discontinued Operations, Net		-			(59	)
Purchases of Investments		(3,342	)		(425	)
Proceeds from the Sale of Investments		3,445			274
Proceeds from Sale of Assets		1,599			1,202
Other		39			(6	)
Net Cash Flows From (Used For) Investing Activities		12			(33	)
FINANCING ACTIVITIES
Issuance of Common Stock		393			13
Repurchase of Common Stock		(427	)		-
Issuance of Long-term Debt		2,045			416
Change in Short-term Debt, Net		(8	)		(201	)
Retirement of Long-term Debt		(2,599	)		(1,898	)
Retirement of Preferred Stock		(66	)		(4	)
Dividends Paid on Common Stock		(408	)		(415	)
Net Cash Flows Used For Financing Activities		(1,070	)		(2,089	)
Net Increase in Cash and Cash Equivalents		529			156
Cash and Cash Equivalents at Beginning of Period		320			778
Cash and Cash Equivalents at End of Period	$	849		$	934
Net Decrease in Cash and Cash Equivalents from Discontinued Operations	$	-		$	(4	)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period		-			13
Cash and Cash Equivalents from Discontinued Operations - End of Period	$	-		$	9
See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(in millions)

(Unaudited)

		Common Stock										Accumulated Other Comprehensive Income (Loss)
		Shares		Amount		Paid-in Capital			Retained Earnings						Total
DECEMBER 31, 2003			404	$	2,626	$	4,184		$	1,490		$	(426	)	$	7,874
Issuance of Common Stock			1		4		9									13
Common Stock Dividends										(415	)					(415	)
Other							4									4
TOTAL																7,476
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Tax:
	Foreign Currency Translation Adjustments,   Net of Tax of $0												(113	)		(113	)
	Cash Flow Hedges, Net of Tax of $4												(8	)		(8	)
	Minimum Pension Liability, Net of Tax of $10												16			16
NET INCOME										912						912
TOTAL COMPREHENSIVE INCOME																807
SEPTEMBER 30, 2004			405	$	2,630	$	4,197		$	1,987		$	(531	)	$	8,283
DECEMBER 31, 2004			405	$	2,632	$	4,203		$	2,024		$	(344	)		8,515
Issuance of Common Stock			10		65		328									393
Common Stock Dividends										(408	)					(408	)
Repurchase of Common Stock							(427	)								(427	)
Other							17									17
TOTAL																8,090
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 $36												(67	)		(67	)
	Minimum Pension Liability, Net of Tax of $0												4			4
	Securities Available for Sale, Net of Tax $0												1			1
NET INCOME										963						963
TOTAL COMPREHENSIVE INCOME																895
SEPTEMBER 30, 2005			415	$	2,697	$	4,121		$	2,579		$	(412	)	$	8,985

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

September 30, 2005 and December 31, 2004

(Unaudited)

(in millions)

	2005			2004
First Mortgage Bonds	$	242		$	417
Defeased TCC First Mortgage Bonds (a)		18			84
Installment Purchase Contracts		1,935			1,773
Notes Payable		919			939
Senior Unsecured Notes		7,342			7,717
Securitization Bonds		648			698
Notes Payable to Trust		113			113
Equity Unit Senior Notes (b)		345			345
Long-term DOE Obligation (c)		234			229
Other Long-term Debt		-			14
Equity Unit Contract Adjustment Payments		-			9
Unamortized Discount, Net		(54	)		(51	)
TOTAL LONG-TERM DEBT OUTSTANDING		11,742			12,287
Less Portion Due Within One Year		717			1,279
TOTAL LONG-TERM PORTION	$	11,025		$	11,008

(a)	On May 7, 2004, we deposited cash and treasury securities of $125 million with a trustee to defease all of TCC’s outstanding First Mortgage Bonds. Trust fund assets related to this obligation of $2 and $72 million are included in Other Temporary Cash Investments at September 30, 2005 and December 31, 2004, respectively, and $21 and $22 million are included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets at September 30, 2005 and December 31, 2004, respectively. Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.
(b)	In June 2005, we remarketed $345 million of 5.75% Equity Unit Senior Notes originally issued in June 2002 with new notes bearing a 4.709% interest rate. See “Remarketing of Senior Notes” section of Note 11.
(c)	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. I&M is the only AEP subsidiary that generated electric power with nuclear fuel prior to that date. Trust fund assets of $265 million and $262 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts in the Condensed Consolidated Balance Sheets at September 30, 2005 and December 31, 2004, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.	Significant Accounting Matters
2.	New Accounting Pronouncements
3.	Rate Matters
4.	Customer Choice and Industry Restructuring
5.	Commitments and Contingencies
6.	Guarantees
7.	Acquisitions, Dispositions, Discontinued Operations, Asset Impairments and Assets Held for Sale
8.	Benefit Plans
9.	Business Segments
10.	Income Taxes
11.	Financing Activities
12.	Company-wide Staffing and Budget Review

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited interim financial statements should be read in conjunction with the 2004 Annual Report as incorporated in and filed with our 2004 Form 10-K.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments that are necessary for a fair presentation of our results of operations for interim periods.

Other Income and Other Expense

The following table provides the components of Other Income and Other Expense as presented in our Condensed Consolidated Statements of Income:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(in millions)				(in millions)
Other Income:
Interest and Dividend Income	$	18	$	7	$	43	$	18
Equity Earnings		3		5		10		15
Nonutility Revenue		16		27		108		85
Gain on Sale of IPPs		-		105		-		105
Gain on Sale of South Coast		-		48		-		48
Gain on Sale of Pac Hydro (a)		56		-		56		-
Gain on Sale of Texas REPs (a)		-		-		112		-
Carrying Charges		27		1		83		2
Other		19		15		72		56
Total Other Income	$	139	$	208	$	484	$	329
Other Expense:
Nonutility Expense	$	12	$	24	$	90	$	75
Other		12		12		40		35
Total Other Expense	$	24	$	36	$	130	$	110

(a) See “Dispositions” section of Note 7.

Components of Accumulated Other Comprehensive Income (Loss)

The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss):

	September 30,			December 31,
	2005			2004
Components	(in millions)
Foreign Currency Translation Adjustments, Net of tax	$	-		$	6
Securities Available for Sale, Net of tax		-			(1	)
Cash Flow Hedges, Net of tax		(67	)		-
Minimum Pension Liability, Net of tax		(345	)		(349	)
Total	$	(412	)	$	(344	)

At September 30, 2005, we expect to reclassify approximately $45 million of net losses 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. Fifteen months is the maximum length of time that we are hedging our exposure to variability in future cash flows with contracts designated as cash flow hedges.

Accounting for Asset Retirement Obligations (ARO)

The following is a reconciliation of the beginning and ending aggregate carrying amounts of ARO:

	Nuclear Decommissioning			Ash Ponds		Wind Mills and Mining Operations			Total
	(in millions)
ARO at January 1, 2005, Including STP	$	960		$	84	$	32		$	1,076
Accretion Expense		43			5		2			50
Liabilities Incurred		-			-		8			8
Revisions in Cash Flow Estimates		(27	) (c)		-		(1	)		(28	)
ARO at September 30, 2005, Including STP		976			89		41			1,106
Less ARO Liability for STP (a)		(256	)		-		-			(256	)
ARO at September 30, 2005	$	720		$	89	$	41		$	850	(b)

(a)	The ARO for TCC’s share of STP was included in Liabilities Held for Sale at December 31, 2004 and was subsequently transferred to the buyer with the sale in the second quarter of 2005 (see “Texas Plants-South Texas Project” section of Note 7).
(b)	The current portion of our ARO, totaling $3 million, is included in Other in the Current Liabilities section in our Condensed Consolidated Balance Sheets.
(c)	The Cook Plant’s operating licenses were renewed for Cook Unit 1 until 2034 and for Cook Unit 2 until 2037.

Accretion expense is included in Maintenance and Other Operation expense in our accompanying Condensed Consolidated Statements of Income.

At September 30, 2005 and December 31, 2004, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $855 million and $791 million, respectively, relating to Cook Plant recorded in Spent Nuclear Fuel and Decommissioning Trusts in our Condensed Consolidated Balance Sheets.

Supplementary Information

		Three Months Ended September 30,				Nine Months Ended September 30,
		2005		2004		2005		2004
Related Party Transactions		(in millions)
AEP Consolidated Purchased Power:
	Ohio Valley Electric Corporation (44.2% owned)	$	49	$	45	$	140	$	115
	Sweeny Cogeneration Limited Partnership (50% owned)		38		-		98		-

		Nine Months Ended September 30,
		2005			2004
Cash Flow Information		(in millions)
Cash was paid (received) for:
	Interest (net of capitalized amounts)	$	492		$	576
	Income Taxes		277			(112	)
Change in construction-related Accounts Payable included in Investing Activities - Construction Expenditures			66			(24	)
Noncash Investing and Financing Activities:  Acquisitions Under Capital Leases			42			90
(Disposition) of Liabilities Related to Acquisitions/Divestures, Net			(20	)		(67	)

Earnings per Share

The following tables present our basic and diluted earnings per share (EPS) calculations included in our Condensed Consolidated Statements of Income:

	Three Months Ended September 30,
	2005					2004
	(In Millions, Except Per Share Data)
			$/share					$/share
Earnings applicable to common stock	$	387				$	530
Average number of basic shares outstanding		388.9	$	0.99			395.7	$	1.34
Average dilutive effect of:
Performance Share Units		1.0		(0.00	)		0.7		(0.00	)
Stock Options		0.5		(0.00	)		0.3		(0.00	)
Restricted Stock Units		0.1		(0.00	)		-		(0.00	)
Average number of diluted shares outstanding		390.5	$	0.99			396.7	$	1.34

	Nine Months Ended September 30,
	2005					2004
	(In Millions, Except Per Share Data)
			$/share					$/share
Earnings applicable to common stock	$	963				$	912
Average number of basic shares outstanding		388.7	$	2.48			395.6	$	2.30
Average dilutive effect of:
Performance Share Units		0.9		(0.01	)		0.5		(0.00	)
Stock Options		0.3		(0.00	)		0.3		(0.00	)
Restricted Stock Units		0.1		(0.00	)		-		(0.00	)
Average number of diluted shares outstanding		390.0	$	2.47			396.4	$	2.30

Our stock option and other equity compensation plans are discussed in Note 12 to the consolidated financial statements in the 2004 Form 10-K.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income.

In connection with preparation of the first quarter of 2005 financial statements, we concluded that it was appropriate to classify our auction rate securities as Other Temporary Cash Investments. Previously, such investments had been classified as Cash and Cash Equivalents in the Condensed Consolidated Balance Sheets. Accordingly, we have revised the classification to exclude from Cash and Cash Equivalents $103 million at December 31, 2004, and to include such amounts as Other Temporary Cash Investments. There were no auction rate securities held at September 30, 2005. At December 31, 2003, auction rate securities approximated $200 million. These revisions had no impact on our previously reported results of operations, operating cash flows or working capital.

2.NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented during 2005 that we have determined relate to our operations.

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

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires 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 previously available under Accounting Principles Board (APB) Opinion No. 25 “Accounting for Stock Issued to Employees.” The statement is effective as of the first annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially adopting the statement.

We will implement SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost will be based on the grant-date fair value of the equity award. We do not expect implementation of SFAS 123R to materially affect our results of operations, cash flows or financial condition.

In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (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. We will apply the principles of SAB 107 in conjunction with our adoption of SFAS 123R.

SFAS 154 “Accounting Changes and Error Corrections” (SFAS 154)

In May 2005, the FASB issued SFAS 154, which replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” The statement applies to all voluntary changes in accounting principle and changes resulting from adoption of a new accounting pronouncement that does not specify transition requirements. SFAS 154 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. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 with early implementation permitted for accounting changes and corrections of errors made in fiscal years beginning after the date this statement is issued. SFAS 154 is effective for us beginning January 1, 2006 and will be applied when applicable.

FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations” (FIN 47)

In March 2005, the FASB issued FIN 47, which interprets the application of SFAS 143 “Accounting for Asset Retirement Obligations.” FIN 47 clarifies that the term conditional asset retirement obligation 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 asset retirement obligation 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 asset retirement obligation.

We will implement FIN 47 during the fourth quarter of 2005. Implementation will require a potential adjustment for the cumulative effect for any nonregulated operations of initially adopting FIN 47 to be recorded as a change in accounting principle, disclosure of pro forma liabilities and asset retirement obligations, and other additional disclosures. We have not completed our evaluation of any potential impact to our results of operations or financial condition.

EITF Issue 03-13 “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”

This issue developed a model for evaluating which cash flows are to be considered in determining whether cash flows have been or will be eliminated and what types of continuing involvement constitute significant continuing involvement when determining whether to report Discontinued Operations. During the first quarter of 2005, we applied this issue to components we disposed or classified as held for sale, including the HPL disposition (see “Houston Pipe Line Company” section of Note 7).

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 that may result from any such future changes. The FASB is currently working on several projects including accounting for uncertain tax positions, business combinations, liabilities and equity, revenue recognition, subsequent events, earnings per share, pension plans, fair value measurements and related tax impacts. We also expect to see more FASB projects as a result of their desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from pending and future projects could have an impact on our future results of operations and financial position.

3.RATE MATTERS

As discussed in our 2004 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and at state commissions. The Rate Matters note within our 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending. The following sections discuss current activities and update the 2004 Annual Report.

APCo Virginia Environmental and Reliability Costs

In April 2004, the Virginia Electric Restructuring Act was amended to include 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 after July 1, 2004. On July 1, 2005, APCo filed a request with the Virginia SCC seeking approval for the recovery of $62 million in incremental E&R costs through June 30, 2006. The $62 million request represents i) expected costs of environmental controls on coal-fired generators to meet the first phase of the Clean Air Interstate Rule and Clean Air Mercury Rule finalized earlier this year, ii) recovery of the incremental cost of the Jacksons Ferry-Wyoming 765 kilovolt transmission line construction and iii) other incremental T&D system reliability costs incurred from July 1, 2004 to June 30, 2006.

In the filing, APCo had requested that a twelve-month E&R recovery factor be applied to electric service bills on an interim basis beginning August 1, 2005. The recovery factor would have been applied as a 9.18% surcharge to customer bills. APCo proposed to practice over/under-recovery deferral accounting for the difference between the actual incremental costs incurred and the revenue recovered.

Through September 30, 2005, APCo has incurred approximately $13 million of actual incremental E&R costs and has deferred $7 million of such costs for future recovery. APCo did not record $2 million of equity carrying costs that are not recognized until collected.  Additionally, E&R costs of $4 million represented capitalized interest that was duplicative of the carrying costs.

On July 14, 2005, the Virginia SCC issued an order that established a procedural schedule for APCo’s proceeding including a public hearing on February 7, 2006. The order provided that no portion of APCo’s application should become effective pending further decision of the Virginia SCC. On October 14, 2005, the Virginia SCC denied APCo’s request to place in effect, on an interim basis subject to refund, its proposed cost recovery surcharge. Under this order, an E&R surcharge will not become effective until the Virginia SCC issues an order following the February 7, 2006 public hearing in this case. The Virginia SCC also ruled in this order that it does not have the authority under applicable Virginia law to approve the recovery of projected E&R costs before their actual incurrence and adjudication, which effectively eliminated projected costs requested in this filing. However, according to this order, APCo may update its request to reflect additional actual costs and/or present additional evidence. If the Virginia SCC denies recovery of any portion of the net incremental amounts deferred to date, it would adversely affect future results of operations and cash flows.

APCo and WPCo West Virginia Rate Case

On August 26, 2005, APCo and WPCo collectively filed an application with the Public Service Commission of West Virginia seeking an initial increase in their retail rates of approximately $82 million. The initial increase included approval to reactivate and modify the suspended Expanded Net Energy Cost (ENEC) Recovery Mechanism which accounted for $72 million of the initial increase and approval to implement a system reliability tracker which accounted for $10 million. ENEC includes fuel and purchased power costs, as well as other energy-related items including off-system sales margins and transmission items. In addition, APCo and WPCo requested a series of supplemental annual increases related to the recovery of the cost of significant environmental and transmission expenditures. The first proposed supplemental increase of $9 million would go in effect on the same date as the initial rate increase, and the remaining proposed supplemental increases of $44 million, $10 million and $38 million would go in effect on January 1, 2007, 2008 and 2009, respectively. It is expected that the proposed rates will become effective on June 23, 2006 under West Virginia law. APCo has a regulatory liability of $52 million of pre-suspension, previously over-recovered ENEC costs which it is proposing to apply plus a carrying cost in the future to any under-recoveries of ENEC costs through the reactivated ENEC Recovery Mechanism. Management is unable to predict the ultimate effect of this filing on future revenues, results of operations, cash flows and financial condition.

I&M Indiana Settlement Agreement

I&M’s fuel and base rates in Indiana were frozen through a prior agreement. In 2004, the IURC ordered the continuation of the fixed fuel adjustment charge on an interim basis through March 2005, pending the outcome of negotiations. Certain of the parties to the negotiations reached a settlement and signed an agreement on March 10, 2005 and filed the agreement with the IURC on March 14, 2005. The IURC approved the agreement on June 1, 2005.

The approved settlement caps fuel rates for the March 2004 through June 2007 billing months at an increasing rate that includes 8.609 mills per KWH reflected in base rates. The settlement provides that the total capped fuel rates will be 9.88 mills per KWH from January 2005 through December 2005, 10.26 mills per KWH from January 2006 through December 2006, and 10.63 mills per KWH from January 2007 through June 2007. Pursuant to a separate IURC order, I&M began billing the 9.88 mills per KWH total fuel rate on an interim basis effective with the April 2005 billing month. In accordance with the agreement, the October 2005 through March 2006 factor will be adjusted for the delayed implementation of the 2005 factor.

The settlement agreement also covers certain events at the Cook Plant. The settlement provides that if an outage of greater than 60 days occurs at Cook Plant, the recovery of actual monthly fuel costs will be in effect for the outage period beyond 60 days, capped by the average AEP System Pool Primary Energy Rate (Primary Energy Rate), the ratio of the sum of fuel and one half maintenance expenses incurred by the pool members to the total kilowatt-hours of net generation, excluding I&M, as defined by the AEP System Interconnection Agreement and adjusted for losses. If a second outage greater than 60 days occurs, actual monthly fuel costs capped at the Primary Energy Rate would be recovered through June 2007. Over the term of the settlement, if total cumulative actual fuel costs (except during a Cook Plant outage of greater than 60 days) are less than the cap prices, the savings will be credited to customers over the next two fuel adjustment clause filings. Cumulative net fuel costs in excess of the capped prices cannot be recovered. If Cook Plant operates at a capacity factor greater than 87% during the fuel cap period, I&M will receive credit for 30% of the savings produced by that performance.

The settlement agreement also caps base rates from January 1, 2005 to June 30, 2007 at the rates in effect as of January 1, 2005. During this cap period, I&M may not implement a general increase in base rates or implement a rider or cost deferral not established in the settlement agreement unless the IURC determines that a significant change in conditions beyond I&M’s control occurs or a material impact on I&M occurs as a result of federal, state or local regulation or statute that mandates reliability standards related to transmission or distribution costs.

I&M experienced a cumulative under-recovery for the period March 2004 through September 2005 of $10 million. Since I&M expects that its cumulative fuel costs through the end of the fuel cap period will exceed the capped fuel rates, the $10 million was recorded as fuel expense.  If future fuel costs per KWH through June 30, 2007 continue to exceed the caps, or if the base rate cap precludes I&M from seeking timely rate increases to recover increases in its cost of service through June 30, 2007, future results of operations and cash flows would be adversely affected.

I&M Michigan Fuel Recovery Plan

In September 2004, I&M filed its 2005 Power Supply Cost Recovery (PSCR) Plan, with the requested PSCR factors implemented pursuant to the statute effective with January 2005 billings, replacing the 2004 factors. On March 29, 2005, the Michigan Public Service Commission (MPSC) issued an order approving an agreement authorizing I&M’s proposed 2005 PSCR Plan factors.

On March 31, 2005, I&M filed its 2004 PSCR Reconciliation seeking recovery of approximately $2 million of unrecovered PSCR fuel costs and interest through the application of customer bill surcharges.

On April 28, 2005, the MPSC issued an Opinion and Order approving I&M’s proposed 2004 PSCR factors as billed and finding in favor of I&M on all issues, including the proposed treatment of net SO₂ and NO_x credits.

On September 30, 2005, I&M filed its 2006 PSCR Plan reflecting projected costs for 2006. The factors proposed by I&M will be placed into effect beginning January 2006 on an interim basis, unless approved by the MPSC prior to that time. If approved, the fuel factors to be placed in effect together with accompanying over/under-recovery deferral accounting should allow I&M to recover its fuel costs in Michigan.

KPCo Rate Filing

On September 26, 2005, KPCo filed a request with the Kentucky Public Service Commission to increase base rates by approximately $65 million to recover increasing costs. The major components of the rate increase include a return on common equity of 11.5% or $26 million, the impact of reduced point-to-point transmission revenues of $10 million, recovery of additional AEP Power Pool capacity costs of $9 million, additional reliability spending of $7 million and increased depreciation expense of $5 million. A final order is expected in April 2006. We are unable to predict the ultimate effect of this filing on future revenues, results of operations, cash flows and financial condition.

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

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 offered to the OCC to collect those reallocated costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation of purchased power costs over three years. In September 2003, the OCC expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs, future results of operations and cash flows would be adversely affected.

In the review of PSO’s 2001 fuel and purchased power practices, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies was inconsistent with the FERC-approved Operating Agreement and SIA and that the AEP West companies should have been allocated greater margins. The parties objected to the inclusion of mark-to-market amounts in developing the allocation base.

The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. On July 25, 2005, the OCC Staff and two intervenors filed testimony in which they quantified the alleged improperly allocated off-system sales margins between AEP East and AEP West companies. Their overall recommendations would result in an increase in off-system sales margins allocated to PSO and thus, a reduction in its recoverable fuel costs through June 2005 of an amount between $38 million and $47 million. PSO does not agree with the intervenors’ and the OCC Staff’s recommendations and will defend vigorously its position. Accordingly, PSO has not recorded a provision for the off-system sales margins issue. Furthermore, should the OCC Staff prevail on this issue, we also believe the reallocation of off-system sales margins to PSO would be substantially less than their recommended amounts. On August 22, 2005, the Attorney General of Oklahoma filed a motion to suspend the procedural schedule, giving the parties sufficient time to review revised data.

As noted in the 2004 Annual Report, 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. On September 29, 2005, the United States District Court, Western District of Texas, issued an order in the TNC fuel proceeding, preempting the PUCT from deciding this same allocation issue in Texas. The Court agreed with us that the FERC had jurisdiction over the SIA and that the sole remedy is at the FERC. It is unknown how the OCC will handle the jurisdictional issue. If the OCC continues to move forward on this issue, it could result in increased off-system sales margins included in the fuel clause adversely affecting future results of operations and cash flows for AEP and PSO. However, based on the position taken by the Federal court in Texas, it would appear that the OCC would be preempted from disallowing fuel recoveries for alleged improper allocations of system sales margins. If the OCC or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between AEP East and AEP West companies.

In April 2005, the OCC heard arguments from intervenors that requested the OCC conduct a prudence review of PSO’s fuel and purchased power practices for 2003. On June 10, 2005, the OCC decided to have its staff conduct that review. Management is unable to predict the ultimate effect of these Oklahoma fuel clause proceedings on revenues, results of operations, cash flows and financial condition.

PSO Lawton Power Supply Agreement

On November 26, 2003, pursuant to an application by Lawton Cogeneration Incorporated seeking approval of a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments, the OCC issued an order approving the Agreement and setting the avoided costs. The order did not approve recovery by PSO of the resultant purchased power costs.

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court. In the appeal, PSO maintained that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement. The Oklahoma Supreme Court issued a decision on June 21, 2005 affirming portions of the OCC’s order and remanding certain provisions. The Court affirmed the OCC’s finding that Lawton established a legally enforceable obligation and ruled that it was within the OCC’s discretion to award a 20-year contract and to base the capacity payment on a peaking unit. The Court directed the OCC to revisit its determination of PSO’s avoided energy cost. The OCC has appointed a settlement judge and negotiations are ongoing. A procedural schedule was issued September 30, 2005, which provides for a January 2006 hearing date. We are unable to predict the final outcome of the remand. However, if the OCC were to ultimately deny recovery of any portion of the cost of the resultant Agreement, it would adversely affect future results of operations and cash flows.

Upon resolution of the litigation, management will review any resultant transaction to determine if it can be accounted for as a purchased power transaction or whether it will be accounted for as a lease or as a generating plant asset on the balance sheet under FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities.”

PSO Rate Review

PSO has been involved in a commission staff-initiated base rate review before the OCC which began in 2003. In that proceeding, PSO made a filing seeking to increase its base rates by $41 million, while various other parties made recommendations to reduce PSO’s base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. The settlement provides for a $7 million annual base revenue reduction offset by a $6 million reduction in annual depreciation expense and recovery through fuel revenues of certain transmission expenses previously recovered in base rates. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. The settlement also provides for recovery, over 24 months, of $9 million of deferred fuel costs associated with a renegotiated coal transportation contract and the continuation of a $12 million vegetation management rider, both of which are earnings neutral. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC issued an order approving the stipulation on May 2, 2005 and new base rates were implemented in June 2005.

SWEPCo and TNC PUCT Staff Review of Earnings

On October 28, 2005, the staff of the PUCT reported results of its review of SWEPCo’s and TNC’s year-end 2004 earnings. Based upon 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 plans to engage SWEPCo in discussions to reconcile the earnings calculation and consider possible ways to address the results. Management is unable to predict the future outcome of this initial report on future revenues, results of operations, cash flows and financial condition. Staff recommended no further action regarding TNC at this time.

SWEPCo Texas Fuel Factor Filing

On November 7, 2005, due mainly to the increased cost of natural gas, SWEPCo filed a petition with the PUCT to increase its annual fixed fuel factor by $49 million and to surcharge $46 million of past under-recoveries over 12 months. Management cannot predict the ultimate outcome of this filing. Actual costs will be subject to review and approval in a future fuel reconciliation.

TCC Rate Case

On August 15, 2005, the PUCT issued an order in an ongoing base rate proceeding, reducing TCC’s annual base rates by $9 million. This reduction in TCC’s annual base rates will be offset by the elimination of a merger-related rate rider credit of $7 million, an increase in other miscellaneous revenues of $4 million and a decrease in depreciation expense of $9 million, resulting in a prospective increase in estimated annual pretax earnings of $11 million. Tariffs were approved and the rate change was implemented effective September 6, 2005. On October 6, 2005 the PUCT voted not to consider motions for rehearing. As a result, the August 15, 2005 order will become final and subject to appeal in mid-November. TCC is considering whether it will appeal this order. Also, in the third quarter of 2005, TCC reclassified $126 million from Accumulated Depreciation and Amortization to Regulatory Liability-Asset Removal Costs based on a depreciation study prepared by TCC and approved by the PUCT.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal

Several parties including the Office of Public Utility Counsel and 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 former affiliated REPs, respectively). In June 2003, the District Court ruled that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor for Mutual Energy WTU, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements of both Mutual Energy WTU and Mutual Energy CPL. The Court upheld the initial PTB orders on all other issues. In an opinion issued on July 28, 2005, the Texas Court of Appeals reversed the District Court on the loss of load issue, but otherwise affirmed its decision. The amount of unaccounted for energy built into the PTB fuel factors attributable to Mutual Energy WTU prior to AEP’s sale of Mutual Energy WTU was approximately $3 million. Our third quarter 2005 pretax earnings were adversely affected by $3 million because of this decision. TNC has filed a motion for rehearing regarding the unaccounted for energy issue at the Court of Appeals.

Texas Unbundled Cost of Service (UCOS) Appeal

The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began in Texas. TCC placed new T&D rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. Certain PUCT rulings in this proceeding, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003, upholding the PUCT’s UCOS order with one exception. The District Court ruled that the excess earnings refund methodology is unlawful because refunding the 1999 through 2001 excess earnings, solely as a credit to nonbypassable T&D rates charged to REPs, and not to the actual consumers of the electricity discriminates against residential and small commercial customers. TCC, TNC and other parties appealed this District Court ruling to the Court of Appeals. In a decision issued on September 23, 2005, the Court of Appeals determined that the refund of excess earnings other than through the true-up process was unlawful under the Texas Restructuring Legislation, thereby reversing the determination of the PUCT and the District Court. This decision, in effect, reversed the District Court’s determination that the refund methodology discriminated against certain customer classes. In all other respects, the decision of the District Court was affirmed. At this time, we are unable to predict if this decision will be appealed to the Texas Supreme Court.

TCC’s position is that, consistent with the Court of Appeals determination, ordering separate early refunds of excess earnings was unlawful because the statute only permits such refunds to be accomplished as a part of the stranded cost determination in the True-up Proceeding. Nonetheless, TCC’s true-up filing was based on a prior PUCT determination that assumed the legality of separate refunds of excess earnings. Therefore, if the Court of Appeals decision were to be implemented by permitting TCC to add a surcharge to its rates to recover previously refunded excess earnings, and stranded cost recovery was also adjusted, TCC’s recovery could be affected in a largely offsetting manner in the two cases. Accordingly, in the third quarter of 2005, based on the probable outcome that the PUCT would implement the surcharge in the future, TCC reduced the amount of its recoverable stranded cost and recorded a separate regulatory asset for $49 million of excess earnings that should be refunded to TCC by the REPs. This resulted in a $9 million reduction to the true-up carrying cost regulatory asset, the effect of which was offset by an increase of $7 million in regulatory assets for the refund of the interest that had been previously refunded to the REPs. TCC cannot predict the ultimate outcome of this litigation; however, TCC believes the Court of Appeals decision significantly contributes to its position that customers are entitled to receive credit for excess earnings and related carrying cost effect on that amount as a reduction to stranded costs and not through an earlier refund in T&D rates.

At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. During the first nine months of 2005, TCC refunded $9 million reducing its unrefunded excess earnings to $1 million. On July 15, 2005, the PUCT approved a preliminary order in the TCC True-up Proceeding that ordered TCC to cease refunding excess earnings at the end of July 2005. Under that order, the unrefunded balance of excess earnings of $1 million as of the end of July 2005 would reduce the balance of stranded costs.

Hold Harmless Proceeding

In a July 2002 order conditionally accepting our choice to join PJM, the FERC directed AEP, ComEd, Midwest Independent System Operator (MISO) and PJM to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from us and ComEd joining PJM instead of MISO.

In July 2004, AEP and PJM filed jointly with the FERC a hold-harmless proposal. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. AEP and ComEd presented studies that showed no adverse effects to the Michigan and Wisconsin utilities. On December 27, 2004, AEP and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250 thousand that was approved by the FERC on March 7, 2005. On April 25, 2005, AEP and International Transmission Company in Michigan filed a settlement that resolves all hold-harmless issues for a one-time payment of $120 thousand that was approved by the FERC on June 24, 2005. On May 19, 2005, AEP and all remaining Michigan companies filed a settlement that resolves all hold-harmless issues for a one-time payment of approximately $2 million, which was approved by the FERC on June 24, 2005.

The payment to the Michigan utilities will be deferred, as was the Wisconsin payment, as a PJM integration cost to be amortized over 15 years and recovery will be sought in future retail rate filings. Management believes that it is probable that these payments will ultimately be recovered from retail and wholesale customers. If the AEP East companies cannot recover these amortizations on a timely basis in their retail base rates, future results of operations and cash flows will be adversely affected.

FERC Order on Regional Through and Out Rates

A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. SECA transition rates are in effect through March 31, 2006. Intervenors in the SECA proceeding are objecting to the SECA rates and our method of determining those rates. The FERC has set SECA rate issues for hearing and indicated that the SECA rates are being recovered subject to refund. We recognized net SECA revenues of $36 million and $93 million in the third quarter and first nine months of 2005, respectively. In addition, we recognized $11 million of net SECA revenues in December 2004. Intervenors in the SECA proceeding are objecting to the SECA rates and our method of determining those rates. Management is unable to determine the probable outcome of the FERC’s SECA rate proceeding.

In a March 31, 2005 FERC filing, we proposed an increase in the revenue requirements and rates for transmission service, and certain ancillary services in the AEP zone of PJM. The customers receiving these services are the AEP East companies, municipal and cooperative wholesale entities and retail customers that exercise retail choice that have load delivery points in the AEP zone of PJM. As proposed, the transmission service rates would increase in two steps, first to reflect an increase in the revenue requirements, and then to reflect the loss of revenues from the discontinuance of SECA transition rates on April 1, 2006. On May 31, 2005, the FERC accepted the filing, set the issues for hearing, and suspended the effective date of the first increase in the OATT rate until November 1, 2005, subject to refund with interest if lower rates are eventually approved. The FERC accepted the two-step increase concept, such that the transmission rates will automatically increase on April 1, 2006, if the SECA revenues cease to be collected, and to the extent that replacement rates are not established. In a separate proceeding, at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present regime may need to be replaced through establishment of regional rates that would compensate AEP, among others, for the regional service provided by high voltage facilities they own that benefit customers throughout PJM. On September 30, 2005, AEP and a nonaffiliated utility (Allegheny Power) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime.

As of September 30, 2005, SECA transition rates have not fully compensated the AEP East companies for their lost T&O revenues. Management is unable to predict whether SECA rates and, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone will be sufficient to replace the SECA transition rate revenues. In addition, we are unable to predict whether the effect of the loss of transmission revenues will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If, (i) the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, or (ii) AEP zonal transmission rates are not sufficiently increased by the FERC after March 31, 2006 to replace the lost T&O/SECA revenues, or (iii) the FERC’s review of our current SECA rate results in a rate reduction which is subject to refund, or (iv) any increase in the AEP East companies’ transmission costs from the loss of transmission revenues are not fully recovered in retail and wholesale rates on a timely basis, or (v) if the FERC does not approve a new rate within PJM, future results of operations, cash flows and financial condition would be adversely affected.

RTO Formation/Integration Costs

Prior to joining PJM, the AEP East companies, with FERC approval, deferred costs incurred to originally form a new RTO (the Alliance) and subsequently to integrate into an existing RTO (PJM) plus carrying costs. In 2004, AEP requested permission to amortize, beginning January 1, 2005, 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 without proposing an amortization period for the $17 million of PJM-billed integration costs in the application. The FERC approved our application and in January 2005, the AEP East companies began amortizing their deferred RTO formation/integration costs not billed by PJM over 15 years and the deferred PJM-billed integration costs over 10 years consistent with a March 8, 2005 requested rate recovery period discussed below. The total amortization related to such costs was $1 million and $3 million in the third quarter and first nine months of 2005, respectively. As of September 30, 2005, the AEP East Companies have $34 million of deferred unamortized RTO formation/integration costs.

On March 8, 2005, AEP and two other utilities jointly filed a request with the FERC to recover their deferred PJM-billed integration costs from all load-serving entities in the PJM RTO over a ten-year period starting January 1, 2005. On May 6, 2005, the FERC issued an order denying the request to recover the amortization of the deferred PJM-billed integration costs from all load-serving entities in the PJM RTO, and instead, ordered the companies to make a Compliance Filing to recover the PJM-billed integration costs solely from the zones of the requesting companies. AEP, together with the other companies, made the Compliance Filing on May 27, 2005. On June 6, 2005, AEP filed a request for rehearing. Subsequently, the FERC approved the compliance rate, and PJM began charging the rate to load serving entities in the AEP zone (and the other companies’ zones), including the AEP East companies on behalf of the load they serve in the AEP zone (about 85% of the total load in the AEP zone). On October 17, 2005, the FERC granted our June 6, 2005 rehearing request and set the following two issues for hearing and settlement discussions and, if necessary, for hearing: (1) whether the PJM OATT is unjust and unreasonable without region-wide recovery of PJM-billed integration costs and (2) a determination of a just and reasonable carrying charge rate on the deferred PJM-billed integration costs. Also, the FERC, in its order, dismissed the May 27, 2005 Compliance Filing as moot. At this time, management is unable to predict the outcome of this proceeding.

On March 31, 2005, we also filed a request for a revised transmission service revenue requirement for the AEP zone of PJM (as discussed above in the “FERC Order on Regional Through and Out Rates” section). Included in the costs reflected in that revenue requirement was the estimated 2005 amortization of our deferred RTO formation/integration costs (other than the deferred PJM-billed integration costs). The AEP East companies will be responsible for paying most of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone. In Ohio, Kentucky and West Virginia, we have made filings to recover the amortization of these costs. I&M is currently subject to a rate freeze.

Until the AEP East Companies can adjust their retail rates to recover the amortization of both RTO deferred costs, results of operations and cash flows will be adversely affected by the amortizations. If the FERC allows AEP to charge the amortization of PJM-billed integration costs throughout the PJM region, it would mitigate any adverse effect from failure to obtain timely recovery in retail rates. If the FERC were to deny the inclusion in the transmission rates of any portion of the amortization of the deferred RTO formation/integration costs it would have an adverse impact on future results of operations and cash flows. If the FERC approves a carrying charge rate that is lower than the carrying charge recognized to date, it could have an adverse effect on future results of operations and cash flows.

Allocation Agreement between AEP East and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East and AEP West companies. The current allocation methodology was established at the time of the AEP-CSW merger and, consistent with the terms of the SIA, on November 1, 2005, we filed a proposed allocation methodology to be used in 2006 and beyond. The proposed allocation methodology 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 accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT accruing to the benefit of the AEP West companies. Previously, the SIA allocation provided for sharing of all such margins among both AEP East and AEP West companies. The allocation ultimately approved by the FERC may differ from the one we proposed. We requested that the new methodology be effective on a prospective basis after the FERC’s order. The impact on future results of operations and cash flows will depend upon the methodology approved by the FERC and the level of future margins by region. Our total trading and marketing margins are unaffected by the allocation methodology. However, because trading and marketing activities are not treated the same for rate-making purposes in each state retail jurisdiction and the timing of inclusion of the margins in rates may differ, our results of operations and cash flow could be affected. Management is unable to predict the ultimate effect of this filing on our future results of operations and cash flows.

4.CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

We are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in our 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring and update the 2004 Annual Report.

OHIO RESTRUCTURING

On January 26, 2005, the PUCO approved Rate Stabilization Plans (RSP) for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the need for additional revenues for specified costs. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM-related administrative costs and congestion costs net of firm transmission rights (FTR) revenue from 2004 and 2005 related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $6 million for CSPCo and $35 million for OPCo in the first nine months of 2005 as a result of implementing this provision of the RSP. Of these amounts, approximately $8 million for CSPCo and $21 million for OPCo relate to 2004 environmental carrying costs and RTO costs. The decline in the third quarter of 2005 reflects the effect of substantial increases in FTR revenues which offset administrative and congestion costs.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding its approval of the RSP. On March 23, 2005, the PUCO denied all applications for rehearing. In the second quarter of 2005, two intervenors filed separate appeals to the Ohio Supreme Court. One of those appeals has been withdrawn. The remaining appeal challenges the RSP and also argues that there is no POLR obligation in Ohio, and therefore CSPCo and OPCo are not entitled to recover any POLR charges.  If the Ohio Supreme Court reverses the PUCO's authorization of the POLR charge, CSPCo and OPCo's 2005 earnings will be adversely affected.  In a nonaffiliated utility's proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, and therefore, CSPCo and OPCo have argued that they can recover the POLR charge.  In addition, if the RSP order is determined on appeal to be illegal under the restructuring legislation, it would have an adverse effect on results of operations, cash flows and possibly financial condition. Although we believe that the RSP plan is legal and we intend to defend vigorously the PUCO’s order, we cannot predict the ultimate outcome of the pending litigation.

On September 28, 2005, the Ohio companies filed with the PUCO to recover through a Transmission Cost Recovery Rider, beginning January 1, 2006, approximately $5 million for CSPCo and $7 million for OPCo of projected 2006 net costs incurred as a result of joining PJM. In addition, the Ohio companies requested to practice over/under-recovery deferral accounting for any differences between the revenues collected starting January 1, 2006 and the actual costs incurred. If the PUCO determines that any of the requested net incremental RTO costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, we are deferring customer choice implementation costs and related carrying costs in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. Through September 30, 2005, we incurred $86 million of such costs, and accordingly, we deferred $46 million of such costs for probable future recovery in distribution rates. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. Pursuant to the RSP, recovery of these amounts will be deferred until the next distribution rate filing to change rates after December 31, 2008. We believe that the deferred customer choice implementation costs were prudently incurred to implement and effect customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows.

TEXAS RESTRUCTURING

The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items including carrying costs in TCC’s true-up filing under the Texas Restructuring Legislation. The PUCT approved TCC’s request to file its True-up Proceeding after the sales of its interest in STP, with only the ownership interest in Oklaunion remaining to be settled. On May 19, 2005, the sales of TCC’s interest in STP closed. On May 27, 2005, TCC filed its true-up request seeking recovery of $2.4 billion of net stranded costs and other true-up items which it believes the Texas Restructuring Legislation allows, including unrecorded equity carrying costs, which are not recognizable until collected, and unrecorded carrying costs on amounts previously provided for totaling approximately $440 million. The filing does not include a deduction for a $238 million provision for a probable depreciation adjustment recorded in December 2004 based on a methodology approved by the PUCT in a nonaffiliated utility’s true-up order. Although it was determined that it was probable that the PUCT would make this adjustment in TCC’s proceeding and the adjustment was provided for, we do not believe the adjustment is appropriate and will litigate the issue, if necessary. As a result, the filing was not reduced by the $238 million provision for probable loss. These items account for the majority of the difference between the $2.4 billion filing and the $1.6 billion net regulatory asset detailed below. As discussed below, the PUCT Staff and various intervenors filed testimony recommending that TCC’s $2.4 billion requested recovery amount be reduced, with certain parties asserting that TCC does not have any stranded costs. The PUCT hearing began on September 26, 2005 and concluded on October 4, 2005. It is anticipated that the PUCT will issue a final order in the fourth quarter of 2005.

The Components of TCC’s Recorded Net True-up Regulatory Asset (inclusive of provisions) recorded as of September 30, 2005 and December 31, 2004 are:

	TCC
	September 30, 2005			December 31, 2004
	(in millions)
Stranded Generation Plant Costs	$	892		$	897
Net Generation-related Regulatory Asset		249			249
Excess Earnings		(49	)		(10	)
Net Stranded Generation Costs		1,092			1,136
Carrying Costs on Stranded Generation Plant Costs		218			225
Net Stranded Generation Costs Designated for Securitization		1,310			1,361
Wholesale Capacity Auction True-up		483			483
Carrying Costs on Wholesale Capacity Auction True-up		114			77
Retail Clawback		(61	)		(61	)
Deferred Over-recovered Fuel Balance		(210	)		(212	)
Net Other Recoverable True-up Amounts		326			287
Total Recorded Net True-up Regulatory Asset	$	1,636		$	1,648

The Components of TNC’s Net True-up Regulatory Liability as of September 30, 2005 and December 31, 2004 are:

	TNC
	September 30, 2005			December 31, 2004
	(in millions)
Retail Clawback	$	(14	)	$	(14	)
Deferred Over-recovered Fuel Balance		(5	)		(4	)
Total Recorded Net True-up Regulatory Liability	$	(19	)	$	(18	)

Deferred Investment Tax Credits Included in Stranded Generation Plant Costs

In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that net stranded generation costs should be reduced by the present value of deferred investment tax credits (ITC) and excess deferred federal income taxes applicable to generating assets. The nonaffiliated utility testified in its True-up Proceeding that acceleration of the sharing of deferred ITC with customers may be a violation of the Internal Revenue Code’s normalization provisions. Management agrees with the nonaffiliated utility that the PUCT’s acceleration of deferred ITC and excess deferred federal income taxes may be a violation of the normalization provisions. As a result, management has not included as a reduction of its net stranded generation costs the present value of TCC’s generation-related deferred ITC of $70 million and the present value of excess deferred federal income taxes of $6 million in its true-up filing. Although deferred ITC and excess deferred federal income taxes are recorded as a liability on TCC’s books, such amounts also are not reflected as a reduction of TCC’s recorded net stranded generation costs regulatory asset in the above table since to do so may be a normalization violation. The Internal Revenue Service (IRS) has issued proposed regulations that would make an exception to the normalization provisions for a utility whose electric generation assets cease to be public utility property. Since the IRS has not issued final regulations, TCC filed a request for a private letter ruling from the IRS on June 28, 2005 to determine whether the PUCT’s action would result in a normalization violation. A normalization violation could result in the repayment of TCC’s accumulated deferred ITC on all property, not just generation property, which approximates $106 million as of September 30, 2005 and a loss of the ability to elect accelerated tax depreciation in the future. Various parties in TCC’s True-up Proceeding have recommended that the present value of the ITCs and the nominal value of excess deferred federal income taxes applicable to generating assets be utilized to reduce TCC’s requested stranded cost amount. Management is unable to predict how the IRS will rule on the private letter ruling request and whether any PUCT order will adversely affect future results of operations and cash flows.

TCC Fuel Reconciliation

On April 14, 2005, the PUCT ruled that specific energy-only purchased power contracts included a capacity component, which is not recoverable in fuel rates. As a result of this decision, in the first quarter of 2005, TCC recorded a provision for over-recovered fuel of $3 million, inclusive of interest. Reflecting all of the decisions in the final order and the resultant provisions for refund, the deferred over-recovery balance was $210 million as of September 30, 2005, including accrued interest. TCC filed a motion for rehearing on several items which was denied by operation of law on July 18, 2005. TCC appealed the PUCT’s decision to state and federal courts in August 2005. As discussed in the “TNC True-up Proceeding” section below, TNC received a decision from the Federal District Court that the PUCT is preempted by federal law from revising the allocation of system sales margins under the FERC-approved SIA by removing mark-to-market amounts from the East/West allocation base. The same issue was presented in TCC’s final fuel reconciliation proceeding for which TCC has also filed an appeal to the Federal District Court. As with TNC, it is expected that the PUCT will also be preempted by the Federal District Court from reallocating the off-system sales margins under the FERC-approved SIA for TCC. Therefore, the PUCT would have to file a complaint with the FERC to address the TCC allocation issue. We are unable to determine whether the PUCT will appeal the Federal District Court decision or file a complaint with the FERC, and if it does either, whether such appeal or complaint would probably be successful. Pending further clarification, TCC has not yet reversed the $46 million provision for fuel cost over-recovery recorded in 2004. If the PUCT or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between AEP East and AEP West companies.

TCC Carrying Costs on Net True-up Regulatory Assets

TCC continues to accrue carrying costs on its net true-up regulatory asset at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to accumulated deferred federal income taxes (ADFIT) on net stranded costs and other true-up items which was retroactively applied to January 1, 2004. In the first nine months of 2005, TCC accrued carrying costs of $57 million which were partially offset by a first quarter adjustment of $27 million based on this order. The net increase of $30 million in carrying costs is included in Other Income on the accompanying Condensed Consolidated Statements of Income in the first nine months of 2005 inclusive of $15 million of carrying costs accrued in the third quarter of 2005.

In an April 2005 open meeting regarding another nonaffiliated utility’s True-up Proceeding, the PUCT determined that the filed cost of debt did not establish a Weighted Average Cost of Capital (WACC) rate or an embedded debt rate because that utility’s Unbundled Cost of Service (UCOS) case was based on a settlement that did not specifically address the debt rate. As a result, the other utility was required to use a subsequently approved lower debt rate to compute its carrying costs than its filed UCOS rate.

To date, this nonaffiliated utility’s issue has not been raised in TCC’s True-up Proceeding. Alternatively, parties have recommended in TCC’s True-up Proceeding that the PUCT reduce TCC’s carrying cost rate to an amount that ranged from 7.5% to the combined rate that was settled upon in TCC’s wires rate proceeding which included a cost of debt of 5.7%. Management is unable to determine the probable outcome of this matter when, or if, it is adjudicated in TCC’s True-up Proceeding. If the PUCT ultimately determines that a lower cost of debt should be used by TCC to calculate carrying costs on its stranded cost balance, it would have an adverse impact on future results of operations and cash flows. Based upon a range of debt rates from 5.7% to 7.5%, through the third quarter of 2005, such adverse effect ranges from $28 million to $107 million, of which $6 million to $22 million would apply to amounts accrued in 2005.

Through September 30, 2005, TCC has computed carrying costs of $509 million, of which $302 million was recognized as income in 2004 and applied to years prior to 2005. Approximately $57 million was recognized as income in the first nine months of 2005 before the $27 million offsetting adjustment discussed above. The remaining equity component of the carrying costs of $177 million through September 30, 2005 will be recognized in income as collected.

TCC Excess Earnings

At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. In the first nine months of 2005, TCC refunded an additional $9 million reducing its unrefunded excess earnings to $1 million. On July 15, 2005, the PUCT approved a preliminary order in TCC’s True-up Proceeding that instructed TCC to stop refunding the excess earnings and to offset the remaining balance, which was $1 million, against stranded costs. However, on September 23, 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order requiring us to refund excess earnings as determined in TCC’s UCOS proceeding was unlawful under the Texas Restructuring Legislation. As such, TCC recorded a regulatory asset for the future recovery of the $49 million refunded to the REPs and a reduction to stranded costs. See the “Texas Unbundled Cost of Service (UCOS) Appeal” section of Note 3 for further details.

TCC True-up Proceeding

As discussed earlier, TCC made its true-up filing requesting $2.4 billion of stranded costs including the effect of the PUCT’s July 15, 2005 order discontinuing the excess earnings refund as discussed in the “Texas Unbundled Cost of Service (UCOS) Appeal” section of Note 3. During September 2005, various parties and the PUCT staff filed testimony recommending reductions to TCC’s requested stranded cost amount including a recommendation that TCC does not have any stranded costs. Hearings began September 26, 2005 and continued until October 4, 2005. An order is expected in the fourth quarter of 2005. When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge (CTC) in the regulated transmission and distribution (T&D) rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

The nonaffiliated utility’s March 2005 order referred to in the “TCC Carrying Costs on Net True-up Regulatory Assets” section above also provided for the present value of the cost free capital benefits of ADFIT associated with stranded generation costs to be offset against other recoverable true-up amounts when establishing the CTC. TCC estimates its present value ADFIT benefit to be $209 million based on its current net true-up regulatory asset. TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT in the nonaffiliated utility’s order and determined that the projected cash flows from the transition charges were more than sufficient to recover TCC’s recorded net true-up regulatory asset since the equity portion of the carrying costs will not be recorded until collected. As a result, no impairment has been recorded. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in its True-up Proceeding, TCC expects to amortize its total net true-up regulatory asset commensurate with recovery over periods to be established by the PUCT in proceedings subsequent to TCC’s True-up Proceeding.

We believe that our filed request for recovery of $2.4 billion of net stranded costs and other true-up items, inclusive of carrying costs, is recoverable under the Texas Restructuring Legislation. However, after recording certain provisions for probable disallowances from TCC’s final fuel proceeding and nonaffiliated true-up proceedings and adjusting for unrecordable equity carrying costs and carrying costs on the provisions, TCC has a $1.6 billion recorded net true-up regulatory asset, inclusive of carrying costs, at September 30, 2005 that is probable of recovery at this time. However, other parties have contended that all or material amounts of our net stranded costs and/or wholesale capacity auction true-up amounts should not be recovered. To the extent decisions of the PUCT in TCC’s True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated utilities, additional provisions for material disallowances and reductions of the net true-up regulatory asset, including recorded carrying costs, are possible. Such disallowances would have a material adverse effect on future results of operations, cash flows and possibly financial condition.

TNC True-Up Proceeding

In March 2005, the ALJ made certain recommendations regarding the deferred fuel balance resulting in an additional provision for refund of $1 million, which results in an over-recovery amount of $5 million. In May 2005, the PUCT issued a favorable order, adopting the ALJ’s recommendation regarding the application of interest to the post-reconciliation period off-system sales margins, but did not adopt the ALJ’s excess earnings recommendation. The PUCT required that excess earnings be addressed in the CTC filing that was made on August 5, 2005. Based upon the ruling regarding the application of interest on post-reconciliation off-system sales margins, TNC adjusted its deferred over-recovered fuel balance during the second quarter of 2005.

In 2004, TNC appealed to the state and federal courts the PUCT’s order in its final fuel reconciliation covering the period from July 2000 through December 31, 2001 in which the PUCT disallowed approximately $30 million of fuel costs. On September 9, 2005, the Texas District Court in Travis County issued a ruling which upheld in all respects the PUCT’s decisions concerning issues appealed to that court by all parties. TNC has filed notice of appeal of that decision. TNC will continue to pursue vigorously the state appeals, but cannot predict their outcome. TNC believes it has fully provided for the PUCT final fuel order.

On September 29, 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing their ruling regarding the allocation of off-system sales margins. The impact of the reallocation resulted in an over-recovery amount of $8 million. The PUCT must appeal the Federal Court decision or file a complaint at FERC, if it wishes to challenge this ruling. We are unable to predict whether the PUCT will appeal the Federal District Court decision and/or file a complaint at FERC, nor are we able to predict whether such actions would be successful. Pending further clarification, TNC has not yet reversed its related $8 million provision for fuel over-recovery. If the PUCT or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between AEP East and AEP West companies.

5.COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within our 2004 Annual Report, we continue to be involved in various legal matters. The 2004 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since our disclosure in the 2004 Annual Report. The matters discussed in the 2004 Annual Report without significant changes in status since year-end include, but are not limited to, (1) nuclear matters, (2) construction and commitments, (3) potential uninsured losses, (4) shareholder lawsuits, (5) coal transportation dispute, and (6) FERC long-term contracts. See disclosure below for significant matters with changes in status subsequent to the disclosure made in our 2004 Annual Report.

Environmental

Federal EPA Complaint and Notice of Violation

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review 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 court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded.

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. The CAA authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). 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.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV were already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaint and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern states each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. The Northeastern states’ complaint has been assigned to the same judge in the U.S. District Court for the Southern District of Ohio. AEP filed an answer to the Northeastern states’ complaint and to the Federal EPA’s complaint, denying the allegations and stating its defenses.

In August 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, a nonaffiliated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not “routine” maintenance, repair and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any nonroutine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A settlement between Ohio Edison, the Federal EPA and other parties to the litigation will avoid further litigation and result in expenditures at the plant.

Other utility enforcement actions and current regulatory activities are discussed in detail in the Commitments and Contingencies note in the 2004 Annual Report. However, since the issuance of the August 2003 decision against Ohio Edison, several other courts have considered the issues of what constitutes “routine maintenance, repair, and replacement” for utility units, and whether increased hours of operation are the measure of an emissions increase. Each court has reached a conclusion that differs markedly from the decision in the Ohio Edison case. These decisions include the District Court opinion in the Duke Energy case issued later in August 2003, the District Court opinion in Alabama Power case issued on June 3, 2005, and the Fourth Circuit Court of Appeals opinion affirming the dismissal of all claims against Duke Energy issued on June 15, 2005. In addition, on June 10, 2005, the Administrator of the Federal EPA rejected all of the petitions for reconsideration of the October 2003 “equipment replacement provision” rule that defines “routine replacement” under the new source review program to include the same types of activities challenged in the pending enforcement actions. Management therefore believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in our case also vary widely from plant to plant.

In June 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which our subsidiaries are members, to reopen petitions for review of the 1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA claims in our case and other related cases. On June 24, 2005, the United States Court of Appeals for the District of Columbia Circuit issued a decision affirming in part the new source review reform regulations adopted by the Federal EPA in December 2002. The court upheld the Federal EPA’s decision to apply actual-to-future actual emissions and includes tests, utilizing a five-year look back period to establish actual baseline emissions for utilities and a ten-year period for other sources. This excludes increased emissions unrelated to a physical change from the projected emissions, and includes emissions associated with demand growth. The court vacated the Federal EPA’s adoption of a broad pollution control project exclusion that includes projects that result in a significant collateral emissions increase, and the “clean unit” applicability test, and remanded certain recordkeeping requirements to the Federal EPA. The court expressed no opinion on the conclusion reached by the Duke Energy court, and found that such issues could be better addressed in a specific factual context.

On August 30, 2005, the United States Court of Appeals for the Fourth Circuit denied the petitions for rehearing filed by the United States and other appellants in the Duke Energy case. On October 13, 2005, the Administrator of the Federal EPA signed a proposed rule that would adopt a test for determining when an emissions increase results from a change at an existing electric utility generating unit under the federal NSR programs that would be consistent with the test adopted and applied by the Fourth Circuit in the Duke Energy case. This would be based on maximum hourly emissions before and after the change. The Federal EPA is also seeking comments on two alternative formulations of the emission increase test.  We have filed a Motion in the NSR litigation that asks the Court, among other things, to dismiss the NSR cases on due process grounds based on the statements and admissions the Federal EPA made in promulgating the proposed rule.

We are unable to estimate the loss or range of loss related to any contingent liability 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 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.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005.

On July 19, 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. On April 11, 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 and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 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 references to a specific heat input value for each Welsh unit.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of approximately $6 thousand against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.

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, financial condition or cash flows.

Carbon Dioxide Public Nuisance Claims

In July 2004, attorneys general from eight states and the corporation counsel for the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions alleged that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. A notice of appeal to the Second Circuit Court of Appeals has been filed on behalf of all plaintiffs. A briefing schedule has not been established.

Operational

Construction

The AEP System has substantial construction activity scheduled to support its operations. Aggregate construction expenditures for 2006 for consolidated operations are estimated at $3.3 billion, including amounts for proposed environmental rules. 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.

TEM Litigation (Power Generation Facility)

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to us. We have subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 220 MW through May 31, 2006 and 270 MW thereafter). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000, (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

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.) has provided a limited guaranty.

On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the New York federal court that the PPA was terminated and (iii) would be pursuing against TEM, and SUEZ-TRACTEBEL S.A. under the guaranty, damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that TEM had breached the contract and awarded us damages of $123 million plus pre-judgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. We asked the court to modify the judgment to (i) award a termination payment to us under the terms of the PPA; (ii) grant our attorneys’ fees; and (iii) render judgment against SUEZ-TRACTEBEL, S.A. on the guaranty. TEM sought reduction of the damages awarded by the court for replacement electric power products made available by OPCo under the PPA.

In September 2005, TEM posted a letter of credit for $142 million as security pending appeal of the judgment. Both parties have filed Notices of Appeal with the United States Court of Appeals for the Second Circuit. If the PPA is deemed terminated or found to be unenforceable by the court ultimately deciding the case, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM.

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

In May 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and filed a petition for review of this Initial Decision, which the SEC granted.

We believe the repeal of PUHCA will end litigation challenging our merger with CSW. All parties to the proceeding have filed motions with the SEC supporting dismissal of the proceeding upon repeal of the PUHCA in February 2006.

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 grants 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 also 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. In July 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 reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed 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 filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to defend vigorously against BOA’s claims.

In October 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 reservoir 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 reservoir 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. On April 6, 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.

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 have objected to Enron’s attempted rejection of these agreements and have filed an adversary proceeding contesting Enron’s right to reject these agreements.

In January 2005, we sold a 98% limited partner interest in HPL. We have indemnified the buyer of the 98% interest in 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 is 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 September 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. The parties are currently in nonbinding, court-sponsored mediation.

In December 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 seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding, court-sponsored mediation.

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 are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows and financial condition.

Natural Gas Markets Lawsuits

In November 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 intent to affect the market price of natural gas and electricity. AEP has been dismissed from the case. The plaintiff had stated an intention to amend the complaint to add an AEP subsidiary as a defendant. The plaintiff amended the complaint but did not name any other AEP company as a defendant. A number of similar cases were filed in California. We were named as a defendant in only one of those cases, the Benscheidt case. However, the plaintiffs in a number of those cases filed a consolidated complaint, naming us as a defendant. In addition, a number of other cases have been 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 had been transferred to the United States District Court for the District of Nevada but were subsequently remanded to California state court. In April 2005, the judge in Nevada dismissed one of the remaining cases in which AEP was a defendant on the basis of the filed rate doctrine. We will continue to defend vigorously each case where an AEP company is a defendant.

Cornerstone Lawsuit

In the third quarter of 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 in the same court against a number of companies including AEP and AEPES making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. In December 2003, the Court issued its initial Pretrial Order consolidating all related cases, appointing co-lead counsel and providing for the filing of an amended consolidated complaint. In January 2004, plaintiffs filed an amended consolidated complaint. The defendants filed a motion to dismiss the complaint which the Court denied in September 2004. Discovery is continuing in the case with a closing date of December 23, 2005. In October 2005, the court granted the plaintiffs motion for class certification. The defendants have filed a petition for leave to appeal this decision. Summary judgment motions are due in January 2006. We intend to continue to defend vigorously against these claims.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against us and four of our subsidiaries, ERCOT and a number of nonaffiliated energy companies including TXU, CenterPoint, Texas Genco, Reliant, TECO and Tractebel. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to their fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. In June 2004, the Court dismissed all claims against the AEP companies. TCE appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. The Fifth Circuit issued its decision in June 2005 and affirmed the lower court’s decision. TCE filed a Petition for Writ of Certiorari with the United States Surpreme Court on October 14, 2005. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit against the same defendants and others. Trial is scheduled in the Utility Choice/Cirro Energy case for April 2006. On October 18, 2005, the U.S. District Court heard oral arguments on our Motion to Dismiss. We intend to continue to defend vigorously against the allegations in these cases.

Bank of Montreal Claim

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals with us. In April 2003, we filed a lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had acted contrary to the appropriate trading contract and industry practice in terminating the contract and calculating termination and liquidation amounts. We claimed that BOM owed us at least $41 million related to previously recorded receivables on which we held approximately $20 million of credit collateral. In September 2005, we reached a settlement, subject to a confidentiality clause, with BOM without material impact on results of operations or financial condition.

Ontario Litigation

In June 2005, we were named as one of 21 defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. We have not been served with the lawsuit. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operation, have emitted NO_x, SO₂ and particulate matter that have harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $50 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. We believe we have meritorious defenses to this action and intend to defend vigorously against it.

6.GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to 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 have entered into standby letters of credit (LOC) with third parties. These LOCs generally 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. We issued all of these LOCs in our ordinary course of business. At September 30, 2005, the maximum future payments for all the LOCs were approximately $327 million with maturities ranging from November 2005 to April 2007. As the parent of the various subsidiaries that have issued these LOCs, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these LOCs are drawn.

GUARANTEES OF THIRD-PARTY OBLIGATIONS

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $54 million with maturity dates ranging from February 2007 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide 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 a third-party miner. At September 30, 2005, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

INDEMNIFICATIONS AND OTHER GUARANTEES

Contracts

We entered 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. We cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events. In 2004 and the first nine months of 2005, we entered into several sale agreements. The status of certain sale agreements is discussed in Note 7. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $2.2 billion. 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 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, we 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 September 30, 2005, the maximum potential loss for this lease agreement was approximately $47 million ($31 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms for a maximum of twenty years. We intend to renew the lease for the full twenty 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. 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 term from approximately 86% to 77% of the projected fair market value of the equipment. At September 30, 2005, 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. AEP has other railcar lease arrangements that do not utilize this type of structure.

7.ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS, ASSET IMPAIRMENTS AND ASSETS HELD FOR SALE

ACQUISITIONS

Ceredo Generating Station (Utility Operations segment)

In August 2005, APCo signed a purchase and sale agreement with Reliant Energy for the purchase of a 505 MW plant located near Ceredo, West Virginia for $100 million. This transaction is expected to be completed no later than the first quarter of 2006.

Waterford Plant (Utility Operations segment)

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford, Ohio. 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, which includes approximately 29,000 customers. On August 2, 2005, we agreed to terms of a transaction, which includes the transfer of Monongahela Power’s Ohio customer base and the assets that serve those customers to CSPCo for an estimated sales price of approximately $45 million. The sale price will be adjusted based on book values of the acquired assets and liabilities at the closing date. In addition, CSPCo will pay $10 million to compensate Monongahela Power for its termination of certain generation cost recovery litigation in Ohio. Hearings at the PUCO were held in September 2005 and we anticipate the purchase, subject to regulatory approval, to close late in the fourth quarter of 2005. Also included in the proposed transaction is 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.

DISPOSITIONS

Houston Pipe Line Company (HPL) (Investments - Gas Operations segment)

In January 2005, we sold a 98% controlling 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. We retained a 2% ownership interest in HPL and provide certain transitional administrative services to the buyer. Although the assets have been 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 have deferred the excess of the sales price over the carrying cost of the net assets transferred as a deferred gain of $373 million as of September 30, 2005, which is reflected in Deferred Credits and Other on our accompanying Condensed Consolidated Balance Sheets and is subject to further purchase price true-up adjustments as defined in the contract. We provided an indemnity in an amount up to the purchase price to the purchaser for damages, if any, arising from litigation with BOA and a resulting inability to use the cushion gas (see “Enron Bankruptcy - Right to use of cushion gas agreements” section of Note 5). 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, the cushion gas arrangement and our 2% ownership interest.

We also have a put option expiring in 2006, which allows us to sell our remaining 2% interest to the buyer for approximately $16 million.

Pacific Hydro Limited (Investments - Other segment)

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.

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 AEP and Centrica 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.

In March 2005, AEP and Centrica entered into a series of agreements resulting in the resolution of open issues related to the sale and the disputed ESM payments for 2003 and 2004. Also in March 2005, we received payments related to the ESM payments of $45 million and $70 million for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in the first quarter of 2005, which is reflected in Other Income on our accompanying Condensed Consolidated Statements of Income. The ESM payments are contingent on Centrica’s future operating results and are capped at $70 million and $20 million for 2005 and 2006, respectively. Any shortfall below the potential $70 million for 2005 will be added to the 2006 cap.

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 an unrelated party. By May 2004, we received notice from the two nonaffiliated co-owners of the Oklaunion Power Station, 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 our nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. These agreements are currently being challenged in Dallas County, Texas State District Court by the unrelated party with which we entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of the unrelated party on October 10, 2005. TCC and the other nonaffiliated co-owners filed an appeal to the Fifth State Court of Appeals in Dallas. Oral argument has been requested but no date has been set. Briefing is scheduled to be completed by November 17, 2005. We cannot predict when these issues will be resolved. We do not expect the sale to have a significant effect on our future results of operations. TCC’s assets and liabilities related to the Oklaunion Power Station have been classified as Assets Held for Sale and Liabilities Held for Sale, respectively, in our Condensed Consolidated Balance Sheets at September 30, 2005 and December 31, 2004. 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.

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 does not have cash flows that can be clearly distinguished operationally. The plant also did 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.

DISCONTINUED OPERATIONS

Certain of our operations were determined to be discontinued operations and have been classified as such for all periods presented. Results of operations of these businesses have been reclassified for the three and nine-month periods ended September 30, 2005 and 2004 as shown in the following tables:

Three months ended September 30, 2005 and 2004:

	SEEBOARD (a)		UK Operations (b)		Total
	(in millions)
2005 Revenue	$	-	$	-	$	-
2005 Pretax Income		13		-		13
2005 Income After tax		20		2		22

	Pushan Power Plant		LIG (c)			UK Operations			Total
	(in millions)
2004 Revenue	$	-	$	1		$	37		$	38
2004 Pretax Income (Loss)		-		(13	)		255			242
2004 Income (Loss) After tax		1		(3	)		120	(d)		118

Nine months ended September 30, 2005 and 2004:

	SEEBOARD (a)		UK Operations (b)			Total
	(in millions)
2005 Revenue	$	-	$	-		$	-
2005 Pretax Income (Loss)		13		(8	)		5
2005 Income (Loss) After tax		29		(3	)		26

	Pushan Power Plant		LIG (c)			UK Operations			Total
	(in millions)
2004 Revenue	$	10	$	165		$	112		$	287
2004 Pretax Income (Loss)		9		(12	)		156			153
2004 Income (Loss) After tax		6		(2	)		56	(e)		60

(a) Relates to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD.

(b) Relates to purchase price true-up adjustments and tax adjustments from the sale of UK Operations.

(c) Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub LLC.

(d) Earnings per share related to the UK Operations was $0.30.

(e) Earnings per share related to the UK Operations was $0.14.

For the nine months ended September 30, 2004, the net decrease in cash and cash equivalents of discontinued operations was $4 million, primarily from the cash flows from operating activities of the discontinued operations.

ASSET IMPAIRMENTS

Conesville Units 1 and 2 (Utility Operations segment)

In the third quarter of 2005, following an extensive review of the commercial viability of CSPCo’s Conesville Units 1 and 2, management committed to a plan to retire these units 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.

A pretax charge of approximately $39 million was recognized in the third quarter of 2005 related to our decision to retire the units. The impairment amount is classified as Asset Impairments and Other Related Charges in our Condensed Consolidated Statements of Income.

Compresion Bajio S de R.L. de C.V. (Investments - Other Segment)

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. 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 which is under review. The impairment amount is classified as Investment Value Losses in our Condensed Consolidated Statements of Income.

ASSETS HELD FOR SALE

The assets and liabilities of the entities that were classified as held for sale at September 30, 2005 and December 31, 2004 are as follows:

	Texas Plants
	September 30, 2005		December 31, 2004
Assets:	(in millions)
Other Current Assets	$	1	$	24
Property, Plant and Equipment, Net		46		413
Regulatory Assets		-		48
Nuclear Decommissioning Trust Fund		-		143
Total Assets Held for Sale	$	47	$	628
Liabilities:
Regulatory Liabilities	$	2	$	1
Asset Retirement Obligations		-		249
Total Liabilities Held for Sale	$	2	$	250

8. BENEFIT PLANS

Components of Net Periodic Benefit Costs

The following table provides the components of our net periodic benefit cost for the following plans for the three and nine months ended September 30, 2005 and 2004:

Three Months Ended September 30, 2005 and 2004:	Pension Plans						Other Postretirement Benefit Plans
	2005			2004			2005			2004
	(in millions)
Service Cost	$	23		$	21		$	10		$	10
Interest Cost		57			57			26			29
Expected (Return) on Plan Assets		(77	)		(72	)		(23	)		(20	)
Amortization of Transition (Asset) Obligation		(1	)		-			6			7
Amortization of Prior Service Costs		-			(1	)		-			-
Amortization of Net Actuarial Loss		13			5			5			8
Net Periodic Benefit Cost	$	15		$	10		$	24		$	34

Nine Months Ended September 30, 2005 and 2004:	Pension Plans						Other Postretirement Benefit Plans
	2005			2004			2005			2004
	(in millions)
Service Cost	$	69		$	64		$	31		$	30
Interest Cost		169			169			79			87
Expected (Return) on Plan Assets		(232	)		(216	)		(68	)		(60	)
Amortization of Transition (Asset) Obligation		(1	)		1			20			21
Amortization of Prior Service Costs		-			(1	)		-			-
Amortization of Net Actuarial Loss		40			13			19			26
Net Periodic Benefit Cost	$	45		$	30		$	81		$	104

9.BUSINESS SEGMENTS

As outlined in our 2004 Annual Report, our business strategy and the core of our business are to focus on domestic electric utility operations. Our previous decision that we no longer sought business interests outside of the footprint of our domestic core utility assets led us to embark on a divestiture of such noncore assets. Major asset divestitures included the sale in 2004 of two generating plants in the UK, LIG and Jefferson Island Storage & Hub, and the sale in January 2005 of a 98% interest in the HPL assets. Consequently, the significance of our three Investments segments is declining.

Our segments and their related business activities are as follows:

Utility Operations

· Domestic generation of electricity for sale to retail and wholesale customers.

· Domestic electricity transmission and distribution.

Investments - Gas Operations

·	Gas pipeline and storage services.
·	Gas marketing and risk management activities.
	Operations of LIG, including Jefferson Island Storage, were classified as Discontinued Operations during 2003 and were sold during 2004. We sold our 98% interest in HPL during the first quarter of 2005.

Investments - UK Operations

·	International generation of electricity for sale to wholesale customers.
·	Coal procurement and transportation to our plants.
	UK Operations were classified as Discontinued Operations during 2003 and were sold during 2004.

Investments - Other

·	Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.
	Four IPPs were sold during 2004.

With the sale of a 98% controlling interest in HPL during January 2005, we have substantially completed planned disposals of all significant noncore assets. Accordingly, effective with the quarter ended March 31, 2005, certain subsidiaries representing shared service functions and costs were reclassified to Utility Operations and Investments - Other from either Investments - Other or All Other. Such reclassifications were deemed necessary given the remaining compositions of the individual segments and the nature of the shared service functions and costs.

The tables below present segment income statement information for the three and nine months ended September 30, 2005 and 2004 and balance sheet information as of September 30, 2005 and December 31, 2004. These amounts include certain estimates and allocations where necessary. Prior year amounts have been reclassified to conform to the current year’s presentation.

			Investments
Three Months Ended	Utility Operations		Gas Operations			UK Operations		Other		All Other (a)			Reconciling Adjustments			Consolidated
September 30, 2005	(in millions)
Revenues from:
External Customers	$	3,132	$	73		$	-	$	95	$	-		$	-		$	3,300
Other Operating Segments		82		(77	)		-		2		1			(8	)		-
Total Revenues	$	3,214	$	(4	)	$	-	$	97	$	1		$	(8	)	$	3,300
Income (Loss) Before Discontinued    Operations	$	352	$	(10	)	$	-	$	28	$	(5	)	$	-		$	365
Discontinued Operations, Net of Tax		-		-			2		20		-			-			22
Net Income (Loss)	$	352	$	(10	)	$	2	$	48	$	(5	)	$	-		$	387
Three Months Ended September 30, 2004
Revenues from:
External Customers	$	2,920	$	760		$	-	$	101	$	-		$	-		$	3,781
Other Operating Segments		30		(16	)		-		5		1			(20	)		-
Total Revenues	$	2,950	$	744		$	-	$	106	$	1		$	(20	)	$	3,781
Income (Loss) Before Discontinued   Operations	$	359	$	(27	)	$	-	$	89	$	(9	)	$	-		$	412
Discontinued Operations, Net of Tax		-		(3	)		120		1		-			-			118
Net Income (Loss)	$	359	$	(30	)	$	120	$	90	$	(9	)	$	-		$	530

			Investments
Nine Months Ended	Utility Operations		Gas Operations			UK Operations			Other		All Other (a)			Reconciling Adjustments			Consolidated
September 30, 2005	(in millions)
Revenues from:
External Customers	$	8,318	$	449		$	-		$	289	$	-		$	-		$	9,056
Other Operating Segments		178		(167	)		-			8		2			(21	)		-
Total Revenues	$	8,496	$	282		$	-		$	297	$	2		$	(21	)	$	9,056
Income (Loss) Before Discontinued    Operations	$	952	$	(2	)	$	-		$	32	$	(45	)	$	-		$	937
Discontinued Operations, Net of Tax		-		-			(3	)		29		-			-			26
Net Income (Loss)	$	952	$	(2	)	$	(3	)	$	61	$	(45	)	$	-		$	963
Nine Months Ended September 30, 2004
Revenues from:
External Customers	$	8,009	$	2,191		$	-		$	356	$	-		$	-		$	10,556
Other Operating Segments		88		23			-			32		5			(148	)		-
Total Revenues	$	8,097	$	2,214		$	-		$	388	$	5		$	(148	)	$	10,556
Income (Loss) Before Discontinued   Operations	$	847	$	(41	)	$	-		$	89	$	(43	)	$	-		$	852
Discontinued Operations, Net of Tax		-		(2	)		56			6		-			-			60
Net Income (Loss)	$	847	$	(43	)	$	56		$	95	$	(43	)	$	-		$	912

			Investments
	Utility Operations		Gas Operations		UK Operations			Other		All Other		Reconciling Adjustments (b)			Consolidated
As of September 30, 2005	(in millions)
Total Property, Plant and Equipment	$	37,361	$	2	$	-		$	833	$	3	$	-		$	38,199
Accumulated Depreciation and Amortization		14,575		1		-			107		1		-			14,684
Total Property, Plant and Equipment - Net	$	22,786	$	1	$	-		$	726	$	2	$	-		$	23,515
Total Assets	$	33,441	$	1,554	$	609	(c)	$	488	$	9,311	$	(9,447	)	$	35,956
Assets Held for Sale		47		-		-			-		-		-			47

As of December 31, 2004
Total Property, Plant and Equipment	$	36,006	$	445	$	-		$	832	$	3	$	-		$	37,286
Accumulated Depreciation and Amortization		14,355		43		-			86		1		-			14,485
Total Property, Plant and Equipment - Net	$	21,651	$	402	$	-		$	746	$	2	$	-		$	22,801
Total Assets	$	32,175	$	1,789	$	221	(d)	$	2,071	$	8,093	$	(9,686	)	$	34,663
Assets Held for Sale		628		-		-			-		-		-			628

(a)	All Other includes interest, litigation and other miscellaneous parent company expenses.
(b)	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.
(c)	Total Assets of $609 million for the Investments-UK Operations segment include $590 million in affiliated accounts receivable related to federal income taxes that are eliminated in consolidation. The majority of the remaining $19 million in assets represents cash equivalents along with value-added tax receivables.
(d)	Total Assets of $221 million for the Investments-UK Operations segment include $124 million in affiliated accounts receivable that are eliminated in consolidation. The majority of the remaining $97 million in assets represents cash equivalents and third party receivables.

10.  INCOME TAXES

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 $81 million that are not expected to reverse during the phase-out. We recorded $4 million as a reduction to Income Taxes and, for the Ohio companies, established a regulatory liability for $57 million pending rate-making treatment in Ohio. 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 $20 million.

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 will be phased-in over a five-year period beginning July 1, 2005 at 23% of the full 0.26% rate. The increase in Taxes Other than Income Taxes for 2005 is expected to be $2 million.

Other tax reforms effective July 1, 2005 include a reduction of the sales and use tax from 6.0% to 5.5%, the phase-out of tangible personal property taxes for our nonutility businesses, the elimination of the 10% rollback in real estate taxes and the increase in the premiums tax on insurance policies; all of which will not have a material impact on future results of operations and cash flows.

11.  FINANCING ACTIVITIES

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2005 are shown in the tables below.

Company	Type of Debt	Principal Amount			Interest Rate	Due Date
		(in millions)
Issuances:
AEP	Senior Unsecured Notes	$	345		4.709%	2007
APCo	Senior Unsecured Notes		200		4.95%	2015
APCo	Senior Unsecured Notes		150		4.40%	2010
APCo	Senior Unsecured Notes		250		5.00%	2017
APCo	Senior Unsecured Notes		250		5.80%	2035
OPCo	Installment Purchase Contracts		54		Variable	2029
OPCo	Installment Purchase Contracts		164		Variable	2028
OPCo	Installment Purchase Contracts		50		Variable	2014
OPCo	Installment Purchase Contracts		50		Variable	2016
OPCo	Installment Purchase Contracts		35		Variable	2022
PSO	Senior Unsecured Notes		75		4.70%	2011
SWEPCo	Senior Unsecured Notes		150		4.90%	2015
SWEPCo	Notes Payable		6		Variable	2006
TCC	Installment Purchase Contracts		162		Variable	2030
TCC	Installment Purchase Contracts		120		Variable	2028
Non-Registrant:
AEP Subsidiary	Notes Payable		6		Variable	2009
Total Issuances		$	2,067	(a)

The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions.

(a) Amount indicated on statement of cash flows of $2,045 million is net of issuance costs and unamortized premium or discount.

Company	Type of Debt	Principal Amount			Interest Rate	Due Date
		(in millions)
Retirements and  Principal Payments:
AEP	Senior Unsecured Notes	$	550		6.125%	2006
AEP	Senior Unsecured Notes		345		5.75%	2007
AEP	Other Debt		9		Variable	2007
AEP and Subsidiaries	Other		18	(b)	Variable	Various
APCo	First Mortgage Bonds		50		8.00%	2005
APCo	First Mortgage Bonds		30		6.89%	2005
APCo	First Mortgage Bonds		45		8.00%	2025
APCo	Senior Unsecured Notes		450		4.80%	2005
OPCo	Installment Purchase Contracts		102		6.375%	2029
OPCo	Installment Purchase Contracts		80		Variable	2028
OPCo	Installment Purchase Contracts		36		Variable	2029
OPCo	Installment Purchase Contracts		50		5.45%	2014
OPCo	Installment Purchase Contracts		50		5.45%	2016
OPCo	Installment Purchase Contracts		35		5.90%	2022
OPCo	Notes Payable		4		6.81%	2008
OPCo	Notes Payable		6		6.27%	2009
PSO	First Mortgage Bonds		50		6.50%	2005
SWEPCo	Senior Unsecured Notes		200		4.50%	2005
SWEPCo	Notes Payable		5		4.47%	2011
SWEPCo	Notes Payable		3		Variable	2008
TCC	Senior Unsecured Notes		150		3.00%	2005
TCC	Senior Unsecured Notes		100		Variable	2005
TCC	First Mortgage Bonds		66		6.625%	2005
TCC	Installment Purchase Contracts		120		6.00%	2028
TCC	Securitization Bonds		29		3.54%	2005
TCC	Securitization Bonds		21		5.01%	2008
Non-Registrant:
AEP Subsidiaries	Notes Payable		12		Variable	Various
Total Retirements		$	2,616	(c)

(b)	Amount reflects mark-to-market of risk management contracts related to long-term debt.
(c)	The cash used for retirement of long-term debt indicated on statement of cash flows of $2,599 million does not include $17 million related to the mark-to-market of risk management contracts.

Preferred Stock Redemption

In January 2005, the following outstanding shares of preferred stock were redeemed:

Company	Series	Number of Shares Redeemed	Amount
			(in millions)
I&M	5.900%	132,000	$	13
I&M	6.250%	192,500		19
I&M	6.875%	157,500		16
I&M	6.300%	132,450		13
OPCo	5.900%	50,000		5
			$	66

Common Stock Repurchase

In March 2005, we repurchased 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 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.

Remarketing of Senior Notes

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 will mature on August 16, 2007. The senior notes were originally issued in June 2002 in connection with our 9.25% equity units. We did not receive any proceeds from the mandatory remarketing. On August 16, 2005, the forward purchase contracts, which formed part of the equity units, settled and holders were required to purchase approximately 8.4 million AEP common shares.

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 15, 2005. The portfolio of U.S. Treasury securities was acquired in connection with the June 2005 remarketing of the senior notes discussed above.

Subsequent Debt Issuance

In October 2005, CSPCo issued $250 million of 5.85% Senior Notes, Series F, due in October 2035.

12.COMPANY-WIDE STAFFING AND BUDGET REVIEW

As result of a company-wide staffing and budget review approximately 500 positions were identified for elimination. Pretax severance benefits expense of $24 million and $4 million was recorded (primarily in Maintenance and Other Operation) in the second and third quarters of 2005, respectively. The following table shows the total 2005 expense recorded and the remaining accrual (reflected primarily in Current Liabilities - Other) as of September 30, 2005:

	Amount (in millions)
Total Expense		28
Less: Total Payments		12
Remaining Accrual at September 30, 2005	$	16

AEP GENERATING COMPANY

AEP GENERATING COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Operating revenues are derived from the sale of our share of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. 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. Fluctuations in Net Income are a result of terms in the unit power agreements which allow for the monthly calculation of return on total capital, largely dependent on the percentage of plant assets in service.

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	2.4
Change in Gross Margin:
Wholesale Sales				(0.2	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(0.9	)
Taxes Other Than Income Taxes	1.0
Total Change in Operating Expenses and Other				0.1
Income Tax Expense				(0.1	)
Third Quarter of 2005 Net Income			$	2.2

Gross margin decreased $0.2 million primarily due to variances in the estimated tax expense component of billed revenues.

The increase in Other Operation and Maintenance expenses resulted from increased unplanned outages and the related costs compared to prior year.

Taxes Other Than Income Taxes decreased due to a $1 million decline in real and personal property tax expense. The decrease reflects an unfavorable adjustment made in 2004 for actual tax expense related to a prior year.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 1.0% and (2.6)%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is primarily due to amortization of investment tax credits, flow-through of book versus tax temporary differences, state income taxes and federal income tax adjustments. The change in the effective tax rate is primarily due to federal income tax adjustments and changes in various permanent and flow-through temporary differences.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	5.7
Change in Gross Margin:
Wholesale Sales				(2.1	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	3.0
Depreciation and Amortization	(0.4	)
Taxes Other Than Income Taxes	0.8
Nonoperating Income and Expenses, Net	0.1
Total Change in Operating Expenses and Other				3.5
Income Tax Expense				(0.3	)
Nine Months Ended September 30, 2005 Net Income			$	6.8

Gross margin decreased $2.1 million primarily due to a decrease in billed operation and maintenance expense partially offset by the impact of the higher percentage of plant assets in service on return on capital. Plant assets in service increased with the completion of the NO_x burner installation in 2004. Gross margin fluctuates consistent with operation and maintenance expense in accordance with the unit power agreements.

The decrease in Other Operation and Maintenance expenses resulted from decreased outages and the related costs compared to prior year. In 2004, Rockport Plant Unit 2 was shut down for planned boiler inspection and repairs from early February through early April.

Depreciation and Amortization increased reflecting increased depreciable generating plant.

The decrease in Taxes Other Than Income Taxes reflects decreased real and personal property taxes of $0.8 million reflecting the 2004 adjustment discussed above.

Income Taxes

The effective tax rates for the nine months ended September 2005 and 2004 were (2.2)% and (8.9)%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is primarily due to amortization of investment tax credits, flow-through of book versus tax temporary differences, state income taxes and federal income tax adjustments. The change in the effective tax rate is primarily due to federal income tax adjustments and changes in various permanent and flow-through temporary differences.

Off-Balance Sheet Arrangement

In prior years, we entered into an off-balance sheet arrangement for the lease of Rockport Plant Unit 2. Our current policy restricts the use of off-balance sheet financing entities or structures to traditional operating lease arrangements. Our off-balance sheet arrangement has not changed significantly since year-end. For complete information on our off-balance sheet arrangement see “Off-balance Sheet Arrangements” in the “Management’s Narrative Financial Discussion and Analysis” section of our 2004 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report 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

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended				Nine Months Ended
	2005		2004		2005		2004
OPERATING REVENUES	$	69,640	$	65,303	$	201,268	$	176,933
OPERATING EXPENSES
Fuel for Electric Generation		37,403		32,857		105,771		79,291
Rent - Rockport Plant Unit 2		17,070		17,070		51,212		51,212
Other Operation		2,759		2,473		8,219		7,628
Maintenance		2,421		1,835		6,411		10,025
Depreciation and Amortization		5,956		5,941		17,901		17,447
Taxes Other Than Income Taxes		1,074		2,070		3,149		3,956
Income Taxes		908		843		2,510		2,240
TOTAL		67,591		63,089		195,173		171,799
OPERATING INCOME		2,049		2,214		6,095		5,134
Nonoperating Income		-		14		84		43
Nonoperating Expenses		44		86		157		235
Nonoperating Income Tax Credit		886		905		2,654		2,709
Interest Charges		652		643		1,848		1,914
NET INCOME	$	2,239	$	2,404	$	6,828	$	5,737

CONDENSED STATEMENTS OF RETAINED EARNINGS

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended				Nine Months Ended
	2005		2004		2005		2004
BALANCE AT BEGINNING OF PERIOD	$	26,947	$	22,251	$	24,237	$	21,441
Net Income		2,239		2,404		6,828		5,737
Cash Dividends Declared		3,015		1,262		4,894		3,785
BALANCE AT END OF PERIOD	$	26,171	$	23,393	$	26,171	$	23,393

The common stock of AEGCo is wholly-owned by AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005		2004
ELECTRIC UTILITY PLANT
Production	$	681,097	$	681,254
General		2,202		3,739
Construction Work in Progress		12,538		7,729
Total		695,837		692,722
Accumulated Depreciation and Amortization		378,645		368,484
TOTAL - NET		317,192		324,238
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		119		119
CURRENT ASSETS
Accounts Receivable - Affiliated Companies		25,547		23,078
Fuel		11,190		16,404
Materials and Supplies		6,898		5,962
Prepayments		17		-
TOTAL		43,652		45,444
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
Unamortized Loss on Reacquired Debt		4,318		4,496
Asset Retirement Obligations		1,264		1,117
Deferred Property Taxes		1,567		557
Other Deferred Charges		406		422
TOTAL		7,555		6,592
TOTAL ASSETS	$	368,518	$	376,393

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

CONDENSED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005		2004
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $1,000 par value per share:
Authorized and Outstanding - 1,000 shares	$	1,000	$	1,000
Paid-in Capital		23,434		23,434
Retained Earnings		26,171		24,237
Total Common Shareholder’s Equity		50,605		48,671
Long-term Debt		-		44,820
TOTAL		50,605		93,491
CURRENT LIABILITIES
Long-term Debt Due Within One Year		44,826		-
Advances from Affiliates		11,314		26,915
Accounts Payable:
General		456		443
Affiliated Companies		16,704		17,905
Taxes Accrued		5,824		8,806
Interest Accrued		456		911
Obligations Under Capital Leases		293		210
Rent Accrued - Rockport Plant Unit 2		23,427		4,963
Other		82		73
TOTAL		103,382		60,226
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		22,296		24,762
Regulatory Liabilities:
Asset Removal Costs		27,693		25,428
Deferred Investment Tax Credits		43,749		46,250
SFAS 109 Regulatory Liability, Net		11,779		12,852
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		95,726		99,904
Obligations Under Capital Leases		12,000		12,264
Asset Retirement Obligations		1,288		1,216
TOTAL		214,531		222,676
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	368,518	$	376,393

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	6,828		$	5,737
Adjustments to Reconcile Net Income to Net Cash Flows  From Operating Activities:
Depreciation and Amortization		17,901			17,447
Deferred Income Taxes		(3,539	)		(1,987	)
Deferred Investment Tax Credits		(2,501	)		(2,502	)
Deferred Property Taxes		(1,010	)		(842	)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		(4,178	)		(4,178	)
Change in Other Noncurrent Assets		(1,767	)		2,415
Change in Other Noncurrent Liabilities		2,079			(2,362	)
Changes in Components of Working Capital:
Accounts Receivable		(2,469	)		2,587
Fuel, Materials and Supplies		4,278			947
Accounts Payable		(1,188	)		(2,875	)
Taxes Accrued		(2,982	)		3,969
Rent Accrued - Rockport Plant Unit 2		18,464			18,464
Other Current Assets		(17	)		(11	)
Other Current Liabilities		(363	)		(372	)
Net Cash Flows From Operating Activities		29,536			36,437
INVESTING ACTIVITIES
Construction Expenditures		(9,041	)		(11,257	)
Net Cash Flows Used For Investing Activities		(9,041	)		(11,257	)
FINANCING ACTIVITIES
Changes in Advances to/from Affiliates, Net		(15,601	)		(21,395	)
Dividends Paid		(4,894	)		(3,785	)
Net Cash Flows Used For Financing Activities		(20,495	)		(25,180	)
Net Increase in Cash and Cash Equivalents		-			-
Cash and Cash Equivalents at Beginning of Period		-			-
Cash and Cash Equivalents at End of Period	$	-		$	-

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $2,104,000 and $2,170,000 and for income taxes was $11,025,000 and $87,000 in 2005 and 2004, respectively. Noncash acquisitions under capital leases were $31,000 and $18,000 in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to AEGCo’s condensed financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to AEGCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Commitments and Contingencies	Note 5
Guarantees	Note 6
Business Segments	Note 9
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	43
Changes in Gross Margin:
Texas Supply	(48	)
Texas Wires	9
Off-system Sales	3
Transmission Revenues	(3	)
Other Revenues	9
Total Change in Gross Margin				(30	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	11
Depreciation and Amortization	(5	)
Taxes Other Than Income Taxes	1
Carrying Costs on Stranded Cost Recovery	15
Nonoperating Income and Expenses, Net	5
Interest Charges	4
Total Change in Operating Expenses and Other				31
Income Tax Expense				(4	)
Third Quarter of 2005 Net Income			$	40

Net Income decreased $3 million in the third quarter of 2005. The key drivers of the decrease were a decrease in gross margin of $30 million, offset by Carrying Costs on Stranded Cost Recovery of $15 million and a decrease in Other Operation and Maintenance of $11 million.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Texas Supply margins decreased $48 million primarily due to a $163 million decrease in revenue from the expiration of the supply contract with our largest REP customer; lower capacity sales of $7 million due to the sale of certain generation plants; a $2 million decrease of ERCOT Reliability-Must Run (RMR) sales; and decreased margins of $3 million. These decreases were partially offset by lower fuel and purchased power expense of $120 million.

· Texas Wires revenues increased $9 million primarily due to an increase in sales volumes of 4% resulting partly from a 14% increase in cooling degree days.

· Margins from Off-system Sales increased $3 million primarily due to favorable optimization activity.

· Other Revenues increased $9 million primarily due to the reclassification of third party construction project revenues discussed below in Other Items.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $11 million primarily due to a $14 million decrease in power plant operations and maintenance due to the sale of certain generation plants along with a $5 million decrease in administrative and general expense primarily related to employee costs. These decreases were partially offset by $10 million of increased third party construction-related expense recorded in operations as discussed below in Other Items.

· Depreciation and Amortization expense increased $5 million primarily due to the recovery and amortization of securitized transition assets.

· Taxes Other Than Income Taxes decreased $1 million primarily due to lower property-related taxes as a result of the sale of certain generation plants.

· Carrying Costs on Stranded Cost Recovery of $15 million were recorded in the third quarter of 2005. There were no carrying Costs recorded prior to December 2004. (See the “TCC Carrying Costs on Net True-up Regulatory Assets” section of Note 4)

· Nonoperating Income and Expenses, Net increased $5 million primarily due to the accrual of interest income as a result of a Texas Appeals Court Order. (See the “TCC Excess Earnings” section of Note 4)

· Interest Charges decreased $4 million primarily due to lower long-term debt outstanding and lower rates.

Other Items:

As a result of the PUCT order discussed in Note 3, “TCC Rate Case”, we implemented new transmission and distribution rates effective September 6, 2005. The effect of that implementation had only a minor effect on Net Income for the third quarter of 2005. However, as a result of the order we reclassified the margins from third party construction projects from nonoperating to operating. While this reclassification affected various line items on the Statements of Income, it had no effect on Net Income.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 34.3% and 28.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The change in the effective tax rate for the comparative period is primarily due to consolidated tax savings from Parent and federal income tax adjustments.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	72
Changes in Gross Margin:
Texas Supply	(84	)
Texas Wires	21
Off-system Sales	1
Transmission Revenues	(4	)
Other Revenues	(2	)
Total Change in Gross Margin				(68	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	41
Depreciation and Amortization	(12	)
Taxes Other Than Income Taxes	3
Carrying Costs on Stranded Cost Recovery	30
Nonoperating Income and Expenses, Net	(1	)
Interest Charges	10
Total Change in Operating Expenses and Other				71
Income Tax Expense				(5	)
Nine Months ended September 30, 2005 Net Income			$	70

Net Income decreased $2 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. The key drivers of the decrease were a decrease in gross margin of $68 million, offset by a decrease in Other Operation and Maintenance of $41 million and an increase of $30 million in Carrying Costs on Stranded Cost Recovery.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Texas Supply margins decreased $84 million primarily due to a $395 million decrease in revenue resulting from the expiration of the supply contract with our largest REP customer; lower capacity sales of $24 million due to the sale of certain generation plants; loss of ERCOT RMR revenue of $18 million; and decreased margins of $4 million. These decreases were partially offset by lower fuel and purchased power expense of $284 million and a decrease in the provision for refund of $62 million due to the 2004 final fuel reconciliation true-up.

· Texas Wires revenue increased $21 million primarily due to an increase in sales volumes of 4% resulting primarily from a 12% increase in degree days.

· Transmission Revenues decreased $4 million primarily due to lower ERCOT revenue.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $41 million primarily due to a $23 million decrease in power plant operations, a $14 million decrease in power plant maintenance both due to the sale of certain generation plants, and a $10 million decrease in administrative and general expense primarily related to employee costs. These decreases were partially offset by $10 million of nonutility construction-related expense recorded in operations as discussed below in Other Items and slightly higher distribution-related expenses.

· Depreciation and Amortization expense increased $12 million primarily related to the recovery and amortization of securitized transition assets.

· Carrying Costs on Stranded Cost Recovery increased $30 million. Carrying Costs on Stranded Cost Recovery of $57 million were recorded in the first nine months of 2005, offset by an adjustment of $27 million for prior years recorded in the first quarter. The adjustment related to a nonaffiliated utility’s securitization proceeding in which the PUCT issued an order in March 2005 that resulted in a reduction in the nonaffiliated utility’s carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to accumulated deferred federal income taxes on net stranded cost and other true-up items retroactively applied to January 1, 2004.

· Interest Charges decreased $10 million primarily due to lower long-term debt outstanding and lower rates.

Other Items:

As a result of the PUCT order discussed in Note 3, “TCC Rate Case”, we implemented new transmission and distribution rates effective September 6, 2005. The effect of that implementation had only a minor effect on Net Income for the nine months ended September 30, 2005. However, as a result of the order we reclassified the margins from third party construction projects from nonoperating to operating. While this reclassification affected various line items on the Statements of Income, it had no effect on Net Income.

Income Taxes

The effective tax rates for the nine months ended September 2005 and 2004 were 28.6% and 24.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is primarily due to consolidated tax savings from Parent and amortization of investment tax credits, offset in part by 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-

Cash Flow

Cash flows for the nine months ended September 30, 2005 and 2004 were as follows:

	2005			2004
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	-		$	760
Cash Flows From (Used For):
Operating Activities		(100,333	)		192,501
Investing Activities		298,047			259,028
Financing Activities		(197,711	)		(450,529	)
Net Increase in Cash and Cash Equivalents		3			1,000
Cash and Cash Equivalents at End of Period	$	3		$	1,760

Operating Activities

Our Net Cash Flows Used For Operating Activities were $100 million for the first nine months of 2005. We produced income of $70 million during the period including noncash expense items of $105 million for Depreciation and Amortization and $(63) 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 these asset and liability accounts relates to a number of items; the most significant are decreases in Taxes Accrued. Taxes Accrued decreased $111 million primarily as a result of taxes remitted to the government related to prior year and current year tax accruals.

Our Net Cash Flows From Operating Activities were $193 million for the first nine months of 2004. We produced income of $72 million during the period including noncash expense items of $93 million for Depreciation and Amortization, $60 million for Over/Under Fuel Recovery and $(121) 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 activity in these asset and liability accounts relates to a number of items; the most significant are increases in Taxes Accrued. Taxes Accrued increased $147 million primarily due to taxes that were accrued during the first nine months of 2004 in excess of the amount remitted to the government.

Investing Activities

Net Cash Flows From Investing Activities were $298 million in 2005 primarily due to $314 million of net proceeds from the sale of STP and a reduction of Other Cash Deposits, Net primarily for the retirement of defeased first mortgage bonds of $66 million. Also, cash flows used for Construction Expenditures of $109 million related to projects for transmission and distribution service reliability. For the remainder of 2005, we expect our Construction Expenditures to be approximately $100 million.

Net Cash Flows From Investing Activities were $259 million in 2004 primarily due to $425 million of net proceeds from the sale of certain generation plants, offset in part by cash deposits of $96 million for future long-term debt retirements and Construction Expenditures of $72 million related to projects for transmission and distribution service reliability.

Financing Activities

Net Cash Flows Used For Financing Activities of $198 million in 2005 were primarily due to the payments of dividends of $150 million and the retirement of long-term debt of $486 million, including $66 million of bonds that were defeased in 2004. This was partially offset by an issuance of new debt of $427 million, including $150 million of affiliated long-term debt.

Net Cash Flows Used For Financing Activities of $451 million in 2004 were primarily due to the retirement of $191 million of long-term debt, increased lending to the Utility Money Pool and payment of dividends.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2005 were:

Issuances

Type of Debt		Principal Amount		Interest Rate		Due Date
	(in thousands)			(%)
Installment Purchase Contract		$	161,700		Variable		2030
Installment Purchase Contract			120,265		Variable		2028
Notes Payable - Affiliated			150,000		4.58		2007

Retirements

		Principal		Interest		Due
Type of Debt		Amount		Rate		Date
	(in thousands)			(%)
Senior Unsecured Notes Payable		$	150,000		3.00		2005
Senior Unsecured Notes Payable			100,000		Variable		2005
Securitization Bonds			29,386		3.54		2005
Securitization Bonds			20,593		5.01		2008
First Mortgage Bonds			65,763		6.625		2005
Installment Purchase Contract			120,265		6.00		2028

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements disclosed above.

Significant Factors

Texas Restructuring

The principal remaining component of the stranded cost recovery process in Texas is the PUCT’s determination and approval of our net stranded generation costs and other recoverable true-up items including carrying costs in our true-up filing. The PUCT approved our request to file our True-up Proceeding after the sales of our interest in STP, with only the ownership interest in Oklaunion remaining to be settled. On May 19, 2005, the sales of our interest in STP closed. On May 27, 2005, we filed our true-up request seeking recovery of $2.4 billion of net stranded costs and other true-up items which we believe the Texas Restructuring Legislation allows. Our request includes unrecorded equity carrying costs through May 27, 2005, all future carrying costs through September 2005 and amounts for stranded costs that we have previously written off (principally, a $238 million provision for a probable depreciation adjustment recorded in December 2004 based on a methodology approved by the PUCT in a nonaffiliated utility’s true-up order). The PUCT hearing concluded on October 4, 2005. It is anticipated that the PUCT will issue a final order in the fourth quarter of 2005.

We continue to accrue carrying costs on our net true-up regulatory asset at the embedded 8.12% debt component rate and will continue to do so until we recover our approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on an assumed cost-of-money benefit for accumulated deferred federal income taxes retroactively applied to January 1, 2004. In the first nine months of 2005, we began to accrue carrying costs based on this order. Through September 30, 2005, we have computed carrying costs of $509 million, of which we have recognized $332 million to-date. The equity component of the carrying costs, which totals $177 million through September 30, 2005, will be recognized in income as collected.

In our True-up Proceeding, parties have recommended that the PUCT reduce our carrying cost rate to an amount that ranged from 7.5% to the combined rate that was settled upon in our wires rate proceeding which included a cost of debt of 5.7%. If the PUCT ultimately determines that a lower rate should be used to calculate carrying costs on our stranded cost balance, a portion of carrying costs previously recorded would have to be reversed and would have an adverse impact on future results of operations and cash flows. Based upon a range of debt rates from 7.5% to 5.7%, through September 30, 2005, such reversal would range from $28 million to $107 million, of which $6 million to $22 million would apply to amounts accrued in 2005.

When the True-up Proceeding is complete, we intend to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated transmission and distribution (T&D) rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

We believe that our filed request for recovery of $2.4 billion of net stranded costs and other true-up items, inclusive of carrying costs, is recoverable under the Texas Restructuring Legislation and that our $1.6 billion recorded net true-up regulatory asset, inclusive of carrying costs at September 30, 2005, is probable of recovery at this time. However, other parties have contended that all or material amounts of our net stranded costs and/or wholesale capacity auction true-up amounts should not be recovered. To the extent decisions of the PUCT in our True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated utilities, additional provisions for material disallowances and reductions of the net true-up regulatory asset, including recorded carrying costs, are possible. Such disallowances would have a material adverse effect on future results of operations, cash flows and possibly 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 “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	9,701
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(3,946	)
Fair Value of New Contracts When Entered During the Period (b)		74
Net Option Premiums Paid/(Received) (c)		-
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		5,011
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		-
Total MTM Risk Management Contract Net Assets		10,840
Net Cash Flow Hedge Contracts (f)		(3,507	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	7,333

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	32,493		$	92		$	32,585
Noncurrent Assets		19,433			101			19,534
Total MTM Derivative Contract Assets		51,926			193			52,119
Current Liabilities		(28,486	)		(3,592	)		(32,078	)
Noncurrent Liabilities		(12,600	)		(108	)		(12,708	)
Total MTM Derivative Contract Liabilities		(41,086	)		(3,700	)		(44,786	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	10,840		$	(3,507	)	$	7,333

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(625	)	$	3,007		$	253		$	139	$	-	$	-	$	2,774
Prices Provided by Other External Sources - OTC Broker Quotes (a)		4,678			1,641			3,723			1,389		-		-		11,431
Prices Based on Models and Other Valuation Methods (b)		(623	)		(3,523	)		(2,528	)		392		1,390		1,527		(3,365	)
Total	$	3,430		$	1,125		$	1,448		$	1,920	$	1,390	$	1,527	$	10,840

(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 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 is 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.
(c)	Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

The table provides detail on designated, effective cash flow hedges included in the Condensed Consolidated Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power
Beginning Balance December 31, 2004	$	657
Changes in Fair Value (a)		(2,871	)
Reclassifications from AOCI to Net Income (b)		(150	)
Ending Balance September 30, 2005	$	(2,364	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,358 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$220	$301	$142	$76	$157	$511	$220	$75

VaR Associated with Debt Outstanding

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 $120 million at September 30, 2005 and December 31, 2004, 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 operation or consolidated financial position.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended						Nine Months Ended
	2005			2004			2005		2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	202,993		$	347,013		$	569,980	$	872,924
Sales to AEP Affiliates		2,528			7,596			12,794		38,622
TOTAL		205,521			354,609			582,774		911,546
OPERATING EXPENSES
Fuel for Electric Generation		1,892			6,967			11,979		50,879
Fuel from Affiliates for Electric Generation		24			1,707			68		101,883
Purchased Electricity for Resale		1,691			114,371			27,057		140,925
Purchased Electricity from AEP Affiliates		-			54			-		6,065
Other Operation		66,661			74,780			199,870		228,287
Maintenance		8,782			12,215			38,254		51,328
Depreciation and Amortization		40,342			34,884			105,062		92,860
Taxes Other Than Income Taxes		22,828			23,814			66,282		69,028
Income Taxes		13,748			18,027			13,897		23,645
TOTAL		155,968			286,819			462,469		764,900
OPERATING INCOME		49,553			67,790			120,305		146,646
Carrying Costs on Stranded Cost Recovery		15,349			-			30,146		-
Nonoperating Income		6,081			6,783			40,637		30,946
Nonoperating Expenses (Credit)		(2,253	)		3,628			21,871		11,384
Nonoperating Income Tax Expense (Credit)		7,386			(1,336	)		14,141		(476	)
Interest Charges		25,374			29,269			85,095		94,609
NET INCOME		40,476			43,012			69,981		72,075
Preferred Stock Dividend Requirements		60			60			181		181
EARNINGS APPLICABLE TO COMMON STOCK	$	40,416		$	42,952		$	69,800	$	71,894

The common stock of TCC is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(148,000	)					(148,000	)
Preferred Stock Dividends						(181	)					(181	)
TOTAL												1,060,868
COMPREHENSIVE INCOME
Other Comprehensive Loss,  Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,762									(5,130	)		(5,130	)
Minimum Pension Liability, Net of Tax of $0									(3,471	)		(3,471	)
NET INCOME						72,075						72,075
TOTAL COMPREHENSIVE INCOME												63,474
SEPTEMBER 30, 2004	$	55,292	$	132,606	$	1,006,917		$	(70,473	)	$	1,124,342
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						(181	)					(181	)
TOTAL												1,118,462
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),  Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,626									(3,021	)		(3,021	)
Minimum Pension Liability, Net of Tax of $0									3,810			3,810
NET INCOME						69,981						69,981
TOTAL COMPREHENSIVE INCOME												70,770
SEPTEMBER 30, 2005	$	55,292	$	132,606	$	1,004,704		$	(3,370	)	$	1,189,232

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Transmission	$	810,540		$	788,371
Distribution		1,468,549			1,433,380
General		228,307			220,435
Construction Work in Progress		84,894			50,612
Total		2,592,290			2,492,798
Accumulated Depreciation and Amortization		628,587			725,225
TOTAL - NET		1,963,703			1,767,573
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		2,310			1,577
Bond Defeasance Funds		21,333			22,110
TOTAL		23,643			23,687
CURRENT ASSETS
Cash and Cash Equivalents		3			-
Other Cash Deposits		41,679			135,132
Accounts Receivable:
Customers		202,012			157,431
Affiliated Companies		20,750			67,860
Accrued Unbilled Revenues		30,095			21,589
Allowance for Uncollectible Accounts		(558	)		(3,493	)
Materials and Supplies		14,161			12,288
Risk Management Assets		32,585			14,048
Margin Deposits		11,565			1,891
Prepayments and Other Current Assets		12,516			9,151
TOTAL		364,808			415,897
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		17,467			15,236
Wholesale Capacity Auction True-Up		596,868			559,973
Unamortized Loss on Reacquired Debt		11,127			11,842
Designated for Securitization		1,309,811			1,361,299
Deferred Debt - Restructuring		10,910			11,596
Other		139,901			102,032
Securitized Transition Assets		608,178			642,384
Long-term Risk Management Assets		19,534			9,508
Prepaid Pension Obligations		110,501			109,628
Deferred Property Taxes		7,600			-
Deferred Charges		32,800			36,986
TOTAL		2,864,697			2,860,484
Assets Held for Sale - Texas Generation Plants		47,210			628,149
TOTAL ASSETS	$	5,264,061		$	5,695,790

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $25 par value 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		1,004,704			1,084,904
Accumulated Other Comprehensive Income (Loss)		(3,370	)		(4,159	)
Total Common Shareholder’s Equity		1,189,232			1,268,643
Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,940			5,940
Total Shareholders’ Equity		1,195,172			1,274,583
Long-term Debt - Nonaffiliated		1,651,178			1,541,552
Long-term Debt - Affiliated		150,000			-
TOTAL		2,996,350			2,816,135
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		52,265			365,742
Advances from Affiliates		12,021			207
Accounts Payable:
General		67,039			109,688
Affiliated Companies		61,631			64,045
Customer Deposits		18,991			6,147
Taxes Accrued		71,613			184,014
Interest Accrued		16,732			41,227
Risk Management Liabilities		32,078			8,394
Obligations Under Capital Leases		390			412
Other		28,139			20,115
TOTAL		360,899			799,991
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		1,194,728			1,247,111
Long-term Risk Management Liabilities		12,708			4,896
Regulatory Liabilities:
Asset Removal Costs		229,324			102,624
Deferred Investment Tax Credits		105,543			107,743
Over-recovery of Fuel Costs		209,526			211,526
Retail Clawback		61,385			61,384
Other		80,302			76,653
Obligations Under Capital Leases		424			468
Deferred Credits and Other		10,885			17,276
TOTAL		1,904,825			1,829,681
Liabilities Held for Sale - Texas Generation Plants		1,987			249,983
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,264,061		$	5,695,790

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	69,981		$	72,075
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		105,062			92,860
Accretion Expense		7,549			12,428
Deferred Income Taxes		(63,426	)		(121,111	)
Deferred Investment Tax Credits		(2,200	)		(3,670	)
Deferred Property Taxes		(7,600	)		(5,959	)
Pension and Postemployment Benefit Reserves		(2,631	)		1,252
Mark-to-Market of Risk Management Contracts		(1,139	)		3,991
Pension Contributions		(170	)		(2,668	)
Carrying Costs		(30,146	)		-
Wholesale Capacity		769			-
Over/Under Fuel Recovery		(2,000	)		60,000
(Gain)/Loss on Sale of Assets		(22	)		(112	)
Change in Other Noncurrent Assets		(14,115	)		(1,511	)
Change in Other Noncurrent Liabilities		3,269			(36,148	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(4,997	)		10,504
Fuel, Materials and Supplies		(1,763	)		(7,495	)
Accounts Payable		(28,003	)		(6,139	)
Taxes Accrued		(110,975	)		147,251	��
Customer Deposits		12,844			4,772
Interest Accrued		(24,495	)		(20,035	)
Other Current Assets		(14,715	)		(1,800	)
Other Current Liabilities		8,590			(5,984	)
Net Cash Flows From (Used For) Operating Activities		(100,333	)		192,501
INVESTING ACTIVITIES
Construction Expenditures		(109,372	)		(71,735	)
Proceeds From Sale of Assets		313,966			426,566
Change in Other Cash Deposits, Net		93,453			(74,132	)
Change in Bond Defeasance Funds and Other		-			(21,671	)
Net Cash Flows From Investing Activities		298,047			259,028
FINANCING ACTIVITIES
Issuance of Long-term Debt- Nonaffiliated		276,663			-
Issuance of Long-term Debt - Affiliated		150,000			-
Retirement of Long-term Debt		(486,007	)		(190,996	)
Changes in Advances to/from Affiliates, Net		11,814			(111,352	)
Dividends Paid on Common Stock		(150,000	)		(148,000	)
Dividends Paid on Cumulative Preferred Stock		(181	)		(181	)
Net Cash Flows Used For Financing Activities		(197,711	)		(450,529	)
Net Increase in Cash and Cash Equivalents		3			1,000
Cash and Cash Equivalents at Beginning of Period		-			760
Cash and Cash Equivalents at End of Period	$	3		$	1,760

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $95,066,000 and $108,791,000 and for income taxes was $207,079,000 and $(1,058,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $277,000 and $258,000 in 2005 and 2004, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $6,959,000 and $(209,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to TCC’s condensed consolidated financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to TCC.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Customer Choice and Industry Restructuring	Note 4
Commitments and Contingencies	Note 5
Guarantees	Note 6
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 7
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

AEP TEXAS NORTH COMPANY

AEP TEXAS NORTH COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	17
Changes in Gross Margin:
Texas Supply	(5	)
Texas Wires	2
Off-system Sales	2
Transmission Revenues	(1	)
Other Revenues	5
Total Change in Gross Margin				3
Changes in Operating Expenses and Other:
Other Operation and Maintenance	5
Depreciation and Amortization	(1	)
Total Change in Operating Expenses and Other				4
Income TaxExpense				(2	)
Third Quarter of 2005 Net Income			$	22

Net income increased $5 million due mainly to increases in gross margin and reduced operating expenses.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Texas Supply margins decreased by $5 million primarily due to lower sales volumes of 55% due to the expiration of the supply contract with our largest REP customer offset by an increase in nonaffiliated margin and capacity sales.

· Texas Wires revenue increased by $2 million primarily due to an increase in sales volumes of 10% resulting from a 29% increase in cooling degree days.

· Margins from Off-system Sales increased by $2 million primarily due to favorable optimization activity.

· Other Revenue increased $5 million primarily due to an increase in ancillary services to ERCOT.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $5 million. The decrease was primarily due to lower expenses for power plants no longer in service and a favorable settlement related to the Ft. Davis wind farm, which was impaired in 2002. A further reduction includes administrative and general expenses, primarily related to lower employee-related costs.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 32.5% and 33.1%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, federal income tax adjustments and state income taxes. The effective tax rate remained relatively flat for the comparative period.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	38
Changes in Gross Margin:
Texas Supply	(5	)
Texas Wires	4
Off-system Sales	(1	)
Other Revenues	1
Total Change in Gross Margin				(1	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	7
Depreciation and Amortization	(2	)
Nonoperating Income and Expenses, Net	(2	)
Interest Charges	2
Total Change in Operating Expenses and Other				5
Income TaxExpense				-
Nine Months Ended September 30, 2005 Net Income			$	42

Net income increased $4 million due mainly to reduced operating expenses.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Texas Supply margins decreased by $5 million primarily due to a decrease of $29 million due to lower sales volumes of 35% resulting from the expiration of the supply contract with our largest REP customer, offset by a decrease in the provision for refunds of $13 million for the 2004 final fuel reconciliation true-up and increased capacity revenue of $10 million.

· Texas Wires revenue increased by $4 million primarily due to higher sales volumes of 7% resulting from a 9% increase in degree days.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $7 million primarily due to decreased operations and maintenance for plants no longer in service. Production expense was further reduced by a favorable settlement related to the Ft. Davis wind farm, which was impaired in 2002, offset in part by increased cost for the disposal of fuel oil inventory. Further decreases were related to reduced customer expense and administrative and general expenses including employee-related costs.

· Nonoperating Income and Expenses, Net decreased $2 million primarily due to $5 million of income in 2004 relating to optimization contracts which expired in December 2004 offset by increased margins of $2 million from third party construction projects and increased interest income of $1 million.

· Interest Charges decreased $2 million primarily due to long-term debt maturities in 2004 and interest in 2004 related to the FERC settlement with wholesale customers.

Income Taxes

The effective tax rates for the nine months ended September 30, 2005 and 2004 were 30.7% and 33.4%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is primarily due to state income taxes and changes in permanent differences.

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	A3	BBB	A
Senior Unsecured Debt	Baa1	BBB	A-

Financing Activity

There were no long-term debt issuances or retirements during the first nine months of 2005.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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’ effects on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	4,192
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(1,705	)
Fair Value of New Contracts When Entered During the Period (b)		32
Net Option Premiums Paid/(Received) (c)		-
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		2,125
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		-
Total MTM Risk Management Contract Net Assets		4,644
Net Cash Flow Hedge Contracts (f)		(1,502	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	3,142

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Condensed Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	13,918		$	39		$	13,957
Noncurrent Assets		8,324			43			8,367
Total MTM Derivative Contract Assets		22,242			82			22,324
Current Liabilities		(12,201	)		(1,538	)		(13,739	)
Noncurrent Liabilities		(5,397	)		(46	)		(5,443	)
Total MTM Derivative Contract Liabilities		(17,598	)		(1,584	)		(19,182	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	4,644		$	(1,502	)	$	3,142

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

  ·   The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(268	)	$	1,288		$	108		$	59	$	-	$	-	$	1,187
Prices Provided by Other External Sources - OTC Broker Quotes (a)		2,004			702			1,595			595		-		-		4,896
Prices Based on Models and Other Valuation Methods (b)		(265	)		(1,509	)		(1,083	)		168		596		654		(1,439	)
Total	$	1,471		$	481		$	620		$	822	$	596	$	654	$	4,644

(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 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.
(c)	Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

The table provides detail on designated, effective cash flow hedges included in the Condensed Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power
Beginning Balance December 31, 2004	$	285
Changes in Fair Value (a)		(1,232	)
Reclassifications from AOCI to Net Income (b)		(64	)
Ending Balance September 30, 2005	$	(1,011	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,010 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$94	$129	$61	$32	$68	$221	$95	$33

VaR Associated with Debt Outstanding

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 $14 million and $13 million at September 30, 2005 and December 31, 2004, 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 operation or financial position.

AEP TEXAS NORTH COMPANY

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended				Nine Months Ended
	2005		2004		2005		2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	111,229	$	139,904	$	280,502	$	318,946
Sales to AEP Affiliates		13,019		12,599		37,189		39,344
TOTAL		124,248		152,503		317,691		358,290
OPERATING EXPENSES
Fuel for Electric Generation		13,289		11,357		37,255		29,518
Fuel from Affiliates for Electric Generation		144		15,497		516		39,263
Purchased Electricity for Resale		34,425		51,517		88,367		92,822
Purchased Electricity from AEP Affiliates		1		309		23		4,385
Other Operation		17,054		23,212		58,019		64,511
Maintenance		5,954		4,544		15,093		15,177
Depreciation and Amortization		10,435		9,448		30,952		28,994
Taxes Other Than Income Taxes		6,047		6,476		17,465		16,873
Income Taxes		10,504		8,248		17,183		16,730
TOTAL		97,853		130,608		264,873		308,273
OPERATING INCOME		26,395		21,895		52,818		50,017
Nonoperating Income		2,878		8,637		44,093		38,025
Nonoperating Expenses		1,826		8,230		39,139		31,128
Nonoperating Income Tax Expense		212		83		1,286		2,186
Interest Charges		4,931		5,366		14,784		17,028
NET INCOME		22,304		16,853		41,702		37,700
Preferred Stock Dividend Requirements		26		26		78		78
EARNINGS APPLICABLE TO COMMON STOCK	$	22,278	$	16,827	$	41,624	$	37,622

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(78	)					(78	)
TOTAL												236,197
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $980									(1,820	)		(1,820	)
NET INCOME						37,700						37,700
TOTAL COMPREHENSIVE INCOME												35,880
SEPTEMBER 30, 2004	$	137,214	$	2,351	$	161,050		$	(28,538	)	$	272,077
DECEMBER 31, 2004	$	137,214	$	2,351	$	170,984		$	(128	)	$	310,421
Common Stock Dividends						(20,827	)					(20,827	)
Preferred Stock Dividends						(78	)					(78	)
TOTAL												289,516
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $698									(1,296	)		(1,296	)
NET INCOME						41,702						41,702
TOTAL COMPREHENSIVE INCOME												40,406
SEPTEMBER 30, 2005	$	137,214	$	2,351	$	191,781		$	(1,424	)	$	329,922

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	288,446		$	287,212
Transmission		288,538			281,359
Distribution		489,002			474,961
General		110,831			115,174
Construction Work in Progress		34,808			23,621
Total		1,211,625			1,182,327
Accumulated Depreciation and Amortization		417,521			405,933
TOTAL - NET		794,104			776,394
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		1,177			1,407
CURRENT ASSETS
Cash and Cash Equivalents		215			-
Other Cash Deposits		800			2,308
Advances to Affiliates		87,651			51,504
Accounts Receivable:
Customers		59,400			90,109
Affiliated Companies		31,564			21,474
Accrued Unbilled Revenues		5,880			3,789
Allowance for Uncollectible Accounts		(9	)		(787	)
Unbilled Construction Costs		3,119			22,065
Fuel Inventory		1,918			3,148
Materials and Supplies		8,581			8,273
Risk Management Assets		13,957			6,071
Margin Deposits		4,952			818
Prepayments and Other		5,159			1,053
TOTAL		223,187			209,825
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
Deferred Debt - Restructuring		5,727			6,093
Unamortized Loss on Reacquired Debt		1,122			2,147
Other		3,292			3,783
Long-term Risk Management Assets		8,367			4,110
Prepaid Pension Obligations		44,901			44,911
Deferred Property Taxes		4,072			-
Other Deferred Charges		2,232			2,859
TOTAL		69,713			63,903
TOTAL ASSETS	$	1,088,181		$	1,051,529

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

CONDENSED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $25 par value 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		191,781			170,984
Accumulated Other Comprehensive Income (Loss)		(1,424	)		(128	)
Total Common Shareholder’s Equity		329,922			310,421
Cumulative Preferred Stock Not Subject to Mandatory Redemption		2,357			2,357
Total Shareholders’ Equity		332,279			312,778
Long-term Debt - Nonaffiliated		276,822			276,748
TOTAL		609,101			589,526
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		37,609			37,609
Accounts Payable:
General		35,404			22,444
Affiliated Companies		49,563			52,801
Customer Deposits		6,491			1,020
Taxes Accrued		27,172			37,269
Interest Accrued		3,378			5,044
Risk Management Liabilities		13,739			3,628
Obligations Under Capital Leases		196			220
Other		10,767			9,628
TOTAL		184,319			169,663
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		141,451			138,465
Long-term Risk Management Liabilities		5,443			2,116
Regulatory Liabilities:
Asset Removal Costs		81,756			81,143
Deferred Investment Tax Credits		17,745			18,698
Over-recovery of Fuel Costs		4,815			3,920
Retail Clawback		13,924			13,924
Excess Earnings		12,898			13,270
SFAS 109 Regulatory Liability, Net		6,897			8,500
Other		921			1,319
Obligations Under Capital Leases		348			314
Deferred Credits and Other		8,563			10,671
TOTAL		294,761			292,340
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	1,088,181		$	1,051,529

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	41,702		$	37,700
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		30,952			28,994
Deferred Income Taxes		(313	)		(1,980	)
Deferred Investment Tax Credits		(953	)		(974	)
Pension and Postemployment Benefit Reserves		(513	)		-
Deferred Property Taxes		(4,072	)		(4,023	)
Mark-to-Market of Risk Management Contracts		(452	)		1,318
Over/Under Fuel Recovery		895			13,500
Change in Other Noncurrent Assets		(672	)		(9,800	)
Change in Other Noncurrent Liabilities		349			(266	)
Changes in Components of Working Capital:
Accounts Receivable, Net		17,750			(7,345	)
Fuel, Materials and Supplies		922			4,447
Accounts Payable		8,467			(3,267	)
Taxes Accrued		(10,097	)		16,879
Customer Deposits		5,471			1,342
Interest Accrued		(1,666	)		(1,962	)
Other Current Assets		10,706			(6,171	)
Other Current Liabilities		1,115			(2,264	)
Net Cash Flows From Operating Activities		99,591			66,128
INVESTING ACTIVITIES
Construction Expenditures		(44,865	)		(27,742	)
Change in Other Cash Deposits, Net		1,508			266
Proceeds from Sale of Assets		1,033			510
Net Cash Flows Used For Investing Activities		(42,324	)		(26,966	)
FINANCING ACTIVITIES
Retirement of Long-term Debt		-			(24,036	)
Changes in Advances to/from Affiliates, Net		(36,147	)		(12,902	)
Dividends Paid on Common Stock		(20,827	)		(2,000	)
Dividends Paid on Cumulative Preferred Stock		(78	)		(78	)
Net Cash Flows Used For Financing Activities		(57,052	)		(39,016	)
Net Increase in Cash and Cash Equivalents		215			146
Cash and Cash Equivalents at Beginning of Period		-			-
Cash and Cash Equivalents at End of Period	$	215		$	146

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $15,192,000 and $17,290,000 and for income taxes was $30,486,000 and $6,905,000 in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 and 2004 were $193,000 and $153,000, respectively. Construction Expenditures include the change in Construction-related Accounts Payable of $1,255,000 and $(726,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to TNC’s condensed financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to TNC.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Customer Choice and Industry Restructuring	Note 4
Commitments and Contingencies	Note 5
Guarantees	Note 6
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	38
Changes in Gross Margin:
Retail Margins	10
Off-system Sales	12
Transmission Revenues	(6	)
Other Revenues	4
Total Change in Gross Margin				20
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(19	)
Depreciation and Amortization	(1	)
Nonoperating Income and Expenses, Net	4
Total Change in Operating Expenses and Other				(16	)
Income Tax Expense				(5	)
Third Quarter of 2005 Net Income			$	37

Net Income decreased by $1 million to $37 million in the third quarter of 2005 in comparison to the third quarter of 2004. The key drivers of the decrease were a $16 million net increase in operating expenses and other and a $5 million increase in Income Tax Expense offset by a $20 million increase in gross margin.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins increased by $10 million in comparison to 2004 primarily due to increases in retail sales. Cooling degree days were 35% higher than 2004.

· Off-system sales margins for 2005 increased by $12 million compared to 2004 primarily due to increased AEP Power Pool physical sales as well as favorable optimization activity.

· Transmission Revenues decreased $6 million primarily due to the elimination of $11 million of revenues related to through and out rates partially offset by an increase of $5 million in revenues due to replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating expenses and other changed between years as follows:

· Other Operation and Maintenance expenses increased $19 million primarily due to $6 million of distribution right-of-way activities and maintenance, a $4 million true-up related to the Virginia Environmental and Reliability deferral and a $3 million increase in system dispatch costs related to our operation in PJM.

· Nonoperating Income and Expenses, Net increased $4 million primarily due to favorable optimization activity coupled with the accrual of carrying costs related to the Virginia Environmental and Reliability deferral.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 35.8% and 29.6%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The increase in the effective tax rate is primarily due to federal income tax adjustments.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	126
Changes in Gross Margin:
Retail Margins	(56	)
Off-system Sales	44
Transmission Revenues	(19	)
Other Revenues	7
Total Change in Gross Margin				(24	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(17	)
Depreciation and Amortization	(3	)
Taxes Other Than Income Taxes	(1	)
Nonoperating Income and Expenses, Net	7
Total Change in Operating Expenses and Other				(14	)
Income Tax Expense				20
Nine Months Ended September 30, 2005 Net Income			$	108

Net Income decreased by $18 million to $108 million in the nine months ended September 30, 2005 in comparison to the nine months ended September 30, 2004. The key drivers of the decrease were a $24 million decrease in gross margin and a $14 million net increase in operating expenses and other partially offset by a $20 million decrease in Income Tax Expense.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins decreased by $56 million in comparison to 2004 primarily due to our higher MLR share caused by the increase in our peak demand established in December 2004 resulting in a $45 million increase in capacity settlement payments under the Interconnection Agreement. In addition, there was a $20 million decrease in fuel margins resulting from higher fuel costs.

· Off-system sales margins for 2005 increased by $44 million compared to 2004 primarily due to increased AEP Power Pool physical sales as well as favorable optimization activity.

· Transmission Revenues decreased $19 million primarily due to the elimination of $34 million of revenues related to through and out rates partially offset by an increase of $15 million due to replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $17 million primarily due to a $10 million increase in system dispatch costs related to our operation in PJM and an increase in transmission equalization charges due to the increase in our MLR as a result of our new peak demand established in December 2004.

· Nonoperating Income and Expenses, Net increased $7 million primarily due to the accrual of carrying costs related to the Virginia Environmental and Reliability deferral coupled with favorable optimization activity.

Income Taxes

The effective tax rates for the nine months ended September 2005 and 2004 were 33.5% and 37.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to an investment tax credit adjustment in 2004 as a result of the Virginia SCC extending the regulatory transition period and a decrease in 2005 state income taxes as a result of recording the effects of Ohio House Bill 66, which phases-out the Ohio Franchise Tax. Participation in the SIA subjects us to 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
First Mortgage Bonds	Baa1	BBB	A-
Senior Unsecured Debt	Baa2	BBB	BBB+

Cash Flow

Cash flows for the nine months ended September 30, 2005 and 2004 were as follows:

	2005			2004
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	536		$	4,561
Cash Flows From (Used For):
Operating Activities		175,640			393,181
Investing Activities		(410,881	)		(256,295	)
Financing Activities		236,270			(137,949	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,029			(1,063	)
Cash and Cash Equivalents at End of Period	$	1,565		$	3,498

Operating Activities

Our Net Cash Flows From Operating Activities were $176 million in 2005. We produced income of $108 million during the period and noncash expense items of $147 million for Depreciation and Amortization partially offset by Pension Contributions of $60 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 no significant items.

Our Net Cash Flows From Operating Activities were $393 million in 2004. We produced income of $126 million during the period and had a noncash expense item of $144 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 had no significant items.

Investing Activities

Our Net Cash Flows Used For Investing Activities during 2005 and 2004 primarily reflect our Construction Expenditures of $422 million and $300 million, respectively. Construction Expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades.In 2005 and 2004, capital projects for transmission expenditures are primarily related to the Jacksons Ferry-Wyoming 765 kV transmission line. Environmental upgrades include the installation of SCR equipment on Amos Unit 1 and the flue gas desulfurization project at the Mountaineer Plant. For the remainder of 2005, we expect our Construction Expenditures to be approximately $270 million.

Financing Activities

Our Net Cash Flows From Financing Activities were $236 million in 2005. We issued four Senior Unsecured Notes totaling $850 million with various interest rates. We also issued Notes Payable - Affiliates of $100 million and received a capital contribution from our parent of $150 million. We retired $450 million of Senior Unsecured Notes with an interest rate of 4.80% and retired three First Mortgage Bonds totaling $125 million with various interest rates. In addition, we repaid $279 million of Advances from Affiliates.

Our Net Cash Flows Used For Financing Activities were $138 million in 2004. We retired $45 million and $21 million of First Mortgage Bonds and $40 million of Installment Purchase Contracts with interest rates of 7.13%, 7.70 and 5.45%, respectively. In addition, we repaid $107 million of Advances from Affiliates and paid $50 million in Common Stock Dividends.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2005 were:

Issuances

		Principal		Interest		Due
Type of Debt		Amount		Rate		Date
	(in thousands)			(%)
Senior Unsecured Notes		$	250,000		5.00		2017
Senior Unsecured Notes			250,000		5.80		2035
Senior Unsecured Notes			200,000		4.95		2015
Senior Unsecured Notes			150,000		4.40		2010
Notes Payable - Affiliated			100,000		4.708		2010

Retirements

		Principal		Interest		Due
Type of Debt		Amount		Rate		Date
	(in thousands)			(%)
Senior Unsecured Notes		$	450,000		4.80		2005
First Mortgage Bonds			50,000		8.00		2005
First Mortgage Bonds			45,000		8.00		2025
First Mortgage Bonds			30,000		6.89		2005

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements discussed above and the coal supply agreement discussed below.

We entered into a 11-year coal supply agreement effective January 1, 2007, with Cline Resources & Development Company (Gatling LLC). The agreement requires a minimum purchase of two million tons of coal per year. The contract contains routine remedy clauses in case of default.

Significant Factors

Ceredo Generating Station

In August 2005, we signed a purchase and sale agreement with Reliant Energy for the purchase of a 505 MW plant located near Ceredo, West Virginia for $100 million. This transaction is expected to be completed no later than the first quarter of 2006.

Virginia Environmental and Reliability Costs

In April 2004, the Virginia Electric Restructuring Act was amended to include a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and T&D system reliability (E&R) costs prudently incurred after July 1, 2004. On July 1, 2005, we filed a request with the Virginia SCC seeking approval for the recovery of $62 million in incremental E&R costs through June 30, 2006. The $62 million request represents i) expected costs of environmental controls on coal-fired generators to meet the first phase of the Clean Air Interstate Rule and Clean Air Mercury Rule finalized earlier this year, ii) recovery of the incremental cost of the Jacksons Ferry-Wyoming 765 kV transmission line construction and iii) other incremental T&D system reliability costs incurred from July 1, 2004 to June 30, 2006.

In our filing, we requested that a twelve-month E&R recovery factor be applied to electric service bills on an interim basis beginning August 1, 2005. The recovery factor would have been applied as a 9.18% surcharge to customer bills. We proposed to practice over/under-recovery deferral accounting for the difference between the actual incremental costs incurred and revenue recovered.

Through September 30, 2005, we have incurred approximately $13 million of actual incremental E&R costs and have deferred $7 million of such costs for future recovery. APCo did not record $2 million of equity carrying costs that are not recognized until collected.  E&R costs of $4 million represented interest capitalized that was duplicative of the carrying costs.

On October 14, 2005, the Virginia SCC denied our request to place in effect, on an interim basis subject to refund, its proposed cost recovery surcharge. Under this order, an E&R surcharge will not become effective until the Virginia SCC issues an order following the February 7, 2006 public hearing in this case. The Virginia SCC also ruled in this order that it does not have the authority under applicable Virginia law to approve the recovery of projected E&R costs before their actual incurrence and adjudication, which effectively eliminated projected costs requested in this filing. However, according to this order, we may update our request to reflect additional actual costs and/or present additional evidence. If the Virginia SCC denies recovery of any portion of the net incremental amounts deferred to date, it would adversely affect future results of operations and cash flows.

West Virginia Rate Case

On August 26, 2005, we, in a joint filing with WPCo, filed an application with the Public Service Commission of West Virginia seeking an initial increase in our retail rates of approximately $77 million. The initial increase included approval to reactivate and modify the suspended Expanded Net Energy Cost (ENEC) Recovery Mechanism which accounted for $65 million of the initial increase and approval to implement a system reliability tracker which accounted for $9 million. ENEC includes fuel and purchased power costs, as well as other energy-related items including off-system sales margins and transmission items. In addition, we requested a series of supplemental annual increases related to the recovery of the cost of significant environmental and transmission expenditures. The first proposed supplemental increase of $9 million would go in effect on the same date as the initial rate increase, and the remaining supplemental increases of $44 million, $10 million and $38 million would go in effect on January 1, 2007, 2008 and 2009, respectively. It is expected that the proposed rates will become effective on June 23, 2006 under West Virginia law. We have a regulatory liability of $52 million pre-suspension, previously over-recovered ENEC costs which we are proposing to apply plus a carrying cost in the future to any of under-recoveries of ENEC costs through the reactivated ENEC Recovery Mechanism. Management is unable to predict the ultimate effect of this filing on future revenues, 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 “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	54,124
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(10,775	)
Fair Value of New Contracts When Entered During the Period (b)		682
Net Option Premiums Paid/(Received) (c)		(685	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		18,118
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		5,741
Total MTM Risk Management Contract Net Assets		67,205
Net Cash Flow and Fair Value Hedge Contracts (f)		(14,929	)
DETM Assignment (g)		(15,405	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	36,871

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	194,468		$	361		$	-		$	194,829
Noncurrent Assets		176,644			397			-			177,041
Total MTM Derivative Contract Assets		371,112			758			-			371,870
Current Liabilities		(170,347	)		(14,271	)		(3,660	)		(188,278	)
Noncurrent Liabilities		(133,560	)		(1,416	)		(11,745	)		(146,721	)
Total MTM Derivative Contract  Liabilities		(303,907	)		(15,687	)		(15,405	)		(334,999	)
Total MTM Derivative Contract Net  Assets (Liabilities)	$	67,205		$	(14,929	)	$	(15,405	)	$	36,871

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009 (c)		Total (d)
Prices Actively Quoted - Exchange Traded Contracts	$	(2,461	)	$	11,840		$	996		$	545	$	-	$	-	$	10,920
Prices Provided by Other External Sources - OTC Broker Quotes (a)		18,934			13,138			18,121			7,227		1,057		-		58,477
Prices Based on Models and Other Valuation Methods (b)		(1,902	)		(10,877	)		(6,413	)		3,788		7,926		5,286		(2,192	)
Total	$	14,571		$	14,101		$	12,704		$	11,560	$	8,983	$	5,286	$	67,205

(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 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.
(c)	There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $7.5 million of this mark-to-market value is in 2010.
(d)	Amounts exclude Cash Flow and Fair Value Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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

The table provides detail on designated, effective cash flow hedges included in the Condensed Consolidated Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power			Foreign Currency			Interest Rate			Total
Beginning Balance December 31, 2004	$	2,422		$	(176	)	$	(11,570	)	$	(9,324	)
Changes in Fair Value (a)		(7,947	)		-			(4,866	)		(12,813	)
Reclassifications from AOCI to Net Income (b)		(3,780	)		3			1,100			(2,677	)
Ending Balance September 30, 2005	$	(9,305	)	$	(173	)	$	(15,336	)	$	(24,814	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $11,509 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$868	$1,183	$558	$297	$577	$1,883	$812	$277

VaR Associated with Debt Outstanding

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 $145 million and $99 million at September 30, 2005 and December 31, 2004, 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 operation or consolidated financial position.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended				Nine Months Ended
	2005		2004		2005			2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	497,663	$	428,688	$	1,441,352		$	1,316,778
Sales to AEP Affiliates		69,381		58,726		178,298			163,655
TOTAL		567,044		487,414		1,619,650			1,480,433
OPERATING EXPENSES
Fuel for Electric Generation		155,185		117,841		391,583			327,246
Purchased Electricity for Resale		24,217		19,727		79,182			54,157
Purchased Electricity from AEP Affiliates		108,008		90,257		341,994			268,537
Other Operation		81,156		70,724		229,448			211,524
Maintenance		44,865		36,240		129,321			130,493
Depreciation and Amortization		50,284		48,877		146,734			144,021
Taxes Other Than Income Taxes		23,662		22,995		71,023			69,947
Income Taxes		20,903		18,063		55,901			78,339
TOTAL		508,280		424,724		1,445,186			1,284,264
OPERATING INCOME		58,764		62,690		174,464	��		196,169
Nonoperating Income		5,554		571		13,744			9,149
Carrying Costs Income		1,255		65		5,320			187
Nonoperating Expenses		3,291		1,497		10,295			7,239
Nonoperating Income Tax Credit		66		1,899		1,344			3,524
Interest Charges		24,976		25,269		76,320			76,169
NET INCOME		37,372		38,459		108,257			125,621
Preferred Stock Dividend Requirements, Including Capital Stock     Expense and Other Expense		238		796		1,940			2,417
EARNINGS APPLICABLE TO COMMON STOCK	$	37,134	$	37,663	$	106,317		$	123,204

The common stock of APCo is wholly-owned by AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(600	)					(600	)
Capital Stock Expense				1,817		(1,817	)					-
TOTAL												1,286,387
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $7,746									(14,366	)		(14,366	)
NET INCOME						125,621						125,621
TOTAL COMPREHENSIVE INCOME												111,255
SEPTEMBER 30, 2004	$	260,458	$	721,716	$	481,922		$	(66,454	)	$	1,397,642
DECEMBER 31, 2004	$	260,458	$	722,314	$	508,618		$	(81,672	)	$	1,409,718
Capital Contribution from Parent				150,000								150,000
Preferred Stock Dividends						(600	)					(600	)
Capital Stock Expense and Other				2,485		(1,340	)					1,145
TOTAL												1,560,263
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $8,340									(15,490	)		(15,490	)
NET INCOME						108,257						108,257
TOTAL COMPREHENSIVE INCOME												92,767
SEPTEMBER 30, 2005	$	260,458	$	874,799	$	614,935		$	(97,162	)	$	1,653,030

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	2,705,316		$	2,502,273
Transmission		1,265,837			1,255,390
Distribution		2,119,502			2,070,377
General		294,533			302,474
Construction Work in Progress		495,661			399,116
Total		6,880,849			6,529,630
Accumulated Depreciation and Amortization		2,499,612			2,443,218
TOTAL - NET		4,381,237			4,086,412
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		20,591			20,378
Other Investments		12,898			18,775
TOTAL		33,489			39,153
CURRENT ASSETS
Cash and Cash Equivalents		1,565			536
Other Cash Deposits		150			1,133
Advances to Affiliates		67,532			-
Accounts Receivable:
Customers		153,437			126,422
Affiliated Companies		131,359			140,950
Accrued Unbilled Revenues		28,824			51,427
Miscellaneous		1,427			1,264
Allowance for Uncollectible Accounts		(3,444	)		(5,561	)
Risk Management Assets		194,829			81,811
Fuel		55,537			45,756
Materials and Supplies		43,330			45,644
Margin Deposits		46,963			8,329
Prepayments and Other		37,312			12,192
TOTAL		758,821			509,903
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		329,729			343,415
Transition Regulatory Assets		22,284			25,467
Unamortized Loss on Reacquired Debt		18,174			18,157
Other		83,747			36,368
Long-term Risk Management Assets		177,041			81,245
Emission Allowances		49,257			38,931
Deferred Property Taxes		22,489			37,071
Deferred Charges and Other		8,986			23,796
TOTAL		711,707			604,450
TOTAL ASSETS	$	5,885,254		$	5,239,918

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
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		874,799			722,314
Retained Earnings		614,935			508,618
Accumulated Other Comprehensive Income (Loss)		(97,162	)		(81,672	)
Total Common Shareholder’s Equity		1,653,030			1,409,718
Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,784			17,784
Total Shareholders’ Equity		1,670,814			1,427,502
Long-term Debt:
Nonaffiliated		1,951,260			1,254,588
Affiliated		100,000			-
Total Long-term Debt		2,051,260			1,254,588
TOTAL		3,722,074			2,682,090
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		100,011			530,010
Advances from Affiliates		-			211,060
Accounts Payable:
General		197,577			130,710
Affiliated Companies		84,583			76,314
Risk Management Liabilities		188,278			89,136
Taxes Accrued		51,382			90,404
Interest Accrued		36,543			21,076
Customer Deposits		95,124			42,822
Obligations Under Capital Leases		5,760			6,742
Other		52,353			56,645
TOTAL		811,611			1,254,919
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		855,612			852,536
Regulatory Liabilities:
Asset Removal Costs		92,641			95,763
Over-recovery of Fuel Cost		52,041			57,843
Deferred Investment Tax Credits		26,981			30,382
Unrealized Gain on Forward Commitments		46,246			23,270
Employee Benefits and Pension Obligations		75,340			130,530
Long-term Risk Management Liabilities		146,721			57,349
Asset Retirement Obligations		26,059			24,626
Obligations Under Capital Leases		9,952			13,136
Deferred Credits		19,976			17,474
TOTAL		1,351,569			1,302,909
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,885,254		$	5,239,918

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	108,257		$	125,621
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		146,734			144,021
Accretion Expense		1,434			1,298
Deferred Income Taxes		25,103			31,596
Deferred Investment Tax Credits		(3,401	)		1,001
Deferred Property Taxes		14,582			14,574
Pension Contributions		(59,812	)		(1,047	)
Pension and Postemployment Benefit Reserves		4,622			(3,869	)
Mark-to-Market of Risk Management Contracts		(21,412	)		18,137
Over/Under Fuel Recovery		(21,001	)		(3,668	)
Carrying Costs Income		(5,320	)		(187	)
Change in Other Noncurrent Assets		(9,584	)		(19,804	)
Change in Other Noncurrent Liabilities		(17,825	)		8,608
Changes in Components of Working Capital:
Accounts Receivable, Net		2,899			59,734
Fuel, Materials and Supplies		(7,467	)		(7,810	)
Accounts Payable		58,112			(30,112	)
Taxes Accrued		(39,022	)		30,357
Customer Deposits		52,302			11,937
Interest Accrued		15,467			16,707
Other Current Assets		(63,754	)		4,629
Other Current Liabilities		(5,274	)		(8,542	)
Net Cash Flows From Operating Activities		175,640			393,181
INVESTING ACTIVITIES
Construction Expenditures		(421,544	)		(300,068	)
Change in Other Cash Deposits, Net		983			40,613
Proceeds from Sale of Assets		9,680			3,160
Net Cash Flows Used For Investing Activities		(410,881	)		(256,295	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		840,469			125,430
Issuance of Long-term Debt - Affiliated		100,000			-
Retirement of Long-term Debt		(575,007	)		(106,006	)
Capital Contribution from Parent		150,000			-
Changes in Advances to/from Affiliates, Net		(278,592	)		(106,773	)
Dividends Paid on Cumulative Preferred Stock		(600	)		(600	)
Dividends Paid on Common Stock		-			(50,000	)
Net Cash Flows From (Used For) Financing Activities		236,270			(137,949	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,029			(1,063	)
Cash and Cash Equivalents at Beginning of Period		536			4,561
Cash and Cash Equivalents at End of Period	$	1,565		$	3,498

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $56,253,000 and $53,622,000 and for income taxes was $61,514,000 and $(831,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 and 2004 were $1,087,000 and $2,848,000, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $17,024,000 and $370,000 in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed consolidated financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to APCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 7
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	53
Changes in Gross Margin:
Retail Margins	17
Off-system Sales	15
Transmission Revenues	(4	)
Other Revenues	2
Total Change in Gross Margin				30
Changes in Operating Expenses and Other:
Asset Impairments and Related Charges	(39	)
Other Operation and Maintenance	(10	)
Taxes Other Than Income Taxes	(9	)
Nonoperating Income and Expenses, Net	5
Interest Charges	1
Total Change in Operating Expenses and Other				(52	)
Income Tax Expense				3
Third Quarter of 2005 Net Income			$	34

Net Income decreased $19 million to $34 million in 2005. The key drivers of the decrease were a $39 million increase in Asset Impairments and Related Charges, a $10 million increase in Other Operation and Maintenance and a $9 million increase in Taxes Other Than Income Taxes partially offset by a $30 million increase in gross margin.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins were $17 million higher than the prior period primarily due to an increase of 53% in cooling degree days partially offset by lower fuel margins.

· Off-system Sales margins increased $15 million primarily due to increased AEP Power Pool physical sales and favorable optimization activity. 

· Transmission Revenues decreased $4 million primarily due to the loss of through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Asset Impairments and Related Charges increased $39 million due to the commitment to a plan to retire units 1 and 2 at our Conesville Plant.  In  September, we formally requested permission from PJM to retire the two units effective December 29, 2005.  We received preliminary approval on October 21, 2005. 

· Other Operation and Maintenance expenses increased $10 million due to increased consumption of NO_x allowances, increased boiler maintenance expenses due to overhaul work from scheduled and forced outages, increased overhead distribution line expenses and increased pension costs.

· Taxes Other Than Income Taxes increased $9 million 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 KWH sales.

· Nonoperating Income and Expenses, Net increased $5 million due to favorable optimization activities and the establishment of a regulatory asset for carrying costs on environmental capital expenditures as a result of the rate stabilization plan order.

Income Tax

The effective tax rates for the third quarter of 2005 and 2004 were 38.0% and 31.5%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The increase in the effective tax rate is primarily due to state income taxes.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	128
Changes in Gross Margin:
Retail Margins	7
Off-system Sales	21
Transmission Revenues	(15	)
Other Revenues	1
Total Change in Gross Margin				14
Changes in Operating Expenses and Other:
Asset Impairments and Related Charges	(39	)
Other Operation and Maintenance	1
Depreciation and Amortization	8
Taxes Other Than Income Taxes	(10	)
Nonoperating Income and Expenses, Net	11
Total Change in Operating Expenses and Other				(29	)
Income Tax Expense				3
Nine Months Ended September 30, 2005 Net Income			$	116

Net Income decreased $12 million to $116 million in 2005. The decrease is primarily due to a $39 million increase in Asset Impairments and Related Charges partially offset by an increase in gross margin of $14 million and an $11 million increase in Nonoperating Income and Expenses, Net.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins were $7 million higher than the prior period primarily due to favorable weather partially offset by lower fuel margins.

· Off-system Sales margins increased $21 million primarily due to increased AEP Power Pool physical sales and favorable optimization activity.

· Transmission Revenues decreased $15 million primarily due to the loss of through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Asset Impairments and Related Charges increased $39 million due to the commitment to a plan to retire units 1 and 2 at our Conesville Plant.  In September, we formally requested permission from PJM to retire two units effective December 29, 2005.  We received preliminary approval on October 21, 2005.

· Depreciation and Amortization expense decreased $8 million primarily due to the order in the rate stabilization plan which resulted in a reversal of unused shopping credits of $18 million partially offset by the establishment of a $7 million regulatory liability to benefit low income customers and for economic development.

· Taxes Other Than Income Taxes increased $10 million 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 KWH sales.

· Nonoperating Income and Expenses, Net increased $11 million due to the establishment of a regulatory asset for carrying costs on environmental capital expenditures as a result of the rate stabilization plan order and increased interest income from the corporate borrowing program.

Income Tax

The effective tax rates for the nine months ended September 2005 and 2004 were 34.7% and 33.6%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The effective tax rates remained relatively flat for the comparative period.

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-

Financing Activity

There were no long-term debt issuances or retirements during the first nine months of 2005.

In October 2005, we issued $250 million of 5.85% Senior Notes, Series F, due in October 2035.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end.

Significant Factors

Monongahela Power Company

In June 2005, the PUCO ordered us to explore the purchase of the Ohio service territory of Monongahela Power, which includes approximately 29,000 customers. On August 2, 2005, we agreed to terms of a transaction, which includes the transfer to us of Monongahela Power’s Ohio customer base and the assets that serve those customers for an estimated sales price of approximately $45 million. The net assets are being acquired at net book value. The sale price will be adjusted based on book values of the acquired assets and certain related liabilities at the closing date. In addition, we will pay $10 million to compensate Monongahela Power for its termination of certain generation cost recovery litigation in Ohio. We are proposing that the $10 million payment be recorded as a regulatory asset and recovered from large commercial and industrial customers in the Monongahela Power Ohio service territory over approximately 5 years with a carrying cost.

Also included in the proposed transaction is 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. We are proposing that beginning June 1, 2007, we will acquire power on the market to meet the needs of the acquired customers through December 31, 2008 (the end of the Rate Stabilization Plans (RSP) period). We have proposed a generation surcharge to be applied to all of our customers to recover the difference between the cost of power included in our generation rates and the higher Allegheny and subsequent market-based purchased power cost to meet the power requirements of the customers acquired from Monongahela Power through the end of the RSP period. We are proposing to institute a true-up mechanism with over/under-recovery deferral accounting for any difference between the surcharge recoveries and the actual cost differential. We have also requested permission to defer with a carrying cost incremental costs associated with the transaction for future recovery in our next distribution rate case. Hearings at the PUCO were held in September 2005.  If the transaction is approved by the PUCO, we expect to close the proposed transaction in December 2005.  Management is unable to predict the ultimate effect of this transaction on revenues, 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 “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	30,919
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(7,681	)
Fair Value of New Contracts When Entered During the Period (b)		599
Net Option Premiums Paid/(Received) (c)		(395	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		15,294
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		229
Total MTM Risk Management Contract Net Assets		38,965
Net Cash Flow Hedge Contracts (f)		(8,013	)
DETM Assignment (g)		(8,932	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	22,020

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	112,753		$	209		$	-		$	112,962
Noncurrent Assets		102,413			230			-			102,643
Total MTM Derivative Contract Assets		215,166			439			-			215,605
Current Liabilities		(98,767	)		(8,204	)		(2,122	)		(109,093	)
Noncurrent Liabilities		(77,434	)		(248	)		(6,810	)		(84,492	)
Total MTM Derivative Contract  Liabilities		(176,201	)		(8,452	)		(8,932	)		(193,585	)
Total MTM Derivative Contract Net  Assets (Liabilities)	$	38,965		$	(8,013	)	$	(8,932	)	$	22,020

(a)	Does not include Cash Flow Hedges.
(b)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009 (c)		Total (d)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,427	)	$	6,865		$	577		$	316	$	-	$	-	$	6,331
Prices Provided by Other External Sources - OTC Broker Quotes (a)		10,978			7,619			10,503			4,190		613		-		33,903
Prices Based on Models and Other Valuation Methods (b)		(1,104	)		(6,305	)		(3,717	)		2,197		4,595		3,065		(1,269	)
Total	$	8,447		$	8,179		$	7,363		$	6,703	$	5,208	$	3,065	$	38,965

(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 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.
(c)	There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $4.4 million of this mark-to-market value is in 2010.
(d)	Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

The table provides detail on designated, effective cash flow hedges included in the Condensed Consolidated Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power
Beginning Balance December 31, 2004	$	1,393
Changes in Fair Value (a)		(4,871	)
Reclassifications from AOCI to Net Income (b)		(1,918	)
Ending Balance September 30, 2005	$	(5,396	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $5,384 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$503	$686	$323	$172	$332	$1,083	$467	$160

VaR Associated with Debt Outstanding

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 $45 million and $48 million at September 30, 2005 and December 31, 2004, 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 operation or financial position.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended					Nine Months Ended
	2005		2004			2005		2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	425,738	$	369,329		$	1,105,863	$	1,050,794
Sales to AEP Affiliates		25,440		21,796			70,451		61,748
TOTAL		451,178		391,125			1,176,314		1,112,542
OPERATING EXPENSES
Fuel for Electric Generation		62,470		49,732			170,380		142,528
Fuel from Affiliates for Electric Generation		-		-			-		10,603
Purchased Electricity for Resale		9,016		5,389			26,922		14,839
Purchased Electricity from AEP Affiliates		109,274		96,193			284,221		263,614
Other Operation		66,217		60,657			173,287		177,920
Maintenance		21,863		17,417			63,947		60,187
Asset Impairments and Other Related Charges		39,109		-			39,109		-
Depreciation and Amortization		37,454		37,933			102,985		111,196
Taxes Other Than Income Taxes		43,342		34,017			112,417		102,069
Income Taxes		19,432		24,525			57,901		65,187
TOTAL		408,177		325,863			1,031,169		948,143
OPERATING INCOME		43,001		65,262			145,145		164,399
Nonoperating Income		4,865		1,681			10,653		7,298
Carrying Costs Income		1,800		127			8,716		358
Nonoperating Expenses		427		444			2,169		2,037
Nonoperating Income Tax Expense (Credit)		1,506		(383	)		3,913		(92	)
Interest Charges		13,508		14,439			42,088		41,666
NET INCOME		34,225		52,570			116,344		128,444
Preferred Stock Dividend Requirements including Capital Stock   Expense and Other Expense		254		254			2,366		762
EARNINGS APPLICABLE TO COMMON STOCK	$	33,971	$	52,316		$	113,978	$	127,682

The common stock of CSPCo is wholly-owned by AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(93,750	)					(93,750	)
Capital Stock Expense				762		(762	)					-
TOTAL												804,131
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,248									(2,317	)		(2,317	)
NET INCOME						128,444						128,444
TOTAL COMPREHENSIVE INCOME												126,127
SEPTEMBER 30, 2004	$	41,026	$	577,162	$	360,714		$	(48,644	)	$	930,258
DECEMBER 31, 2004	$	41,026	$	577,415	$	341,025		$	(60,816	)	$	898,650
Common Stock Dividends						(85,500	)					(85,500	)
Capital Stock Expense and Other				2,366		(2,366	)					-
TOTAL												813,150
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $3,655									(6,789	)		(6,789	)
NET INCOME						116,344						116,344
TOTAL COMPREHENSIVE INCOME												109,555
SEPTEMBER 30, 2005	$	41,026	$	579,781	$	369,503		$	(67,605	)	$	922,705

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	1,849,869		$	1,658,552
Transmission		446,356			432,714
Distribution		1,325,806			1,300,252
General		161,915			167,985
Construction Work in Progress		120,624			131,743
Total		3,904,570			3,691,246
Accumulated Depreciation and Amortization		1,479,077			1,471,950
TOTAL - NET		2,425,493			2,219,296
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		21,780			22,322
Other Investments		4,094			5,147
TOTAL		25,874			27,469
CURRENT ASSETS
Cash and Cash Equivalents		1,068			25
Other Cash Deposits		-			33
Advances to Affiliates		-			141,550
Accounts Receivable:
Customers		46,411			41,130
Affiliated Companies		73,450			72,854
Accrued Unbilled Revenues		19,987			19,580
Miscellaneous		2,432			1,145
Allowance for Uncollectible Accounts		(498	)		(674	)
Fuel		29,054			34,026
Materials and Supplies		25,861			37,137
Risk Management Assets		112,962			46,631
Margin Deposits		27,230			4,848
Prepayments and Other		17,501			11,499
TOTAL		355,458			409,784
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		18,131			16,481
Transition Regulatory Assets		151,851			156,676
Unamortized Loss on Reacquired Debt		12,581			13,155
Other		42,223			25,691
Long-term Risk Management Assets		102,643			46,735
Deferred Property Taxes		17,711			64,754
Deferred Charges and Other		50,807			49,855
TOTAL		395,947			373,347
TOTAL ASSETS	$	3,202,772		$	3,029,896

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
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		579,781			577,415
Retained Earnings		369,503			341,025
Accumulated Other Comprehensive Income (Loss)		(67,605	)		(60,816	)
Total Common Shareholder’s Equity		922,705			898,650
Preferred Stock - No Shares Outstanding		-			-
Authorized - 2,500,000 shares at $100 par value
Authorized - 7,000,000 shares at $25 par value
Total Shareholder’s Equity		922,705			898,650
Long-term Debt:
Nonaffiliated		851,822			851,626
Affiliated		100,000			100,000
Total Long-term Debt		951,822			951,626
TOTAL		1,874,527			1,850,276
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		36,000			36,000
Advances from Affiliates		138,541			-
Accounts Payable:
General		57,904			63,606
Affiliated Companies		53,489			45,745
Customer Deposits		55,651			24,890
Taxes Accrued		102,791			195,284
Interest Accrued		8,300			16,320
Risk Management Liabilities		109,093			42,172
Obligations Under Capital Leases		3,057			3,854
Other		22,875			24,338
TOTAL		587,701			452,209
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		437,994			464,545
Regulatory Liabilities:
Asset Removal Costs		108,265			103,104
Deferred Investment Tax Credits		25,953			27,933
Other		24,009			-
Employee Benefits and Pension Obligations		25,321			62,778
Long-term Risk Management Liabilities		84,492			32,731
Obligations Under Capital Leases		6,873			8,660
Asset Retirement Obligations		12,222			11,585
Deferred Credits and Other		15,415			16,075
TOTAL		740,544			727,411
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	3,202,772		$	3,029,896

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	116,344		$	128,444
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		102,985			111,196
Deferred Income Taxes		(9,441	)		10,210
Deferred Investment Tax Credits		(1,980	)		(2,133	)
Impairment of Long-Lived Assets		39,109			-
Pension and Postemployment Benefit Reserves		374			(1,894	)
Deferred Property Taxes		47,640			46,512
Mark-to-Market of Risk Management Contracts		(12,768	)		10,130
Carrying Costs Income		(8,716	)		(358	)
Pension Contributions		(37,831	)		(24	)
Gain on Sale of Assets		(1,560	)		(2,315	)
Change in Other Noncurrent Assets		(20,439	)		(33,811	)
Change in Other Noncurrent Liabilities		13,710			7,362
Changes in Components of Working Capital:
Accounts Receivable, Net		(7,747	)		24,242
Fuel, Materials and Supplies		19,345			(13,545	)
Accounts Payable		3,023			(13,269	)
Taxes Accrued		(94,788	)		2,115
Customer Deposits		30,761			6,684
Interest Accrued		(8,020	)		(8,640	)
Other Current Assets		(28,384	)		2,958
Other Current Liabilities		(3,259	)		(2,903	)
Net Cash Flows From Operating Activities		138,358			270,961
INVESTING ACTIVITIES
Construction Expenditures		(118,222	)		(103,257	)
Change in Other Cash Deposits, Net		33			666
Purchase of Waterford Plant		(218,356	)		-
Proceeds from Sale of Assets		4,639			3,392
Net Cash Flows Used For Investing Activities		(331,906	)		(99,199	)
FINANCING ACTIVITIES
Changes in Advances to/from Affiliates, Net		280,091			(164,888	)
Dividends Paid on Common Stock		(85,500	)		(93,750	)
Issuance of Long-term Debt - Nonaffiliated		-			90,057
Issuance of Long-term Debt - Affiliated		-			100,000
Retirement of Long-term Debt		-			(103,245	)
Net Cash Flows From (Used For) Financing Activities		194,591			(171,826	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,043			(64	)
Cash and Cash Equivalents at Beginning of Period		25			3,377
Cash and Cash Equivalents at End of Period	$	1,068		$	3,313

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $50,095,000 and $46,034,000 and for income taxes was $109,382,000 and $(5,282,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $520,000 and $731,000 in 2005 and 2004, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $(981,000) and $(2,266,000) in 2005 and 2004, respectively. In connection with the acquisition of the Waterford Plant in September 2005, we assumed $2,295,000 of liabilities.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to CSPCo’s condensed consolidated financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to CSPCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Customer Choice and Industry Restructuring	Note 4
Commitments and Contingencies	Note 5
Guarantees	Note 6
Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	Note 7
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	52
Changes in Gross Margin:
Retail Margins	32
Transmission Revenues	(6	)
Total Change in Gross Margin				26
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(17	)
Taxes Other Than Income Taxes	(7	)
Nonoperating Income and Expenses, Net	4
Total Change in Operating Expenses and Other				(20	)
Income Tax Expense				(5	)
Third Quarter of 2005 Net Income			$	53

Net Income increased $1 million to $53 million in the third quarter of 2005. The key drivers of the increase were a $26 million increase in gross margin partially offset by a $17 million increase in Other Operation and Maintenance expenses and a $7 million increase in Taxes Other Than Income Taxes.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins increased $32 million primarily due to increases in retail sales to residential and commercial customers and capacity settlement payments received under the Interconnection Agreement related to the increase in an affiliate’s peak load. Increased retail sales primarily reflect warmer summer weather. Cooling degree days were 17% higher than normal and 67% higher than 2004.

· Transmission Revenues decreased $6 million primarily due to the loss of through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $17 million primarily due to a $9 million increase related to higher costs of labor and allowances for power generation and a $4 million increase in distribution maintenance expense for overhead power lines.

· Taxes Other Than Income Taxes increased due to a $5 million increase in real & personal property taxes and a $2 million increase in payroll-related taxes related to higher labor costs.

· Nonoperating Income and Expenses, Net increased due to $3 million of favorable results from favorable optimization activities. 

Income Tax

The effective tax rates for the third quarter of 2005 and 2004 were 38.0% and 34.5%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate is primarily due to federal income tax adjustments.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	122
Changes in Gross Margin:
Retail Margins	48
Transmission Revenues	(17	)
Off-system Sales and Other Revenues	2
Total Change in Gross Margin				33
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(20	)
Taxes Other Than Income Taxes	(9	)
Interest Charges	4
Total Change in Operating Expenses and Other				(25	)
Income Tax Expense				(2	)
Nine Months Ended September 30, 2005 Net Income			$	128

Net Income increased $6 million to $128 million in the first nine months of 2005. The key driver of the increase was a $33 million increase in gross margin partially offset by a $20 million increase in Other Operation and Maintenance expenses.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins increased $48 million primarily due to a $33 million increase in capacity settlement payments received under the Interconnection Agreement related to the increase in an affiliate’s peak load and higher residential revenue of $20 million reflecting warm summer weather partially offset by an increase in unrecovered fuel costs due to fuel caps in our Indiana jurisdiction.

· Transmission Revenues decreased $17 million primarily due to the loss of through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate change

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $20 million primarily due to a $9 million increase in distribution maintenance mainly related to January 2005 storm damage, a $5 million increase in system dispatch costs related to our operation in PJM and $4 million of accruals for employee severance costs partially offset by the settlement and cancellation of COLI policies in February 2005.

· Taxes Other Than Income Taxes increased $9 million primarily due to a $6 million increase in real and personal property taxes and a $3 million increase in payroll-related taxes.

· Interest Charges decreased $4 million primarily due to lower long-term debt outstanding and lower interest rates.

Income Tax

The effective tax rates for the nine months ended September 2005 and 2004 were 35.7% and 36.1%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative periods.

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 the first nine months of 2005 and 2004 were as follows:

	2005			2004
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	465		$	3,899
Cash Flows From (Used For):
Operating Activities		204,343			414,654
Investing Activities		(176,571	)		(129,398	)
Financing Activities		(27,506	)		(286,774	)
Net Increase (Decrease) in Cash and Cash Equivalents		266			(1,518	)
Cash and Cash Equivalents at End of Period	$	731		$	2,381

Operating Activities

Net Cash Flows From Operating Activities were $204 million for the first nine months of 2005. We produced Net Income of $128 million during the period including noncash expense items of $163 million for depreciation, amortization and accretion. 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 most significant activities in these asset and liability accounts were contributions of $46 million to our pension trust and $137 million of federal income tax payments.

Net Cash Flows From Operating Activities were $415 million during 2004. We produced Net Income of $122 million during the period and noncash expense items of $158 million for depreciation, amortization and accretion. The other changes in assets and liabilities represent items that had a 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; the most significant relates to Taxes Accrued. 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.

Investing Activities

Net Cash Flows Used For Investing Activities during 2005 were $177 million due primarily to Construction Expenditures. Construction Expenditures were primarily for nuclear generation, transmission and distribution assets to upgrade or replace equipment and improve reliability. For the remainder of 2005, we expect our construction expenditures to be approximately $130 million.

Net Cash Flows Used For Investing Activities were $129 million during 2004 for Construction Expenditures.

Financing Activities

Net Cash Flows Used For Financing Activities were $28 million during 2005. We used cash of $61 million to retire preferred stock and $52 million to pay common dividends. These activities were supported by additional borrowing from the Utility Money Pool of $86 million. There were no long-term debt issuances or retirements during the first nine months of 2005.

Net Cash Flows Used For Financing Activities were $287 million during 2004. We used cash from operations to retire long-term debt and pay common dividends.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Off-Balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current policy restricts the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that are entered in the normal course of business. Our off-balance sheet arrangements have not changed significantly since year-end. For complete information on our off-balance sheet arrangements, including the lease of Rockport Plant Unit 2, see “Off-balance Sheet Arrangements” in the “Management’s Financial Discussion and Analysis” section of our 2004 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the $61 million retirement of preferred stock and entering a long-term power contract.

During October 2005, we entered into a 20-year power agreement effective January 1, 2006, with Indiana Municipal Power Agency (IMPA). The 150 megawatt agreement is expected to generate annual revenue of approximately $55 million. The contract contains routine remedy clauses in case of default.

Significant Factors

Nuclear Licenses

In August 2005, the Nuclear Regulatory Commission approved the renewal of operating licenses for the two generating units at our Cook Plant. The licenses now expire in 2034 for Unit 1 and 2037 for Unit 2. Based on this renewal, we adjusted our asset retirement obligation liability and related plant asset. We are evaluating the effect of relicensing on current depreciation rates and decommissioning funding. If any changes are necessary, we will need IURC and MPSC approval.

Spent Nuclear Fuel Litigation

As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, we, along with a number of nonaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, we filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In January 2003, the U.S. Court of Federal Claims ruled in our favor on the issue of liability. The case was tried in March 2004 on the issue of damages owed to us by the DOE. In May 2004, the U.S. Court of Federal Claims ruled against us and denied damages, ruling that pre-breach and post-breach damages are not recoverable in a partial breach case. In July 2004, we appealed this ruling to the U.S. Court of Appeals for the Federal Circuit. In September 2005, the U.S. Court of Appeals ruled that the trial court erred in ruling that pre-breach damages in a partial breach case are per se not recoverable, but denied us our pre-breach damages on the facts alleged. The Court of Appeals also ruled that the trial court did not err in determining that post-breach damages are not recoverable in a partial breach case, but determined that we may recover our post-breach damages in later suits as the costs are incurred.

Indiana Settlement Agreement

Our fuel and base rates in Indiana were frozen through a prior agreement. In 2004, the IURC ordered the continuation of the fixed fuel adjustment charge on an interim basis through March 2005, pending the outcome of negotiations. Certain of the parties to the negotiations reached a settlement and signed an agreement on March 10, 2005 and filed the agreement with the IURC on March 14, 2005. The IURC approved the agreement on June 1, 2005.

The approved settlement caps fuel rates for the March 2004 through June 2007 billing months at an increasing rate that includes 8.609 mills per KWH reflected in base rates. The settlement provides that the total capped fuel rates will be 9.88 mills per KWH from January 2005 through December 2005, 10.26 mills per KWH from January 2006 through December 2006, and 10.63 mills per KWH from January 2007 through June 2007. Pursuant to a separate IURC order, we began billing the 9.88 mills per KWH total fuel rate on an interim basis effective with the April 2005 billing month. In accordance with the agreement, the October 2005 through March 2006 factor will be adjusted for the delayed implementation of the 2005 factor.

The settlement agreement also covers certain events at the Cook Plant. The settlement provides that if an outage of greater than 60 days occurs at Cook Plant, the recovery of actual monthly fuel costs will be in effect for the outage period beyond 60 days, capped by the average AEP System Pool Primary Energy Rate (Primary Energy Rate), the ratio of the sum of fuel and one half maintenance expenses incurred by the pool members to the total kilowatt-hours of net generation, excluding us, as defined by the AEP System Interconnection Agreement and adjusted for losses. If a second outage greater than 60 days occurs, actual monthly fuel costs capped at the Primary Energy Rate would be recovered through June 2007. Over the term of the settlement, if total cumulative actual fuel costs (except during a Cook Plant outage of greater than 60 days) are less than the cap prices, the savings will be credited to customers over the next two fuel adjustment clause filings. Cumulative net fuel costs in excess of the capped prices cannot be recovered. If Cook Plant operates at a capacity factor greater than 87% during the fuel cap period, we will receive credit for 30% of the savings produced by that performance.

The settlement agreement also caps base rates from January 1, 2005 to June 30, 2007 at the rates in effect as of January 1, 2005. During this cap period, we may not implement a general increase in base rates or implement a rider or cost deferral not established in the settlement agreement unless the IURC determines that a significant change in conditions beyond our control occurs or a material impact on us occurs as a result of federal, state or local regulation or statute that mandates reliability standards related to transmission or distribution costs.

We experienced a cumulative under-recovery for the period March 2004 through September 2005 of $10 million. Since we expect that its cumulative fuel costs through the end of the fuel cap period will exceed the capped fuel rates, the $10 million was recorded as fuel expense.  If future fuel costs per KWH through June 30, 2007 continue to exceed the caps, or if the base rate cap precludes us from seeking timely rate increases to recover increases in its cost of service through June 30, 2007, future results of operations and cash flows would be adversely affected.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	34,573
(Gain) Loss from Contracts Realized/Settled During the Period (a)		216
Fair Value of New Contracts When Entered During the Period (b)		-
Net Option Premiums Paid/(Received) (c)		(648	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		1,330
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		4,234
Total MTM Risk Management Contract Net Assets		39,705
Net Cash Flow and Fair Value Hedge Contracts (f)		(6,813	)
DETM Assignment (g)		(9,123	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	23,769

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	115,223		$	2,146		$	-		$	117,369
Noncurrent Assets		105,169			235			-			105,404
Total MTM Derivative Contract Assets		220,392			2,381			-			222,773
Current Liabilities		(101,169	)		(8,697	)		(2,167	)		(112,033	)
Noncurrent Liabilities		(79,518	)		(497	)		(6,956	)		(86,971	)
Total MTM Derivative Contract Liabilities		(180,687	)		(9,194	)		(9,123	)		(199,004	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	39,705		$	(6,813	)	$	(9,123	)	$	23,769

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009 (c)		Total (d)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,458	)	$	7,012		$	590		$	323	$	-	$	-	$	6,467
Prices Provided by Other External Sources - OTC Broker Quotes (a)		11,152			7,712			11,045			4,280		626		-		34,815
Prices Based on Models and Other Valuation Methods (b)		(1,129	)		(6,605	)		(3,856	)		2,189		4,694		3,130		(1,577	)
Total	$	8,565		$	8,119		$	7,779		$	6,792	$	5,320	$	3,130	$	39,705

(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 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.
(c)	There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $4.4 million of this mark-to-market value is in 2010.
(d)	Amounts exclude Cash Flow and Fair Value Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The table provides detail on designated, effective cash flow hedges included in the Condensed Consolidated Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2004	$	1,558		$	(5,634	)	$	(4,076	)
Changes in Fair Value (a)		(4,907	)		1,256			(3,651	)
Reclassifications from AOCI to Net  Income (b)		(2,162	)		428			(1,734	)
Ending Balance September 30, 2005	$	(5,511	)	$	(3,950	)	$	(9,461	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $5,950 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$514	$701	$330	$176	$371	$1,211	$522	$178

VaR Associated with Debt Outstanding

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 $52 million and $53 million at September 30, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended					Nine Months Ended
	2005		2004			2005		2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	409,282	$	372,556		$	1,128,374	$	1,067,144
Sales to AEP Affiliates		84,207		70,378			244,616		193,048
TOTAL		493,489		442,934			1,372,990		1,260,192
OPERATING EXPENSES
Fuel for Electric Generation		89,334		75,086			245,500		204,709
Purchased Electricity for Resale		11,784		10,063			35,786		22,617
Purchased Electricity from AEP Affiliates		82,763		74,498			228,756		203,291
Other Operation		109,210		100,535			300,212		307,501
Maintenance		42,300		33,737			144,988		118,055
Depreciation and Amortization		42,726		43,170			127,695		128,581
Taxes Other Than Income Taxes		17,007		10,291			49,624		40,979
Income Taxes		31,403		28,072			69,663		67,169
TOTAL		426,527		375,452			1,202,224		1,092,902
OPERATING INCOME		66,962		67,482			170,766		167,290
Nonoperating Income		22,793		20,304			61,999		60,758
Nonoperating Expenses		19,255		20,810			54,506		52,837
Nonoperating Income Tax Expense (Credit)		1,145		(953	)		1,558		1,538
Interest Charges		16,343		16,381			48,427		52,087
NET INCOME		53,012		51,548			128,274		121,586
Preferred Stock Dividend Requirements including Capital Stock   Expense		86		119			311		356
EARNINGS APPLICABLE TO COMMON STOCK	$	52,926	$	51,429		$	127,963	$	121,230

The common stock of I&M is wholly-owned by AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(79,293	)					(79,293	)
Preferred Stock Dividends						(255	)					(255	)
Capital Stock Expense				107		(101	)					6
TOTAL												998,505
COMPREHENSIVE INCOME
Other Comprehensive Loss,  Net of Taxes:
Cash Flow Hedges, Net of Tax of $4,720									(8,765	)		(8,765	)
NET INCOME						121,586						121,586
TOTAL COMPREHENSIVE INCOME												112,821
SEPTEMBER 30, 2004	$	56,584	$	858,801	$	229,812		$	(33,871	)	$	1,111,326
DECEMBER 31, 2004	$	56,584	$	858,835	$	221,330		$	(45,251	)	$	1,091,498
Common Stock Dividends						(52,000	)					(52,000	)
Preferred Stock Dividends						(255	)					(255	)
Capital Stock Expense and Other				2,455		(56	)					2,399
TOTAL												1,041,642
COMPREHENSIVE INCOME
Other Comprehensive Loss,  Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,900									(5,385	)		(5,385	)
NET INCOME						128,274						128,274
TOTAL COMPREHENSIVE INCOME												122,889
SEPTEMBER 30, 2005	$	56,584	$	861,290	$	297,293		$	(50,636	)	$	1,164,531

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	3,111,119		$	3,122,883
Transmission		1,024,558			1,009,551
Distribution		1,016,092			990,826
General (including nuclear fuel)		259,800			275,622
Construction Work in Progress		264,049			163,515
Total		5,675,618			5,562,397
Accumulated Depreciation and Amortization		2,698,727			2,603,479
TOTAL - NET		2,976,891			2,958,918
OTHER PROPERTY AND INVESTMENTS
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds		1,120,190			1,053,439
Nonutility Property, Net		49,035			50,440
Other Investments		13,262			21,848
TOTAL		1,182,487			1,125,727
CURRENT ASSETS
Cash and Cash Equivalents		731			465
Other Cash Deposits		-			46
Advances to Affiliates		-			5,093
Accounts Receivable:
Customers		66,701			62,608
Affiliated Companies		106,996			124,134
Miscellaneous		2,772			4,339
Allowance for Uncollectible Accounts		(16	)		(187	)
Fuel		20,892			27,218
Materials and Supplies		105,365			103,342
Risk Management Assets		117,369			52,141
Margin Deposits		27,812			5,400
Prepayments and Other		27,607			10,541
TOTAL		476,229			395,140
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		124,979			147,167
Incremental Nuclear Refueling Outage Expenses, Net		33,738			44,244
Unrealized Loss on Forward Commitments		33,285			7,366
Unamortized Loss on Reacquired Debt		22,231			21,039
DOE Decontamination Fund		10,353			14,215
Other		34,042			23,649
Long-term Risk Management Assets		105,404			52,256
Emission Allowances		31,301			27,093
Deferred Property Taxes		12,558			22,372
Deferred Charges and Other Assets		15,912			28,955
TOTAL		423,803			388,356
TOTAL ASSETS	$	5,059,410		$	4,868,141

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
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			858,835
Retained Earnings		297,293			221,330
Accumulated Other Comprehensive Income (Loss)		(50,636	)		(45,251	)
Total Common Shareholder’s Equity		1,164,531			1,091,498
Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,084			8,084
Total Shareholders’ Equity		1,172,615			1,099,582
Long-term Debt		1,317,825			1,312,843
TOTAL		2,490,440			2,412,425
CURRENT LIABILITIES
Cumulative Preferred Stock Due Within One Year		-			61,445
Advances from Affiliates		81,101			-
Accounts Payable:
General		98,153			91,472
Affiliated Companies		58,374			51,066
Customer Deposits		57,599			29,366
Taxes Accrued		37,409			123,159
Interest Accrued		22,823			12,465
Risk Management Liabilities		112,033			47,174
Obligations Under Capital Leases		5,501			6,124
Other		87,654			70,237
TOTAL		560,647			492,508
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		292,912			315,730
Regulatory Liabilities:
Asset Removal Costs		289,405			280,054
Deferred Investment Tax Credits		77,306			82,802
Excess ARO for Nuclear Decommissioning		269,406			245,175
Unrealized Gain on Forward Commitments		65,687			35,534
Other		33,816			33,695
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		63,692			66,472
Long-term Risk Management Liabilities		86,971			36,815
Obligations Under Capital Leases		38,152			44,608
Asset Retirement Obligations		720,532			711,769
Employee Benefits and Pension Obligations		31,388			70,027
Deferred Credits and Other		39,056			40,527
TOTAL		2,008,323			1,963,208
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,059,410		$	4,868,141

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	128,274		$	121,586
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		127,695			128,581
Accretion Expense		35,742			29,608
Amortization, Net of Deferrals of Incremental Nuclear Refueling Outage Expenses		10,506			31,195
Deferred Income Taxes		2,269			2,772
Deferred Investment Tax Credits		(5,496	)		(5,496	)
Deferred Property Taxes		9,814			10,020
Pension Contributions		(46,051	)		(2,916	)
Mark-to-Market of Risk Management Contracts		(11,275	)		10,760
Change in Other Noncurrent Assets		4,873			(21,135	)
Change in Other Noncurrent Liabilities		(6,420	)		(4,050	)
Changes in Components of Working Capital:
Accounts Receivable, Net		14,441			41,624
Fuel, Materials and Supplies		4,303			(9,391	)
Accounts Payable		5,511			(13,238	)
Taxes Accrued		(85,750	)		55,077
Customer Deposits		28,233			9,115
Interest Accrued		10,358			2,742
Rent Accrued - Rockport Plant Unit 2		18,464			18,464
Other Current Assets		(39,478	)		5,230
Other Current Liabilities		(1,670	)		4,106
Net Cash Flows From Operating Activities		204,343			414,654
INVESTING ACTIVITIES
Construction Expenditures		(190,171	)		(130,241	)
Change in Other Cash Deposits, Net		46			(31	)
Proceeds from Sale of Assets		13,554			874
Net Cash Flows Used For Investing Activities		(176,571	)		(129,398	)
FINANCING ACTIVITIES
Retirement of Cumulative Preferred Stock		(61,445	)		(2,011	)
Retirement of Long-term Debt		-			(205,155	)
Changes in Advances to/from Affiliates, Net		86,194			(60	)
Dividends Paid on Common Stock		(52,000	)		(79,293	)
Dividends Paid on Cumulative Preferred Stock		(255	)		(255	)
Net Cash Flows Used For Financing Activities		(27,506	)		(286,774	)
Net Increase (Decrease) in Cash and Cash Equivalents		266			(1,518	)
Cash and Cash Equivalents at Beginning of Period		465			3,899
Cash and Cash Equivalents at End of Period	$	731		$	2,381

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $34,999,000 and $46,694,000 and for income taxes was $149,058,000 and $(4,725,000) in 2005 and 2004, respectively. Noncash acquisitions under capital leases were $1,465,000 and $10,092,000 in 2005 and 2004, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $8,478,000 and $(10,646,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to I&M.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

KENTUCKY POWER COMPANY

KENTUCKY POWER COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	6
Changes in Gross Margin:
Retail Margins	8
Off-system Sales	1
Transmission Revenues	(1	)
Total Change in Gross Margin				8
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(4	)
Nonoperating Income and Expenses, Net	1
Total Change in Operating Expenses and Other:				(3	)
Income Tax Expense				(3	)
Third Quarter of 2005 Net Income			$	8

Net Income increased by $2 million to $8 million in the third quarter of 2005 in comparison to the third quarter of 2004. The key driver of the increase was an $8 million increase in gross margin partially offset by a $3 million increase in operating expenses and other and a $3 million increase in Income Tax Expense.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins increased by $8 million in comparison to 2004 primarily due to increases in retail sales to residential customers and the recording of a liability for the over-collection of fuel costs in the third quarter of 2004 that lowered retail margins in the prior year. The increase in retail sales to residential customers was primarily due to a 63% increase in cooling degree days in comparison to 2004. The increase in Retail Margins was partially offset by an increase in capacity settlement payments under the Interconnection Agreement.

· Off-system Sales margins for 2005 increased by $1 million compared to 2004 primarily due to increased AEP Power Pool physical sales.

· Transmission Revenues decreased $1 million primarily due to the elimination of revenues related to through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $4 million primarily due to distribution line maintenance and system dispatch costs related to our operation in PJM.

· Nonoperating Income and Expenses, Net increased $1 million due to favorable optimization activities.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 31.1% and 11.4%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate is primarily due to federal income tax adjustments.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	22
Changes in Gross Margin:
Retail Margins	(3	)
Off-system Sales	8
Transmission Revenues	(4	)
Other Revenues	(1	)
Total Change in Gross Margin				-
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(4	)
Nonoperating Income and Expenses, Net	2
Total Change in Operating Expenses and Other				(2	)
Nine Months Ended September 30, 2005 Net Income			$	20

Net Income decreased by $2 million to $20 million in the nine months ended September 30, 2005 in comparison to the nine months ended September 30, 2004. The key driver of the decrease was a $2 million increase in operating expenses and other.

The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins decreased by $3 million in comparison to 2004 primarily due to an increase in capacity settlement payments under the Interconnection Agreement resulting from our higher MLR share caused by the increase in our peak load established in January 2005.

· Off-system Sales margins for 2005 increased by $8 million compared to 2004 primarily due to increased AEP Power Pool physical sales.

· Transmission Revenues decreased $4 million primarily due to the elimination of revenues related to through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $4 million primarily due to increased transmission charges under the Transmission Equalization Agreement resulting from our higher MLR as well as system dispatch costs related to our operation in PJM.

· Nonoperating Income and Expenses, Net increased $2 million due to favorable optimization activities.

Income Taxes

The effective tax rates for the nine months ended September 2005 and 2004 were 28.5% and 27.4%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative periods.

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

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2005 were:

Issuances

None

Retirements

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
Notes Payable-Affiliated	$	20,000		6.501		2006

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the $20 million retirement of Notes Payable-Affiliated.

Significant Factors

Rate Filing

On September 26, 2005, we filed a request with the Kentucky Public Service Commission to increase base rates by approximately $65 million to recover increasing costs. A final order is expected in April 2006. We are unable to predict the ultimate effect of this filing on future revenues, 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 “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	12,691
(Gain) Loss from Contracts Realized/Settled During the Period (a)		36
Fair Value of New Contracts When Entered During the Period (b)		-
Net Option Premiums Paid/(Received) (c)		(171	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		820
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		2,615
Total MTM Risk Management Contract Net Assets		15,991
Net Cash Flow and Fair Value Hedge Contracts (f)		(4,399	)
DETM Assignment (g)		(3,666	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	7,926

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.

Reconciliation of MTM Risk Management Contracts to

Condensed Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	46,287		$	86		$	-		$	46,373
Noncurrent Assets		42,060			95			-			42,155
Total MTM Derivative Contract Assets		88,347			181			-			88,528
Current Liabilities		(40,554	)		(3,489	)		(871	)		(44,914	)
Noncurrent Liabilities		(31,802	)		(1,091	)		(2,795	)		(35,688	)
Total MTM Derivative Contract Liabilities		(72,356	)		(4,580	)		(3,666	)		(80,602	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	15,991		$	(4,399	)	$	(3,666	)	$	7,926

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009 (c)		Total (d)
Prices Actively Quoted - Exchange Traded Contracts	$	(586	)	$	2,818		$	237		$	130	$	-	$	-	$	2,599
Prices Provided by Other External Sources - OTC Broker Quotes (a)		4,504			3,125			4,323			1,720		251		-		13,923
Prices Based on Models and Other Valuation Methods (b)		(454	)		(2,594	)		(1,528	)		900		1,887		1,258		(531	)
Total	$	3,464		$	3,349		$	3,032		$	2,750	$	2,138	$	1,258	$	15,991

(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 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.
(c)	There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $1.8 million of this mark-to-market value is in 2010.
(d)	Amounts exclude Cash Flow and Fair Value Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The table provides detail on designated, effective cash flow hedges included in the Condensed Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2004	$	569		$	244		$	813
Changes in Fair Value (a)		(1,889	)		-			(1,889	)
Reclassifications from AOCI to Net Income (b)		(895	)		(64	)		(959	)
Ending Balance September 30, 2005	$	(2,215	)	$	180		$	(2,035	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,124 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$207	$282	$133	$71	$135	$442	$191	$65

VaR Associated with Debt Outstanding

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 and $16 million at September 30, 2005 and December 31, 2004, 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 operation or financial position.

KENTUCKY POWER COMPANY

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended					Nine Months Ended
	2005		2004			2005		2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	127,129	$	100,950		$	352,083	$	302,376
Sales to AEP Affiliates		16,160		13,111			41,356		32,096
TOTAL		143,289		114,061			393,439		334,472
OPERATING EXPENSES
Fuel for Electric Generation		41,907		29,380			100,491		75,498
Purchased Electricity for Resale		1,563		359			5,473		1,118
Purchased Electricity from AEP Affiliates		45,300		37,366			131,049		101,730
Other Operation		15,992		13,405			45,969		40,176
Maintenance		7,180		5,925			21,578		23,464
Depreciation and Amortization		11,318		11,004			33,695		32,768
Taxes Other Than Income Taxes		2,457		2,208			7,101		6,931
Income Taxes		3,212		935			7,499		8,489
TOTAL		128,929		100,582			352,855		290,174
OPERATING INCOME		14,360		13,479			40,584		44,298
Nonoperating Income		966		(137	)		2,032		1,297
Nonoperating Expenses		89		168			401		1,755
Nonoperating Income Tax Expense (Credit)		283		(144	)		492		(238	)
Interest Charges		7,227		7,158			21,665		22,239
NET INCOME	$	7,727	$	6,160		$	20,058	$	21,839

The common stock of KPCo is wholly-owned by AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(16,000	)					(16,000	)
TOTAL												301,138
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $542									(1,005	)		(1,005	)
NET INCOME						21,839						21,839
TOTAL COMPREHENSIVE INCOME												20,834
SEPTEMBER 30, 2004	$	50,450	$	208,750	$	69,990		$	(7,218	)	$	321,972
DECEMBER 31, 2004	$	50,450	$	208,750	$	70,555		$	(8,775	)	$	320,980
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,534									(2,848	)		(2,848	)
NET INCOME						20,058						20,058
TOTAL COMPREHENSIVE INCOME												17,210
SEPTEMBER 30, 2005	$	50,450	$	208,750	$	90,613		$	(11,623	)	$	338,190

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005		2004
ELECTRIC UTILITY PLANT
Production	$	470,873	$	462,641
Transmission		386,461		385,667
Distribution		451,199		438,766
General		59,718		57,929
Construction Work in Progress		23,068		16,544
Total		1,391,319		1,361,547
Accumulated Depreciation and Amortization		421,738		398,455
TOTAL - NET		969,581		963,092
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		5,433		5,438
Other Investments		350		422
TOTAL		5,783		5,860
CURRENT ASSETS
Cash and Cash Equivalents		347		127
Other Cash Deposits		8		5
Advances to Affiliates		9,641		16,127
Accounts Receivable:
Customers		25,239		22,130
Affiliated Companies		23,279		23,046
Accrued Unbilled Revenues		5,933		7,340
Miscellaneous		717		94
Allowance for Uncollectible Accounts		-		(34	)
Fuel		12,851		6,551
Materials and Supplies		7,285		9,385
Risk Management Assets		46,373		19,845
Margin Deposits		11,180		1,960
Prepayments and Other		6,793		1,782
TOTAL		149,646		108,358
DEFERRED DEBITS AND OTHER ASSETS					��
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		98,737		103,849
Other		26,256		14,558
Long-term Risk Management Assets		42,155		19,067
Emission Allowances		12,077		9,666
Deferred Property Taxes		1,803		7,036
Deferred Charges and Other		7,498		11,761
TOTAL		188,526		165,937
TOTAL ASSETS	$	1,313,536	$	1,243,247

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
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		90,613			70,555
Accumulated Other Comprehensive Income (Loss)		(11,623	)		(8,775	)
Total Common Shareholder’s Equity		338,190			320,980
Long-term Debt:
Nonaffiliated		426,657			428,310
Affiliated		20,000			80,000
Total Long-term Debt		446,657			508,310
TOTAL		784,847			829,290
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Affiliated		40,000			-
Accounts Payable:
General		29,759			20,080
Affiliated Companies		26,546			24,899
Risk Management Liabilities		44,914			17,205
Taxes Accrued		8,695			9,248
Interest Accrued		9,507			6,754
Customer Deposits		25,085			12,309
Obligations Under Capital Leases		1,294			1,561
Other		8,849			9,038
TOTAL		194,649			101,094
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		222,727			227,536
Regulatory Liabilities:
Asset Removal Costs		30,247			28,232
Deferred Investment Tax Credits		5,845			6,722
Other Regulatory Liabilities		26,772			15,622
Employee Benefits and Pension Obligations		9,980			17,729
Long-term Risk Management Liabilities		35,688			13,484
Obligations Under Capital Leases		2,123			2,802
Deferred Credits		658			736
TOTAL		334,040			312,863
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	1,313,536		$	1,243,247

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	20,058		$	21,839
Adjustments to Reconcile Net Income to Net Cash Flows  From Operating Activities:
Depreciation and Amortization		33,695			32,768
Deferred Income Taxes		1,836			6,536
Deferred Investment Tax Credits		(877	)		(877	)
Deferred Property Taxes		5,233			5,091
Pension Contributions		(9,137	)		(338	)
Pension and Postemployment Benefit Reserves		1,388			(610	)
Mark-to-Market of Risk Management Contracts		(5,204	)		3,994
Over/Under Fuel Recovery		(4,453	)		1,886
(Gain)/Loss on Sale of Assets		(41	)		1,062
Change in Other Noncurrent Assets		(5,196	)		(10,558	)
Change in Other Noncurrent Liabilities		8,700			7,112
Changes in Components of Working Capital:
Accounts Receivable, Net		(2,592	)		9,817
Fuel, Materials and Supplies		(4,200	)		3,106
Accounts Payable		12,876			7,788
Taxes Accrued		(553	)		4,012
Customer Deposits		12,776			2,828
Interest Accrued		2,753			2,159
Other Current Assets		(14,231	)		817
Other Current Liabilities		(456	)		(530	)
Net Cash Flows From Operating Activities		52,375			97,902
INVESTING ACTIVITIES
Construction Expenditures		(38,837	)		(27,797	)
Change in Other Cash Deposits, Net		(3	)		11
Proceeds from Sale of Assets		199			1,538
Net Cash Flows Used For Investing Activities		(38,641	)		(26,248	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Affiliated		-			20,000
Retirement of Long-term Debt-Affiliated		(20,000	)		-
Changes in Advances to/from Affiliates, Net		6,486			(75,875	)
Dividends Paid on Common Stock		-			(16,000	)
Net Cash Flows Used For Financing Activities		(13,514	)		(71,875	)
Net Increase (Decrease) in Cash and Cash Equivalents		220			(221	)
Cash and Cash Equivalents at Beginning of Period		127			863
Cash and Cash Equivalents at End of Period	$	347		$	642

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $17,250,000 and $19,198,000 and for income taxes was $7,466,000 and $(3,233,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 and 2004 were $273,000 and $697,000, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $(1,550,000) and $(1,127,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to KPCo’s condensed financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to KPCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

OHIO POWER COMPANY CONSOLIDATED

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	51
Changes in Gross Margin:
Retail Margins	12
Off-system Sales	14
Transmission Revenues	(5	)
Other Revenues	(2	)
Total Change in Gross Margin				19
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(20	)
Depreciation and Amortization	(2	)
Taxes Other Than Income Taxes	(9	)
Nonoperating Income and Expenses, Net	19
Total Change in Operating Expenses and Other				(12	)
Income Tax Expense				(2	)
Third Quarter of 2005 Net Income			$	56

Net Income increased $5 million in the third quarter of 2005. The key drivers of the increase were a $19 million increase in gross margin and a $19 million increase in Nonoperating Income and Expenses, Net partially offset by a $20 million increase in Other Operation and Maintenance expense and a $9 million increase in Taxes Other Than Income Taxes.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins were $12 million higher than the prior period primarily due to:

- increased retail sales of $25 million due to increased industrial, residential and commercial sales from higher usage and favorable weather conditions,

- partially offset by decreased fuel margins of $15 million, of which $9 million is related to an amendment to the PJM Services and Cost Allocation Agreement and the Buckeye Station Agreement.

· Margins from Off-system Sales increased $14 million primarily due to increased AEP Power Pool physical sales and favorable optimization activity.

· Transmission Revenues decreased $5 million primarily due to the loss of through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $20 million primarily due to $11 million of increased consumption expenses associated with SO₂ and NO_x allowances, $4 million from increased boiler maintenance expenses due to overhaul work from scheduled and forced outages and $3 million from increased maintenance of overhead lines due to storm repair, increased tree trimming expenses and greater expenses for transmission inspection programs.

· Taxes Other Than Income Taxes increased $9 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 KWH sales.

· Nonoperating Income and Expenses, Net increased $19 million primarily due to the establishment of a regulatory asset for carrying costs on environmental capital expenditures as a result of the rate stabilization plan order and favorable optimization activities.

Income Tax

The effective tax rates for the third quarter of 2005 and 2004 were 31.9% and 32.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The effective tax rates remained relatively flat for the comparative period.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	170
Changes in Gross Margin:
Retail Margins	41
Off-system Sales	26
Transmission Revenues	(19	)
Total Change in Gross Margin				48
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(6	)
Depreciation and Amortization	(13	)
Taxes Other Than Income Taxes	(9	)
Nonoperating Income and Expenses, Net	48
Interest Charges	11
Total Change in Operating Expenses and Other				31
Income Tax Expense				(22	)
Nine Months Ended September 30, 2005 Net Income			$	227

Net Income increased $57 million in 2005. The increase is primarily due to a $48 million increase in gross margin, a $48 million increase in Nonoperating Income and Expenses, Net and an $11 million decrease in Interest Charges offset by a $22 million increase in Income Tax Expense and a $13 million increase in Depreciation and Amortization expense.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail Margins were $41 million higher than the prior period primarily due to:

- increased retail sales of $39 million due to increased residential, commercial and industrial sales from higher usage and favorable weather conditions,

- a favorable variance of $18 million from the receipt of SO₂ allowances from Buckeye Power, Inc. under the Cardinal Station Allowance Agreement,

- and an increase of $8 million from capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak load,

- partially offset by decreased fuel margins of $31 million which includes an amendment to the PJM Services and Cost Allocation Agreement and the Buckeye Station Agreement of $9 million.

· Margins from Off-system Sales increased $26 million primarily due to increased AEP Power Pool physical sales and favorable optimization activity.

· Transmission Revenues decreased $19 million primarily due to the loss of through and out rates, net of replacement SECA rates. See “FERC Order on Regional Through and Out Rates” for additional discussion of these FERC rate changes.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $6 million primarily due to increased consumption expenses associated with SO₂ and NO_x allowances and increased maintenance of overhead lines due to storm repair, increased tree trimming expenses and greater expenses for transmission inspection programs offset by the settlement and cancellation of the COLI policy in February 2005 and decreased administrative expenses related to the Gavin scrubber.

· Depreciation and Amortization expense increased $13 million due to the establishment of a $7 million regulatory liability to benefit low income customers and for economic development, as ordered in the rate stabilization plan. The increase is also attributable to a higher depreciation base in electric utility plants.

· Taxes Other Than Income Taxes increased $9 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 KWH sales.

· Nonoperating Income and Expenses, Net increased $48 million primarily due to the establishment of a $37 million regulatory asset for carrying costs on environmental capital expenditures as a result of the rate stabilization plan order and favorable optimization activities slightly offset by decreased pension costs in 2004 as a result of a settlement related to the sale of the coal companies prior to 2003.

· Interest Charges decreased by $11 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 Charges also decreased due to refinancing debt maturities and optional redemptions with lower cost debt.

Income Tax

The effective tax rates for the nine months ended September 2005 and 2004 were 32.7% and 34.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The effective tax rates remained relatively flat for the comparative period.

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 the nine months ended September 30, 2005 and 2004 were as follows:

	2005			2004
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	9,300		$	7,233
Cash Flows From (Used For):
Operating Activities		313,784			448,099
Investing Activities		(451,347	)		(151,912	)
Financing Activities		129,645			(299,977	)
Net Decrease in Cash and Cash Equivalents		(7,918	)		(3,790	)
Cash and Cash Equivalents at End of Period	$	1,382		$	3,443

Operating Activities

Our Net Cash Flows From Operating Activities were $314 million for the first nine months of 2005. We produced income of $227 million during the period and a noncash expense item of $228 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 primarily relates to two items Taxes Accrued and Accounts Payable. Taxes Accrued decreased $115 million due primarily to the payment of the 2004 federal income tax liability during 2005 and personal property tax. Accounts Payable increased $60 million due to higher fuel and allowance acquisition costs not paid at September 30, 2005.

Our Net Cash Flows From Operating Activities were $448 million for the first nine months of 2004. We produced income of $170 million during the period and a noncash expense item of $214 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a 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 primarily relates to a $52 million increase in Taxes Accrued primarily due to increased accrued federal income taxes offset by decreased accrued personal property taxes.

Investing Activities

Our Net Cash Flows Used for Investing Activities for the first nine months of 2005 were $451 million primarily due to Construction Expenditures for environmental upgrades, as well as projects to improve service reliability for transmission and distribution. For the remainder of 2005, we expect our Construction Expenditures to be approximately $305 million.

Our Net Cash Flows Used For Investing Activities for the first nine months of 2004 were $152 million. The change is primarily due to Construction Expenditures offset by a cash deposit that we used to redeem $50 million of debt in January 2004.

Financing Activities

Our Net Cash Flows From Financing Activities during the first nine months of 2005 were $130 million primarily due to increased borrowings from the Utility Money Pool.

Our Net Cash Flows Used For Financing Activities during the first nine months of 2004 were $300 million primarily due to decreased repayments of borrowings from the Utility Money Pool and dividend payments on Common Stock.

Financing Activity

In January 2005, we redeemed $5 million of 5.90% Cumulative Preferred Stock Subject to Mandatory Redemption. Additionally, long-term debt issuances and retirements during the nine months ended September 30, 2005 were:

Issuances

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
Installment Purchase Contracts	$	54,500		Variable		2029
Installment Purchase Contracts		163,500		Variable		2028
Installment Purchase Contracts		50,000		Variable		2016
Installment Purchase Contracts		50,000		Variable		2014
Installment Purchase Contracts		35,000		Variable		2022

Retirements and Principal Payments

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
Installment Purchase Contracts	$	102,000		6.375		2029
Installment Purchase Contracts		80,000		Variable		2028
Installment Purchase Contracts		36,000		Variable		2029
Installment Purchase Contracts		50,000		5.45		2014
Installment Purchase Contracts		50,000		5.45		2016
Installment Purchase Contracts		35,000		5.90		2022
Notes Payable		4,390		6.81		2008
Notes Payable		6,500		6.27		2009

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements discussed above.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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.

Roll-Forward of MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	47,777
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(13,828	)
Fair Value of New Contracts When Entered During the Period (b)		835
Net Option Premiums Paid/(Received) (c)		(1,372	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		18,093
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		314
Total MTM Risk Management Contract Net Assets		51,819
Net Cash Flow Hedge Contracts (f)		(10,778	)
DETM Assignment (g)		(12,267	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	28,774

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(g)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	157,786		$	5,007		$	-		$	162,793
Noncurrent Assets		143,373			316			-			143,689
Total MTM Derivative Contract Assets		301,159			5,323			-			306,482
Current Liabilities		(140,353	)		(15,761	)		(2,914	)		(159,028	)
Noncurrent Liabilities		(108,987	)		(340	)		(9,353	)		(118,680	)
Total MTM Derivative Contract Liabilities		(249,340	)		(16,101	)		(12,267	)		(277,708	)
Total MTM Derivative Contract Net Asset (Liabilities)	$	51,819		$	(10,778	)	$	(12,267	)	$	28,774

(a)	Does not include Cash Flow Hedges.
(b)	See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009 (c)		Total (d)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,960	)	$	9,429		$	793		$	434	$	-	$	-	$	8,696
Prices Provided by Other External Sources - OTC Broker Quotes (a)		15,336			8,420			15,527			5,755		841		-		45,879
Prices Based on Models and Other Valuation Methods (b)		(1,544	)		(9,259	)		(5,306	)		2,832		6,312		4,209		(2,756	)
Total	$	11,832		$	8,590		$	11,014		$	9,021	$	7,153	$	4,209	$	51,819

(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 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.
(c)	There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $6 million of this mark-to-market value is in 2010.
(d)	Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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

The table provides detail on designated, effective cash flow hedges included in the Condensed Consolidated Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power			Interest   Rate		Foreign  Currency			Total
Beginning Balance December 31, 2004	$	1,599		$	-	$	(358	)	$	1,241
Changes in Fair Value (a)		(7,540	)		1,047		-			(6,493	)
Reclassifications from AOCI to Net Income (b)		(2,319	)		-		10			(2,309	)
Ending Balance September 30, 2005	$	(8,260	)	$	1,047	$	(348	)	$	(7,561	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $7,924 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$691	$942	$444	$237	$464	$1,513	$652	$223

VaR Associated with Debt Outstanding

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 $121 million and $146 million at September 30, 2005 and December 31, 2004, 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 operation or consolidated financial position.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended					Nine Months Ended
	2005		2004			2005		2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	471,175	$	417,176		$	1,377,528	$	1,260,440
Sales to AEP Affiliates		164,341		147,602			472,787		429,503
TOTAL		635,516		564,778			1,850,315		1,689,943
OPERATING EXPENSES
Fuel for Electric Generation		199,965		164,353			548,919		476,127
Purchased Electricity for Resale		20,247		14,456			61,432		40,794
Purchased Electricity from AEP Affiliates		36,012		26,007			86,723		68,479
Other Operation		110,666		94,643			277,399		281,963
Maintenance		44,990		41,047			142,100		131,831
Depreciation and Amortization		73,799		71,857			227,687		214,027
Taxes Other Than Income Taxes		53,374		44,681			144,202		135,517
Income Taxes		21,684		26,897			92,319		89,099
TOTAL		560,737		483,941			1,580,781		1,437,837
OPERATING INCOME		74,779		80,837			269,534		252,106
Nonoperating Income		59,107		46,180			164,310		115,635
Carrying Costs Income		8,882		182			38,430		539
Nonoperating Expenses		53,251		50,809			146,305		108,109
Nonoperating Income Tax Expense (Credit)		4,693		(2,660	)		18,180		(693	)
Interest Charges		28,416		28,365			80,417		91,232
NET INCOME		56,408		50,685			227,372		169,632
Preferred Stock Dividend Requirements (Including Other Expense)		183		184			723		550
EARNINGS APPLICABLE TO COMMON STOCK	$	56,225	$	50,501		$	226,649	$	169,082

The common stock of OPCo is wholly-owned by AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(144,114	)					(144,114	)
Preferred Stock Dividends						(550	)					(550	)
TOTAL												1,319,361
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,820									(3,380	)		(3,380	)
Minimum Pension Liability, Net of Tax of $2,123									(3,942	)		(3,942	)
NET INCOME						169,632						169,632
TOTAL COMPREHENSIVE INCOME												162,310
SEPTEMBER 30, 2004	$	321,201	$	462,484	$	754,115		$	(56,129	)	$	1,481,671
DECEMBER 31, 2004	$	321,201	$	462,485	$	764,416		$	(74,264	)	$	1,473,838
Common Stock Dividends						(22,499	)					(22,499	)
Preferred Stock Dividends						(549	)					(549	)
Other				4,151		(174	)					3,977
TOTAL												1,454,767
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $4,739									(8,802	)		(8,802	)
NET INCOME						227,372						227,372
TOTAL COMPREHENSIVE INCOME												218,570
SEPTEMBER 30, 2005	$	321,201	$	466,636	$	968,566		$	(83,066	)	$	1,673,337

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	4,251,784		$	4,127,284
Transmission		999,475			978,492
Distribution		1,245,883			1,202,550
General		236,900			248,749
Construction Work in Progress		491,411			240,957
Total		7,225,453			6,798,032
Accumulated Depreciation and Amortization		2,689,961			2,617,238
TOTAL - NET		4,535,492			4,180,794
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		44,690			44,774
Other		8,836			13,409
TOTAL		53,526			58,183
CURRENT ASSETS
Cash and Cash Equivalents		1,382			9,300
Other Cash Deposits		28			37
Advances to Affiliates		-			125,971
Accounts Receivable:
Customers		118,233			98,951
Affiliated Companies		175,843			144,175
Accrued Unbilled Revenues		15,144			10,641
Miscellaneous		7,490			7,626
Allowance for Uncollectible Accounts		(991	)		(93	)
Fuel		93,008			70,309
Materials and Supplies		58,710			55,569
Emissions Allowances		34,072			95,303
Risk Management Assets		162,793			79,541
Margin Deposits		37,899			7,056
Prepayments and Other		16,328			10,492
TOTAL		719,939			714,878
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		174,821			169,866
Transition Regulatory Assets		161,050			225,273
Unamortized Loss on Reacquired Debt		13,866			11,046
Other		72,795			22,189
Long-term Risk Management Assets		143,689			66,727
Deferred Property Taxes		22,412			70,214
Deferred Charges and Other Assets		62,341			74,095
TOTAL		650,974			639,410
TOTAL ASSETS	$	5,959,931		$	5,593,265

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
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		466,636			462,485
Retained Earnings		968,566			764,416
Accumulated Other Comprehensive Income (Loss)		(83,066	)		(74,264	)
Total Common Shareholder’s Equity		1,673,337			1,473,838
Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,641			16,641
Total Shareholders’ Equity		1,689,978			1,490,479
Long-term Debt:
Nonaffiliated		1,589,860			1,598,706
Affiliated		200,000			400,000
Total Long-term Debt		1,789,860			1,998,706
TOTAL		3,479,838			3,489,185
Minority Interest		12,289			14,083
CURRENT LIABILITIES
Short-term Debt - Nonaffiliated		15,365			23,498
Long-term Debt Due Within One Year - Affiliated		200,000			-
Long-term Debt Due Within One Year - Nonaffiliated		12,354			12,354
Cumulative Preferred Stock Subject to Mandatory Redemption		-			5,000
Advances from Affiliates		55,508			-
Accounts Payable:
General		219,079			143,247
Affiliated Companies		139,432			116,615
Customer Deposits		63,684			22,620
Taxes Accrued		118,028			233,026
Interest Accrued		20,912			39,254
Risk Management Liabilities		159,028			70,311
Obligations Under Capital Leases		8,951			9,081
Other		79,608			74,977
TOTAL		1,091,949			749,983
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		913,308			943,465
Regulatory Liabilities:
Asset Removal Costs		111,376			102,875
Deferred Investment Tax Credits		10,255			12,539
Other		51,215			-
Long-term Risk Management Liabilities		118,680			46,261
Deferred Credits		17,358			24,377
Employee Benefits and Pension Obligations		68,615			126,825
Obligations Under Capital Leases		31,375			31,652
Asset Retirement Obligations		48,328			45,606
Other		5,345			6,414
TOTAL		1,375,855			1,340,014
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,959,931		$	5,593,265

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	227,372		$	169,632
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		227,687			214,027
Accretion Expense		2,722			2,548
Deferred Income Taxes		11,492			2,080
Deferred Investment Tax Credits		(2,284	)		(2,283	)
Deferred Property Taxes		47,802			46,804
Pension and Postemployment Benefit Reserves		1,810			1,903
Mark-to-Market of Risk Management Contracts		(10,840	)		11,632
Pension Contributions		(60,020	)		(574	)
Carrying Costs Income		(38,430	)		(539	)
Change in Other Noncurrent Assets		(8,972	)		(22,471	)
Change in Other Noncurrent Liabilities		(1,296	)		(4,719	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(54,419	)		17,891
Fuel, Materials and Supplies		(25,840	)		(6,930	)
Accounts Payable		60,224			4,378
Taxes Accrued		(114,998	)		51,710
Customer Deposits		41,064			10,600
Interest Accrued		(18,342	)		(19,340	)
Other Current Assets		24,551			(27,550	)
Other Current Liabilities		4,501			(700	)
Net Cash Flows From Operating Activities		313,784			448,099
INVESTING ACTIVITIES
Construction Expenditures		(460,282	)		(205,799	)
Change in Other Cash Deposits, Net		9			50,967
Proceeds from Sale of Assets		8,926			2,920
Net Cash Flows Used For Investing Activities		(451,347	)		(151,912	)
FINANCING ACTIVITIES
Change in Short-term Debt, Net		(8,133	)		(6,379	)
Issuance of Long-term Debt - Nonaffiliated		348,237			-
Issuance of Long-term Debt - Affiliated		-			400,000
Retirement of Long-term Debt - Nonaffiliated		(363,890	)		(382,390	)
Retirement of Cumulative Preferred Stock		(5,000	)		(2,250	)
Changes in Advances to/from Affiliates, Net		181,479			(164,294	)
Dividends Paid on Common Stock		(22,499	)		(144,114	)
Dividends Paid on Cumulative Preferred Stock		(549	)		(550	)
Net Cash Flows From (Used For) Financing Activities		129,645			(299,977	)
Net Decrease in Cash and Cash Equivalents		(7,918	)		(3,790	)
Cash and Cash Equivalents at Beginning of Period		9,300			7,233
Cash and Cash Equivalents at End of Period	$	1,382		$	3,443

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $92,073,000 and $107,177,000 and for income taxes was $158,627,000 and $(21,600,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $7,591,000 and $13,896,000 in 2005 and 2004, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $38,425,000 and $(1,051,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed consolidated financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to OPCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Customer Choice and Industry Restructuring	Note 4
Commitments and Contingencies	Note 5
Guarantees	Note 6
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

PUBLIC SERVICE COMPANY OF OKLAHOMA

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	39
Changes in Gross Margin:
Retail and Off-system Sales Margins	19
Transmission Revenues	2
Total Change in Gross Margin				21
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(9	)
Depreciation and Amortization	2
Nonoperating Income and Expenses, Net	1
Total Change in Operating Expenses and Other				(6	)
Income Tax Expense				(5	)
Third Quarter of 2005 Net Income			$	49

Net Income increased $10 million to $49 million in the third quarter of 2005. The key drivers of the increase were a $21 million increase in gross margin, partially offset by a $9 million increase in Other Operation and Maintenance expense and a $5 million increase in Income Tax Expense.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail and Off-system Sales Margins increased $19 million primarily due to an increase in base margins for higher sales volumes resulting from a 27% increase in cooling degree days.

Operating Expenses and Other increased between years as follows:

· Other Operation and Maintenance expense increased $9 million primarily due to $4 million of plant operation and maintenance and $3 million of overhead line maintenance.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 37.3% and 37.6%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income		$	37
Changes in Gross Margin:
Retail and Off-system Sales Margins	19
Transmission Revenues	2
Total Change in Gross Margin			21
Changes in Operating Expenses and Other:
Other Operation and Maintenance	16
Depreciation and Amortization	1
Taxes Other Than Income Taxes	4
Interest Charges	3
Nonoperating Income and Expenses, Net	2
Total Change in Operating Expenses and Other			26
Income Tax Expense			(16	)
Nine Months Ended September 30, 2005 Net Income		$	68

Net Income increased $31 million to $68 million for the nine months ended September 30, 2005. The key drivers of the increase were a $21 million increase in gross margin, a $16 million decrease in Other Operation and Maintenance expense and a $4 million decrease in Taxes Other Than Income Taxes, partially offset by a $16 million increase in Income Tax Expense.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail and Off-system Sales Margins increased $19 million primarily due to an increase in base margins for higher volumes resulting from an 8% increase in degree days.

Operating Expenses and Other decreased between years as follows:

· Other Operation and Maintenance expenses decreased $16 million. Transmission-related expenses decreased $5 million primarily due to adjustments in 2004 for affiliated OATT and ancillary services resulting from revised ERCOT data for the years 2001 through 2003. Distribution expenses decreased $4 million resulting primarily from a 2004 labor settlement. Administrative and general expenses decreased approximately $10 million due to lower outside services and employee-related expenses, offset in part by increased customer-related expense of $5 million. Plant operation expense increased $3 million. Maintenance decreased $4 million primarily due to the higher cost of scheduled power plant maintenance and overhead line maintenance, both in 2004.

· Taxes Other Than Income Taxes decreased $4 million primarily due to an adjustment for property related-taxes recorded in 2005.

· Interest Charges decreased $3 million primarily due to the retirement of higher rate First Mortgage Bonds and Trust Preferred Securities in 2004 which were replaced by lower rate Senior Unsecured Notes and affiliated notes.

Income Taxes

The effective tax rates for the nine months ended September 30, 2005 and 2004 were 33.0% and 32.2%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

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-

Financing Activity

Long-term issuances and retirements during the first nine months of 2005 were:

Issuances

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
Senior Unsecured Notes	$	75,000		4.70		2011

Retirements

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
First Mortgage Bonds	$	50,000		6.50		2005

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements discussed above.

Significant Factors

Oklahoma Regulatory Activity

Rate Review

We have been involved in a commission staff-initiated base rate review before the OCC which began in 2003. In March 2005, a settlement was negotiated and approved by the ALJ. The settlement provides for a $7 million annual base revenue reduction offset by a $6 million reduction in annual depreciation expense and recovery through fuel revenues of certain transmission expenses previously recovered in base rates. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. The settlement also provides for recovery over 24 months of $9 million of deferred fuel costs associated with a renegotiated coal transportation contract and the continuation of a $12 million vegetation management rider, both of which are earnings neutral. Finally, the settlement stipulates that we may not file for a base rate increase before April 1, 2006. The OCC issued an order approving the stipulation on May 2, 2005, and new base rates were implemented in June 2005. We anticipate that this order will favorably impact results of operations and cash flows beginning in 2006.

Fuel and Purchased Power

In 2002, we 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, we offered to the OCC to collect those reallocated costs over 18 months. In August 2003, the OCC Staff filed testimony recommending we recover $42 million of the reallocation over three years. Subsequently, the OCC expanded the case to include a full prudence review of our 2001 fuel and purchased power practices and off-system sales margin sharing between AEP East and AEP West companies for the year 2002. On July 25, 2005, the OCC Staff and two intervenors filed testimony in which they quantified the alleged improperly allocated off-system sales margins between AEP East and AEP West companies. Their overall recommendations would result in an increase in off-system sales margins and thus, a reduction in our recoverable fuel costs through June 2005 of an amount between $38 million and $47 million. We do not agree with the intervenors’ and the OCC Staff’s recommendations and will defend vigorously our position. In addition, PSO believes the amount of such alleged improper allocations is significantly overstated.

As noted in the 2004 Annual Report, an Oklahoma ALJ found that the OCC lacks authority to examine whether we deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. On September 29, 2005, the United States District Court, Western District of Texas, issued an order in the TNC fuel proceeding, preempting the PUCT from deciding this same allocation issue in Texas. Based on the position taken by the Federal court in Texas, it would appear that the OCC would be preempted from finding a disallowance in Oklahoma.

On June 10, 2005, the OCC decided to have its staff conduct a prudence review of our fuel and purchased power practices for 2003.

Management is unable to predict the ultimate effect of these proceedings on revenues, results of operations, cash flows and financial condition.

Generation

In September 2005, we began seeking proposals for up to 500 MW of new peaking and up to 600 MW of new base load generation to supplement existing power supply resources to effectively meet customers’ power demand requirements. We are soliciting purchase power agreements or plant acquisitions and they will be evaluated along with our self-build options. The target for commercial operation is June 1, 2008 for the peaking generation and June 1, 2011 for the base load generation.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	14,771
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(98	)
Fair Value of New Contracts When Entered During the Period (b)		-
Net Option Premiums Paid/(Received) (c)		(222	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		-
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		3,274
Total MTM Risk Management Contract Net Assets		17,725
Net Cash Flow Hedge Contracts (f)		(5,764	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	11,961

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Operations. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Condensed Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	53,434		$	150		$	53,584
Noncurrent Assets		32,440			166			32,606
Total MTM Derivative Contract Assets		85,874			316			86,190
Current Liabilities		(47,060	)		(5,902	)		(52,962	)
Noncurrent Liabilities		(21,089	)		(178	)		(21,267	)
Total MTM Derivative Contract Liabilities		(68,149	)		(6,080	)		(74,229	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	17,725		$	(5,764	)	$	11,961

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,027	)	$	4,942		$	416		$	228	$	-	$	-	$	4,559
Prices Provided by Other External Sources - OTC Broker Quotes (a)		7,629			2,634			6,404			2,282		-		-		18,949
Prices Based on Models and Other Valuation Methods (b)		(1,027	)		(5,938	)		(4,207	)		596		2,284		2,509		(5,783	)
Total	$	5,575		$	1,638		$	2,613		$	3,106	$	2,284	$	2,509	$	17,725

(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 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.
(c)	Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The table provides detail on designated, effective cash flow hedges included in the Condensed Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2004	$	1,000		$	(600	)	$	400
Changes in Fair Value (a)		(4,656	)		48			(4,608	)
Reclassifications from AOCI to Net Income (b)		(227	)		41			(186	)
Ending Balance September 30, 2005	$	(3,883	)	$	(511	)	$	(4,394	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $3,985 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$362	$494	$233	$124	$238	$778	$335	$115

VaR Associated with Debt Outstanding

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 $35 million at September 30, 2005 and December 31, 2004. 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 operation or financial position.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended					Nine Months Ended
	2005		2004			2005			2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	416,005	$	355,260		$	939,066		$	788,167
Sales to AEP Affiliates		16,032		1,371			32,314			7,467
TOTAL		432,037		356,631			971,380			795,634
OPERATING EXPENSES
Fuel for Electric Generation		192,955		139,693			456,662			315,773
Fuel from Affiliates for Electric Generation		-		19			-			30
Purchased Energy for Resale		39,186		41,059			84,111			55,810
Purchased Electricity from AEP Affiliates		26,643		24,083			64,877			79,182
Other Operation		39,630		36,882			106,102			117,256
Maintenance		17,809		11,777			43,321			47,774
Depreciation and Amortization		20,842		22,762			65,708			67,097
Taxes Other Than Income Taxes		9,769		9,483			25,507			29,027
Income Taxes		28,793		23,671			33,598			18,767
TOTAL		375,627		309,429			879,886			730,716
OPERATING INCOME		56,410		47,202			91,494			64,918
Nonoperating Income		1,460		640			2,462			1,011
Nonoperating Expenses		412		356			1,348			1,660
Nonoperating Income Tax Expense (Credit)		127		(162	)		(294	)		(1,021	)
Interest Charges		8,677		8,668			25,173			27,922
NET INCOME		48,654		38,980			67,729			37,368
Preferred Stock Dividend Requirements		53		53			159			159
EARNINGS APPLICABLE TO COMMON  STOCK	$	48,601	$	38,927		$	67,570		$	37,209

The common stock of PSO is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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
Gain on Reacquired Preferred Stock							2						2
Common Stock Dividends							(26,250	)					(26,250	)
Preferred Stock Dividends							(159	)					(159	)
TOTAL													456,601
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,335										(2,479	)		(2,479	)
NET INCOME							37,368						37,368
TOTAL COMPREHENSIVE INCOME													34,889
SEPTEMBER 30, 2004	$	157,230	$	230,016		$	150,565		$	(46,321	)	$	491,490
DECEMBER 31, 2004	$	157,230	$	230,016		$	141,935		$	75		$	529,256
Common Stock Dividends							(27,000	)					(27,000	)
Preferred Stock Dividends							(159	)					(159	)
TOTAL													502,097
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,581										(4,794	)		(4,794	)
NET INCOME							67,729						67,729
TOTAL COMPREHENSIVE INCOME													62,935
SEPTEMBER 30, 2005	$	157,230	$	230,016		$	182,505		$	(4,719	)	$	565,032

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	1,069,327		$	1,072,022
Transmission		477,425			468,735
Distribution		1,132,326			1,089,187
General		200,740			200,044
Construction Work in Progress		61,112			41,028
Total		2,940,930			2,871,016
Accumulated Depreciation and Amortization		1,163,806			1,117,113
TOTAL - NET		1,777,124			1,753,903
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		4,594			4,401
Other Investments		-			81
TOTAL		4,594			4,482
CURRENT ASSETS
Cash and Cash Equivalents		1,911			91
Other Cash Deposits		6			188
Accounts Receivable:
Customers		21,078			34,002
Affiliated Companies		58,524			46,399
Miscellaneous		7,759			6,984
Allowance for Uncollectible Accounts		(12	)		(76	)
Fuel		13,306			14,268
Materials and Supplies		40,320			35,485
Risk Management Assets		53,584			21,388
Regulatory Asset for Under-Recovered Fuel Costs		82,174			366
Margin Deposits		19,002			2,881
Prepayments and Other		10,576			1,378
TOTAL		308,228			163,354
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
Unamortized Loss on Reacquired Debt		13,018			14,705
Other		40,703			17,246
Long-term Risk Management Assets		32,606			14,477
Prepaid Pension Obligations		82,356			82,419
Deferred Property Taxes		8,123			-
Deferred Charges and Other Assets		16,267			18,232
TOTAL		193,073			147,079
TOTAL ASSETS	$	2,283,019		$	2,068,818

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
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		182,505			141,935
Accumulated Other Comprehensive Income (Loss)		(4,719	)		75
Total Common Shareholder’s Equity		565,032			529,256
Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,262			5,262
Total Shareholders’ Equity		570,294			534,518
Long-term Debt:
Nonaffiliated		521,056			446,092
Affiliated		-			50,000
Total Long-term Debt		521,056			496,092
TOTAL		1,091,350			1,030,610
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		-			50,000
Long-term Debt Due Within One Year - Affiliated		50,000			-
Advances from Affiliates		22,601			55,002
Accounts Payable:
General		140,811			71,442
Affiliated Companies		58,069			58,632
Customer Deposits		58,161			33,757
Taxes Accrued		19,315			18,835
Interest Accrued		3,498			4,023
Risk Management Liabilities		52,962			13,705
Obligations Under Capital Leases		581			537
Other		24,859			30,477
TOTAL		430,857			336,410
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		415,897			384,090
Long-term Risk Management Liabilities		21,267			7,455
Regulatory Liabilities:
Asset Removal Costs		215,325			220,298
Deferred Investment Tax Credits		27,530			28,620
SFAS 109 Regulatory Liability, Net		20,236			21,963
Unrealized Gain on Forward Commitments		41,820			19,676
Obligations Under Capital Leases		1,021			747
Deferred Credits and Other		17,716			18,949
TOTAL		760,812			701,798
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	2,283,019		$	2,068,818

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	67,729		$	37,368
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		65,708			67,097
Deferred Property Taxes		(8,123	)		(8,648	)
Deferred Income Taxes		32,661			10,519
Deferred Investment Tax Credits		(1,090	)		(1,343	)
Pension and Postemployment Benefit Reserves		(777	)		2,142
Mark-to-Market of Risk Management Contracts		(2,954	)		4,034
Pension Contributions		(198	)		(2,630	)
Change in Other Noncurrent Assets		(32,286	)		(15,667	)
Change in Other Noncurrent Liabilities		28,380			10,035
Changes in Components of Working Capital:
Accounts Receivable, Net		(40	)		(6,754	)
Fuel, Materials and Supplies		(3,873	)		(249	)
Fuel Recovery		(81,808	)		(1,874	)
Accounts Payable		67,802			(4,132	)
Customer Deposits		24,404			7,929
Taxes Accrued		480			27,363
Interest Accrued		(525	)		(73	)
Other Current Assets		(25,319	)		3,194
Other Current Liabilities		(5,574	)		(12,955	)
Net Cash Flows From Operating Activities		124,597			115,356
INVESTING ACTIVITIES
Construction Expenditures		(87,804	)		(57,654	)
Change in Other Cash Deposits, Net		182			10,520
Proceeds from Sale of Assets		-			458
Net Cash Flows Used For Investing Activities		(87,622	)		(46,676	)
FINANCING ACTIVITIES
Issuance of Long-term Debt		74,405			83,129
Retirement of Long-term Debt		(50,000	)		(112,020	)
Reacquired Preferred Stock		-			(3	)
Changes in Advances to/from Affiliates, Net		(32,401	)		(13,605	)
Dividends Paid on Common Stock		(27,000	)		(26,250	)
Dividends Paid on Cumulative Preferred Stock		(159	)		(159	)
Net Cash Flows Used For Financing Activities		(35,155	)		(68,908	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,820			(228	)
Cash and Cash Equivalents at Beginning of Period		91			3,738
Cash and Cash Equivalents at End of Period	$	1,911		$	3,510

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $21,954,000 and $24,518,000 and for income taxes was $14,241,000 and $2,387,000 in 2005 and 2004, respectively. Noncash capital lease acquisitions were $798,000 and $448,000 in 2005 and 2004, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $1,004,000 and $(1,842,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to PSO.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2005 Compared to Third Quarter of 2004

Reconciliation of Third Quarter of 2004 to Third Quarter of 2005 Net Income

(in millions)

Third Quarter of 2004 Net Income			$	47
Changes in Gross Margin:
Retail and Off-system Sales Margins (a)	19
Transmission Revenues	4
Other Revenues	2
Total Change in Gross Margin				25
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(20	)
Depreciation and Amortization	1
Taxes Other Than Income Taxes	(2	)
Nonoperating Income and Expenses, Net	1
Interest Charges	1
Total Change in Operating Expenses and Other				(19	)
Income Tax Expense				(3	)
Third Quarter of 2005 Net Income			$	50

(a)   Includes firm wholesale sales to municipals and cooperatives.

Net Income increased $3 million to $50 million in the third quarter of 2005. The key drivers of the increase were a $25 million increase in gross margin partially offset by a $20 million increase in Other Operation and Maintenance expense and a $3 million increase in Income Tax Expense.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail and Off-system Sales Margins increased $19 million primarily due to an increase in both retail base margins and wholesale base margins due to higher volumes resulting primarily from a 32% increase in cooling degree days.

· Transmission Revenues increased $4 million due to increased SPP revenue.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expense increased $20 million primarily due to increased power plant operation and maintenance expense of $8 million resulting from extended planned power plant outages and higher transmission-related expense from SPP. Distribution maintenance expense increased $6 million primarily due to $4 million of storm damage related to Hurricane Rita and higher overhead line expense. Customer-related expenses and administrative and general expenses increased $6 million, offset in part by lower employee-related expenses.

Income Taxes

The effective tax rates for the third quarter of 2005 and 2004 were 34.1% and 32.8%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Reconciliation of Nine Months Ended September 30, 2004 to

Nine Months Ended September 30, 2005 Net Income

(in millions)

Nine Months Ended September 30, 2004 Net Income			$	80
Changes in Gross Margin:
Retail and Off-system Sales Margins (a)	11
Transmission Revenues	4
Other Revenues	4
Total Change in Gross Margin				19
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(21	)
Depreciation and Amortization	(2	)
Interest Charges	4
Total Change in Operating Expenses and Other				(19	)
Income Tax Expense				1
Nine Months Ended September 30, 2005 Net Income			$	81

(a)   Includes firm wholesale sales to municipals and cooperatives.

Net Income increased $1 million to $81 million for the nine months ended September 30, 2005. The key drivers of the change were a $19 million increase in gross margin offset by a $21 million increase in Other Operation and Maintenance expense.

The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:

· Retail and Off-system Sales Margins increased $11 million primarily due to an increase in both retail base margins and wholesale base margins due to higher volumes resulting primarily from a 10% increase in degree days. These margins were offset in part by unfavorable optimization activity and increased purchased capacity.

· Transmission Revenues increased $4 million primarily due to increased SPP revenues.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expense increased $21 million primarily due to increased power plant operation and maintenance expense of $13 million resulting from extended planned power plant outages in 2005. This increase was partially offset by a $5 million adjustment in 2004 for affiliated OATT and ancillary services resulting from revised ERCOT data for the years 2001 through 2003. Distribution maintenance and customer expense increased $12 million primarily due to $4 million of storm damage related to Hurricane Rita and higher overhead line expense, offset in part by lower administrative and general and employee-related expenses.

· Interest Charges decreased $4 million primarily due to decreased long-term debt.

Income Taxes

The effective tax rates for the nine months ended September 30, 2005 and 2004 were 30.5% and 31.4%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

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 the nine months ended September 30, 2005 and 2004 were as follows:

	2005			2004
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	2,308		$	5,676
Cash Flows From (Used For):
Operating Activities		160,994			214,921
Investing Activities		(105,557	)		(63,535	)
Financing Activities		(53,941	)		(153,738	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,496			(2,352	)
Cash and Cash Equivalents at End of Period	$	3,804		$	3,324

Operating Activities

Our Net Cash Flows From Operating Activities were $161 million in 2005. We produced income of $81 million during the period and noncash expense items of $99 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 Payable and Customer Deposits. Accounts Payable increased $42 million primarily due to higher energy and fuel-related purchases. Customer Deposits increased $27 million primarily due to increased deposits for power trading customers.

Our Net Cash Flows From Operating Activities were $215 million in 2004. We produced income of $80 million during the period and noncash expense items of $97 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 Payable, Fuel, Materials and Supplies, and Taxes Accrued. Accounts Payable decreased $20 million related to lower vendor-related payables and lower energy transactions. Fuel, Materials and Supplies decreased $14 million primarily due to lower purchases of fuel. Taxes Accrued increased $64 million primarily due to the annual tax accruals related to 2004 property taxes and by an increase of income tax-related accruals.

Investing Activities

Net Cash Flows Used For Investing Activities during 2005 and 2004 were $106 million and $64 million, respectively. They were comprised of Construction Expenditures related to projects for improved transmission and distribution service reliability. For the remainder of 2005, we expect our Construction Expenditures to be approximately $100 million.

Financing Activities

Net Cash Flows Used For Financing Activities were $54 million during 2005. During the nine months ended September 30, 2005, we borrowed $40 million from the Utility Money Pool, issued Senior Unsecured Notes for $150 million for the purpose of funding the July 1, 2005 maturity of our $200 million Senior Unsecured Notes and retired $8 million of Notes Payable. Common stock dividends were $40 million.

Net Cash Flows Used For Financing Activities were $154 million during 2004. During the nine months ended September 30, 2004, we decreased our Utility Money Pool borrowing by $29 million, retired $120 million of First Mortgage Bonds, retired $7 million of Notes Payable, replaced $95 million of Installment Purchase Contracts with lower variable interest rate long-term debt of the same principal amount and paid $45 million in common stock dividends.

Financing Activity

Long-term issuances and retirements during the first nine months of 2005 were:

Issuances

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
Senior Unsecured Notes	$	150,000		4.90		2015
Notes Payable		5,771		Variable		2006

Retirements

	Principal		Interest		Due
Type of Debt	Amount		Rate		Date
	(in thousands)		(%)
Notes Payable	$	5,122		4.47		2011
Notes Payable		3,000		Variable		2008
Senior Unsecured Notes		200,000		4.50		2005

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements discussed above.

Significant Factors

Generation

In September 2005, we began seeking proposals for new generation to supplement existing power supply resources to effectively meet customers’ power demand requirements. The proposals will be evaluated along with our self-build options to meet short-term and long-term capacity needs.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for 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

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2005

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2004	$	17,527
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(3,653	)
Fair Value of New Contracts When Entered During the Period (b)		47
Net Option Premiums Paid/(Received) (c)		(326	)
Change in Fair Value Due to Valuation Methodology Changes		-
Changes in Fair Value of Risk Management Contracts (d)		4,510
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e)		2,563
Total MTM Risk Management Contract Net Assets		20,668
Net Cash Flow Hedge Contracts (f)		(6,921	)
Total MTM Risk Management Contract Net Assets at September 30, 2005	$	13,747

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005.
(d)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(e)	“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheets

As of September 30, 2005

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	62,400		$	176		$	62,576
Noncurrent Assets		38,031			194			38,225
Total MTM Derivative Contract Assets		100,431			370			100,801
Current Liabilities		(55,023	)		(6,975	)		(61,998	)
Noncurrent Liabilities		(24,740	)		(316	)		(25,056	)
Total MTM Derivative Contract Liabilities		(79,763	)		(7,291	)		(87,054	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	20,668		$	(6,921	)	$	13,747

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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, giving 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 September 30, 2005

(in thousands)

	Remainder of 2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,199	)	$	5,769		$	485		$	266	$	-	$	-	$	5,321
Prices Provided by Other External Sources - OTC Broker Quotes (a)		8,890			3,056			7,564			2,665		-		-		22,175
Prices Based on Models and Other Valuation Methods (b)		(1,198	)		(6,978	)		(4,928	)		680		2,667		2,929		(6,828	)
Total	$	6,493		$	1,847		$	3,121		$	3,611	$	2,667	$	2,929	$	20,668

(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 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.
(c)	Amounts exclude Cash Flow Hedges.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The table provides detail on designated, effective cash flow hedges included in the Condensed Consolidated Balance Sheets. The data in the table indicates the magnitude of cash flow hedges we have in place. 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

Nine Months Ended September 30, 2005

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2004	$	1,188		$	(2,008	)	$	(820	)
Changes in Fair Value (a)		(5,452	)		(3,378	)		(8,830	)
Reclassifications from AOCI to Net Income (b)		(270	)		135			(135	)
Ending Balance September 30, 2005	$	(4,534	)	$	(5,251	)	$	(9,785	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at September 30, 2005. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $5,063 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

Nine Months Ended				Twelve Months Ended
September 30, 2005				December 31, 2004
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$423	$577	$272	$145	$283	$923	$398	$136

VaR Associated with Debt Outstanding

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 $31 million and $31 million at September 30, 2005 and December 31, 2004, 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 operation or consolidated financial position.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	Three Months Ended						Nine Months Ended
	2005			2004			2005			2004
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	459,083		$	316,679		$	1,015,132		$	782,179
Sales to AEP Affiliates		14,614			14,888			38,573			54,597
TOTAL		473,697			331,567			1,053,705			836,776
OPERATING EXPENSES
Fuel for Electric Generation		179,598			109,468			385,875			292,536
Purchased Electricity for Resale		45,194			18,958			91,377			20,884
Purchased Electricity from AEP Affiliates		27,363			6,685			55,230			21,105
Other Operation		59,966			46,825			151,530			141,686
Maintenance		22,353			15,350			65,713			55,009
Depreciation and Amortization		32,930			33,676			98,580			96,940
Taxes Other Than Income Taxes		18,175			16,544			49,725			48,259
Income Taxes		25,896			23,443			36,353			38,013
TOTAL		411,475			270,949			934,383			714,432
OPERATING INCOME		62,222			60,618			119,322			122,344
Nonoperating Income		1,256			704			3,566			2,899
Nonoperating Expenses		473			669			1,564			2,003
Nonoperating Income Tax Credit		107			398			678			1,295
Interest Charges		12,346			12,944			38,027			41,766
Minority Interest		(1,035	)		(898	)		(2,735	)		(2,592	)
NET INCOME		49,731			47,209			81,240			80,177
Preferred Stock Dividend Requirements		57			57			172			172
EARNINGS APPLICABLE TO COMMON STOCK	$	49,674		$	47,152		$	81,068		$	80,005

The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(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						(45,000	)					(45,000	)
Preferred Stock Dividends						(172	)					(172	)
TOTAL												651,488
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net  of Taxes:
Cash Flow Hedges, Net of Tax of $2,189									(4,064	)		(4,064	)
Minimum Pension Liability, Net of Tax of $12,420									23,066			23,066
NET INCOME						80,177						80,177
TOTAL COMPREHENSIVE INCOME												99,179
SEPTEMBER 30, 2004	$	135,660	$	245,003	$	394,912		$	(24,908	)	$	750,667
DECEMBER 31, 2004	$	135,660	$	245,003	$	389,135		$	(1,180	)	$	768,618
Common Stock Dividends						(40,000	)					(40,000	)
Preferred Stock Dividends						(172	)					(172	)
TOTAL												728,446
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $4,827									(8,965	)		(8,965	)
NET INCOME						81,240						81,240
TOTAL COMPREHENSIVE INCOME												72,275
SEPTEMBER 30, 2005	$	135,660	$	245,003	$	430,203		$	(10,145	)	$	800,721

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2005 and December 31, 2004

(Unaudited)

(in thousands)

	2005			2004
ELECTRIC UTILITY PLANT
Production	$	1,664,614		$	1,663,161
Transmission		641,282			632,964
Distribution		1,144,445			1,114,480
General		435,727			427,910
Construction Work in Progress		75,491			48,852
Total		3,961,559			3,887,367
Accumulated Depreciation and Amortization		1,762,337			1,709,758
TOTAL - NET		2,199,222			2,177,609
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		4,047			4,049
Other Investments		4,611			4,628
TOTAL		8,658			8,677
CURRENT ASSETS
Cash and Cash Equivalents		3,804			2,308
Other Cash Deposits		1,748			6,292
Advances to Affiliates		-			39,106
Accounts Receivable:
Customers		35,940			39,042
Affiliated Companies		36,050			28,817
Miscellaneous		6,329			5,856
Allowance for Uncollectible Accounts		(383	)		(45	)
Fuel Inventory		38,883			45,793
Materials and Supplies		36,707			36,051
Risk Management Assets		62,576			25,379
Regulatory Asset for Under-Recovered Fuel Costs		62,738			4,687
Margin Deposits		22,185			3,419
Prepayments and Other		24,577			18,331
TOTAL		331,154			255,036
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		22,826			18,000
Unamortized Loss on Reacquired Debt		18,671			20,765
Other		28,528			16,350
Long-term Risk Management Assets		38,225			17,179
Prepaid Pension Obligations		80,255			81,132
Deferred Property Taxes		9,579			-
Deferred Charges and Other		44,919			51,561
TOTAL		243,003			204,987
TOTAL ASSETS	$	2,782,037		$	2,646,309

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

September 30, 2005 and December 31, 2004

(Unaudited)

	2005			2004
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $18 par value 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		430,203			389,135
Accumulated Other Comprehensive Income (Loss)		(10,145	)		(1,180	)
Total Common Shareholder’s Equity		800,721			768,618
Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,700			4,700
Total Shareholders’ Equity		805,421			773,318
Long-term Debt:
Nonaffiliated		687,376			545,395
Affiliated		50,000			50,000
Total Long-term Debt		737,376			595,395
TOTAL		1,542,797			1,368,713
Minority Interest		1,607			1,125
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		15,663			209,974
Advances from Affiliates		605			-
Accounts Payable:
General		87,889			40,001
Affiliated Companies		27,155			33,285
Customer Deposits		57,121			30,550
Taxes Accrued		50,129			45,474
Interest Accrued		11,851			12,509
Risk Management Liabilities		61,998			18,607
Obligations Under Capital Leases		5,021			3,692
Regulatory Liability for Over-Recovered Fuel Costs		1,769			9,891
Other		36,792			33,417
TOTAL		355,993			437,400
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		411,467			399,756
Long-term Risk Management Liabilities		25,056			9,128
Reclamation Reserve		-			7,624
Regulatory Liabilities:
Asset Removal Costs		257,573			249,892
Deferred Investment Tax Credits		32,319			35,539
Excess Earnings		3,167			3,167
Other		33,809			21,320
Asset Retirement Obligations		33,743			27,361
Obligations Under Capital Leases		34,250			30,854
Deferred Credits and Other		50,256			54,430
TOTAL		881,640			839,071
Commitments and Contingencies (Note 5)
TOTAL CAPITALIZATION AND LIABILITIES	$	2,782,037		$	2,646,309

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2005 and 2004

(Unaudited)

(in thousands)

	2005			2004
OPERATING ACTIVITIES
Net Income	$	81,240		$	80,177
Adjustments to Reconcile Net Income to Net Cash Flows  From Operating Activities:
Depreciation and Amortization		98,580			96,940
Deferred Property Taxes		(9,579	)		(9,687	)
Deferred Income Taxes		11,552			(7,303	)
Deferred Investment Tax Credits		(3,220	)		(3,244	)
Pension and Postemployment Benefit Reserves		(116	)		3,103
Mark-to-Market of Risk Management Contracts		(3,141	)		4,712
Pension Contributions		(231	)		(3,463	)
Change in Other Noncurrent Assets		(13,329	)		(7,485	)
Change in Other Noncurrent Liabilities		11,005			10,425
Changes in Components of Working Capital:
Accounts Receivable, Net		(4,266	)		(9,812	)
Fuel, Materials and Supplies		6,254			14,525
Over/Under Fuel Recovery		(66,173	)		12,304
Accounts Payable		42,158			(20,066	)
Taxes Accrued		4,655			63,540
Customer Deposits		26,571			7,873
Interest Accrued		(658	)		(4,885	)
Other Current Assets		(25,012	)		2,940
Other Current Liabilities		4,704			(15,673	)
Net Cash Flows From Operating Activities		160,994			214,921
INVESTING ACTIVITIES
Construction Expenditures		(110,209	)		(68,216	)
Change in Other Cash Deposits, Net		4,544			805
Proceeds from Sale of Assets		108			3,876
Net Cash Flows Used For Investing Activities		(105,557	)		(63,535	)
FINANCING ACTIVITIES
Issuance of Long-term Debt-Nonaffiliated		154,642			92,441
Issuance of Long-term Debt-Affiliated		-			50,000
Retirement of Long-term Debt		(208,122	)		(222,457	)
Changes in Advances to/from Affiliates, Net		39,711			(28,550	)
Dividends Paid on Common Stock		(40,000	)		(45,000	)
Dividends Paid on Cumulative Preferred Stock		(172	)		(172	)
Net Cash Flows Used For Financing Activities		(53,941	)		(153,738	)
Net Increase (Decrease) in Cash and Cash Equivalents		1,496			(2,352	)
Cash and Cash Equivalents at Beginning of Period		2,308			5,676
Cash and Cash Equivalents at End of Period	$	3,804		$	3,324

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $33,748,000 and $40,136,000 and for income taxes was $49,176,000 and $11,326,000 in 2005 and 2004, respectively. Noncash capital lease acquisitions were $4,414,000 and $18,018,000 in 2005 and 2004, respectively. Construction Expenditures include the change in construction-related Accounts Payable of $(400,000) and $(321,000) in 2005 and 2004, respectively.

See Condensed Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to financial statements for other subsidiary registrants. Listed below are the condensed notes that apply to SWEPCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Benefit Plans	Note 8
Business Segments	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Company-wide Staffing and Budget Review	Note 12

CONDENSED NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to financial statements that follow are a combined presentation for AEP’s registrant subsidiaries. The following list indicates the registrants to which the footnotes apply:
1.	Significant Accounting Matters	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2.	New Accounting Pronouncements	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3.	Rate Matters	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4.	Customer Choice and Industry Restructuring	CSPCo, OPCo, TCC, TNC
5.	Commitments and Contingencies	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6.	Guarantees	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7.	Acquisitions, Dispositions, Asset Impairments and Assets Held for Sale	APCo, CSPCo, TCC
8.	Benefit Plans	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
9.	Business Segments	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10.	Income Taxes	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
11.	Financing Activities	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
12.	Company-wide Staffing and Budget Review	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

1.SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited interim financial statements should be read in conjunction with the 2004 Annual Report as incorporated in and filed with the 2004 Form 10-K.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the balance sheet in the capitalization section. The components of Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries are shown in the following table:

	September 30,			December 31,
	2005			2004
	(in thousands)
Components
Cash Flow Hedges:
APCo	$	(24,814	)	$	(9,324	)
CSPCo		(5,396	)		1,393
I&M		(9,461	)		(4,076	)
KPCo		(2,035	)		813
OPCo		(7,561	)		1,241
PSO		(4,394	)		400
SWEPCo		(9,785	)		(820	)
TCC		(2,364	)		657
TNC		(1,011	)		285
Minimum Pension Liability:
APCo	$	(72,348	)	$	(72,348	)
CSPCo		(62,209	)		(62,209	)
I&M		(41,175	)		(41,175	)
KPCo		(9,588	)		(9,588	)
OPCo		(75,505	)		(75,505	)
PSO		(325	)		(325	)
SWEPCo		(360	)		(360	)
TCC		(1,006	)		(4,816	)
TNC		(413	)		(413	)

Accounting for Asset Retirement Obligations (ARO)

All of AEP’s Registrant Subsidiaries implemented SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003, which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred. Upon establishment of a legal liability, SFAS 143 requires a corresponding asset to be established which will be depreciated over its useful life.

The following is a reconciliation of beginning and ending aggregate carrying amounts of ARO by Registrant Subsidiary:

	Balance at January 1, 2005		Accretion		Liabilities Incurred		Liabilities Settled			Revisions in Cash Flow Estimates			Balance at September 30, 2005
	(in millions)
AEGCo (a)	$	1.2	$	0.1	$	-	$	-		$	-		$	1.3
APCo (a)		24.6		1.4		-		-			-			26.0
CSPCo (a)		11.6		0.6		-		-			-			12.2
I&M (b)		711.8		35.7		-		-			(27.0	)		720.5
OPCo (a)		45.6		2.7		-		-			-			48.3
SWEPCo (c)		27.4		1.1		8.8		(0.1	)		(0.8	)		36.4
TCC (d)		248.9		7.5		-		(256.4	)		-			-

(a)	Consists of ARO related to ash ponds.
(b)	Consists of ARO related to ash ponds ($1.3 million at September 30, 2005) and nuclear decommissioning costs for the Cook Plant ($719.2 million at September 30, 2005). The Cook Plant’s operating licenses were renewed for Cook Unit 1 until 2034 and for Cook Unit 2 until 2037.
(c)	Consists of ARO related to Sabine Mining Company and Dolet Hills Lignite Company, LLC (Dolet Hills). The current portion of Dolet Hills ARO, totaling $2.6 million, is included in Other in the Current Liabilities section of SWEPCo’s September 30, 2005 Condensed Consolidated Balance Sheet.
(d)	The ARO for TCC’s share of STP was included in Liabilities Held for Sale - Texas Generation Plants in TCC’s Consolidated Balance Sheet at December 31, 2004 and was subsequently transferred to the buyer with the sale in the second quarter of 2005 (see “Texas Plants - South Texas Project” section of Note 7).

Accretion expense is included in Other Operation expense in the respective income statements of the individual Registrant Subsidiaries.

As of September 30, 2005 and December 31, 2004, the fair value of assets that are legally restricted for purposes of settling I&M’s nuclear decommissioning liabilities totaled $855 million and $791 million, respectively, and were recorded in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds on I&M’s Condensed Consolidated Balance Sheets.

Related Party Transactions

The amounts of power purchased from Ohio Valley Electric Corporation, which is 44.2% owned by AEP and CSPCo, were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2005		2004		2005		2004
	(in thousands)
APCo	$	19,501	$	16,647	$	54,763	$	44,276
CSPCo		5,103		4,468		14,752		11,956
I&M		7,920		9,042		22,704		19,438
OPCo		16,703		14,938		47,757		39,501

CSPCo entered into a ten year Power Purchase Agreement (PPA) with Sweeny, on behalf of the AEP West companies, from January 1, 2005 to December 31, 2014. The PPA is for unit contingent power up to a maximum of 315 MW. The delivery point for the power under the PPA is in TCC’s system. The power is sold in ERCOT. The purchase of Sweeny power and its sale to nonaffiliates are shared among the AEP West companies under the CSW Operating Agreement. Refer to Note 17 of the 2004 Annual Report for a discussion of the CSW Operating Agreement. The purchases from Sweeny were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2005		2004		2005		2004
	(in thousands)
PSO	$	11,051	$	-	$	31,160	$	-
SWEPCo		13,189		-		27,570		-
TCC		5,548		-		20,120		-
TNC		8,559		-		19,638		-

Reclassification

Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income (Loss).

2.NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented during 2005 that we have determined relate to our operations.

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

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires 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 previously available under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” The statement is effective as of the first annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement.

The Registrant Subsidiaries will implement SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost will be based on the grant-date fair value of the equity award. The Registrant Subsidiaries do not expect implementation of SFAS 123R to materially affect their results of operations, cash flows or financial condition.

In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (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. The Registrant Subsidiaries will apply the principles of SAB 107 in conjunction with their adoption of SFAS 123R.

SFAS 154 “Accounting Changes and Error Corrections” (SFAS 154)

In May 2005, the FASB issued SFAS 154, which replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” The statement applies to all voluntary changes in accounting principle and changes resulting from adoption of a new accounting pronouncement that does not specify transition requirements. SFAS 154 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. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 with early implementation permitted for accounting changes and corrections of errors made in fiscal years beginning after the date this statement is issued. SFAS 154 is effective for the Registrant Subsidiaries beginning January 1, 2006 and will be applied when applicable.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47)

In March 2005, the FASB issued FIN 47, which interprets the application of SFAS 143 “Accounting for Asset Retirement Obligations.” FIN 47 clarifies that the term conditional asset retirement obligation 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 asset retirement obligation 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 asset retirement obligation.

The Registrant Subsidiaries will implement FIN 47 during the fourth quarter of 2005. Implementation will require a potential adjustment for the cumulative effect for any nonregulated operations of initially adopting FIN 47 to be recorded as a change in accounting principle, disclosure of pro forma liabilities and asset retirement obligations, and other additional disclosures. The Registrant Subsidiaries have not completed their evaluation of any potential impact to their results of operations or financial condition.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, management cannot determine the impact on the reporting of operations that may result from any such future changes. The FASB is currently working on several projects including accounting for uncertain tax positions, business combinations, liabilities and equity, revenue recognition, subsequent events, pension plans, fair value measurements and related tax impacts. Management also expects to see more FASB projects as a result of the FASB’s desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from these and future projects could have an impact on future results of operations and financial position.

3.RATE MATTERS

As discussed in the 2004 Annual Report, certain AEP subsidiaries are involved in rate and regulatory proceedings at the FERC and at state commissions. The Rate Matters note within the 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending. The following sections discuss current activities and update the 2004 Annual Report.

APCo Virginia Environmental and Reliability Costs - Affecting APCo

In April 2004, the Virginia Electric Restructuring Act was amended to include 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 after July 1, 2004. On July 1, 2005, APCo filed a request with the Virginia SCC seeking approval for the recovery of $62 million in incremental E&R costs through June 30, 2006. The $62 million request represents i) expected costs of environmental controls on coal-fired generators to meet the first phase of the Clean Air Interstate Rule and Clean Air Mercury Rule finalized earlier this year, ii) recovery of the incremental cost of the Jacksons Ferry-Wyoming 765 kilovolt transmission line construction and iii) other incremental T&D system reliability costs incurred from July 1, 2004 to June 30, 2006.

In the filing, APCo requested that a twelve-month E&R recovery factor be applied to electric service bills on an interim basis beginning August 1, 2005. The recovery factor would have been applied as a 9.18% surcharge to customer bills. APCo proposed to practice over/under-recovery deferral accounting for the difference between the actual incremental costs incurred and the revenue recovered.

Through September 30, 2005, APCo has incurred approximately $13 million of actual incremental E&R costs and has deferred $7 million of such costs for future recovery.  APCo did not record $2 million of equity carrying costs that are not recognized until collected.  E&R costs of $4 million represented interest capitalized that was duplicative of the carrying costs.

On July 14, 2005, the Virginia SCC issued an order that established a procedural schedule for APCo’s proceeding including a public hearing on February 7, 2006. The order provided that no portion of APCo’s application should become effective pending further decision of the Virginia SCC. On October 14, 2005, the Virginia SCC denied APCo’s request to place in effect, on an interim basis subject to refund, its proposed cost recovery surcharge. Under this order, an E&R surcharge will not become effective until the Virginia SCC issues an order following the February 7, 2006 public hearing in this case. The Virginia SCC also ruled in this order that it does not have the authority under applicable Virginia law to approve the recovery of projected E&R costs before their actual incurrence and adjudication, which effectively eliminated projected costs requested in this filing. However, according to this order, APCo may update its request to reflect additional actual costs and/or present additional evidence. If the Virginia SCC denies recovery of any portion of the net incremental amounts deferred to date, it would adversely affect APCo’s future results of operations and cash flows.

APCo West Virginia Rate Case - Affecting APCo

On August 26, 2005, APCo in a joint filing with WPCo, filed an application with the Public Service Commission of West Virginia seeking an initial increase in APCo’s retail rates of approximately $77 million. The initial increase included approval to reactivate and modify the Expanded Net Energy Cost (ENEC) Recovery Mechanism which accounted for $65 million of the initial increase and approval to implement a system reliability tracker which accounted for $9 million. ENEC includes fuel and purchased power costs, as well as other energy-related items including off-system sales margins and transmission items. In addition, APCo and WPCo requested a series of supplemental annual increases related to the recovery of the cost of significant environmental and transmission expenditures. The first supplemental increase of $9 million would go in effect on the same date as the initial rate increase, and the remaining supplemental increases of $44 million, $10 million and $38 million would go in effect on January 1, 2007, 2008 and 2009, respectively. It is expected that the proposed rates will become effective on June 23, 2006 under West Virginia law. APCo has a regulatory liability of $52 million of previously over-recovered ENEC costs which it is proposing to apply plus a carrying cost in the future to any under-recoveries of ENEC costs through the reactivated ENEC Recovery Mechanism. Management is unable to predict the ultimate effect of this filing on APCo’s future revenues, results of operations, cash flows and financial condition.

I&M Indiana Settlement Agreement - Affecting I&M

I&M’s fuel and base rates in Indiana were frozen through a prior agreement. In 2004, the IURC ordered the continuation of the fixed fuel adjustment charge on an interim basis through March 2005, pending the outcome of negotiations. Certain of the parties to the negotiations reached a settlement and signed an agreement on March 10, 2005 and filed the agreement with the IURC on March 14, 2005. The IURC approved the agreement on June 1, 2005.

The approved settlement caps fuel rates for the March 2004 through June 2007 billing months at an increasing rate that includes 8.609 mills per KWH reflected in base rates. The settlement provides that the total capped fuel rates will be 9.88 mills per KWH from January 2005 through December 2005, 10.26 mills per KWH from January 2006 through December 2006, and 10.63 mills per KWH from January 2007 through June 2007. Pursuant to a separate IURC order, I&M began billing the 9.88 mills per KWH total fuel rate on an interim basis effective with the April 2005 billing month. In accordance with the agreement, the October 2005 through March 2006 factor will be adjusted for the delayed implementation of the 2005 factor.

The settlement agreement also covers certain events at the Cook Plant. The settlement provides that if an outage of greater than 60 days occurs at Cook Plant, the recovery of actual monthly fuel costs will be in effect for the outage period beyond 60 days, capped by the average AEP System Pool Primary Energy Rate (Primary Energy Rate), the ratio of the sum of fuel and one half maintenance expenses incurred by the pool members to the total kilowatt-hours of net generation, excluding I&M, as defined by the AEP System Interconnection Agreement and adjusted for losses. If a second outage greater than 60 days occurs, actual monthly fuel costs capped at the Primary Energy Rate would be recovered through June 2007. Over the term of the settlement, if total cumulative actual fuel costs (except during a Cook Plant outage of greater than 60 days) are less than the cap prices, the savings will be credited to customers over the next two fuel adjustment clause filings. Cumulative net fuel costs in excess of the capped prices cannot be recovered. If Cook Plant operates at a capacity factor greater than 87% during the fuel cap period, I&M will receive credit for 30% of the savings produced by that performance.

The settlement agreement also caps base rates from January 1, 2005 to June 30, 2007 at the rates in effect as of January 1, 2005. During this cap period, I&M may not implement a general increase in base rates or implement a rider or cost deferral not established in the settlement agreement unless the IURC determines that a significant change in conditions beyond I&M’s control occurs or a material impact on I&M occurs as a result of federal, state or local regulation or statute that mandates reliability standards related to transmission or distribution costs.

I&M experienced a cumulative under-recovery for the period March 2004 through September 2005 of $10 million. Since I&M expects that its cumulative fuel costs through the end of the fuel cap period will exceed the capped fuel rates, the $10 million was recorded as fuel expense.  If future fuel costs per KWH through June 30, 2007 continue to exceed the caps, or if the base rate cap precludes I&M from seeking timely rate increases to recover increases in its cost of service through June 30, 2007, I&M’s future results of operations and cash flows would be adversely affected.

I&M Michigan Fuel Recovery Plan - Affecting I&M

In September 2004, I&M filed its 2005 Power Supply Cost Recovery (PSCR) Plan, with the requested PSCR factors implemented pursuant to the statute effective with January 2005 billings, replacing the 2004 factors. On March 29, 2005, the Michigan Public Service Commission (MPSC) issued an order approving an agreement authorizing I&M’s proposed 2005 PSCR Plan factors.

On March 31, 2005, I&M filed its 2004 PSCR Reconciliation seeking recovery of approximately $2 million of unrecovered PSCR fuel costs and interest through the application of customer bill surcharges.

On April 28, 2005, the MPSC issued an Opinion and Order approving I&M’s proposed 2004 PSCR factors as billed and finding in favor of I&M on all issues, including the proposed treatment of net SO₂ and NO_x credits.

On September 30, 2005, I&M filed its 2006 PSCR Plan reflecting projected costs for 2006. The factors proposed by I&M will be placed into effect beginning January 2006 on an interim basis, unless approved by the MPSC prior to that time. If approved, the fuel factors to be placed in effect together with accompanying over/under-recovery deferral accounting should allow I&M to recover its fuel costs in Michigan.

KPCo Rate Filing - Affecting KPCo

On September 26, 2005, KPCo filed a request with the Kentucky Public Service Commission to increase base rates by approximately $65 million to recover increasing costs. The major components of the rate increase include a return on common equity of 11.5% or $26 million, the impact of reduced point-to-point transmission revenues of $10 million, recovery of additional AEP Power Pool capacity costs of $9 million, additional reliability spending of $7 million and increased depreciation expense of $5 million. A final order is expected in April 2006. Management is unable to predict the ultimate effect of this filing on KPCo’s future revenues, results of operations, cash flows and financial condition.

PSO Fuel and Purchased Power - Affecting 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 offered to the OCC to collect those reallocated costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation of purchased power costs over three years. In September 2003, the OCC expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs, PSO’s future results of operations and cash flows would be adversely affected.

In the review of PSO’s 2001 fuel and purchased power practices, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies was inconsistent with the FERC-approved Operating Agreement and SIA and that the AEP West companies should have been allocated greater margins. The parties objected to the inclusion of mark-to-market amounts in developing the allocation base.

The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. On July 25, 2005, the OCC Staff and two intervenors filed testimony in which they quantified the alleged improperly allocated off-system sales margins between AEP East and AEP West companies. Their overall recommendations would result in an increase in off-system sales margins allocated to PSO and thus, a reduction in its recoverable fuel costs through June 2005 of an amount between $38 million and $47 million. PSO does not agree with the intervenors’ and the OCC Staff’s recommendations and will defend vigorously its position. Accordingly, PSO has not recorded a provision for the off-system sales margins issue. Furthermore, should the OCC Staff prevail on this issue, PSO also believes the reallocation of off-system sales margins to PSO would be substantially less than their recommended amounts. On August 22, 2005, the Attorney General of Oklahoma filed a motion to suspend the procedural schedule, giving the parties sufficient time to review revised data.

As noted in the 2004 Annual Report, 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. On September 29, 2005, the United States District Court, Western District of Texas, issued an order in the TNC fuel proceeding, preempting the PUCT from deciding this same allocation issue in Texas. The Court agreed with us that the FERC had jurisdiction over the SIA and that the sole remedy is at the FERC. It is unknown how the OCC will handle the jurisdictional issue. If the OCC continues to move forward on this issue, it could result in increased off-system sales margins included in the fuel clause adversely affecting future results of operations and cash flows for AEP and PSO. However, based on the position taken by the Federal court in Texas, it would appear that the OCC would be preempted from disallowing fuel recoveries for alleged improper allocations of system sales margins. If the OCC or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between AEP East and AEP West companies.

In April 2005, the OCC heard arguments from intervenors that requested the OCC conduct a prudence review of PSO’s fuel and purchased power practices for 2003. On June 10, 2005, the OCC decided to have its staff conduct that review. Management is unable to predict the ultimate effect of these Oklahoma fuel clause proceedings on PSO’s revenues, results of operations, cash flows and financial condition.

PSO Lawton Power Supply Agreement - Affecting PSO

On November 26, 2003, pursuant to an application by Lawton Cogeneration Incorporated seeking approval of a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments, the OCC issued an order approving the Agreement and setting the avoided costs. The order did not approve recovery by PSO of the resultant purchased power costs.

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court. In the appeal, PSO maintained that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement. The Oklahoma Supreme Court issued a decision on June 21, 2005 affirming portions of the OCC’s order and remanding certain provisions. The Court affirmed the OCC’s finding that Lawton established a legally enforceable obligation and ruled that it was within the OCC’s discretion to award a 20-year contract and to base the capacity payment on a peaking unit. The Court directed the OCC to revisit its determination of PSO’s avoided energy cost. The OCC has appointed a settlement judge and negotiations are ongoing. A procedural schedule was issued September 30, 2005, which provides for a January 2006 hearing date. Management is unable to predict the final outcome of the remand. However, if the OCC were to ultimately deny recovery of any portion of the cost of the resultant Agreement, it would adversely affect PSO’s future results of operations and cash flows.

Upon resolution of the litigation, management will review any resultant transaction to determine if it can be accounted for as a purchased power transaction or whether it will be accounted for as a lease or as a generating plant asset on the balance sheet under FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities.”

PSO Rate Review - Affecting PSO

PSO has been involved in a commission staff-initiated base rate review before the OCC which began in 2003. In that proceeding, PSO made a filing seeking to increase its base rates by $41 million, while various other parties made recommendations to reduce PSO’s base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. The settlement provides for a $7 million annual base revenue reduction offset by a $6 million reduction in annual depreciation expense and recovery through fuel revenues of certain transmission expenses previously recovered in base rates. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. The settlement also provides for recovery, over 24 months, of $9 million of deferred fuel costs associated with a renegotiated coal transportation contract and the continuation of a $12 million vegetation management rider, both of which are earnings neutral. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC issued an order approving the stipulation on May 2, 2005 and new base rates were implemented in June 2005.

SWEPCo Texas Fuel Factor Filing - Affecting SWEPCo

On November 7, 2005, due mainly to the increased cost of natural gas, SWEPCo filed a petition with the PUCT to increase its annual fixed fuel factor by $49 million and to surcharge $46 million of past under-recoveries over 12 months. Management cannot predict the ultimate outcome of this filing. Actual costs will be subject to review and approval in a future fuel reconciliation.

SWEPCo and TNC PUCT Staff Review of Earnings - Affecting SWEPCo and TNC

On October 28, 2005, the staff of the PUCT reported results of its review of SWEPCo’s and TNC’s year-end 2004 earnings. Based upon 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 plans to engage SWEPCo in discussions to reconcile the earnings calculation and consider possible ways to address the results. Management is unable to predict the future outcome of this initial report on future revenues, results of operations, cash flows and financial condition. Staff recommended no further action regarding TNC at this time.

SWEPCo Louisiana Fuel Audit - Affecting SWEPCo

The Louisiana Public Service Commission (LPSC) performed an audit of SWEPCo’s fuel costs for the years 1999 through 2002. On July 22, 2005, the LPSC approved the uncontested settlement in that proceeding, which required SWEPCO to refund approximately $18 thousand for the four-year period. The LPSC also recommended that the $18 thousand be donated to the United Way to assist needy customers.

TCC Rate Case - Affecting TCC

On August 15, 2005, the PUCT issued an order in an ongoing base rate proceeding, reducing TCC’s annual base rates by $9 million. This reduction in TCC’s annual base rates will be offset by the elimination of a merger-related rate rider credit of $7 million, an increase in other miscellaneous revenues of $4 million and a decrease in depreciation expense of $9 million, resulting in a prospective increase in estimated annual pretax earnings of $11 million. Tariffs were approved and the rate change was implemented effective September 6, 2005. On October 6, 2005 the PUCT voted not to consider motions for rehearing. As a result, the August 15, 2005 order will become final and subject to appeal in mid-November. TCC is considering whether it will appeal this order. Also, in the third quarter 2005, TCC reclassified $126 million from Accumulated Depreciation and Amortization to Regulatory Liability-Asset Removal Costs based on a depreciation study prepared by TCC and approved by the PUCT.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC

Several parties including the Office of Public Utility Counsel and 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 former affiliated REPs, respectively). In June 2003, the District Court ruled that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor for Mutual Energy WTU, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements of both Mutual Energy WTU and Mutual Energy CPL. The Court upheld the initial PTB orders on all other issues. In an opinion issued on July 28, 2005, the Texas Court of Appeals reversed the District Court on the loss of load issue, but otherwise affirmed its decision. The amount of unaccounted for energy built into the PTB fuel factors attributable to Mutual Energy WTU prior to AEP’s sale of Mutual Energy WTU was approximately $3 million. AEP’s third quarter 2005 pretax earnings were adversely affected by $3 million because of this decision. TNC has filed a motion for rehearing regarding the unaccounted for energy issue at the Court of Appeals.

Texas Unbundled Cost of Service (UCOS) Appeal - Affecting TCC

The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began in Texas. TCC placed new T&D rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. Certain PUCT rulings in this proceeding, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003, upholding the PUCT’s UCOS order with one exception. The District Court ruled that the excess earnings refund methodology is unlawful because refunding the 1999 through 2001 excess earnings, solely as a credit to nonbypassable T&D rates charged to REPs, and not to the actual consumers of the electricity discriminates against residential and small commercial customers. TCC, TNC and other parties appealed this District Court ruling to the Court of Appeals. In a decision issued on September 23, 2005, the Court of Appeals determined that the refund of excess earnings other than through the true-up process was unlawful under the Texas Restructuring Legislation, thereby reversing the determination of the PUCT and the District Court. This decision, in effect, reversed the District Court’s determination that the refund methodology discriminated against certain customer classes. In all other respects, the decision of the District Court was affirmed. At this time, management is unable to predict if this decision will be appealed to the Texas Supreme Court.

TCC’s position is that, consistent with the Court of Appeals determination, ordering separate early refunds of excess earnings was unlawful because the statute only permits such refunds to be accomplished as a part of the stranded cost determination in the True-up Proceeding. Nonetheless, TCC’s true-up filing was based on a prior PUCT determination that assumed the legality of separate refunds of excess earnings. Therefore, if the Court of Appeals decision were to be implemented by permitting TCC to add a surcharge to its rates to recover previously refunded excess earnings, and stranded cost recovery was also adjusted, TCC’s recovery could be affected in a largely offsetting manner in the two cases. Accordingly, in the third quarter of 2005, based on the probable outcome that the PUCT would implement the surcharge in the future, TCC reduced the amount of its recoverable stranded cost and recorded a separate regulatory asset for $49 million of excess earnings that should be refunded to TCC by the REPs. This resulted in a $9 million reduction to the true-up carrying cost regulatory asset, the effect of which was offset by an increase of $7 million in regulatory assets for the refund of the interest that had been previously refunded to the REPs. TCC cannot predict the ultimate outcome of this litigation; however, TCC believes the Court of Appeals decision significantly contributes to its position that customers are entitled to receive credit for excess earnings and related carrying cost effect on that amount as a reduction to stranded costs and not through an earlier refund in T&D rates.

At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. During the first nine months of 2005, TCC refunded $9 million reducing its unrefunded excess earnings to $1 million. On July 15, 2005, the PUCT approved a preliminary order in the TCC True-up Proceeding that ordered TCC to cease refunding excess earnings at the end of July 2005. Under that order, the unrefunded balance of excess earnings of $1 million as of the end of July 2005 would reduce the balance of stranded costs.

Hold Harmless Proceeding - Affecting APCo, CSPCo, I&M, KPCo and OPCo

In a July 2002 order conditionally accepting AEP’s choice to join PJM, the FERC directed AEP, ComEd, Midwest Independent System Operator (MISO) and PJM to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from AEP and ComEd joining PJM instead of MISO.

In July 2004, AEP and PJM filed jointly with the FERC a hold-harmless proposal. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. AEP and ComEd presented studies that showed no adverse effects to the Michigan and Wisconsin utilities. On December 27, 2004, AEP and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250 thousand that was approved by the FERC on March 7, 2005. On April 25, 2005, AEP and International Transmission Company in Michigan filed a settlement that resolves all hold-harmless issues for a one-time payment of $120 thousand that was approved by the FERC on June 24, 2005. On May 19, 2005, AEP and all remaining Michigan companies filed a settlement that resolves all hold-harmless issues for a one-time payment of approximately $2 million, which was approved by the FERC on June 24, 2005.

The payment to the Michigan utilities will be deferred, as was the Wisconsin payment, as a PJM integration cost to be amortized over 15 years and recovery will be sought in future retail rate filings. Management believes that it is probable that these payments will ultimately be recovered from retail and wholesale customers. If the AEP East companies cannot recover these amortizations on a timely basis in their retail base rates, their future results of operations and cash flows will be adversely affected.

FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo and OPCo

A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. SECA transition rates are in effect through March 31, 2006. The FERC has set the SECA rate issue for hearing and indicated that the SECA rates are being recovered subject to refund. Intervenors in that proceeding are objecting to the SECA rates and AEP’s method of determining those rates. Management is unable to determine the probable outcome of the FERC’s SECA rate proceeding. SECA revenues by Registrant Subsidiary are shown in the following table:

Company	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005		December 2004
	(in millions)
APCo	$	11.3	$	30.3	$	3.5
CSPCo		6.4		16.1		2.0
I&M		6.6		17.4		2.3
KPCo		2.7		7.2		0.8
OPCo		8.8		22.3		2.8

In a March 31, 2005 FERC filing, AEP proposed an increase in the revenue requirements and rates for transmission service, and certain ancillary services in the AEP zone of PJM. The customers receiving these services are the AEP East companies, municipal and cooperative wholesale entities and retail customers that exercise retail choice that have load delivery points in the AEP zone of PJM. As proposed, the transmission service rates would increase in two steps, first to reflect an increase in the revenue requirements, and then to reflect the loss of revenues from the discontinuance of SECA transition rates on April 1, 2006. On May 31, 2005, the FERC accepted the filing, set the issues for hearing, and suspended the effective date of the first increase in the OATT rate until November 1, 2005, subject to refund with interest if lower rates are eventually approved. The FERC accepted the two-step increase concept, such that the transmission rates will automatically increase on April 1, 2006, if the SECA revenues cease to be collected, and to the extent that replacement rates are not established. In a separate proceeding, at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present regime may need to be replaced through establishment of regional rates that would compensate AEP, among others, for the regional service provided by high voltage facilities they own that benefit customers throughout PJM. On September 30, 2005, AEP and a nonaffiliated utility (Allegheny Power) jointly filed a regional transmission rate design proposal with the FERC. This investigation provides AEP an opportunity to propose and support a new PJM rate regime.

As of September 30, 2003, SECA transition rates have not fully compensated the AEP East companies for their lost T&O revenues. Management is unable to predict whether, SECA rates and effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone will be sufficient to replace the SECA transition rate revenues. In addition, we are unable to predict whether the effect of the loss of transmission revenues will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If, (i) the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, or (ii) AEP zonal transmission rates are not sufficiently increased by the FERC after March 31, 2006 to replace the lost T&O/SECA revenues, or (iii) the FERC’s review of our current SECA rate results in a rate reduction which is subject to refund, or (iv) any increase in the AEP East companies’ transmission costs from the loss of transmission revenues are not fully recovered in retail and wholesale rates on a timely basis, or (v) if the FERC does not approve a new rate within PJM, future results of operations, cash flows and financial condition would be adversely affected.

RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo and OPCo

Prior to joining PJM, the AEP East companies, with FERC approval, deferred costs incurred to originally form a new RTO (the Alliance) and subsequently to join an existing RTO (PJM). In 2004, AEP requested permission to amortize, beginning January 1, 2005, 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 without proposing an amortization period for the $17 million of PJM-billed integration costs in the application. The FERC approved AEP’s application. The formation and integration costs included in AEP’s application by company follows:

Company	PJM-Billed Integration Costs		Non-PJM Billed Formation/ Integration Costs
	(in millions)
APCo	$	4.8	$	5.1
CSPCo		2.0		2.2
I&M		3.8		3.8
KPCo		1.1		1.1
OPCo		5.5		5.7

In January 2005, the AEP East companies began amortizing their deferred RTO formation/integration costs not billed by PJM over 15 years and the deferred PJM-billed integration costs over 10 years (the latter, consistent with a March 8, 2005 requested rate recovery period discussed below). The total amortization related to such costs was $1 million and $3 million in the third quarter and first nine months of 2005, respectively. As of September 30, 2005, the AEP East Companies have $34 million of deferred unamortized RTO formation/integration costs as follows:

Company	PJM-Billed Integration Costs		Non-PJM Billed Formation/ Integration Costs
	(in millions)
APCo	$	4.9	$	4.8
CSPCo		2.0		2.0
I&M		3.8		3.5
KPCo		1.2		1.1
OPCo		5.6		5.3

On March 8, 2005, AEP and two other utilities jointly filed a request with the FERC to recover their deferred PJM-billed integration costs from all load-serving entities in the PJM RTO over a ten-year period starting January 1, 2005. On May 6, 2005, the FERC issued an order denying the request to recover the amortization of the deferred PJM-billed integration costs from all load-serving entities in the PJM RTO, and instead, ordered the companies to make a Compliance Filing to recover the PJM-billed integration costs solely from the zones of the requesting companies. AEP, together with the other companies, made the Compliance Filing on May 27, 2005. On June 6, 2005, AEP filed a request for rehearing. Subsequently, the FERC approved the compliance rate, and PJM began charging the rate to load serving entities in the AEP zone (and the other companies’ zones), including the AEP East companies on behalf of the load they serve in the AEP zone (about 85% of the total load in the AEP zone). On October 17, 2005, the FERC granted AEP’s June 6, 2005 rehearing request and set the following two issues for hearing and settlement discussions and, if necessary, for hearing: (1) whether the PJM OATT is unjust and unreasonable without region-wide recovery of PJM-billed integration costs and (2) a determination of a just and reasonable carrying charge rate on the deferred PJM-billed integration costs. Also, the FERC, in its order, dismissed the May 27, 2005 Compliance Filing as moot. At this time, management is unable to predict the outcome of this proceeding.

On March 31, 2005, AEP also filed a request for a revised transmission service revenue requirement for the AEP zone of PJM (as discussed above in the “FERC Order on Regional Through and Out Rates” section). Included in the costs reflected in that revenue requirement was the estimated 2005 amortization of deferred RTO formation/integration costs (other than the deferred PJM-billed integration costs). The AEP East companies will be responsible for paying most of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone. CSPCo, OPCo, APCo and KPCo have made filings to recover the amortization of these costs. I&M is currently subject to a rate freeze.

Until the AEP East Companies can adjust their retail rates to recover the amortization of both RTO deferred costs, results of operations and cash flows will be adversely affected by the amortizations. If the FERC allows AEP to charge the amortization of PJM-billed integration costs throughout the PJM region, it would mitigate any adverse effect from failure to obtain timely recovery in retail rates. If the FERC were to deny the inclusion in the transmission rates of any portion of the amortization of the deferred RTO formation/integration costs it would have an adverse impact on future results of operations and cash flows. If the FERC approves a carrying charge rate that is lower than the carrying charge recognized to date, it could have an adverse effect on the AEP East companies’ future results of operations and cash flows.

Allocation Agreement between AEP East and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East and AEP West companies. The current allocation methodology was established at the time of the AEP-CSW merger and, consistent with the terms of the SIA, AEP filed on November 1, 2005, a proposed allocation methodology to be used in 2006 and beyond. The proposed allocation methodology 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 accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT accruing to the benefit of the AEP West companies. Previously, the SIA allocation provided for the sharing of all such margins among all AEP East and AEP West companies. The allocation ultimately approved by the FERC may differ from the one proposed. AEP requested that the new methodology be effective on a prospective basis after the FERC’s order. Management is unable to predict the ultimate effect of this filing on the AEP East and AEP West companies’ future results of operations and cash flows because the impact will depend upon the ultimate methodology approved by the FERC and the level of future trading and marketing margins.

      4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

Certain AEP subsidiaries are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in the 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring and update the 2004 Annual Report.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo

On January 26, 2005, the PUCO approved Rate Stabilization Plans (RSP) for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the need for additional revenues for specified costs. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM-related administrative costs and congestion costs net of firm transmission rights (FTR) revenue from 2004 and 2005 related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $6 million for CSPCo and $35 million for OPCo in the first nine months of 2005 as a result of implementing this provision of the RSP. Of these amounts, approximately $8 million for CSPCo and $21 million for OPCo relate to 2004 environmental carrying costs and RTO costs. The decline in the third quarter of 2005 reflects the effect of substantial increases in FTR revenues which offset administrative and congestion costs.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding its approval of the RSP. On March 23, 2005, the PUCO denied all applications for rehearing. In the second quarter of 2005, two intervenors filed separate appeals to the Ohio Supreme Court. One of those appeals has been withdrawn.  The remaining appeal challenges the RSP and also argues that there is no POLR obligation in Ohio, and therefore CSPCo and OPCo are not entitled to recover any POLR charges.  If the Ohio Supreme Court reverses the PUCO's authorization of the POLR charge, CSPCo's and OPCo's 2005 earnings will be adversely affected.  In a nonaffiliated utility's proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio and therefore, CSPCo and OPCo have argued that they can recover the POLR charge.  In addition, if the RSP order is determined on appeal to be illegal under the restructuring legislation, it would have an adverse effect on results of operations, cash flows and possibly financial condition. Although management believes that the RSP plan is legal and intends to defend vigorously the PUCO’s order, management cannot predict the ultimate outcome of the pending litigation.

The PUCO’s order in the RSP requires CSPCo and OPCo to allot a combined total of $14 million of previously provided for unused CSPCo shopping incentives to benefit their low-income customers and economic development programs over the three-year period ending December 31, 2008. In a March 23, 2005 rehearing order, the PUCO clarified that the Ohio companies have a regulatory liability of only $14 million of unused shopping incentives. In the second quarter of 2005, CSPCo ceased applying unused shopping incentives to reduce its recoverable transition regulatory asset. Assuming that the $14 million regulatory liability is allocated equally to CSPCo and OPCo, in the second quarter of 2005, CSPCo increased its recoverable transition regulatory asset by $18 million due to the reversal of the unused shopping incentives, transferred $7 million to a regulatory liability and credited the remaining $11 million to pretax earnings and OPCo recorded a regulatory liability of $7 million which it charged to pretax earnings.

On September 28, 2005, the Ohio companies filed with the PUCO to recover through a transmission cost recovery rider, beginning January 1, 2006, approximately $5 million for CSPCo and $7 million for OPCo of projected 2006 net costs incurred as a result of joining PJM. In addition, the Ohio companies requested to practice over/under-recovery deferral accounting for any differences between the revenues collected starting January 1, 2006 and the actual costs incurred. If the PUCO determines that any of the requested net incremental RTO costs are unrecoverable, it would have an adverse impact on the Ohio companies’ future results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, the Ohio companies are deferring customer choice implementation costs and related carrying costs in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. Through September 30, 2005, CSPCo and OPCo incurred $42 million and $44 million, respectively, of such costs, and accordingly, deferred $22 million and $24 million, respectively, of such costs for probable future recovery in distribution rates. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. Pursuant to the RSP, recovery of these amounts will be deferred until the next distribution rate filing to change rates after December 31, 2008. Management believes that the deferred customer choice implementation costs were prudently incurred to implement and effect customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on the Ohio companies’ future results of operations and cash flows.

TEXAS RESTRUCTURING - Affecting TCC and TNC

The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items including carrying costs in TCC’s true-up filing under the Texas Restructuring Legislation. The PUCT approved TCC’s request to file its True-up Proceeding after the sales of its interest in STP, with only the ownership interest in Oklaunion remaining to be settled. On May 19, 2005, the sales of TCC’s interest in STP closed. On May 27, 2005, TCC filed its true-up request seeking recovery of $2.4 billion of net stranded costs and other true-up items which it believes the Texas Restructuring Legislation allows, including unrecorded equity carrying costs, which are not recognizable until collected, and unrecorded carrying costs on amounts previously provided for totaling approximately $440 million. The filing does not include a deduction for a $238 million provision for a probable depreciation adjustment recorded in December 2004 based on a methodology approved by the PUCT in a nonaffiliated utility’s true-up order. Although it was determined that it was probable that the PUCT would make this adjustment in TCC’s proceeding and the adjustment was provided for, TCC does not believe the adjustment is appropriate and will litigate the issue, if necessary. As a result, the filing was not reduced by the $238 million provision for probable loss. These items account for the majority of the difference between the $2.4 billion filing and the $1.6 billion net regulatory asset detailed below. As discussed below, the PUCT Staff and various intervenors filed testimony recommending that TCC’s $2.4 billion requested recovery amount be reduced, with certain parties asserting that TCC does not have any stranded costs. The PUCT hearing began on September 26, 2005 and concluded on October 4, 2005. It is anticipated that the PUCT will issue a final order in the fourth quarter of 2005.

The Components of TCC’s Recorded Net True-up Regulatory Asset (inclusive of provisions) recorded as of September 30, 2005 and December 31, 2004 are:

	TCC
	September 30, 2005			December 31, 2004
	(in millions)
Stranded Generation Plant Costs	$	892		$	897
Net Generation-related Regulatory Asset		249			249
Excess Earnings		(49	)		(10	)
Net Stranded Generation Costs		1,092			1,136
Carrying Costs on Stranded Generation Plant Costs		218			225
Net Stranded Generation Costs Designated for Securitization		1,310			1,361
Wholesale Capacity Auction True-up		483			483
Carrying Costs on Wholesale Capacity Auction True-up		114			77
Retail Clawback		(61	)		(61	)
Deferred Over-recovered Fuel Balance		(210	)		(212	)
Net Other Recoverable True-up Amounts		326			287
Total Recorded Net True-up Regulatory Asset	$	1,636		$	1,648

The Components of TNC’s Net True-up Regulatory Liability as of September 30, 2005 and December 31, 2004 are:

	TNC
	September 30, 2005			December 31, 2004
	(in millions)
Retail Clawback	$	(14	)	$	(14	)
Deferred Over-recovered Fuel Balance		(5	)		(4	)
Total Recorded Net True-up Regulatory Liability	$	(19	)	$	(18	)

Deferred Investment Tax Credits Included in Stranded Generation Plant Costs

In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that net stranded generation costs should be reduced by the present value of deferred investment tax credits (ITC) and excess deferred federal income taxes applicable to generating assets. The nonaffiliated utility testified in its True-up Proceeding that acceleration of the sharing of deferred ITC with customers may be a violation of the Internal Revenue Code’s normalization provisions. Management agrees with the nonaffiliated utility that the PUCT’s acceleration of deferred ITC and excess deferred federal income taxes may be a violation of the normalization provisions. As a result, management has not included as a reduction of its net stranded generation costs the present value of TCC’s generation-related deferred ITC of $70 million and the present value of excess deferred federal income taxes of $6 million in its true-up filing. Although deferred ITC and excess deferred federal income taxes are recorded as a liability on TCC’s books, such amounts also are not reflected as a reduction of TCC’s recorded net stranded generation costs regulatory asset in the above table since to do so may be a normalization violation. The Internal Revenue Service (IRS) has issued proposed regulations that would make an exception to the normalization provisions for a utility whose electric generation assets cease to be public utility property. Since the IRS has not issued final regulations, TCC filed a request for a private letter ruling from the IRS on June 28, 2005 to determine whether the PUCT’s action would result in a normalization violation. A normalization violation could result in the repayment of TCC’s accumulated deferred ITC on all property, not just generation property, which approximates $106 million as of September 30, 2005 and a loss of the ability to elect accelerated tax depreciation in the future. Various parties in TCC’s True-up Proceeding have recommended that the present value of the ITCs and the nominal value of excess deferred federal income taxes applicable to generating assets be utilized to reduce TCC’s requested stranded cost amount. Management is unable to predict how the IRS will rule on the private letter ruling request and whether any PUCT order will adversely affect TCC’s future results of operations and cash flows.

TCC Fuel Reconciliation

On April 14, 2005, the PUCT ruled that specific energy-only purchased power contracts included a capacity component, which is not recoverable in fuel rates. As a result of this decision, in the first quarter of 2005, TCC recorded a provision for over-recovered fuel of $3 million, inclusive of interest. Reflecting all of the decisions in the final order and the resultant provisions for refund, the deferred over-recovery balance was $210 million as of September 30, 2005, including accrued interest. TCC filed a motion for rehearing on several items which was denied by operation of law on July 18, 2005. TCC appealed the PUCT’s decision to state and federal courts in August 2005. As discussed in the “TNC True-up Proceeding” section below, TNC received a decision from the Federal District Court that the PUCT is preempted by federal law from revising the allocation of system sales margins under the FERC-approved SIA by removing mark-to-market amounts from the East/West allocation base. The same issue was presented in TCC’s final fuel reconciliation proceeding for which TCC has also filed an appeal to the Federal District Court. As with TNC, it is expected that the PUCT will also be preempted by the Federal District Court from reallocating the off-system sales margins under the FERC-approved SIA for TCC. Therefore, the PUCT would have to file a complaint with the FERC to address the TCC allocation issue. TCC is unable to determine whether the PUCT will appeal the Federal District Court decision or file a complaint with the FERC, and if it does either, whether such appeal or complaint would probably be successful. Pending further clarification, TCC has not yet reversed the $46 million provision for fuel cost over-recovery recorded in 2004. If the PUCT or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between AEP East and AEP West companies.

TCC Carrying Costs on Net True-up Regulatory Assets

TCC continues to accrue carrying costs on its net true-up regulatory asset at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to accumulated deferred federal income taxes (ADFIT) on net stranded costs and other true-up items which was retroactively applied to January 1, 2004. In the first nine months of 2005, TCC accrued carrying costs of $57 million which were partially offset by a first quarter adjustment of $27 million based on this order. The net increase of $30 million in carrying costs is included in Carrying Costs on Stranded Cost Recovery on TCC’s Condensed Consolidated Statements of Income in the first nine months of 2005 inclusive of $15 million of carrying costs accrued in the third quarter of 2005.

In an April 2005 open meeting regarding another nonaffiliated utility’s True-up Proceeding, the PUCT determined that the filed cost of debt did not establish a Weighted Average Cost of Capital (WACC) rate or an embedded debt rate because that utility’s Unbundled Cost of Service (UCOS) case was based on a settlement that did not specifically address the debt rate. As a result, the other utility was required to use a subsequently approved lower debt rate to compute its carrying costs than its filed UCOS rate.

To date, this nonaffiliated utility’s issue has not been raised in TCC’s True-up Proceeding. Alternatively, parties have recommended in TCC’s True-up Proceeding that the PUCT reduce TCC’s carrying cost rate to an amount that ranged from 7.5% to the combined rate that was settled upon in TCC’s wires rate proceeding which included a cost of debt of 5.7%. Management is unable to determine the probable outcome of this matter when, or if, it is adjudicated in TCC’s True-up Proceeding. If the PUCT ultimately determines that a lower cost of debt should be used by TCC to calculate carrying costs on its stranded cost balance, it would have an adverse impact on TCC’s future results of operations and cash flows. Based upon a range of debt rates from 5.7% to 7.5%, through the third quarter of 2005, such adverse effect ranges from $28 million to $107 million, of which $6 million to $22 million would apply to amounts accrued in 2005.

Through September 30, 2005, TCC has computed carrying costs of $509 million, of which $302 million was recognized as income in 2004 and applied to years prior to 2005. Approximately $57 million was recognized as income in the first nine months of 2005 before the $27 million offsetting adjustment discussed above. The remaining equity component of the carrying costs of $177 million through September 30, 2005 will be recognized in income as collected.

TCC Excess Earnings

At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. In the first nine months of 2005, TCC refunded an additional $9 million reducing its unrefunded excess earnings to $1 million. On July 15, 2005, the PUCT approved a preliminary order in TCC’s True-up Proceeding that instructed TCC to stop refunding the excess earnings and to offset the remaining balance, which was $1 million, against stranded costs. However, on September 23, 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order requiring TCC to refund excess earnings as determined in its UCOS proceeding was unlawful under the Texas Restructuring Legislation. As such, TCC recorded a regulatory asset for the future recovery of the $49 million refunded to the REPs and a reduction to stranded costs. See the “Texas Unbundled Cost of Service (UCOS) Appeal” section of Note 3 for further details.

TCC True-up Proceeding

As discussed earlier, TCC made its true-up filing requesting $2.4 billion of stranded costs including the effect of the PUCT’s July 15, 2005 order discontinuing the excess earnings refund as discussed in the “Texas Unbundled Cost of Service (UCOS) Appeal” section of Note 3. During September 2005, various parties and the PUCT staff filed testimony recommending reductions to TCC’s requested stranded cost amount including a recommendation that TCC does not have any stranded costs. Hearings began September 26, 2005 and continued until October 4, 2005. An order is expected in the fourth quarter of 2005. When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge (CTC) in the regulated transmission and distribution (T&D) rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

The nonaffiliated utility’s March 2005 order referred to in the “TCC Carrying Costs on Net True-up Regulatory Assets” section above also provided for the present value of the cost free capital benefits of ADFIT associated with stranded generation costs to be offset against other recoverable true-up amounts when establishing the CTC. TCC estimates its present value ADFIT benefit to be $209 million based on its current net true-up regulatory asset. TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT in the nonaffiliated utility’s order and determined that the projected cash flows from the transition charges were more than sufficient to recover TCC’s recorded net true-up regulatory asset since the equity portion of the carrying costs will not be recorded until collected. As a result, no impairment has been recorded. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in its True-up Proceeding, TCC expects to amortize its total net true-up regulatory asset commensurate with recovery over periods to be established by the PUCT in proceedings subsequent to TCC’s True-up Proceeding.

TCC believes that its filed request for recovery of $2.4 billion of net stranded costs and other true-up items, inclusive of carrying costs, is recoverable under the Texas Restructuring Legislation. However, after recording certain provisions for probable disallowances from TCC’s final fuel proceeding and nonaffiliated true-up proceedings and adjusting for unrecordable equity carrying costs and carrying costs on the provisions, TCC has a $1.6 billion recorded net true-up regulatory asset, inclusive of carrying costs, at September 30, 2005 that is probable of recovery at this time. However, other parties have contended that all or material amounts of TCC’s net stranded costs and/or wholesale capacity auction true-up amounts should not be recovered. To the extent decisions of the PUCT in TCC’s True-up Proceeding differ from TCC’s interpretation and application of the Texas Restructuring Legislation and evaluation of other true-up orders of nonaffiliated utilities, additional provisions for material disallowances and reductions of the net true-up regulatory asset, including recorded carrying costs, are possible. Such disallowances would have a material adverse effect on TCC’s future results of operations, cash flows and possibly financial condition.

TNC True-Up Proceeding

In March 2005, the ALJ made certain recommendations regarding the deferred fuel balance resulting in an additional provision for refund of $1 million, which results in an over-recovery amount of $5 million. In May 2005, the PUCT issued a favorable order, adopting the ALJ’s recommendation regarding the application of interest to the post-reconciliation period off-system sales margins, but did not adopt the ALJ’s excess earnings recommendation. The PUCT required that excess earnings be addressed in the CTC filing that was made on August 5, 2005. Based upon the ruling regarding the application of interest on post-reconciliation off-system sales margins, TNC adjusted its deferred over-recovered fuel balance during the second quarter of 2005.

In 2004, TNC appealed to the state and federal courts the PUCT’s order in its final fuel reconciliation covering the period from July 2000 through December 31, 2001 in which the PUCT disallowed approximately $30 million of fuel costs. On September 9, 2005, the Texas District Court in Travis County issued a ruling which upheld in all respects the PUCT’s decisions concerning issues appealed to that court by all parties. TNC has filed notice of appeal of that decision. TNC will continue to pursue vigorously the state appeals, but cannot predict their outcome. TNC believes it has fully provided for the PUCT final fuel order.

On September 29, 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing their ruling regarding the allocation of off-system sales margins. The impact of the reallocation resulted in an over-recovery amount of $8 million. The PUCT must appeal the Federal Court decision or file a complaint at FERC, if it wishes to challenge this ruling. TNC is unable to predict whether the PUCT will appeal the Federal District Court decision and/or file a complaint at FERC, nor is it able to predict whether such actions would be successful. Pending further clarification, TNC has not yet reversed its related $8 million provision for fuel over-recovery. If the PUCT or another party files a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies due to a reallocation of off-system sales margins between AEP East and AEP West companies.

5.COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within the 2004 Annual Report, certain Registrant Subsidiaries continue to be involved in various legal matters. The 2004 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since their disclosure in the 2004 Annual Report. The matters discussed in the 2004 Annual Report without significant changes in status since year-end include, but are not limited to, (1) nuclear matters, (2) construction and commitments, (3) potential uninsured losses and (4) FERC long-term contracts. See disclosure below for significant matters with changes in status subsequent to the disclosure made in the 2004 Annual Report.

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review 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 court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at the generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. 

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. The CAA authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). 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.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV were already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaint and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern states each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. The Northeastern states’ complaint has been assigned to the same judge in the U.S. District Court for the Southern District of Ohio. AEP filed an answer to the Northeastern states’ complaint and to the Federal EPA’s complaint denying the allegations and stating its defenses.

In August 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, a nonaffiliated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not “routine” maintenance, repair, and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any nonroutine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A settlement between Ohio Edison, the Federal EPA and other parties to the litigation will avoid further litigation and result in expenditures at the plant.

Other utility enforcement actions and current regulatory activities are discussed in detail in the Commitments and Contingencies note in the 2004 Annual Report. However, since the issuance of the August 2003 decision against Ohio Edison, several other courts have considered the issues of what constitutes “routine maintenance, repair, and replacement” for utility units, and whether increased hours of operation are the measure of an emissions increase. Each court has reached a conclusion that differs markedly from the decision in the Ohio Edison case. These decisions include the District Court opinion in the Duke Energy case issued later in August 2003, the District Court opinion in Alabama Power issued on June 3, 2005, and the Fourth Circuit Court of Appeals opinion affirming the dismissal of all claims against Duke Energy issued on June 15, 2005. In addition, on June 10, 2005, the Administrator of the Federal EPA rejected all of the petitions for reconsideration of the October 2003 “equipment replacement provision” rule that defines “routine replacement” under the new source review (NSR) program to include the same types of activities challenged in the pending enforcement actions. Management therefore believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in the AEP case also vary widely from plant to plant.

In June 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which the AEP subsidiaries are members, to reopen petitions for review of the 1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA claims in the AEP case and other related cases. On June 24, 2005, the United States Court of Appeals for the District of Columbia Circuit issued a decision affirming in part the new source review reform regulations adopted by the Federal EPA in December 2002. The court upheld the Federal EPA’s decision to apply an actual-to-future actual emissions, and includes test, utilizing a five-year look back period to establish actual baseline emissions for utilities and a ten-year period for other sources. This excludes increased emissions unrelated to a physical change from the projected emissions and includes emissions associated with demand growth. The court vacated the Federal EPA’s adoption of a broad pollution control project exclusion that includes projects that result in a significant collateral emissions increase, and the “clean unit” applicability test, and remanded certain recordkeeping requirements to the Federal EPA. The court expressed no opinion on the conclusion reached by the Duke Energy court, and found that such issues could be better addressed in a specific factual context.

On August 30, 2005, the United States Court of Appeals for the Fourth Circuit denied the petitions for rehearing filed by the United States and other appellants in the Duke Energy case. On October 13, 2005, the Administrator of the Federal EPA signed a proposed rule that would adopt a test for determining when an emissions increase results from a change at an existing electric utility generating unit under the federal NSR programs that would be consistent with the test adopted and applied by the Fourth Circuit in the Duke Energy case. This would be based on maximum hourly emissions before and after the change. The Federal EPA is also seeking comments on two alternative formulations of the emission increase test.  We have filed a Motion in the NSR litigation that asks the Court, among other things, to dismiss the NSR cases on due process grounds based on the statements and admissions the Federal EPA made in promulgating the proposed rule.

Management is unable to estimate the loss or range of loss related to any contingent liability the 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 the AEP subsidiaries do not prevail, management believes they 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 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.

SWEPCo Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005.

On July 19, 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. On April 11, 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 $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 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 references to a specific heat input value for each Welsh unit.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of $6 thousand against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.

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, financial condition or cash flows.

Carbon Dioxide Public Nuisance Claims -- Affecting AEP System

In July 2004, attorneys general from eight states and the corporation counsel for the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions alleged that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. A notice of appeal to the Second Circuit Court of Appeals has been filed on behalf of all plaintiffs. A briefing schedule has not been established.

OPERATIONAL

Construction - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

The AEP System has substantial construction activity scheduled to support its operations. The following table shows the estimated construction expenditures by company for 2006 including amounts for proposed environmental rules:

	(in millions)
AEGCo	$	16
APCo		794
CSPCo		275
I&M		252
KPCo		88
OPCo		1,057
PSO		222
SWEPCo		260
TCC		235
TNC		76

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.

TEM Litigation (Power Generation Facility) - Affecting OPCo

AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP has subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 220 MW through May 31, 2006 and 270 MW thereafter). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

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 alleges that TEM has breached the PPA, and is seeking a determination of OPCo’s rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of OPCo’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) has provided a limited guaranty.

On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA was terminated and (iii) would be pursuing against TEM, and SUEZ-TRACTEBEL S.A. under the guaranty, damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that TEM had breached the contract and awarded us damages of $123 million plus pre-judgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. We asked the court to modify the judgment to (i) award a termination payment to us under the terms of the PPA; (ii) grant our attorneys’ fees; and (iii) render judgment against SUEZ-TRACTEBEL, S.A. on the guaranty. TEM sought reduction of the damages awarded by the court for replacement electric power products made available by OPCo under the PPA.

In September 2005, TEM posted a letter of credit for $142 million as security pending appeal of the judgment. Both parties have filed Notices of Appeal with the United States Court of Appeals for the Second Circuit. If the PPA is deemed terminated or found to be unenforceable by the court ultimately deciding the case, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover claimed termination value damages from TEM.

Merger Litigation-Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

In May 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and filed a petition for review of this Initial Decision, which the SEC granted. The SEC is reviewing the Initial Decision. Management believes the repeal of PUHCA will end litigation challenging the merger with CSW. All parties to the proceeding have filed motions with the SEC supporting dismissal of the proceeding upon repeal of the PUHCA in February 2006.

Enron Bankruptcy -Affecting APCo, CSPCo, I&M, KPCo and OPCo

In 2002, certain subsidiaries of AEP 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 subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - Commodity trading settlement disputes - In September 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. The AEP subsidiaries asserted their right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in nonbinding court-sponsored mediation.

In December 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 seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding court-sponsored mediation.

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 are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged the offsetting of receivables and payables. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on results of operations, cash flows and financial condition.

Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003 against AEP and four of its subsidiaries, including TCC and TNC, ERCOT and a number of nonaffiliated energy companies including TXU, CenterPoint, Texas Genco, Reliant, TECO, and Tractebel.  The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to their fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs.  In June 2004, the Court dismissed all claims against the AEP companies. TCE appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. The Fifth Circuit issued its decision in June 2005 and affirmed the lower court’s decision. TCE filed a Petition for Writ of Certiorari with the United States Supreme Court on October 14, 2005. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit against the same defendants and others.  Trial is scheduled in the Utility Choice/Cirro Energy case for April 2006. On October 18, 2005, the U.S. District Court heard oral arguments on Management’s Motion to Dismiss. Management intends to continue to vigorously defend against the allegations in these cases.

Ontario Litigation - Affecting CSPCo and OPCo

In June 2005, CSPCo and OPCo were named as one of 21 defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. They have not been served with the lawsuit. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operations, have emitted NO_x, SO₂ and particulate matter that have harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $50 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. We believe we have meritorious defenses to this action and intend to defend vigorously against it.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, have disputed transportation costs for coal received between July 2000 and the present time. The joint plant has remitted less than the amount billed. The dispute is pending before the Surface Transportation Board with a decision expected during the first quarter of 2006. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded provisions for possible loss in December 2004 and the first nine months of 2005. The provisions were deferred as a regulatory asset under PSO’s fuel mechanism and affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.

6.GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to 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 (LOC) with third parties. These LOCs generally 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 September 30, 2005, the maximum future payments of the LOCs include $44 million, $1 million, $51 million, $4 million and $43 million for CSPCo, I&M, OPCo, SWEPCo and TCC, respectively, with maturities ranging from November 2005 to April 2007. There is no recourse to third parties in the event these letters of credit are drawn.

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $54 million with maturity dates ranging from February 2007 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide 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 a third party miner. At September 30, 2005, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

SWEPCo consolidates Sabine due to the application of FIN 46. SWEPCo does not have an ownership interest in Sabine.

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. Registrant Subsidiaries cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events. In 2004 and the first nine months of 2005, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except for TCC. TCC sales agreements include indemnifications with a maximum exposure of $443 million related to the sale prices of its generation assets. The status of certain sales agreements is discussed in Note 7. There are no material liabilities recorded for any indemnifications.

Registrant Subsidiaries are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and for activity conducted by any Registrant Subsidiary 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 September 30, 2005, 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
Subsidiary	(in millions)
APCo	$	6
CSPCo		3
I&M		4
KPCo		2
OPCo		6
PSO		5
SWEPCo		5
TCC		5
TNC		3

7.ACQUISITIONS, DISPOSITIONS, ASSET IMPAIRMENTS AND ASSETS HELD FOR SALE

ACQUISITIONS

Ceredo Generating Station - Affecting APCo

In August 2005, APCo signed a purchase and sale agreement with Reliant Energy for the purchase of a 505 MW plant located near Ceredo, West Virginia for $100 million. This transaction is expected to be completed no later than the first quarter of 2006.

Waterford Plant - Affecting CSPCo

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford, Ohio. 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, which includes approximately 29,000 customers. On August 2, 2005, AEP agreed to terms of a transaction, which includes the transfer of Monongahela Power’s Ohio customer base and the assets that serve those customers to CSPCo for an estimated sales price of approximately $45 million. The sale price will be adjusted based on book values of the acquired assets and liabilities at the closing date. In addition, CSPCo will pay $10 million to compensate Monongahela Power for its termination of certain generation cost recovery litigation in Ohio. Hearings at the PUCO were held in September 2005 and AEP anticipates the purchase, subject to regulatory approval, to close late in the fourth quarter of 2005. Also included in the proposed transaction is 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.

DISPOSITIONS

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 an unrelated party. In May 2004, TCC received notice from the two nonaffiliated co-owners of the Oklaunion Power Station, 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 its nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. These agreements are currently being challenged in Dallas County, Texas State District Court by the unrelated party with which TCC entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of the unrelated party on October 10, 2005. TCC and the other nonaffiliated co-owners filed an appeal to the Fifth State Court of Appeals in Dallas. Oral argument has been requested but no date has been set. Briefing is scheduled to be completed by November 17, 2005. TCC cannot predict when these issues will be resolved. TCC does not expect the sale to have a significant effect on its results of operations. TCC’s assets and liabilities related to the Oklaunion Power Station have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Condensed Consolidated Balance Sheets at September 30, 2005 and December 31, 2004. 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.

Texas Plants - South Texas Project - Affecting TCC

In February 2004, TCC signed an agreement to sell its 25.2% share of STP 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 STP. The sale was completed for approximately $314 million and the assumption of liabilities of $22 million in May 2005 and did not have significant effect on TCC’s results of operations. The plant did not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also did 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.

ASSET IMPAIRMENTS

Conesville Units 1 and 2 - Affecting CSPCo

In the third quarter of 2005, following an extensive review of the commercial viability of CSPCo’s Conesville Units 1 and 2, CSPCo committed to a plan to retire these units 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.

A pretax charge of approximately $39 million was recognized in the third quarter of 2005 related to CSPCo’s decision to retire the units. The impairment amount is classified as Asset Impairments and Other Related Charges in CSPCo’s Condensed Consolidated Statements of Income.

ASSETS HELD FOR SALE

The assets and liabilities of the TCC plants held for sale at September 30, 2005 and December 31, 2004 are as follows:

	Texas Plants
	September 30, 2005		December 31, 2004
Assets:	(in millions)
Other Current Assets	$	1	$	24
Property, Plant and Equipment, Net		46		413
Regulatory Assets		-		48
Nuclear Decommissioning Trust Fund		-		143
Total Assets Held for Sale - Texas Generation Plants	$	47	$	628
Liabilities:
Regulatory Liabilities	$	2	$	1
Asset Retirement Obligations		-		249
Total Liabilities Held for Sale - Texas Generation Plants	$	2	$	250

8.BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either a 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 death benefits for retired employees in the U.S.

The following tables provide the components of AEP’s net periodic benefit cost for the plans for the three and nine months ended September 30, 2005 and 2004:

Three Months Ended September 30, 2005 and 2004	Pension Plans						Other Postretirement Benefit Plans
	2005			2004			2005			2004
	(in millions)
Service Cost	$	23		$	21		$	10		$	10
Interest Cost		57			57			26			29
Expected (Return) on Plan Assets		(77	)		(72	)		(23	)		(20	)
Amortization of Transition (Asset) Obligation		(1	)		-			6			7
Amortization of Prior Service Cost		-			(1	)		-			-
Amortization of Net Actuarial Loss		13			5			5			8
Net Periodic Benefit Cost	$	15		$	10		$	24		$	34

Nine Months Ended September 30, 2005 and 2004	Pension Plans						Other Postretirement Benefit Plans
	2005			2004			2005			2004
	(in millions)
Service Cost	$	69		$	64		$	31		$	30
Interest Cost		169			169			79			87
Expected (Return) on Plan Assets		(232	)		(216	)		(68	)		(60	)
Amortization of Transition (Asset) Obligation		(1	)		1			20			21
Amortization of Prior Service Cost		-			(1	)		-			-
Amortization of Net Actuarial Loss		40			13			19			26
Net Periodic Benefit Cost	$	45		$	30		$	81		$	104

The following table provides the net periodic benefit cost (credit) for the plans by the following Registrant Subsidiaries for the three and nine months ended September 30, 2005 and 2004:

Three Months Ended September 30, 2005 and 2004	Pension Plans						Other Postretirement Benefit Plans
	2005			2004			2005		2004
	(in thousands)
APCo	$	1,848		$	318		$	4,756	$	6,462
CSPCo		534			(405	)		1,928		2,765
I&M		2,365			1,117			3,134		4,313
KPCo		376			142			515		742
OPCo		1,206			(98	)		3,353		4,801
PSO		72			696			1,661		2,110
SWEPCo		364			901			1,642		2,101
TCC		(219	)		749			1,789		2,535
TNC		41			338			784		1,073

Nine Months Ended September 30, 2005 and 2004	Pension Plans						Other Postretirement Benefit Plans
	2005			2004			2005		2004
	(in thousands)
APCo	$	5,544		$	954		$	15,248	$	19,386
CSPCo		1,602			(1,219	)		6,273		8,295
I&M		7,095			3,345			10,229		12,939
KPCo		1,128			430			1,689		2,226
OPCo		3,618			(308	)		10,812		14,403
PSO		216			2,096			5,329		6,330
SWEPCo		1,092			2,703			5,244		6,303
TCC		(657	)		2,241			5,732		7,605
TNC		123			1,014			2,507		3,219

9.BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment. The one reportable segment is a vertically integrated electricity generation, transmission and distribution business except AEGCo, which is an electricity generation business. 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 bundled cost-based rates and regulatory oversight on the business process, cost structures and operating results.

10.INCOME TAXES

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 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.

(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 Taxes.

  (d)       Total deferred state income tax liabilities that reversed during 2005 related to Ohio law change.

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 will be phased-in over a five-year period beginning July 1, 2005 at 23% of the full 0.26% rate. The increase in Taxes Other than Income Taxes for 2005 is expected to be $1 million and $1 million for CSPCo and OPCo, respectively.

Other tax reforms effective July 1, 2005 include a reduction of the sales and use tax from 6.0% to 5.5%, the phase-out of tangible personal property taxes for our nonutility businesses, the elimination of the 10% rollback in real estate taxes and the increase in the premiums tax on insurance polices; all of which will not have a material impact on future results of operations and cash flows.

11.FINANCING ACTIVITIES

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2005 were:

Company	Type of Debt		Principal Amount		Interest Rate		Due Date
			(in thousands)		(%)
Issuances:
APCo		Senior Unsecured Notes	$	200,000		4.95		2015
APCo		Senior Unsecured Notes		150,000		4.40		2010
APCo		Senior Unsecured Notes		250,000		5.00		2017
APCo		Senior Unsecured Notes		250,000		5.80		2035
OPCo		Installment Purchase Contracts		54,500		Variable		2029
OPCo		Installment Purchase Contracts		163,500		Variable		2028
OPCo		Installment Purchase Contracts		50,000		Variable		2014
OPCo		Installment Purchase Contracts		50,000		Variable		2016
OPCo		Installment Purchase Contracts		35,000		Variable		2022
PSO		Senior Unsecured Notes		75,000		4.70		2011
SWEPCo		Senior Unsecured Notes		150,000		4.90		2015
SWEPCo		Notes Payable		5,771		Variable		2006
TCC		Installment Purchase Contracts		161,700		Variable		2030
TCC		Installment Purchase Contracts		120,265		Variable		2028

The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions. In October 2005, CSPCo issued $250 million of 5.85% Senior Notes, Series F, due in October 2035.

Company	Type of Debt		Principal Amount		Interest Rate		Due Date
			(in thousands)		(%)
Retirements and  Principal Payments:
APCo		Other Debt	$	7		13.718		2026
APCo		First Mortgage Bonds		50,000		8.00		2005
APCo		First Mortgage Bonds		30,000		6.89		2005
APCo		First Mortgage Bonds		45,000		8.00		2025
APCo		Senior Unsecured Notes		450,000		4.80		2005
OPCo		Installment Purchase Contracts		102,000		6.375		2029
OPCo		Installment Purchase Contracts		80,000		Variable		2028
OPCo		Installment Purchase Contracts		36,000		Variable		2029
OPCo		Installment Purchase Contracts		50,000		5.45		2014
OPCo		Installment Purchase Contracts		50,000		5.45		2016
OPCo		Installment Purchase Contracts		35,000		5.90		2022
OPCo		Notes Payable		4,390		6.81		2008
OPCo		Notes Payable		6,500		6.27		2009
PSO		First Mortgage Bonds		50,000		6.50		2005
SWEPCo		Senior Unsecured Notes		200,000		4.50		2005
SWEPCo		Notes Payable		5,122		4.47		2011
SWEPCo		Notes Payable		3,000		Variable		2008
TCC		Senior Unsecured Notes		150,000		3.00		2005
TCC		Senior Unsecured Notes		100,000		Variable		2005
TCC		First Mortgage Bonds		65,763		6.625		2005
TCC		Installment Purchase Contracts		120,265		6.00		2028
TCC		Securitization Bonds		29,386		3.54		2005
TCC		Securitization Bonds		20,593		5.01		2008

In addition to the transactions reported in the tables above, the following table lists intercompany issuances and retirements of debt due to AEP:

Company	Type of Debt		Principal Amount		Interest Rate		Due Date
			(in thousands)		(%)
Issuances:
APCo		Notes Payable	$	100,000		4.708		2010
TCC		Notes Payable		150,000		4.58		2007
Retirements:
KPCo		Notes Payable	$	20,000		6.501		2006

Other Matters

On January 3, 2005, the following outstanding shares of preferred stock were redeemed:

Company	Series		Number of Shares Redeemed		Amount
					(in millions)
I&M		5.900%		132,000	$	13
I&M		6.250%		192,500		19
I&M		6.875%		157,500		16
I&M		6.300%		132,450		13
OPCo		5.900%		50,000		5
					$	66

Lines of Credit - 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. In addition, the AEP System also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The AEP System Corporate Borrowing Program operates in accordance with the terms and conditions outlined by the SEC. AEP has authority from the SEC through March 31, 2007 for short-term borrowings sufficient to fund the Utility Money Pool and the Nonutility Money Pool as well as its own requirements in an amount not to exceed $7.2 billion. The Utility Money Pool participants’ money pool activity and corresponding SEC authorized limits for the nine months ended September 30, 2005 are described in the following table:

									Loans
									(Borrowings)			SEC
	Maximum		Maximum		Average		Average		to/from Utility			Authorized
	Borrowings		Loans to		Borrowings		Loans to		Money Pool as of			Short-Term
	from Utility		Utility		from Utility		Utility Money		September 30,			Borrowing
Company	Money Pool		Money Pool		Money Pool		Pool		2005			Limit
	(in thousands)
AEGCo	$	45,694	$	9,305	$	15,921	$	4,803	$	(11,314	)	$	125,000
APCo		242,718		321,977		145,700		47,285		67,532			600,000
CSPCo		159,959		181,238		152,178		95,714		(138,541	)		350,000
I&M		203,248		11,768		92,108		5,797		(81,101	)		500,000
KPCo		8,342		35,779		3,019		15,044		9,641			200,000
OPCo		123,508		182,495		50,134		79,120		(55,508	)		600,000
PSO		55,009		66,159		22,377		35,074		(22,601	)		300,000
SWEPCo		28,421		188,215		9,738		35,617		(605	)		350,000
TCC		320,508		120,937		134,094		39,060		(12,021	)		600,000
TNC		-		119,569		-		62,415		87,651			250,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the nine months ended September 30, 2005 were 3.93% and 1.63%, respectively. The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2005 are summarized for all Registrant Subsidiaries in the following table:

Company	Average Interest Rate for Funds Borrowed from the Utility Money Pool	Average Interest Rate for Funds Loaned to the Utility Money Pool
	(in percentages)
AEGCo	2.91	3.14
APCo	3.30	2.72
CSPCo	3.92	2.76
I&M	3.25	2.12
KPCo	3.52	2.54
OPCo	3.67	2.40
PSO	2.62	3.52
SWEPCo	3.64	2.60
TCC	3.07	2.43
TNC	-	3.13

12.COMPANY-WIDE STAFFING AND BUDGET REVIEW

The following table shows the severance benefits expense recorded in 2005 (primarily in Maintenance and Other Operation) 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 receives allocated expenses.

	Three Months Ended June 30, 2005		Three Months Ended Sept. 30, 2005		Nine Months Ended Sept. 30, 2005
Company	(in millions)
AEGCo	$	0.2	$	0.1	$	0.3
APCo		3.9		0.6		4.5
CSPCo		2.3		0.3		2.6
I&M		4.0		0.7		4.7
KPCo		0.7		0.4		1.1
OPCo		3.4		0.5		3.9
PSO		1.2		0.2		1.4
SWEPCo		1.6		0.2		1.8
TCC		3.8		0.5		4.3
TNC		1.1		0.2		1.3

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the management’s discussion and analysis of Registrant Subsidiaries. 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, and (iii) footnotes of each individual registrant. The Combined Management’s Discussion and Analysis of Registrants Subsidiaries section of the 2004 Annual Report should be read in conjunction with this report.

Budgeted Construction Expenditures

Construction expenditures for Registrant Subsidiaries for 2006 are:

	Projected Construction Expenditures
Company	(in millions)
AEGCo	$	16
APCo		794
CSPCo		275
I&M		252
KPCo		88
OPCo		1,057
PSO		222
SWEPCo		260
TCC		235
TNC		76

Significant Factors

FERC Order on Regional Through and Out Rates

A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. SECA transition rates are in effect through March 31, 2006. The FERC has set the SECA rate issue for hearing and indicated that the SECA rates are being recovered subject to refund. Intervenors in that proceeding are objecting to the SECA rates and AEP’s method of determining those rates. Management is unable to determine the probable outcome of the FERC’s SECA rate proceeding. SECA revenues by Registrant Subsidiary are shown in the following table:

Company	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005		December 2004
	(in millions)
APCo	$	11.3	$	30.3	$	3.5
CSPCo		6.4		16.1		2.0
I&M		6.6		17.4		2.3
KPCo		2.7		7.2		0.8
OPCo		8.8		22.3		2.8

In a March 31, 2005 FERC filing, AEP proposed an increase in the revenue requirements and rates for transmission service, and certain ancillary services in the AEP zone of PJM. The customers receiving these services are the AEP East companies, municipal and cooperative wholesale entities and retail customers that exercise retail choice that have load delivery points in the AEP zone of PJM. As proposed, the transmission service rates would increase in two steps, first to reflect an increase in the revenue requirements, and then to reflect the loss of revenues from the discontinuance of SECA transition rates on April 1, 2006. On May 31, 2005, the FERC accepted the filing, set the issues for hearing, and suspended the effective date of the first increase in the OATT rate until November 1, 2005, subject to refund with interest if lower rates are eventually approved. The FERC accepted the two-step increase concept, such that the transmission rates will automatically increase on April 1, 2006, if the SECA revenues cease to be collected, and to the extent that replacement rates are not established. In a separate proceeding, at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present regime may need to be replaced through establishment of regional rates that would compensate AEP, among others, for the regional service provided by high voltage facilities they own that benefit customers throughout PJM. On September 30, 2005, AEP and a nonaffiliated utility (Allegheny Power) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime.

As of September 30, 2005, SECA transition rates have not fully compensated the AEP East companies for their lost T&O revenues. Management is unable to predict whether, SECA rates and effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone will be sufficient to replace the SECA transition rate revenues. In addition, we are unable to predict whether the effect of the loss of transmission revenues will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If, (i) the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, or (ii) AEP zonal transmission rates are not sufficiently increased by the FERC after March 31, 2006 to replace the lost T&O/SECA revenues, or (iii) the FERC’s review of our current SECA rate results in a rate reduction which is subject to refund, or (iv) any increase in the AEP East companies’ transmission costs from the loss of transmission revenues are not fully recovered in retail and wholesale rates on a timely basis, or (v) if the FERC does not approve a new rate within PJM or within the PJM, future results of operations, cash flows and financial condition would be adversely affected.

Allocation Agreement between AEP East and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East and AEP West companies. The current allocation methodology was established at the time of the AEP-CSW merger and, consistent with the terms of the SIA, AEP filed on November 1, 2005, a proposed allocation methodology to be used in 2006 and beyond. The proposed allocation methodology 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 accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT accruing to the benefit of the AEP West companies. Previously, the SIA allocation provided for the sharing of all such margins among all AEP East and AEP West companies. The allocation ultimately approved by the FERC may differ from the one proposed. AEP requested that the new methodology be effective on a prospective basis after the FERC’s order. Management is unable to predict the ultimate effect of this filing on the AEP East and AEP West companies’ future results of operations and cash flows because the impact will depend upon the ultimate methodology approved by the FERC and the level of future trading and marketing margins.

AEP Power Pool - Capacity

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 will change as generating assets are added, retired or sold. As a result of CSPCo’s acquisition of the Waterford Plant (netted against the planned retirement of Conesville Plant Units 1 and 2) and APCo’s expected purchase of the Ceredo Generating Station, CSPCo and APCo, as net purchasers from the AEP Power Pool, are expected to incur reduced capacity charges. Also, KPCo, as a net purchaser from the AEP Power Pool, is expected to incur increased capacity charges while OPCo and I&M, as net sellers to the AEP Power Pool, are expected to receive reduced capacity revenues.

CSW Operating Agreement

We plan to make a filing with the FERC to remove TCC and TNC from the CSW Operating Agreement and the SIA. Under the Texas Restructuring Legislation, TCC and TNC are completing the final stage of exiting the generation business and have already ceased serving retail load. TCC and TNC will no longer be involved in the coordinated planning and operation of power supply facilities as contemplated by both the CSW Operating Agreement and the SIA. Therefore, TCC and TNC will no longer share trading and marketing margins, which due to restructuring, benefited their results of operations and cash flows. Conversely, PSO and SWEPCo’s share of trading and marketing margins will increase. PSO and SWEPCo share these margins with their ratepayers.

Ohio Regulatory Activity

Ohio Restructuring

On January 26, 2005, the PUCO approved Rate Stabilization Plans (RSP) for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the need for additional revenues for specified costs. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM-related administrative costs and congestion costs net of firm transmission rights (FTR) revenue from 2004 and 2005 related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $6 million for CSPCo and $35 million for OPCo in the first nine months of 2005 as a result of implementing this provision of the RSP. Of these amounts, approximately $8 million for CSPCo and $21 million for OPCo relate to 2004 environmental carrying costs and RTO costs. The decline in the third quarter of 2005 reflects the effect of substantial increases in FTR revenues which offset administrative and congestion costs.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding its approval of the RSP.  On March 23, 2005, the PUCO denied all applications for rehearing. In the second quarter of 2005, two intervenors filed separate appeals to the Ohio Supreme Court.  One of those appeals has been withdrawn.  The remaining appeal challenges the RSP and also argues that there is no POLR obligation in Ohio, and therefore CSPCo and OPCo are not entitled to recover any POLR charges.  If the Ohio Supreme Court reverses the PUCO's authorization of the POLR charge, CSPCo's and OPCo's 2005 earnings will be adversely affected.  In a nonaffiliated utility's proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, and therefore, CSPCo and OPCo have argued that they can recover the POLR charge.  In addition, if the RSP order is determined on appeal to be illegal under the restructuring legislation, it would have an adverse effect on the Ohio companies’ results of operations, cash flows and possibly financial condition. Although the Ohio companies believe that the RSP plan is legal and intend to defend vigorously the PUCO’s order, they cannot predict the ultimate outcome of the pending litigation.

On September 28, 2005, the Ohio companies filed with the PUCO to recover through a transmission cost recovery rider, beginning January 1, 2006, approximately $5 million for CSPCo and $7 million for OPCo of projected 2006 net costs incurred as a result of joining PJM. In addition, the Ohio companies requested to practice over/under-recovery deferral accounting for any differences between the revenues collected starting January 1, 2006 and the actual costs incurred. If the PUCO determines that any of the requested net incremental RTO costs are unrecoverable, it would have an adverse impact on the Ohio companies’ future results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, the Ohio companies are deferring customer choice implementation costs and related carrying costs in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. Through September 30, 2005, CSPCo and OPCo incurred $42 million and $44 million, respectively, of such costs, and accordingly, deferred $22 million and $24 million, respectively, of such costs for probable future recovery in distribution rates. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. Pursuant to the RSP, recovery of these amounts will be deferred until the next distribution rate filing to change rates after December 31, 2008. The Ohio companies believe that the deferred customer choice implementation costs were prudently incurred to implement and effect customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on the Ohio companies’ future results of operations and cash flows.

Integrated Gasification Combined Cycle (IGCC) Power Plant

On March 18, 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new approximately 600 MW IGCC power plant using clean-coal technology. The application proposes 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 from 2007 through mid-2010 when the plant is projected to be placed in commercial operation. 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 RSP. 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. As of September 30, 2005, AEP has deferred $6 million of pre-construction IGCC costs. These costs primarily relate to an agreement with GE Energy and Bechtel Corporation to begin the front-end engineering design process.

Litigation

Registrant Subsidiaries continue to be involved in various litigation matters as described in the “Significant Factors - Litigation” section of the Combined Management’s Discussion and Analysis of Registrant Subsidiaries in the 2004 Annual Report. The 2004 Annual Report should be read in conjunction with this report in order to understand other litigation matters that did not have significant changes in status since the issuance of the 2004 Annual Report, but may have an impact on future results of operations, cash flows and financial condition. Other matters described in the 2004 Annual Report that did not have significant changes during the first nine months of 2005, that should be read in order to gain a full understanding of the current litigation include disclosure related to the Coal Transportation Dispute, Enron Bankruptcy and Potential Uninsured Losses. Additionally, refer to the Commitments and Contingencies footnote in the Condensed Notes to Financial Statements of Registrant Subsidiaries for further discussion of these matters.

New Source Review Litigation

See discussion of New Source Review Litigation under “Environmental Matters.”

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and filed a petition for review of this Initial Decision, which the SEC has granted.

Management believes the repeal of PUHCA will end litigation challenging the AEP/CSW merger. All parties to the proceeding have filed motions with the SEC supporting dismissal of the proceeding upon repeal of the PUHCA in February 2006.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against AEP and four of its subsidiaries, including TCC and TNC, ERCOT and a number of nonaffiliated energy companies, including TXU, CenterPoint, Texas Genco, Reliant, TECO, and Tractebel.  The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against TCC and TNC, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs.  In June 2004, the Court dismissed all claims against AEP and its subsidiaries. TCE appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. The Fifth Circuit issued its decision in June 2005 and affirmed the lower court’s decision. TCE filed a Petition for Writ of Certiorari with the United States Supreme Court on October 14, 2005. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit against the same defendants and others.  Trial is scheduled in the Utility Choice/Cirro Energy case for April 2006. On October 18, 2005, the U.S. District Court heard oral argument on our Motion to Dismiss. We intend to continue to vigorously defend against the allegations in these cases.

Ontario Litigation

In June 2005, CSPCo and OPCo were named as two of 21 defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. They have not been served with the lawsuit. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operation, have emitted NO_x, SO₂ and particulate matter that have harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $50 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. Management believes they have meritorious defenses to this action and intend to defend vigorously against it.

Environmental Matters

As discussed in the 2004 Annual Report, there are emerging environmental control requirements that management expects will result in substantial capital investments and operational costs. The sources of these future requirements include:

· Legislative and regulatory proposals to adopt stringent controls on SO₂, NO_x and mercury emissions from coal-fired power plants,

· Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and

· Possible future requirements to reduce carbon dioxide emissions to address concerns about global climatic change.

This discussion updates certain events occurring in 2005. You should also read the “Significant Factors - Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries in the 2004 Annual Report for a description of all environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) the Comprehensive Environmental Response Compensation and Liability Act (Superfund) and state remediation, (4) global climate change, (5) costs for spent nuclear fuel disposal and decommissioning, and (6) Clean Water Act regulation.

Future Reduction Requirements for SO₂, NO_x, and Mercury

Regulatory Emissions Reductions

In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO₂, NO_x and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

· The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO₂ and NO_x emissions across the Eastern United States (29 states and the District of Columbia) and make progress toward attainment of the new fine particulate matter and ground-level ozone national ambient air quality standards. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program.

· The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.

On March 14, 2005, the Administrator of the Federal EPA signed the final CAIR. The rule includes both a seasonal and annual NO_x control program as well as an annual SO₂ control program. All of the states in which the Registrant Subsidiaries’ generating facilities are located will be subject to the seasonal and annual NO_x control programs and the annual SO₂ control program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the annual programs only. Arkansas will be subject to the seasonal NO_x control program only. Oklahoma is not affected by CAIR. In addition, the compliance deadline for Phase I for the NO_x control program has been accelerated to 2009, and will replace any obligations imposed by the NO_x State Implementation Plan (SIP) Call in 2009. On August 24, 2005, the Administrator of the Federal EPA published a proposed rule that includes a federal implementation plan (FIP) to reduce transport of fine particulate matter and ozone, modeled on the final CAIR, and proposes to deny the Section 126 petition filed by the State of North Carolina to require reductions of NO_x and SO₂ from specific facilities in thirteen states, including several AEP facilities. The proposed rule denies North Carolina’s petition for action based on its ozone non-attainment area, since the Federal EPA’s modeling predicts that this area will be in attainment with the 8-hour standard in 2010. The Federal EPA also proposes to deny the petition based on North Carolina’s PM_2.5 non-attainment areas, based on the reductions prescribed by the FIP, or to withdraw its Section 126 findings with respect to any state that submits a SIP implementing the CAIR requirements.

On March 15, 2005, the Administrator of the Federal EPA signed a final Clean Air Mercury Rule (CAMR) that will permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. The final CAMR imposes a national cap on mercury emissions from coal-fired power plants of 38 tons by 2010 and 15 tons by 2018. On October 21, 2005, the Federal EPA announced its decision to reconsider several issues in connection with the CAMR, including the legal basis for its decision to withdraw the December 2000 finding under Section 112 of the CAA and the impacts associated with the implementation of an emissions cap and trading program.

In April 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include "Best Available Retrofit Technology" (BART) requirements for individual facilities in their SIPs to address regional haze. The requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. On June 15, 2005, the Federal EPA issued its final "Clean Air Visibility Rule" (CAVR). The record for the final rule contains an analysis that demonstrates that for electric generating units subject to CAIR, CAIR will result in more visibility improvements than BART would provide. Therefore, states that adopt the CAIR are allowed to substitute CAIR for controls otherwise required by BART. On July 20, 2005, the Federal EPA also issued a proposed rule detailing the requirements for an emissions trading program that can satisfy the BART requirements for the regional haze program.

The changes in the Federal EPA’s final CAIR, CAMR and CAVR have not caused us to revise our estimates of the capital investments necessary to achieve compliance with these requirements. However, the final rules give states substantial discretion in developing their rules to implement these programs, and states will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. In addition, the CAIR, CAMR and CAVR have been challenged in the United States Court of Appeals for the District of Columbia. As a result, the ultimate requirements may not be known for several years and may depart significantly from the rules described herein. If the final rules are remanded by the court, if states elect not to participate in the federal cap-and-trade programs, and/or if states elect to impose additional requirements on individual units that are already subject to the CAIR, CAVR and/or CAMR, our costs could increase significantly. The cost of compliance could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.

New Source Review (NSR) Litigation

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review 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 Court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at the generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. 

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.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV were already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern states each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. The Northeastern states’ complaint has been assigned to the same judge in the U.S. District Court for the Southern District of Ohio. AEP filed an answer to the Northeastern states’ complaint to the Federal EPA’s complaint, denying the allegations and stating its defenses.

On June 24, 2005, the United States Court of Appeals for the District of Columbia Circuit issued a decision affirming in part the new source review reform regulations adopted by the Federal EPA in December 2002. The court upheld the Federal EPA’s decision to apply an actual-to-future actual emissions, and includes test, utilizing a five-year look back period to establish actual baseline emissions for utilities and a ten-year period for other sources. This excludes increased emissions unrelated to a physical change from the projected emissions and includes emissions associated with demand growth. The court vacated the Federal EPA’s adoption of a broad pollution control project exclusion that includes projects that result in a significant collateral emissions increase, and the “clean unit” applicability test, and remanded certain recordkeeping requirements to the Federal EPA.

On August 30, 2005, the United States Court of Appeals for the Fourth Circuit denied the petitions for rehearing filed by the United States and other appellants in the Duke Energy case. On October 13, 2005, the Administrator of the Federal EPA signed a proposed rule that would adopt a test for determining when an emissions increase results from a change at an existing electric utility generating unit under the federal NSR programs that would be consistent with the test adopted and applied by the Fourth Circuit in the Duke Energy case. This would be based on maximum hourly emissions before and after the change. The Federal EPA is also seeking comments on two alternative formulations of the emission increase test.  We have filed a Motion in the NSR litigation that asks the Court, among other things, to dismiss the NSR cases on due process grounds based on the statements and admissions the Federal EPA made in promulgating the proposed rule.

Management is unable to estimate the loss or range of loss related to any contingent liability the 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 the AEP subsidiaries do not prevail, management believes they 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 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.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005.

On July 19, 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. On April 11, 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 and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 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 references 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.

Emergency Release Reporting

Superfund requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances that cross property boundaries of the releasing facility.

On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to the alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. I&M and the Federal EPA signed a Final Consent Agreement and Final Order related to the Administrative Complaint effective June 30, 2005. I&M paid a $15 thousand penalty and will invest in a supplemental environmental project at the Cook Plant.

On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant SCR system. The Federal EPA indicated its intent to seek civil penalties. OPCo and the Federal EPA signed a Final Consent Agreement and Final Order related to the Administrative Complaint effective September 30, 2005. OPCo paid a $16 thousand penalty and will invest in a supplemental environmental project at the Gavin Plant.

Carbon Dioxide Public Nuisance Claims

In July 2004, attorneys general from eight states and the corporation counsel for the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions alleged that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. A notice of appeal to the Second Circuit Court of Appeals has been filed on behalf of all plaintiffs. A briefing schedule has not been established.

CONTROLS AND PROCEDURES

During the third quarter of 2005, management, including the principal executive officer and principal financial officer of each of AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the Registrants’ 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 SEC’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 the Registrants’ 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 September 30, 2005, 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 was no change 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 third quarter of 2005 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see Note 5, Commitments and Contingencies, incorporated herein by reference.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

NONE

Item 5. Other Information

NONE

Item 6. Exhibits

AEP

31(a) - Certification of AEP Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(c) - Certification of AEP Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.

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

31(b) - Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(d) - Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

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.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

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

By: /s/Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

Date: November 4, 2005

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 report on Form 10-Q of American Electric Power Company, Inc.;

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

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

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

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

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

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

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

5.   The registrant’s other certifying officer 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 the registrant’s board of directors (or persons performing the equivalent functions):

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: November 4, 2005By:          /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, Michael G. Morris, certify that:

1.   I have reviewed this report on Form 10-Q 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 each registrant as of, and for, the periods presented in this report;

4.   Each registrant’s other certifying officer 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 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 evaluation; 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.   Each registrant’s other certifying officer 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 the registrant’s board of directors (or persons performing the equivalent functions):

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: November 4, 2005By:          /s/ Michael G. Morris

Michael G. Morris

Chief Executive Officer

EXHIBIT 31(c)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Susan Tomasky, certify that:

1.   I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;

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

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

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

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

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

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

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

5.   The registrant’s other certifying officer 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 the registrant’s board of directors (or persons performing the equivalent functions):

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:November 4, 2005By:          /s/ Susan Tomasky

Susan Tomasky

Chief Financial Officer

EXHIBIT 31(d)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Susan Tomasky, certify that:

1.   I have reviewed this report on Form 10-Q 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 each registrant as of, and for, the periods presented in this report;

4.   Each registrant’s other certifying officer 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 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 evaluation; 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.   Each registrant’s other certifying officer 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 the registrant’s board of directors (or persons performing the equivalent functions):

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: November 4, 2005By:          /s/ Susan Tomasky

Susan Tomasky

Chief Financial Officer

Exhibit 32(a)

This Certification 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 Quarterly Report of the Companies (as defined below) on Form 10-Q (the “Reports”) for the quarterly period ended September 30, 2005 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

November 4, 2005

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 Certification 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 Quarterly Report of the Companies (as defined below) on Form 10-Q (the “Reports”) for the quarterly period ended September 30, 2005 as filed with the Securities and Exchange Commission on the date hereof, I, Susan Tomasky, 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/ Susan Tomasky

Susan Tomasky

Chief Financial Officer

November 4, 2005

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.