Indiana Michigan Power 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