Aep Generating 10-Q 2006 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, 2006

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filer   X      Accelerated filer Non-accelerated filer

Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are large accelerated filers, accelerated filers, or non-accelerated filers. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer    Accelerated filer Non-accelerated filer   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 of the registrants at October 31, 2006
AEP Generating Company	1,000
	($1,000 par value)
AEP Texas Central Company	2,211,678
	($25 par value)
AEP Texas North Company	5,488,560
	($25 par value)
American Electric Power Company, Inc.	395,572,735
	($6.50 par value)
Appalachian Power Company	13,499,500
	(no par value)
Columbus Southern Power Company	16,410,426
	(no par value)
Indiana Michigan Power Company	1,400,000
	(no par value)
Kentucky Power Company	1,009,000
	($50 par value)
Ohio Power Company	27,952,473
	(no par value)
Public Service Company of Oklahoma	9,013,000
	($15 par value)
Southwestern Electric Power Company	7,536,640
	($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO QUARTERLY REPORTS ON FORM 10-Q

September 30, 2006

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
	Index to Condensed Notes to Condensed Consolidated Financial Statements
AEP Generating Company:
	Management’s Narrative Financial Discussion and Analysis
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
AEP Texas Central Company and Subsidiaries:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
AEP Texas North Company and Subsidiary:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Appalachian Power Company and Subsidiaries:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
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
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Indiana Michigan Power Company and Subsidiaries:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Kentucky Power Company:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Ohio Power Company Consolidated:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Public Service Company of Oklahoma:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Southwestern Electric Power Company Consolidated:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Condensed Notes to Condensed 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 1A.	Risk Factors
	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

ADFIT	Accumulated Deferred Federal Income Taxes.
ADITC	Accumulated Deferred Investment Tax Credits.
AEGCo	AEP Generating Company, an AEP electric generating subsidiary.
AEP or Parent	American Electric Power Company, Inc.
AEP Consolidated	AEP and its majority owned consolidated subsidiaries and consolidated entities.
AEP East companies	APCo, CSPCo, I&M, KPCo and OPCo.
AEPES	AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System	American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or AEP   Power Pool	Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEPSC	American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP West companies	PSO, SWEPCo, TCC and TNC.
AFUDC	Allowance for Funds Used During Construction.
ALJ	Administrative Law Judge.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
CAA	Clean Air Act.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo	Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW	Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement	Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing their generating capacity allocation. AEPSC acts as the agent.
CTC	Competition Transition Charge.
DETM	Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
ECAR	East Central Area Reliability Council.
EDFIT	Excess Deferred Federal Income Taxes.
EITF	Financial Accounting Standards Board’s Emerging Issues Task Force.
EPACT	Energy Policy Act of 2005.
ERCOT	Electric Reliability Council of Texas.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
GAAP	Accounting Principles Generally Accepted in the United States of America.
HPL	Houston Pipe Line Company LP, a former AEP subsidiary that was sold in January 2005.
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.
IRS	Internal Revenue Service.
IURC	Indiana Utility Regulatory Commission.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KPSC	Kentucky Public Service Commission.
kV	Kilovolt.
KWH	Kilowatthour.
MISO	Midwest Independent Transmission System Operator.
MTM	Mark-to-Market.

MW	Megawatt.
MWH	Megawatthour.
NOx	Nitrogen oxide.
Nonutility Money Pool	AEP System’s Nonutility Money Pool.
NRC	Nuclear Regulatory Commission.
NSR	New Source Review.
NYMEX	New York Mercantile Exchange.
OATT	Open Access Transmission Tariff.
OCC	Corporation Commission of the State of Oklahoma.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
OTC	Over the counter.
PJM	Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB	Price-to-Beat.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
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 or leased by AEGCo and I&M.
RSP	Rate Stabilization Plan.
RTO	Regional Transmission Organization.
S&P	Standard and Poor’s.
SEC	United States Securities and Exchange Commission.
SECA	Seams Elimination Cost Allocation.
SFAS	Statement of Financial Accounting Standards issued by the FASB.
SFAS 133	Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SIA	System Integration Agreement.
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.
TEM	SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring Legislation	Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC	AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding	A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Utility Money Pool	AEP System’s Utility Money Pool.
VaR	Value at Risk, a method to quantify risk exposure.
Virginia SCC	Virginia State Corporation Commission.
WPCo	Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC	Public Service Commission of West Virginia.

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

· Electric load and customer growth.

· Weather conditions, including storms.

· Available sources and costs of, and transportation for, fuels and the creditworthiness of fuel suppliers and transporters.

· Availability of generating capacity and the performance of our generating plants.

· Our ability to recover regulatory assets and stranded costs in connection with deregulation.

· Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.

· Our ability to build or acquire generating capacity when needed at acceptable prices and terms and to recover those costs through applicable rate cases or competitive rates.

· New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances.

· Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for new investments, transmission service and environmental compliance).

· Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp. and related matters).

· Our ability to constrain operation and maintenance costs.

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

· Inflationary and interest rate trends.

· Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.

· Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including 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 implementation of EPACT and membership in and integration into 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

Several factors, both positive and negative, contributed to our performance in the third quarter of 2006. We continued receiving favorable outcomes in various regulatory activities resulting in increased revenues. We also continued securing new power supply contracts with municipal and cooperative customers and our barging subsidiary produced strong results. Some of these positive factors were offset in part by mild weather and an impairment related to our Plaquemine Cogeneration Facility in connection with the pending sale to Dow Chemical Company.

Regulatory Activity

Our significant regulatory activity progressed with the following major developments:

· In July 2006, an ALJ rendered an initial decision to the FERC recommending that current transmission rates in PJM are unjust and unreasonable and should be redesigned to replace the PJM license plate rates effective April 1, 2006. If approved by the FERC, the new regional rates would result in parties outside of the AEP zone in PJM contributing a significant portion of AEP’s transmission revenue requirement, some of which may be treated as a refund to retail customers. The favorable impact of the initial ALJ decision is not determinable pending the decision of the FERC and subject to analysis of refunds to retail customers, if any.

· In July 2006, the FERC approved our request for use of an incentive rate treatment for our proposed 550-mile 765 kV transmission line project. The approval is conditioned upon PJM including the project in its formal Regional Transmission Expansion Plan, which should be finalized in early 2007.

· In July 2006, the West Virginia Public Service Commission approved a settlement agreement in APCo and WPCo’s base rate case, providing for a $44 million annual increase in rates effective July 28, 2006. These rates include a surcharge for recovery of the cost of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.

· In August 2006, an ALJ rendered an initial decision to the FERC indicating the rate design for recovery of SECA charges was flawed and that the SECA rates charged were unfair, unjust and discriminatory and that refunds should be made. We believe this decision is contrary to other FERC rulings and intend to defend against a SECA rates refund.

· In September 2006, the Virginia SCC’s chief hearing examiner issued an opinion recommending disallowance of our $21 million environmental and reliability cost recovery case filed in June 2005. We subsequently wrote off our related assets which reduced pretax earnings by $36 million in the third quarter of 2006. We believe the hearing examiner’s recommendation is contrary to the law and have urged the Virginia SCC not to adopt that recommendation.

· In September 2006, we announced our intention to file transmission and distribution wires rate cases in Texas in late 2006.  We anticipate requesting an $83 million increase for TCC and a $25 million increase for TNC.

· In September 2006, we filed a notice of intent in Oklahoma to file a base rate case in November 2006.

· In October 2006, we filed state environmental permit applications for clean-coal power plants in Ohio and West Virginia, representing another step towards the commencement of construction of our IGCC plants.

· In October 2006, we implemented an interim increase in Virginia retail base rates, subject to refund, as ordered by the Virginia SCC related to our $198 million net base rate case filing from May 2006. Hearings are scheduled for December 2006.

· In October 2006, TCC issued $1.74 billion senior secured transition bonds as previously approved by the PUCT. In October 2006, TCC repaid $345 million of intercompany notes to AEP and also paid a special dividend of $585 million to AEP. We will use the remaining proceeds to reduce a portion of TCC’s debt and equity.

· In October 2006, the IURC denied our request to revise I&M’s book depreciation rates without adjusting base tariff rates.

Fuel Costs

During 2006, spot market prices for coal and natural gas have declined. In contrast, market prices for fuel oil have increased and continue to be volatile. We still expect an approximate ten percent increase in coal costs during 2006 and a six to eight percent increase in 2007 even considering softening fuel markets and favorable transportation effects during the first nine months of the year. We have price risk related to these commodity prices. We do not have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs.

In Indiana, our fuel recovery mechanism is temporarily capped, subject to preestablished escalators, at a fixed rate through June 2007. As a consequence of the cap, we incurred under-recoveries of $17 million for the first nine months of 2006 and expect additional under-recoveries for the remainder of 2006. Our Ohio companies increased their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans, which are intended to recover increases in generation costs, including increased fuel costs. These increased rates, along with the reinstated fuel cost adjustment rate clause for over- or under-recovery of fuel, off-system sales margins, certain transmission items and related costs effective July 1, 2006 in West Virginia, will help offset future negative impacts of fuel price increases on our gross margins.

Barging Operations

With the exception of the Plaquemine Cogeneration Facility impairment in the third quarter of 2006, we achieved favorable 2006 results in our Investments - Other segment primarily due to our barging operations. AEP MEMCO LLC (MEMCO) handles the dispatching and logistics for our river operations, which consist primarily of coal deliveries to our plants, coal movement between plants for ensuring continued operations during market disruptions and transportation of bargeable commodities for third parties. MEMCO continues to benefit from strong market demand for barging services as well as a tight supply of barges, which allowed it to negotiate favorable annual freight contracts for 2006 and beyond for hauling a variety of commodities for third parties. The strong freight market, enhanced operating conditions when compared with the flooding and ice encountered during the first quarter of 2005, and the continued implementation of programs to maximize equipment use, all contributed to an increase in tonnage transported and a corresponding increase in earnings.

Power Generation Facility

In August 2006, we reached an agreement to sell our Plaquemine Cogeneration Facility (the Facility) to Dow Chemical Company (Dow) for $64 million. We expect the sale to close in the fourth quarter of 2006. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on the terms of the agreement to sell the Facility to Dow. In addition to the cash proceeds, the sale agreement allows us to participate in gross margin sharing on the Facility for five years and we retain the right to any judgment paid by TEM for breaching the original PPA, as discussed in Note 5.

Assuming the sale closes, our future earnings will be favorably impacted by eliminating ongoing operating losses. These improvements will be partially offset by interest expense associated with continuing debt service obligations.

Dividend Increase

In October 2006, our Board of Directors approved a five percent increase in our quarterly dividend to $0.39 per share from $0.37 per share.

RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their major activities are:

Utility Operations
	·	Generation of electricity for sale to U.S. retail and wholesale customers.
	·	Electricity transmission and distribution in the U.S.
Investments - Other
	·	Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.

Our consolidated Income Before Discontinued Operations for the three and nine months ended September 30, 2006 and 2005 were as follows (Earnings and Weighted Average Number of Basic Shares Outstanding in millions):

	Three Months Ended September 30,												Nine Months Ended September 30,
	2006						2005						2006						2005
	Earnings			EPS (c)			Earnings			EPS (c)			Earnings			EPS (c)			Earnings			EPS (c)
Utility Operations	$	379		$	0.96		$	352		$	0.91		$	904		$	2.29		$	952		$	2.45
Investments - Other		(109	) (d)		(0.28	) (d)		28			0.07			(80	) (d)		(0.20	) (d)		32			0.08
All Other (a)		(2	)		-			(5	)		(0.01	)		(7	)		(0.02	)		(45	)		(0.12	)
Investments - Gas Operations (b)		(3	)		(0.01	)		(10	)		(0.03	)		(2	)		-			(2	)		-
Income Before Discontinued Operations	$	265		$	0.67		$	365		$	0.94		$	815		$	2.07		$	937		$	2.41
Weighted Average Number of Basic   Shares Outstanding					394						389						394						389

(a)	All Other includes the parent company’s guarantee revenues, interest income and expense, as well as other nonallocated costs.
(b)	We sold our remaining gas pipeline and storage assets in 2005.
(c)	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.
(d)	Loss primarily due to an after-tax impairment of $136 million (approximately $0.34 per share) related to our Plaquemine Cogeneration Facility.

Third Quarter of 2006 Compared to Third Quarter of 2005

Income Before Discontinued Operations in the third quarter of 2006 decreased $100 million compared to the third quarter of 2005 principally due to an impairment of the Plaquemine Cogeneration Facility as a result of the pending sale and decreases in Utility Operations earnings related to lower transmission revenues from the loss of SECA rates and the write off of Virginia environmental and reliability regulatory assets pursuant to a hearing examiner's recommendation, which we have urged the Virginia SCC not to adopt. These decreases were partially offset by an earnings increase in Utility Operations primarily related to new retail rates implemented in Ohio and Kentucky and increased off-system sales margins.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Income Before Discontinued Operations for the nine months ended September 30, 2006 decreased $122 million compared to the nine months ended September 30, 2005 due to a $48 million decrease in Utility Operations earnings from decreases in transmission revenues from the loss of SECA rates and increases in operating expenses, partially offset by new retail rates implemented in Ohio and Kentucky. In addition, our Investments - Other segment earnings decreased $112 million from an impairment of the Plaquemine Cogeneration Facility related to the pending sale. These decreases were partially offset by a decrease of $38 million in interest expense, net of interest income, at the parent company.

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

Utility Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in millions)
Revenues	$	3,441	$	3,237	$	9,209	$	8,623
Fuel and Purchased Energy		1,384		1,252		3,637		3,163
Gross Margin		2,057		1,985		5,572		5,460
Depreciation and Amortization		369		328		1,041		963
Other Operating Expenses		973		1,014		2,806		2,757
Operating Income		715		643		1,725		1,740
Other Income, Net		20		43		105		122
Interest Expense and Preferred Stock Dividend  Requirements		161		145		475		445
Income Tax Expense		195		189		451		465
Income Before Discontinued Operations	$	379	$	352	$	904	$	952

Summary of Selected Sales and Weather Data

For Utility Operations

For the Three and Nine Months Ended September 30, 2006 and 2005

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in millions of KWH)
Energy Summary
Retail:
Residential		13,482		14,152		36,010		37,332
Commercial		10,799		10,900		29,149		29,204
Industrial		13,468		13,380		40,405		39,633
Miscellaneous		677		682		1,890		1,968
Subtotal		38,426		39,114		107,454		108,137
Texas Retail and Other		105		115		312		504
Total Retail		38,531		39,229		107,766		108,641
Wholesale		13,465		13,135		35,131		37,515
Texas Wires Delivery		7,877		8,093		20,338		20,348
Total KWHs		59,873		60,457		163,235		166,504

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on results of operations. In general, degree day changes in our eastern region have a larger effect on results of operations than changes in our western region due to the relative size of the two regions and the associated number of customers within each. Cooling degree days and heating degree days in our service territory for the quarter and year-to-date periods ended September 30, 2006 and 2005 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in degree days)
Weather Summary
Eastern Region
Actual - Heating (a)		10		1		1,573		1,940
Normal - Heating (b)		7		7		1,999		1,995
Actual - Cooling (c)		685		834		914		1,122
Normal - Cooling (b)		688		674		970		955
Western Region (d)
Actual - Heating (a)		0		0		664		795
Normal - Heating (b)		2		2		1,007		1,007
Actual - Cooling (c)		1,468		1,523		2,325		2,225
Normal - Cooling (b)		1,410		1,397		2,079		2,059

(a)	Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the 30-year average of degree days.
(c)	Eastern Region and Western Region cooling days are calculated on a 65 degree temperature base.
(d)	Western Region statistics represent PSO/SWEPCo customer base only.

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006

Income from Utility Operations Before Discontinued Operations

(in millions)

Third Quarter of 2005			$	352
Changes in Gross Margin:
Retail Margins	29
Off-system Sales	75
Transmission Revenues	(38	)
Other	6
Total Change in Gross Margin				72
Changes in Operating Expenses and Other:
Maintenance and Other Operation	(15	)
Asset Impairments and Other Related Charges	39
Depreciation and Amortization	(41	)
Taxes Other Than Income Taxes	17
Other Income, Net	(23	)
Interest and Other Charges	(16	)
Total Change in Operating Expenses and Other				(39	)
Income Tax Expense				(6	)
Third Quarter of 2006			$	379

Income from Utility Operations Before Discontinued Operations increased $27 million to $379 million in 2006. The key driver of the increase was a $72 million net increase in Gross Margin, partially offset by a $39 million increase in Operating Expenses and Other.

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

· Retail Margins increased $29 million primarily due to the following:

· A $72 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our Rate Stabilization Plans (RSPs) and a $12 million increase related to new rates implemented in Kentucky as approved in our base rate case;

· A $20 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily as a result of new power supply contracts; and

· An $18 million increase related to the purchase of the Ohio service territory of Monongahela Power in December 2005; partially offset by

 · A $22 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market;

 · A $33 million decrease related to increased refunds to retail customers of a portion of off-system sales margins due to higher off-system sales and the reinstatement of the off-system sales margins sharing mechanism in West Virginia effective July 1, 2006 in conjunction with the West Virginia rate case settlement;

 · A $14 million increase in delivered fuel costs, which relates to AEP East companies with inactive, capped or frozen fuel clauses; and

 · A $30 million decrease in usage related to mild weather. As compared to the prior year, we experienced an 18% decrease in cooling degree days in the eastern region and a 4% decrease in the western region.

· Margins from Off-system Sales for 2006 increased $75 million primarily due to positive margins from hedges of plant output and strong physical sales in the east, where AEP’s generation availability factor was high in July and August when wholesale prices were favorable.

· Transmission Revenues decreased $38 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

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

· Maintenance and Other Operation expenses increased $15 million primarily due to increases in generation expenses for base operations, maintenance and an abandonment of digital turbine control equipment at the Cook Plant, increases in transmission and distribution expenses related to vegetation management and storm restoration and the establishment of a regulatory asset for PJM administrative fees in 2005 which reduced expenses in the prior period, offset by the establishment of a net regulatory asset for recovery of prior years’ Ohio ice storm damage costs and lower incentive pay accruals.

· Asset Impairments and Other Related Charges were $39 million in 2005 due to our commitment to a plan in September 2005 to retire two units at our Conesville Plant. We retired the two units effective December 29, 2005.

· Depreciation and Amortization expense increased $41 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases, higher depreciable property balances and the write off of Virginia environmental and reliability regulatory assets.

· Taxes Other Than Income Taxes decreased $17 million primarily due to adjustments related to real and personal property taxes and sales and use taxes.

· Other Income, Net decreased $23 million primarily related to the write off of carrying costs on Virginia environmental and reliability regulatory assets.

· Interest and Other Charges increased $16 million primarily due to additional debt issued in late 2005 and early 2006 and an increase in regulatory interest related to Texas regulatory liabilities partially offset by an increase in allowance for borrowed funds used during construction.

· Income Tax Expense increased $6 million due to the increase in pretax income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to Nine Months Ended September 30, 2006

Income from Utility Operations Before Discontinued Operations

(in millions)

Nine Months Ended September 30, 2005			$	952
Changes in Gross Margin:
Retail Margins	198
Off-system Sales	2
Transmission Revenues	(93	)
Other	5
Total Change in Gross Margin				112
Changes in Operating Expenses and Other:
Maintenance and Other Operation	(42	)
Gain on Disposition of Assets, Net	(47	)
Asset Impairments and Other Related Charges	39
Depreciation and Amortization	(78	)
Other Income, Net	(16	)
Interest and Other Charges	(30	)
Total Change in Operating Expenses and Other				(174	)
Income Tax Expense				14
Nine Months Ended September 30, 2006			$	904

Income from Utility Operations Before Discontinued Operations decreased $48 million to $904 million in 2006. The key driver of the decrease was a $174 million increase in Operating Expenses and Other, offset by a $112 million increase in Gross Margin and a $14 million decrease in Income Tax Expense.

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

· Retail Margins increased $198 million primarily due to the following:

· A $175 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs, a $22 million increase related to new rates implemented in Kentucky as approved in our base rate case and a $12 million increase related to new rates implemented in Oklahoma in June 2005;

· A $21 million increase in financial transmission rights revenue, net of congestion, due to improved management of price risk related to serving retail load within PJM under current transmission constraints;

· A $58 million increase related to increased usage and customer growth in the industrial and commercial classes of which $47 million relates to the purchase of the Ohio service territory of Monongahela Power in December 2005; and

 · A $50 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily as a result of new power supply contracts; partially offset by

 · An $84 million increase in delivered fuel cost, which relates to the AEP East companies with inactive, capped or frozen fuel clauses;

 · A $66 million decrease in usage related to mild weather. As compared to the prior year, our eastern region and western region experienced 19% and 17% declines, respectively, in heating degree days. Also compared to the prior year, our eastern region experienced a 19% decrease in cooling degree days. These decreases were partially offset by an increase of 5% in cooling degree days in the western region; and

 · A $15 million decrease related to increased refunds to retail customers of a portion of off-system sales margins due to higher off-system sales and the reinstatement of the off-system sales margins sharing mechanism in West Virginia effective July 1, 2006 in conjunction with the West Virginia rate case settlement.

· Transmission Revenues decreased $93 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $19 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

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

· Maintenance and Other Operation expenses increased $42 million primarily due to increases in generation expenses related to base operations, maintenance and planned and forced plant outages, distribution expenses related to vegetation management and the establishment of a regulatory asset for PJM administrative fees in 2005 which reduced expenses in the prior period. These increases were partially offset by favorable variances related to expenses from the January 2005 ice storm in Ohio and Indiana, decreases related to the sale of STP in May 2005 and lower incentive accruals.

· Asset Impairments and Other Related Charges were $39 million in 2005 due to our commitment to a plan in September 2005 to retire two units at our Conesville Plant. We retired the two units effective December 29, 2005.

· Gain on Disposition of Assets, Net decreased $47 million resulting from revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase-and-sale agreement from the sale of our REPs in 2002. In 2005, we reached a settlement with Centrica and received $112 million related to two years of earnings sharing whereas in 2006 we received $70 million related to one year of earnings sharing.

· Depreciation and Amortization expense increased $78 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases, higher depreciable property balances and the write off of Virginia environmental and reliability regulatory assets.

· Other Income, Net decreased $16 million primarily due to the write off of carrying costs on Virginia environmental and reliability regulatory assets and a decrease in Ohio carrying costs income as a result of the implementation of the Ohio rate stabilization plans in January 2006, partially offset by an increase in the allowance for equity funds used during construction.

· Interest and Other Charges increased $30 million from the prior period primarily due to additional debt issued in late 2005 and early 2006 and increasing interest rates, partially offset by an increase in allowance for borrowed funds used during construction.

· Income Tax Expense decreased $14 million due to the decrease in pretax income.

Investments - Other

Third Quarter of 2006 Compared to Third Quarter of 2005

Loss Before Discontinued Operations from our Investments - Other segment was $109 million in 2006 compared to income of $28 million in 2005. The change was primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility related to the pending sale and a $32 million after-tax gain on the sale of Pacific Hydro Limited in the third quarter of 2005, partially offset by favorable barging activity at MEMCO due to strong demand and a tight supply of barges resulting in increased barge freight rates. Also, the third quarter 2006 operating conditions for our barging operations improved from 2005 when Hurricane Katrina increased operating costs.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Loss Before Discontinued Operations from our Investments - Other segment was $80 million in 2006 compared to income of $32 million in 2005. The change was primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility related to the pending sale and a $32 million after-tax gain on the sale of Pacific Hydro Limited in the third quarter of 2005, partially offset by favorable barging activity at MEMCO due to strong demand and a tight supply of barges resulting in increased barge freight rates. Additionally, 2006 operating conditions for our barging operations improved from 2005 when hurricanes, severe ice and flooding caused increased operating costs.

Other

Parent

Third Quarter of 2006 Compared to Third Quarter of 2005

The parent company’s Loss Before Discontinued Operations decreased $3 million from 2005 primarily due to lower interest expense as a result of the maturity of senior unsecured notes of $396 million in the second quarter of 2006, partially offset by higher interest expense due to the issuance of $345 million of senior notes in June 2005.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

The parent company’s Loss Before Discontinued Operations decreased $38 million from 2005 primarily due to lower interest expense and associated buyback costs related to the redemption of $550 million of senior unsecured notes in April 2005 and increased affiliated interest income related to favorable results from the corporate borrowing program.

Investments - Gas Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

The Loss Before Discontinued Operations from our Gas Operations segment improved $7 million primarily related to results from gas contracts that were not sold with the gas pipeline and storage assets.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

The Loss Before Discontinued Operations from our Gas Operations segment was essentially flat. Prior year results included one month of HPL’s operations due to the sale of HPL in January 2005. Current year results relate primarily to gas contracts that were not sold with the gas pipeline and storage assets.

AEP System Income Taxes

The decrease in income tax expense of $63 million between the third quarter of 2006 and the third quarter of 2005 is primarily due to a decrease in pretax book income.

The decrease in income tax expense of $77 million between the nine months ended September 30, 2006 and the nine months ended September 30, 2005 is primarily due to a decrease in pretax book income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization ($ in millions)

	September 30, 2006				December 31, 2005
Long-term Debt, including amounts due within one year	$	12,763	57.0	%	$	12,226	57.2	%
Short-term Debt		23	0.1			10	0.0
Total Debt		12,786	57.1			12,236	57.2
Common Equity		9,525	42.6			9,088	42.5
Preferred Stock		61	0.3			61	0.3
Total Debt and Equity Capitalization	$	22,372	100.0	%	$	21,385	100.0	%

The amount of our common equity increased primarily due to earnings exceeding the amount of dividends paid in 2006. As a result, our ratio of total debt to total capital improved from 57.2% to 57.1%.

In September 2006, the FASB issued SFAS 158 related to phase one of its pension and postretirement benefit accounting project. It could have a  negative impact on our debt to capital ratio when reported at December 31, 2006. The new standard requires the recognition of an additional minimum liability for fully-funded pension and postretirement benefit plans, thereby eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net actuarial gains and losses. This could require recognition of a significant net-of-tax accumulated other comprehensive income reduction to common equity for those jurisdictions where a regulatory asset cannot be recorded. We estimate regulatory assets could offset as much as two-thirds of any net-of-tax accumulated other comprehensive income reduction.  The effective date is fiscal years ending after December 15, 2006.

Liquidity

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

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At September 30, 2006, our available liquidity was approximately $3.2 billion as illustrated in the table below:

	Amount		Maturity
	(in millions)
Commercial Paper Backup:
Revolving Credit Facility	$	1,500		March 2010
Revolving Credit Facility		1,500		April 2011
Total		3,000
Cash and Cash Equivalents		259
Total Liquidity Sources		3,259
Less: Letter of Credit Drawn		34
Net Available Liquidity	$	3,225

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

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain covenants that 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, 2006, this contractually-defined percentage was 54.2%. Nonperformance of these covenants could result in an event of default under these credit agreements. At September 30, 2006, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

The two amended revolving credit facilities do not contain a material adverse change clause.

Under a regulatory order, our utility subsidiaries, other than TCC, cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% of its capital. In addition, this order restricts the 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, 2006, all utility subsidiaries were comfortably in compliance with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At September 30, 2006, our utility subsidiaries had not exceeded those authorized limits.

Credit Ratings

AEP’s ratings have not been adjusted by any rating agency during 2006 and AEP is currently on a stable outlook by the rating agencies. Our current credit ratings are as follows:

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

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

Cash Flow

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

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	401		$	320
Net Cash Flows From Operating Activities		2,213			1,699
Net Cash Flows Used For Investing Activities		(2,474	)		(60	)
Net Cash Flows From (Used For) Financing Activities		119			(1,110	)
Net Increase (Decrease) in Cash and Cash Equivalents		(142	)		529
Cash and Cash Equivalents at End of Period	$	259		$	849

Cash from operations, bank-sponsored receivables purchase agreement and short-term borrowings provide working capital and allows us to meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of September 30, 2006, we had credit facilities totaling $3 billion to support our commercial paper program without an outstanding balance. The maximum amount of commercial paper outstanding during the nine months ended September 30, 2006 was $325 million. The weighted-average interest rate for our commercial paper during the first nine months of 2006 was 4.96%. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements. Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders. See the discussion below for further detail related to the components of our cash flows.

Operating Activities

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Net Income	$	821		$	963
Less: Discontinued Operations, Net of Tax		(6	)		(26	)
Income Before Discontinued Operations		815			937
Noncash Items Included in Earnings		1,164			987
Changes in Assets and Liabilities		234			(225	)
Net Cash Flows From Operating Activities	$	2,213		$	1,699

The key drivers of the increase in cash from operations for the first nine months of 2006 were no Pension Contributions to Qualified Plan Trusts in 2006 compared with a $306 million contribution in 2005 and increased recovery of deferred fuel. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs.

Net Cash Flows From Operating Activities were $2.2 billion in 2006 consisting primarily of Income Before Discontinued Operations of $815 million adjusted for noncash charges of $1.2 billion, which principally includes $1.1 billion for Depreciation and Amortization. Changes in Assets and Liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant is a $235 million decrease in cash related to customer deposits held for trading activities generally due to lower gas and power market prices.

Net Cash Flows From Operating Activities were $1.7 billion in 2005 consisting primarily of Income Before Discontinued Operations of $937 million adjusted for noncash charges of $987 million, which principally includes $988 million for Depreciation and Amortization. Changes in Assets and Liabilities represent those items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $311 million cash increase from Customer Deposits held for trading activities and increases from Accounts Payable and Accrued Taxes. Cash increased $173 million related to Accounts Payable due to higher fuel and allowance acquisition costs not paid at September 30, 2005. Accrued Taxes 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. We also realized gains on sales of assets of $172 million and made contributions of $306 million to our pension trust fund.

Investing Activities

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Investment Securities:
Purchases of Investment Securities	$	(8,153	)	$	(4,319	)
Sales of Investment Securities		8,056			4,378
Change in Investment Securities, Net		(97	)		59
Construction Expenditures		(2,445	)		(1,610	)
Acquisition of Waterford Plant		-			(218	)
Change in Other Temporary Cash Investments, Net		20			99
Proceeds from Sales of Assets		120			1,599
Other		(72	)		11
Net Cash Flows Used for Investing Activities	$	(2,474	)	$	(60	)

Net Cash Flows Used For Investing Activities were $2.5 billion in 2006 primarily due to Construction Expenditures supporting our environmental investment plan. These cash flows were consistent with our budgeted cash flows for investing activities for the nine months ended September 30, 2006.  We forecast $1.3 billion of Construction Expenditures for the remainder of 2006, which will be funded through results of operations and financing activities.

During 2006, we purchased $8.2 billion of investments and received $8.1 billion of proceeds from the sales of securities. During 2005, we purchased $4.3 billion of investments and received $4.4 billion of proceeds from the sales of securities. In our normal course of business, we purchase taxable and tax exempt securities with cash available for short-term investments. The increased purchases and sales in 2006 reflect our investing in expanded investment security types. These amounts also include purchases and sales within our nuclear trusts.

Net Cash Flows Used For Investing Activities were $60 million in 2005 primarily due to the proceeds from the sale of HPL and STP, a portion of which we used to repurchase common stock and retire senior unsecured notes. Our Construction Expenditures of $1.6 billion included generation, environmental, transmission and distribution investment.

We forecast $3.5 billion of construction expenditures for 2007, which will be funded through results of operations and financing activities. These 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, legal reviews and the ability to access capital.

Financing Activities

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Issuance of Common Stock	$	24		$	393
Repurchase of Common Stock		-			(427	)
Issuance/Retirement of Debt, Net		529			(562	)
Dividends Paid on Common Stock		(437	)		(408	)
Other		3			(106	)
Net Cash Flows From (Used for) Financing Activities	$	119		$	(1,110	)

Net Cash Flows From Financing Activities in 2006 were $119 million. During 2006, we issued $115 million of new obligations relating to pollution control bonds, issued $1 billion of senior unsecured notes and retired $396 million of senior unsecured notes for a net increase in senior unsecured notes outstanding of $604 million and retired $100 million of first mortgage bonds and $52 million of securitization bonds. See Note 13 for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used For Financing Activities in 2005 were $1.1 billion. During 2005, we repurchased common stock and reduced outstanding long-term debt using the proceeds from the sale of HPL and the conversion of the equity units to common stock. In addition, our subsidiaries retired $66 million of cumulative preferred stock, which is reflected in the Other amount in the above table.  In addition to the equity unit conversion, we had limited stock issuances related to stock options exercised.

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 guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business. Our significant off-balance sheet arrangements changed from year-end as follows:

	September 30, 2006		December 31, 2005
	(in millions)
AEP Credit	$	548	$	516
Rockport Plant Unit 2		2,437		2,511
Railcars		31		31

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” - “Financing Activities” above.

Other

Cook Plant Outage

In September 2006, Cook Plant Unit 1 began a regular scheduled refueling outage. This outage includes the replacement of major components, including the reactor vessel head. Installation of capital projects exceeding $100 million will be completed during this outage and were included in our capital forecast. The improvements and replacement of major components should increase unit capacity and efficiency. We expect to restart Cook Plant Unit 1 in early November 2006 as planned.  We refueled Cook Plant Unit 2 during March and April 2006 and plan to replace its vessel head during its next refueling outage in the fall of 2007.

Texas REPs

As part of the purchase and sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities. In March of 2006, we received a $70 million payment for our share in earnings for 2005. The payment for 2006 is contingent on Centrica’s future operating results, contractually capped at $20 million and, to the extent earned, is expected to be received and recorded in the first quarter of 2007.

New Generation

In September 2005, PSO sought proposals for new peaking generation to be online in 2008 and in December 2005 sought proposals for base load generation to be online in 2011. PSO received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from neutral third parties. In March 2006, PSO announced plans to add 170 MW of peaking generation to its Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Combined preliminary cost estimates for these additions are approximately $120 million. In July 2006, PSO announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the new unit. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion.

In December 2005, SWEPCo sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, SWEPCo announced plans to construct new generation to satisfy the demands of its customers. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural gas fired plant at the existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also plans to build a new base load coal plant by 2011 in Hempstead County, Arkansas to meet the longer-term generation needs of its customers. Preliminary cost estimates for the new facilities are approximately $1.4 billion (this total excludes the related transmission investment).

The 2006 through 2008 estimated construction expenditures as disclosed in our 2005Annual Report on Form 10-K included cost estimates for these new facilities. All new generation construction projects discussed above are subject to regulatory approvals from the various states in which the subsidiaries operate. Construction is expected to begin in 2007.

SIGNIFICANT FACTORS

We continue to be involved in various matters described in the “Significant Factors” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2005 Annual Report. The 2005 Annual Report should be read in conjunction with this report in order to understand significant factors without material changes in status since the issuance of our 2005 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

ERCOT Transmission Project

In October 2006, we announced our intent to form a joint venture company to fund, own and operate new electric transmission assets in ERCOT and we signed a memorandum of understanding with MidAmerican Energy Holdings Co. (MidAmerican) as our joint venture partner. We will contribute Texas transmission assets currently under construction valued at approximately $100 million to the joint venture company. A MidAmerican subsidiary would make a cash contribution to the joint venture company. The equity ownership of the new company would be split 50-50 between AEP and MidAmerican with an anticipated utility capitalization structure targeted at 40 percent equity and 60 percent debt. The joint venture is anticipated to be active in 2007 and is subject to regulatory approval from the PUCT and the FERC.

We believe there is a high degree of regulatory certainty for transmission investment due to the predetermination of ERCOT’s need based on significant Texas economic growth as well as “green generation” initiatives. In addition, a streamlined annual interim transmission cost of service review process is available, which will help reduce regulatory lag. The use of a joint venture structure will allow us to reduce its up-front capital requirements for this type of significant investment while allowing us to participate in more projects than previously anticipated.

AEP Interstate Project

In January 2006, we filed a proposal with the FERC and PJM to build a new 765 kV 550-mile transmission line from West Virginia to New Jersey. The 765 kV line is designed to reduce PJM congestion costs by substantially improving west-east peak transfer capability by approximately 5,000 MW and reducing transmission line losses by up to 280 MW. It will also enhance reliability of the Eastern transmission grid. A new subsidiary, AEP Transmission Co., LLC, will own the line and undertake construction of the project. The projected cost for the project is approximately $3 billion, of which ownership may be shared with other third party participants. The project is subject to PJM, state and federal regulatory approvals and appropriate incentive cost recovery mechanisms. The projected in-service date is 2014, assuming three years to site and acquire rights-of-way and five years to construct the line. We were the first to file with the Department of Energy (DOE) seeking to have the proposed route designated a National Interest Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005 provides for NIETC designation for areas experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers. In August 2006, the DOE issued the “National Electric Transmission Congestion Study”. In this study, DOE indicated that the mid-Atlantic Coastal area, where the AEP Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation. This finding should help AEP to obtain early National Interest Transmission Corridor Designation as promulgated by the National Energy Policy Act of 2005. In October 2006, both AEP and PJM filed comments with the DOE encouraging corridor designation that is consistent with the proposed line.

In July 2006, the FERC granted conditional approval for incentive rate treatment for the proposed line. The approval is conditioned upon the new line being included in PJM’s formal Regional Transmission Expansion Plan to be finalized later this year or in early 2007. The approved incentives include, (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the option to timely recover the cost of capital associated with construction work in progress; and (c) the ability to defer expense and recover costs incurred during the pre-construction and pre-operating period. Since the FERC approved these rate making principles, we expect to implement the incentives in future FERC rate filings.

Texas Regulatory Activity

Texas Restructuring

In June 2006, TCC filed to implement a CTC refund of $357 million for its other true-up items over eight years. The differences between the components of TCC’s Recorded Net Regulatory Liabilities - Other True-up Items as of September 30, 2006 (including interest) and its Net CTC Refund Proposed request are detailed below:

	(in millions)
Wholesale Capacity Auction True-up	$	61
Carrying Costs on Wholesale Capacity Auction True-up		31
Retail Clawback including Carrying Costs		(65	)
Deferred Over-recovered Fuel Balance		(184	)
Retrospective ADFIT Benefit		(77	)
Other		(4	)
Recorded Net Regulatory Liabilities - Other True-up Items		(238	)
Unrecorded Prospective ADFIT Benefit		(240	)
Gross CTC Refund Proposed		(478	)
FERC Jurisdictional Fuel Refund Deferral		16
ADITC and EDFIT Benefit Refund Deferral		98
Net CTC Refund Proposed, After Deferrals		(364	)
True-up Proceeding Expense Surcharge		7
Net CTC Refund Proposed, After Deferrals and Expenses	$	(357	)

In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that TCC began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) by the end of 2006 to residential customers. The CTC refund to the other customer classes during the interim period will be as proposed by TCC, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Municipal customers and other intervenors appealed the PUCT orders seeking to further reduce TCC’s true-up recoveries. If we determine, as a result of future PUCT orders or appeal court rulings, that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. TCC appealed the PUCT orders seeking relief in both state and federal court where it believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law.  The significant items appealed by TCC are:

· the PUCT ruled that TCC did not comply with the statute and PUCT rules regarding the auction of 15% of its Texas jurisdictional installed capacity,

· that TCC acted in a manner that was commercially unreasonable because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled gas units with the sale of its coal unit,

· and two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation.

These appeals could take years to resolve and could result in material effects on future results of operations. If the PUCT rejects TCC’s deferral proposal and a normalization violation occurs, future results of operations and cash flows could be adversely affected by the recapture of $104 million of TCC’s ADITC and the loss by TCC of future accelerated tax depreciation election. The estimated future impact on earnings of the Texas Restructuring as of September 30, 2006, exclusive of a possible normalization violation and any effects of appeal litigation, over the 14-year securitization net recovery period assuming the PUCT approves TCC’s CTC filing, including the interim refund, is detailed below:

	(in millions)
ADITC and EDFIT Benefits Reducing Securitization	$	98
ADFIT Benefit Applied to Reduce 2002 Securitization of Regulatory Assets		(60	)
Securitization Settlement		(77	)
Unrecorded Prospective ADFIT Benefit Increasing the CTC Refund		(240	)
Unrecorded Equity Carrying Costs Recognized as Collected		224
Future Interest Payable on Proposed CTC Refund		(19	)
Deferred Fuel - Federal Jurisdictional Issue		16
Net Adverse Earnings Impact Over 14 Years	$	(58	)

If the PUCT changes its oral decision regarding the proposed CTC deferral and the two contingent federal matters are refunded to customers, the future adverse impact on results of operations over the next 14 years will increase to $181 million. This potential adverse impact on results of operations over the next 14 years would be more than offset by the annual cost of money benefit from the $2.2 billion in net proceeds that resulted from the sale of bonds in connection with the initial regulatory asset securitization in 2002 of $797 million and from the $1.74 billion sale of securitization bonds in October 2006 less the proposed $357 million CTC refund over the next eight years.

Litigation

In the ordinary course of business, we and our subsidiaries are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring, Note 7 - Commitments and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report. Additionally, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies included herein. Adverse results in these proceedings have the potential to materially affect the results of operations, cash flows and financial condition of AEP and its subsidiaries.

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

Environmental Matters

We have committed to substantial capital investments and additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

· Requirements under the CAA to reduce emissions of SO₂, NO_x, particulate matter and mercury from fossil fuel-fired power plants;

· Requirements under the Clean Water Act 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.

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites, and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units. All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. A separate lawsuit, initiated by certain environmental intervenor groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and 2000 against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at our power plants occurred over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

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

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

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.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 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.

Adoption of New Accounting Pronouncements

Beginning in 2006, we adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, did not materially affect our quarter-over-quarter and year-to-date net income and earnings per share. We have not granted options as part of our regular stock-based compensation program since 2003.  However, we have used options in limited circumstances totaling 149,000 options in 2004, 10,000 options in 2005 and none during 2006.  As of September 30, 2006, we have $49.1 million of total unrecognized compensation cost related to unvested share-based compensation arrangements. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.57 years. See Note 2 - New Accounting Pronouncements in our Condensed Notes to Condensed Consolidated Financial Statements for further discussion.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

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

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

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

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

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

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value included in our condensed balance sheet as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

September 30, 2006

(in millions)

	Utility Operations			Investments - Gas Operations			Sub-Total MTM Risk Management Contracts			PLUS: MTM of Cash Flow and Fair Value Hedges			Total
Current Assets	$	444		$	99		$	543		$	26		$	569
Noncurrent Assets		337			130			467			4			471
Total Assets		781			229			1,010			30			1,040
Current Liabilities		(373	)		(99	)		(472	)		(24	)		(496	)
Noncurrent Liabilities		(184	)		(137	)		(321	)		(3	)		(324	)
Total Liabilities		(557	)		(236	)		(793	)		(27	)		(820	)
Total MTMDerivative Contract Net Assets   (Liabilities)	$	224		$	(7	)	$	217		$	3		$	220

MTM Risk Management Contract Net Assets (Liabilities)

Nine Months Ended September 30, 2006

(in millions)

	Utility Operations			Investments-Gas Operations			Total
Total MTM Risk Management Contract Net Assets (Liabilities) at   December 31, 2005	$	215		$	(19	)	$	196
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(8	)		10			2
Fair Value of New Contracts at Inception When Entered During the Period (a)		1			-			1
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option   Contracts Entered During The Period		(1	)		-			(1	)
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts		1			-			1
Changes in Fair Value due to Market Fluctuations During the Period (b)		19			2			21
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		(3	)		-			(3	)
Total MTM Risk Management Contract Net Assets (Liabilities) at   September 30, 2006	$	224		$	(7	)		217
Net Cash Flow and Fair Value Hedge Contracts								3
Ending Net Risk Management Assets at September 30, 2006							$	220

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	“Changes in Fair Value 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. Approximately $7 million of the regulatory deferral change is due to the change in the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities, 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, 2006

(in millions)

	Remainder 2006			2007			2008			2009			2010			After 2010		Total
Utility Operations:
Prices Actively Quoted -   Exchange Traded Contracts	$	-		$	(9	)	$	22		$	(1	)	$	-		$	-	$	12
Prices Provided by Other External   Sources - OTC Broker Quotes (a)		(4	)		119			29			23			-			-		167
Prices Based on Models and Other Valuation Methods (b)		(1	)		(15	)		5			19			28			9		45
Total	$	(5	)	$	95		$	56		$	41		$	28		$	9	$	224
Investments - Gas Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	-		$	7		$	-		$	-		$	-		$	-	$	7
Prices Provided by Other External   Sources - OTC Broker Quotes (a)		(2	)		(4	)		-			-			-			-		(6	)
Prices Based on Models and Other Valuation Methods (b)		-			-			(2	)		(4	)		(3	)		1		(8	)
Total	$	(2	)	$	3		$	(2	)	$	(4	)	$	(3	)	$	1	$	(7	)
Total:
Prices Actively Quoted - Exchange Traded Contracts	$	-		$	(2	)	$	22		$	(1	)	$	-		$	-	$	19
Prices Provided by Other External   Sources - OTC Broker Quotes (a)		(6	)		115			29			23			-			-		161
Prices Based on Models and Other Valuation Methods (b)		(1	)		(15	)		3			15			25			10		37
Total	$	(7	)	$	98		$	54		$	37		$	25		$	10	$	217

(a)	Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter (OTC) brokers, 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.
	Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.

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

Maximum Tenor of the Liquid Portion of Risk Management Contracts

As of September 30, 2006

Commodity	Transaction Class	Market/Region	Tenor
			(in Months)
Natural Gas	Futures	NYMEX / Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	18
	Swaps	Northeast, Mid-Continent, Gulf  Coast, Texas	18
	Exchange Option Volatility	NYMEX / Henry Hub	12
Power	Futures	AEP East - PJM	36
	Physical Forwards	AEP East	39
	Physical Forwards	AEP West	39
	Physical Forwards	West Coast	39
	Peak Power Volatility (Options)	AEP East - Cinergy, PJM	12
Emissions	Credits	SO2, NOx	27
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 remaining 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 derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2005 to September 30, 2006. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as effective cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges

Nine Months Ended September 30, 2006

(in millions)

	Power and Gas			Interest Rate			Total
Beginning Balance in AOCI, December 31, 2005	$	(6	)	$	(21	)	$	(27	)
Changes in Fair Value		13			(3	)		10
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		7			1			8
Ending Balance in AOCI, September 30, 2006	$	14		$	(23	)	$	(9	)
After-Tax Portion Expected to be Reclassified to Earnings During Next 12 Months	$	15		$	(2	)	$	13

Credit Risk

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

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of September 30, 2006, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 2.56%, expressed in terms of net MTM assets and net receivables. As of September 30, 2006, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10%		Net Exposure of Counterparties >10%
Investment Grade	$	802	$	140	$	662		1	$	70
Split Rating		4		4		-		1		-
Noninvestment Grade		15		15		-		2		-
No External Ratings:
Internal Investment Grade		33		-		33		3		21
Internal Noninvestment Grade		40		22		18		3		17
Total as of September 30, 2006	$	894	$	181	$	713		10	$	108
As of December 31, 2005	$	1,366	$	484	$	882		10	$	322

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2008. This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information

Estimated Next Three Years

As of September 30, 2006

	Remainder 2006	2007	2008
Estimated Plant Output Hedged	91%	88%	87%

VaR Associated with Risk Management Contracts

Commodity Price Risk

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

VaR Model

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in millions)				(in millions)
End	High	Average	Low	End	High	Average	Low
$2	$10	$3	$1	$3	$5	$3	$1

The High VaR for the nine months ended September 30, 2006 occurred in mid-August during a period of high gas and power price volatility. The following day, positions were flattened and the VaR was significantly reduced.

Interest Rate Risk

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $550 million at September 30, 2006 and $615 million at December 31, 2005. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Three and Nine Months Ended September 30, 2006 and 2005

(in millions, except per-share amounts)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Utility Operations	$	3,485		$	3,152		$	9,282		$	8,437
Gas Operations		(47	)		73			(80	)		449
Other		156			103			436			326
TOTAL		3,594			3,328			9,638			9,212
EXPENSES
Fuel and Other Consumables Used for Electric Generation		1,113			1,066			2,962			2,659
Purchased Energy for Resale		267			181			670			494
Purchased Gas for Resale		4			5			4			255
Maintenance and Other Operation		904			873			2,634			2,588
Gain/Loss on Disposition of Assets, Net		-			(1	)		(68	)		(116	)
Asset Impairments and Other Related Charges		209			39			209			39
Depreciation and Amortization		376			336			1,065			988
Taxes Other Than Income Taxes		186			205			567			566
TOTAL		3,059			2,704			8,043			7,473
OPERATING INCOME		535			624			1,595			1,739
Interest and Investment Income		22			18			41			43
Carrying Costs Income		3			27			66			83
Allowance For Equity Funds Used During Construction		12			5			25			17
Gain on Disposition of Equity Investments, Net		-			56			3			56
Investment Value Losses		-			(7	)		-			(7	)
INTEREST AND OTHER CHARGES
Interest Expense		174			163			518			524
Preferred Stock Dividend Requirements of Subsidiaries		1			1			2			6
TOTAL		175			164			520			530
INCOME BEFORE INCOME TAX EXPENSE, MINORITY   INTEREST EXPENSE AND EQUITY EARNINGS		397			559			1,210			1,401
Income Tax Expense		133			196			394			471
Minority Interest Expense		1			1			2			3
Equity Earnings of Unconsolidated Subsidiaries		2			3			1			10
INCOME BEFORE DISCONTINUED OPERATIONS		265			365			815			937
DISCONTINUED OPERATIONS, Net of Tax		-			22			6			26
NET INCOME	$	265		$	387		$	821		$	963
WEIGHTED AVERAGE NUMBER OF BASIC SHARES   OUTSTANDING		394			389			394			389
BASIC EARNINGS PER SHARE
Income Before Discontinued Operations	$	0.67		$	0.94		$	2.07		$	2.41
Discontinued Operations, Net of Tax		-			0.05			0.01			0.07
TOTAL BASIC EARNINGS PER SHARE	$	0.67		$	0.99		$	2.08		$	2.48
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES   OUTSTANDING		396			390			396			390
DILUTED EARNINGS PER SHARE
Income Before Discontinued Operations	$	0.67		$	0.94		$	2.06		$	2.40
Discontinued Operations, Net of Tax		-			0.05			0.01			0.07
TOTAL DILUTED EARNINGS PER SHARE	$	0.67		$	0.99		$	2.07		$	2.47
CASH DIVIDENDS PAID PER SHARE	$	0.37		$	0.35		$	1.11		$	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, 2006 and December 31, 2005

(in millions)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	259		$	401
Other Temporary Cash Investments		198			127
Accounts Receivable:
Customers		751			826
Accrued Unbilled Revenues		314			374
Miscellaneous		52			51
Allowance for Uncollectible Accounts		(34	)		(31	)
Total Receivables		1,083			1,220
Fuel, Materials and Supplies		810			726
Risk Management Assets		569			926
Margin Deposits		90			221
Regulatory Asset for Under-Recovered Fuel Costs		66			197
Other		100			127
TOTAL		3,175			3,945
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		16,712			16,653
Transmission		6,952			6,433
Distribution		11,179			10,702
Other (including coal mining and nuclear fuel)		3,277			3,116
Construction Work in Progress		2,848			2,217
Total		40,968			39,121
Accumulated Depreciation and Amortization		15,146			14,837
TOTAL - NET		25,822			24,284
OTHER NONCURRENT ASSETS
Regulatory Assets		3,196			3,262
Securitized Transition Assets and Other		558			593
Spent Nuclear Fuel and Decommissioning Trusts		1,191			1,134
Investments in Power and Distribution Projects		45			97
Goodwill		76			76
Long-term Risk Management Assets		471			886
Employee Benefits and Pension Assets		1,059			1,105
Other		682			746
TOTAL		7,278			7,899
Assets Held for Sale		110			44
TOTAL ASSETS	$	36,385		$	36,172

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, 2006 and December 31, 2005

(Unaudited)

			2006			2005
CURRENT LIABILITIES			(in millions)
Accounts Payable			$	1,180		$	1,144
Short-term Debt				23			10
Long-term Debt Due Within One Year				1,789			1,153
Risk Management Liabilities				496			906
Accrued Taxes				828			651
Accrued Interest				192			183
Customer Deposits				336			571
Other				752			842
TOTAL				5,596			5,460
NONCURRENT LIABILITIES
Long-term Debt				10,974			11,073
Long-term Risk Management Liabilities				324			723
Deferred Income Taxes				4,673			4,810
Regulatory Liabilities and Deferred Investment Tax Credits				2,955			2,747
Asset Retirement Obligations				975			936
Employee Benefits and Pension Obligations				349			355
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2				150			157
Deferred Credits and Other				803			762
TOTAL				21,203			21,563
TOTAL LIABILITIES				26,799			27,023
Cumulative Preferred Stock Not Subject to Mandatory Redemption				61			61
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDERS’ EQUITY
Common Stock Par Value $6.50:
	2006	2005
Shares Authorized	600,000,000	600,000,000
Shares Issued	415,979,691	415,218,830
(21,499,992 shares were held in treasury at September 30, 2006 andDecember 31, 2005)				2,704			2,699
Paid-in Capital				4,153			4,131
Retained Earnings				2,669			2,285
Accumulated Other Comprehensive Income (Loss)				(1	)		(27	)
TOTAL				9,525			9,088
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	36,385		$	36,172

   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, 2006 and 2005

(in millions)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	821		$	963
Less: Discontinued Operations, Net of Tax		(6	)		(26	)
Income Before Discontinued Operations		815			937
Adjustments for Noncash Items:
Depreciation and Amortization		1,065			988
Accretion of Asset Retirement Obligations		47			50
Deferred Income Taxes		(88	)		(33	)
Deferred Investment Tax Credits		(20	)		(23	)
Asset Impairments, Investment Value Losses and Other Related Charges		209			46
Carrying Costs Income		(66	)		(83	)
Mark-to-Market of Risk Management Contracts		(21	)		-
Amortization of Nuclear Fuel		38			42
Deferred Property Taxes		105			94
Pension Contributions to Qualified Plan Trusts		-			(306	)
Fuel Over/Under-Recovery, Net		158			(183	)
Gain on Sales of Assets and Equity Investments, Net		(71	)		(172	)
Change in Other Noncurrent Assets		72			(84	)
Change in Other Noncurrent Liabilities		(21	)		34
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		139			5
Fuel, Materials and Supplies		(84	)		54
Accounts Payable		(49	)		173
Accrued Taxes		176			118
Customer Deposits		(235	)		311
Other Current Assets		142			(246	)
Other Current Liabilities		(98	)		(23	)
Net Cash Flows From Operating Activities		2,213			1,699
INVESTING ACTIVITIES
Construction Expenditures		(2,445	)		(1,610	)
Acquisition of Waterford Plant		-			(218	)
Change in Other Temporary Cash Investments, Net		20			99
Purchases of Investment Securities		(8,153	)		(4,319	)
Sales of Investment Securities		8,056			4,378
Proceeds from Sales of Assets		120			1,599
Other		(72	)		11
Net Cash Flows Used For Investing Activities		(2,474	)		(60	)
FINANCING ACTIVITIES
Issuance of Common Stock		24			393
Repurchase of Common Stock		-			(427	)
Change in Short-term Debt, Net		11			(8	)
Issuance of Long-term Debt		1,229			2,045
Retirement of Long-term Debt		(711	)		(2,599	)
Dividends Paid on Common Stock		(437	)		(408	)
Other		3			(106	)
Net Cash Flows From (Used For) Financing Activities		119			(1,110	)
Net Increase (Decrease) in Cash and Cash Equivalents		(142	)		529
Cash and Cash Equivalents at Beginning of Period		401			320
Cash and Cash Equivalents at End of Period	$	259		$	849
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	462		$	492
Net Cash Paid for Income Taxes		206			277
Noncash Acquisitions Under Capital Leases		66			42
Construction Expenditures Included in Accounts Payable at September 30,		334			182
Disposition of Liabilities Related to Acquisitions/Divestitures, Net		-			20

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, 2006 and 2005

(in millions)

(Unaudited)

	Common Stock										Accumulated
	Shares		Amount		Paid-in Capital			Retained Earnings			Other Comprehensive Income (Loss)			Total
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 of $0												1			1
NET INCOME									963						963
TOTAL COMPREHENSIVE INCOME															895
SEPTEMBER 30, 2005		415	$	2,697	$	4,121		$	2,579		$	(412	)	$	8,985
DECEMBER 31, 2005		415	$	2,699	$	4,131		$	2,285		$	(27	)	$	9,088
Issuance of Common Stock		1		5		19									24
Common Stock Dividends									(437	)					(437	)
Other						3									3
TOTAL															8,678
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Tax:
Cash Flow Hedges, Net of Tax of $10												18			18
Securities Available for Sale, Net of Tax of $4												8			8
NET INCOME									821						821
TOTAL COMPREHENSIVE INCOME															847
SEPTEMBER 30, 2006		416	$	2,704	$	4,153		$	2,669		$	(1	)	$	9,525

   See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES

INDEX TO 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.	Company-wide Staffing and Budget Review
8.	Acquisitions, Dispositions, Discontinued Operations, Assets Held for Sale and Asset Impairments
9.	Benefit Plans
10.	Stock-Based Compensation
11.	Income Taxes
12.	Business Segments
13.	Financing Activities

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

         1.SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed consolidated financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (SEC). Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods. The results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of results that may be expected for the year ending December 31, 2006. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2005 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 2005 as filed with the SEC on March 1, 2006.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on our Condensed Consolidated Balance Sheets in the common shareholders’ equity section. The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss):

	September 30,			December 31,
	2006			2005
Components	(in millions)
Securities Available for Sale, Net of Tax	$	27		$	19
Cash Flow Hedges, Net of Tax		(9	)		(27	)
Minimum Pension Liability, Net of Tax		(19	)		(19	)
Total	$	(1	)	$	(27	)

At September 30, 2006, we expect to reclassify approximately $13 million of net gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve months at the time the hedged transactions affect Net Income. The actual amounts that are reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ as a result of market fluctuations.

At September 30, 2006, thirty-nine months is the maximum length of time that our exposure to variability in future cash flows is hedged with contracts designated as cash flow hedges.

Stock-Based Compensation Plans

At September 30, 2006, we have options outstanding under two stock-based employee compensation plans: The Amended and Restated American Electric Power System Long-Term Incentive Plan and the Central and South West Corporation Long-Term Incentive Plan. We also grant performance share units, phantom stock units, restricted shares and restricted stock units to employees, in accordance with plans previously approved by shareholder votes.

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

In conjunction with the adoption of SFAS 123R, we changed our method of attributing the value of stock-based compensation to expense from the accelerated multiple-option approach to the straight-line single-option method. Compensation expense for all share-based payment awards granted prior to January 1, 2006 will continue to be recognized using the accelerated multiple-option approach while compensation expense for all share-based payment awards granted on or after January 1, 2006 is recognized using the straight-line single-option method. As stock-based compensation expense recognized in our Condensed Consolidated Statements of Operations for the three and nine months periods ended September 30, 2006 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In our pro forma information presented below as required under SFAS 123 for the periods prior to 2006, we accounted for forfeitures as they occurred.

For the three and nine months ended September 30, 2005, no stock option expense was reflected in Net Income as we accounted for stock options using the intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, “Accounting For Stock Issued to Employees.” Under the intrinsic value method, no stock option expense is recognized when the exercise price of the stock options granted equals the fair value of the underlying stock at the date of grant. During the first nine months of 2005 the Board of Directors granted 10,000 options. For the three and nine months ended September 30, 2006 and 2005, compensation cost is included in Net Income for the performance share units, phantom stock units, restricted shares, restricted stock units and the Director’s stock units. See Note 10 for additional discussion.

Pro Forma Information Under SFAS 123, “Accounting for Stock-Based Compensation,” for Periods Presented Prior to January 1, 2006

The following table shows the effect on our Net Income and Earnings Per Share as if we had applied fair value measurement and recognition provisions of SFAS 123to stock-based employee and director compensation awards for the three and nine months ended September 30, 2005:

	Three Months Ended			Nine Months Ended
	(in millions, except per share data)
Net Income, As Reported	$	387		$	963
Add: Stock-based Compensation Expense Included in Reported Net Income, Net of Related Tax Effects		4			10
Deduct: Stock-based Compensation Expense Determined Under Fair Value Based Method for All Awards,   Net of Related Tax Effects		(5	)		(11	)
Pro Forma Net Income	$	386		$	962
Earnings Per Share:
Basic - As Reported	$	0.99		$	2.48
Basic - Pro Forma (a)	$	0.99		$	2.48
Diluted - As Reported	$	0.99		$	2.47
Diluted - Pro Forma (a)	$	0.99		$	2.47

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

Earnings Per Share (EPS)

The following table presents our basic and diluted Earnings Per Share (EPS) calculations included in our Condensed Consolidated Statements of Operations:

	Three Months Ended September 30,
	2006				2005
	(in millions, except per share data)
			$/share				$/share
Earnings applicable to common stock	$	265			$	387
Average number of basic shares outstanding		393.9	$	0.67		388.9	$	0.99
Average dilutive effect of:
Performance Share Units		2.0		-		1.0		-
Stock Options		0.2		-		0.5		-
Restricted Stock Units		0.1		-		0.1		-
Restricted Shares		0.1		-		-		-
Average number of diluted shares outstanding		396.3	$	0.67		390.5	$	0.99

	Nine Months Ended September 30,
	2006					2005
	(in millions, except per share data)
			$/share					$/share
Earnings applicable to common stock	$	821				$	963
Average number of basic shares outstanding		393.8	$	2.08			388.7	$	2.48
Average dilutive effect of:
Performance Share Units		1.6		(0.01	)		0.9		(0.01	)
Stock Options		0.2		-			0.3		-
Restricted Stock Units		0.1		-			0.1		-
Restricted Shares		0.1		-			-		-
Average number of diluted shares outstanding		395.8	$	2.07			390.0	$	2.47

Our stock option and other equity compensation plans are discussed in Note 10.

Related Party Transactions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in millions)
AEP Consolidated Purchased Energy:
Ohio Valley Electric Corporation (43.47% Owned)	$	54	$	49	$	167	$	140
Sweeny Cogeneration Limited Partnership (50% Owned)		30		38		92		98
AEP Consolidated Other Revenues - Barging and Other   Transportation Services - Ohio Valley Electric Corporation   (43.47% Owned)		8		6		23		14

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.  These revisions had no impact on our previously reported results of operations, financial condition or changes in shareholders’ equity.

On our Condensed Consolidated Statements of Cash Flows, we included purchases and sales of investments within our Spent Nuclear Fuel and Decommissioning Trusts as a component of Investing Activities rather than Operating Activities.

         2.NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented in 2006 that we determined relate to our operations.

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

In December 2004, the FASB issued SFAS 123R. 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.” We recorded an insignificant cumulative effect of a change in accounting principle in the first quarter of 2006 for the effect of initially applying the statement primarily reflected in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued three FASB Staff Positions (FSP) during 2005 and one in February 2006 that provided additional implementation guidance. We applied the principles of SAB 107 and the applicable FSPs in conjunction with our adoption of SFAS 123R.

We adopted SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards granted after the time of adoption and 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 is based on the grant-date fair value of the equity award. Stock-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense recognized in our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested as of, January 1, 2006 based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123 and compensation expense for the share-based payment awards granted subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Our implementation of SFAS 123R did not materially affect our results of operations, cash flows or financial condition.

SFAS 157 “Fair Value Measurements”

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

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. We are currently in the process of determining the effect this standard will have on our financial statements. Although SFAS 157 is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. SFAS 157 will be effective for us starting January 1, 2008.

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

In September 2006, the FASB issued SFAS 158. SFAS 158 amends previous standards. It requires employers to fully recognize the obligations associated with defined benefit pension, retiree healthcare and other postretirement (OPEB) plans in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to SFAS 87, “Employers’ Accounting for Pensions,” or SFAS 106, “Employer’s Accounting for Postretirement Benefits Other Than Pensions.” It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit postretirement plan affects net periodic benefit costs for the next fiscal year.

The effect of SFAS 158 is to adjust AOCI at the end of each year, for both underfunded and overfunded pension and OPEB plans, to an amount equal to the remaining unrecognized SFAS 87 and SFAS 106 deferrals for unamortized actuarial losses or gains, prior service costs, or transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition.

The year-end AOCI measure is volatile based on fluctuating investment returns and discount rates. Favorable changes include higher returns that increase plan assets and higher discount rates that reduce the discounted benefit obligation.

SFAS 158 is effective for initial recognition of a defined benefit postretirement plan and related disclosure for fiscal years ending after December 15, 2006. We have not completed the process of determining the effect of this standard on our financial statements, including whether a portion of the adjustment required by SFAS 158 can be deferred as a regulatory asset under SFAS 71.

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

In June 2006, the EITF reached a consensus on the income statement presentation of various types of taxes. The scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes. The presentation of taxes within the scope of this issue on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22, “Disclosure of Accounting Policies.” The EITF’s decision on gross/net presentation requires that any such taxes reported on a gross basis be disclosed on an aggregate basis in interim and annual financial statements, for each period for which an income statement is presented, if those amounts are significant.

EITF 06-3 is effective for fiscal years beginning after December 15, 2006. As disclosed in Note 1 of the 2005 Annual Report, we act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customers. Our policy is to present these taxes on a net basis and we do not recognize these taxes as revenues or expenses. Therefore, this issue will not have a material impact on our financial statements.

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

In July 2006, the FASB issued FIN 48 which clarifies the application of SFAS 109, “Accounting for Income Taxes.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have not completed the process of determining the effect of this interpretation on our financial statements.

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

In September 2006, the SEC staff issued SAB 108. SAB 108 addresses the diversity in practice when quantifying the effect of an error on financial statements. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying misstatements in current year financial statements. We will be required to adopt the provisions of SAB 108 effective December 31, 2006. We believe that the adoption of SAB 108 will not have a material impact on our financial statements.

Future Accounting Changes

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

        3.RATE MATTERS

As discussed in our 2005 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and state commissions. The Rate Matters note within our 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations and cash flows. Rate matters that are not believed to be reasonably likely to affect future results of operations and cash flows are not included in this report or the 2005 Annual Report. The following sections discuss ratemaking developments in 2006 and update the 2005 Annual Report.

APCo Virginia Environmental and Reliability Costs

The Virginia Electric Restructuring Act (the statute) includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred on and after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 2004 through September 2005. Through August 31, 2006, APCo deferred as a regulatory asset $47 million of incremental E&R costs incurred since July 1, 2004 based on a legal opinion that such costs were probable of recovery under the law.

In January 2006, the Virginia SCC staff proposed that APCo be allowed to increase its electric rates at an ongoing level of $20 million to recover current, rather than past, incremental E&R costs. The staff proposal would effectively disallow the recovery of costs incurred prior to the authorization and implementation of new rates, including all incremental E&R costs that were deferred as a regulatory asset. At the E&R hearings, which concluded in March 2006, the staff amended its testimony to recommend a $24 million increase in APCo’s ongoing rates. In September 2006, the Hearing Examiner issued a report recommending adoption of the staff proposal with minor modifications, which would result in (a) an on-going level of E&R cost recovery of $29 million only if the Virginia SCC decides that any rate increase from the base rate case (described below) does not include the $29 million ongoing level of E&R costs, and (b) the disallowance of all previously deferred incremental E&R costs. In the third quarter of 2006, we concluded that the Virginia SCC might not grant recovery of actual incremental E&R costs incurred during the period from July 2004 through September 2006. Accordingly, we wrote off all of the E&R regulatory asset, adversely affecting pretax earnings by $36 million, net of the reinstatement of related AFUDC and capitalized interest. We believe that the staff’s proposal and the Hearing Examiner’s recommendation are contrary to the statute. The Virginia SCC’s final order in this proceeding is pending.

If the Virginia SCC properly implements the statute as interpreted in its October 2005 order and as supported by the Virginia Attorney General’s office in October 2006, we should be able to recover all of our incremental E&R costs prudently incurred since July 1, 2004. If the Virginia SCC adopts the Hearing Examiner's findings, based on advice of counsel, we will appeal the decision.

APCo Virginia Base Rate Case

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%. In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to the fuel factor where they can be adjusted annually. APCo also proposed to share the off-system sales margins with the customers with 40% going to reduce rates and 60% being retained by APCo. This resultant proposed off-system sales fuel rate credit, which is estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in revenues of $198 million. The major components of the $225 million rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity. In May 2006, the Virginia SCC issued an order, consistent with Virginia law, placing the net requested base rate increase of $198 million into effect October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed their direct testimony recommending a base rate increase of $13 million. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo plans to file rebuttal testimony in November 2006. Hearings are scheduled to begin in December 2006. We are unable to predict the ultimate effect of this filing on future revenues, cash flows and financial condition.

APCo and WPCo West Virginia Rate Case

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

· A $56 million increase in Expanded Net Energy Cost (ENEC) for fuel, purchased power expenses, off system sales credits and other energy related costs;

· A $23 million special construction surcharge providing recovery of the costs of scrubbers and the new Wyoming-Jacksons Ferry 765 kV line to date;

· An $18 million general base rate reduction resulting predominantly from a reduction in the return on equity to 10.5% and a $9 million reduction in depreciation expense which affects cash flows but not earnings; and

· A $17 million credit to refund a portion of deferred prior over-recoveries of ENEC of $51 million, recorded in regulatory liabilities on the Condensed Consolidated Balance Sheets, which will impact cash flows but not earnings.

In addition, the agreement provides a surcharge mechanism that allows APCo and WPCo to adjust their rates annually for the timely recovery in each of the next three years of the incremental cost of ongoing environmental investments in scrubbers at APCo’s Mountaineer and John Amos power plants and the costs of the new Wyoming-Jacksons Ferry 765 kV line. Although the amount of these annual surcharge increases cannot be determined until the incremental costs are known and reviewed by the WVPSC, APCo estimates that they will result in an annual increase in revenues of $36 million effective July 1, 2007, $14 million effective July 1, 2008 and $18 million effective July 1, 2009.

The settlement further provides for the reinstatement of the ENEC mechanism effective July 1, 2006 with over/under recovery deferral accounting and annual ENEC proceedings to affect annual rate adjustments for changes in fuel and purchased power costs beginning in 2007. The settlement provides for the return to customers of the remaining $34 million of the prior ENEC regulatory liability plus interest at a LIBOR rate on the unrefunded balance in future ENEC proceedings.

I&M Depreciation Study Filing

In December 2005, I&M filed a petition with the IURC seeking authorization to revise its book depreciation rates applicable to its electric utility plant in service effective January 1, 2006. Based on a depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. A public hearing was held in May 2006 and the final brief was filed in June 2006. As proposed by I&M, the book depreciation expense reduction would increase earnings, but would not impact cash flows until electric service rates are revised.

An order issued by the IURC on October 19, 2006 does not dispute our revised depreciation accounting rates but, nevertheless, the IURC denied I&M's request to revise its book depreciation rates between base rate cases. The IURC believes that depreciation rates for an electric utility should not be changed between general rate cases unless it was “absolutely essential” and a direct benefit to customers was shown. I&M has twenty days in which to file for a rehearing or reconsideration. We have not yet decided whether we will file for a rehearing or reconsideration or if and when we will file to adjust base rates to reflect the depreciation study.

KPCo Rate Filing

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

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

In 2002, PSO under-recovered $44 million of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO proposed collection of those reallocated costs over 18 months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 through 2003 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with their proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from their recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. The United States District Court for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals and will defend its position. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs or offsets under-recovered fuel deferrals with additional reallocated off-system sales margins, our future results of operations and cash flows could be adversely affected. However, if the position taken by the federal court in Texas applies to PSO’s case, the OCC could be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party may file a complaint at the FERC alleging the allocation of off-system sales margins adopted by PSO is improper which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies. Management is unable to predict the ultimate effect, if any, of these Oklahoma fuel clause proceedings and any future FERC proceedings on future results of operations, cash flows and financial condition.

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

In February 2006, a law was enacted requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served. PSO is subject to the required biennial reviews. The OCC staff indicated that it expects the review process to begin in late 2006 or early 2007.

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

PSO Rate Filing

In September 2006, PSO filed a notice of its intent to file in November 2006 a plan to modify the base rates of PSO’s Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007.

SWEPCo Louisiana Fuel Inquiry

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

SWEPCo PUCT Staff Review of Earnings

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

SWEPCo Louisiana Compliance Filing

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. In April 2004, at the request of the LPSC, SWEPCo filed updated financial information with a test year ending December 31, 2003. Both filings indicated that SWEPCo’s rates should not be reduced. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed updated financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorized return on equity of 11.1%.

In July 2006, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, based on a proposed 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain ongoing operations and maintenance expense levels and the recommended base rate reduction does not include the impact of a proposed consolidated federal income tax adjustment, which, if approved, would increase the proposed rate reduction. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. Hearings are expected to occur late in the fourth quarter of 2006. A decision is not expected until 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ultimately ordered, it would adversely impact future results of operations and cash flows.

TCC and TNC Rate Filings

In September 2006, we announced that TCC and TNC will each file transmission and distribution wires rate cases in Texas in late 2006.  We anticipate requesting an $83 million annual increase for TCC and a $25 million annual increase for TNC.  Both requests include the impact of the expiration of the CSW merger savings credits.

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 the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued in July 2005, the Texas Court of Appeals reversed the District Court. The cities appealed the appeals court decision to the Supreme Court of Texas, which has ordered full briefing, but has not granted review. Management cannot predict the outcome of further appeals, but a reversal of the favorable court of appeals decision regarding the loss of load issue could result in the issue being returned to the PUCT for further consideration. If that were to happen and if the PUCT orders refunds of PTB revenues, it could adversely impact results of operations and cash flows for the portion of the refund applicable to the period of time that TCC and TNC owned the REPs.

RTO Formation/Integration Costs

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. Total amortization related to such costs was $1 million in both the third quarter of 2006 and 2005. In the first nine months of 2006 and 2005, total amortization related to such costs was $4 million and $3 million, respectively. As of September 30, 2006 and December 31, 2005, the AEP East companies had $30 million and $31 million, respectively, of deferred unamortized RTO and PJM formation/integration costs.

In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs and related carrying costs not billed by PJM of $2 million per year. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone. As a result, the AEP East companies will need to recover the 85% through their retail rates.

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

As a result of recently approved rate increases, CSPCo, OPCo and KPCo recover the amortization of RTO formation/integration costs billed to the AEP East companies in Ohio and Kentucky. APCo received approval to include the amortization of RTO formation/integration costs in retail rates in West Virginia effective July 28, 2006. In Virginia, APCo filed a base rate case, which includes recovery of these costs when rates became effective October 2, 2006, subject to refund. In Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded from recovering its share of the deferred RTO costs until that date or until it can file for a rate increase in Indiana. I&M has not yet filed for recovery in Michigan.

Until I&M can adjust its retail rates in Indiana and Michigan to recover the amortization of its deferred RTO formation/integration costs, results of operations and cash flows will be adversely affected by approximately 15% of the amortizations. If the Virginia, Indiana or Michigan commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs, it could result in a write off of up to 25% of the total remaining deferred balance, adversely impacting future results of operations and cash flows.  In the event of a disallowance, we would appeal that decision to the appropriate state or federal courts.

Transmission Rate Proceedings at the FERC

SECA Revenue Subject to Refund

In accordance with FERC orders, we collected SECA rates to mitigate lost through-and-out transmission service (T&O) revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected subject to refund or surcharge. The AEP East companies also paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, we would also receive refunds related to the SECA rates we paid. The AEP East companies recognized gross SECA revenues as follows:

	(in millions)
Three Months Ended September 30, 2006	$	-
Three Months Ended September 30, 2005		43
Nine Months Ended September 30, 2006 (a)		43
Nine Months Ended September 30, 2005		120

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

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

A hearing in the SECA case was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates were not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory, and that new compliance filings and refunds should be made. The ALJ also found that unpaid SECA rates must be paid in the recommended reduced amount.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund, and have reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. It would also provide refunds of SECA rates paid by the AEP East companies in considerably less significant amounts. Based on the completed settlements, and before the issuance of the ALJ’s initial decision, the AEP East companies provided for $22 million in net refunds, of which $18 million was recorded in the second quarter of 2006 in Utility Operations Revenues on the Condensed Consolidated Statements of Operations.

We, together with Exelon and DP&L, filed an extensive brief noting exceptions to the initial ALJ decision and asking the FERC to reverse the decision in large part. Reply briefs were filed in October 2006. We believe that the FERC should reject the initial ALJ decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, we believe the ALJ’s findings on key issues are largely without merit. As a result, we have not provided for a possible refund of SECA rates in excess of our current provisions. If the FERC does adopt the ALJ’s recommendations, we will appeal the decision to the courts. Although we believe we have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement which allowed increases in our wholesale transmission OATT rates in three steps: first, beginning retroactively on November 1, 2005, second, beginning on April 1, 2006 when the SECA revenues were eliminated and third, beginning on August 1, 2006 when the new Wyoming-Jacksons Ferry 765 kV line went into service. We estimate that this rate increase will increase wholesale transmission revenues by $22 million in 2006 and $28 million in 2007.

The Elimination of T&O and SECA Rates and the FERC PJM Regional Transmission Rate Proceeding

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

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

· AEP/AP proposed a Highway/Byway rate design in which:

· The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.

· The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.

· Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues than the AEP/AP proposal.

· In a competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues than the AEP/AP proposal.

· In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues than the AEP/AP proposal.

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

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

From the elimination of T&O rates in December 2004 through the expiration of SECA rates on March 31, 2006, SECA transition rates failed to fully compensate the AEP East companies for their lost T&O revenues. Effective with the expiration of the SECA transition rates on March 31, 2006, the increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone was not sufficient to replace the prior T&O revenues or the lower temporary SECA transition rate revenues; however, a favorable outcome in the PJM regional transmission rate proceeding, made retroactive to April 1, 2006 could mitigate a large portion of the shortfall. Full mitigation of the effects of eliminated T&O revenues and the less favorable terminated SECA revenues will require cost recovery through state retail rate proceedings pending any resolution that may result from the above FERC regional transmission rate proceeding. The status of such state retail rate proceedings is as follows:

· In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.

· In Ohio, CSPCo and OPCo recover the FERC-approved OATT which reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.

· In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.

· In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.

· In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.

· In Michigan, I&M has not yet filed to seek recovery of the lost transmission revenues.

We presently recover from retail customers approximately 65% of the reduction in transmission revenues of $128 million a year. On October 2, 2006, when new base rates went into effect subject to refund in Virginia, that percentage increased to 80%.

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

We believe that the AEP/AP proposal or the Postage Stamp proposal combined with the retail recovery discussed above would be an effective replacement for the eliminated T&O and SECA rates.

Management is unable to predict whether the FERC will approve either the ALJ’s decision or another regional rate design. Future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues and the resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates in Indiana and Michigan.

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

In April 2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate schedule to charge SPP for reactive power from Calpine’s generating facility. The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCO and a small portion of TNC operate in SPP. An ALJ initially ruled against Calpine and we concluded that the likelihood of the FERC awarding Calpine a reactive power capacity rate was remote. In September 2006, the FERC issued its decision reversing the ALJ decision, granting Calpine’s request and requiring Calpine to make a compliance filing within 30 days. Our share of this SPP expense could be approximately 90% of the total amount billed by Calpine. Based on this information, we recorded an expense provision, including interest, of $8 million in September 2006 for the retroactive reactive power liability. We will seek rehearing at the FERC and may appeal the decision if the FERC either denies rehearing or rules in favor of Calpine on rehearing.

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

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

The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of expanded net energy fuel clause recovery mechanisms and related off-system sales sharing mechanisms by state. Our total trading and marketing margins are unaffected by the allocation methodology.

         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 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant events occurring in 2006 related to customer choice and industry restructuring and update the 2005 Annual Report.

TEXAS RESTRUCTURING

In February 2006, the PUCT issued an order in TCC’s $2.4 billion True-up Proceeding, which determined that TCC’s true-up regulatory asset was $1.475 billion including carrying costs through September 2005. In December 2005, TCC adjusted its recorded net true-up regulatory asset to comply with the order. The PUCT issued an order on rehearing in April 2006, which made minor changes to, but otherwise affirmed, the February 2006 order. We appealed, seeking additional recovery consistent with the Texas Restructuring Legislation and related rules. Other parties appealed the PUCT’s true-up order claiming it permits TCC to over-recover stranded generation costs and other true-up items.

TCC Securitization Proceeding

TCC filed an application in March 2006 requesting recovery through securitization of $1.8 billion of net stranded generation plant costs and related carrying costs through August 31, 2006. The $1.8 billion request did not include TCC’s negative other true-up items, which total $478 million. See “CTC Proceeding for Other True-up Items” section of this note. Intervenors and the PUCT staff filed testimony regarding TCC’s securitization request in April 2006. In May 2006, TCC filed a letter with the PUCT reducing its request by $6 million of current carrying costs and reduced the recorded net recoverable regulatory asset by the recorded debt-related component. In May 2006, TCC and the other parties filed a settlement with the PUCT, which further reduced the securitizable amount by $77 million and settled several issues that would have delayed the sale of the securitization bonds. The PUCT approved the settlement in June 2006 authorizing $1.697 billion including carrying costs through August 31, 2006, the assumed securitization date, plus estimated issuance costs of $23 million, for a total of $1.72 billion. We issued TCC securitization bonds on October 11, 2006 for $1.74 billion, including additional issuance costs and carrying costs to October 11, 2006.

TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT. We determined that the projected cash flows from the securitization less the proposed CTC refund would be more than sufficient to recover TCC’s recorded net true-up regulatory asset due to the existence of $224 million of unrecorded equity-related carrying costs which are not recorded until collected in regulated rates. As a result, no additional impairment was recorded for the approved reduction in the amount to be securitized. However, the $77 million agreed upon reduction in the securitizable amount will have a negative impact on future earnings.

Consistent with certain prior securitization determinations, the PUCT issued a specific order in the securitization proceeding that calculated a $315 million cost-of-money benefit from true-up related ADFIT through August 2006, of which $75 million ($77 million through September 30, 2006) relates to the recorded benefit prior to the date of securitization and $240 million relates to the unrecorded benefit subsequent to the date of securitization. The PUCT included the $315 million ADFIT-related stranded cost benefit in the CTC refund of $478 million. In June 2006, we transferred the effects of the ADFIT on recorded carrying costs from the securitizable asset to the CTC refund, thereby increasing the carrying costs identified to the securitizable assets in the table below.

The differences between the securitization amount ordered by the PUCT of $1.74 billion and the Recorded Securitizable True-up Regulatory Asset of $1.57 billion by component at September 30, 2006 are detailed in the table below:

	(in millions)
Stranded Generation Plant Costs	$	974
Net Generation-related Regulatory Asset		249
Excess Earnings		(49	)
Recorded Net Stranded Generation Plant Costs		1,174
Recorded Debt Carrying Costs on Net Stranded Generation Plant Costs		400
Recorded Securitizable True-up Regulatory Asset		1,574
Unrecorded But Recoverable Equity Carrying Costs		224
Unrecorded Estimated October 2006 Debt Carrying Costs		3
Unrecorded Excess Earnings, Related Carrying Costs and Other		53
Unrecorded Settlement Reduction		(77	)
Reduction for the Present Value of ADITC and EDFIT Benefits		(61	)
Approved Securitizable Amount as of October 11, 2006		1,716
Unrecorded Securitization Bond Issuance Costs		24
Amount Securitized on October 11, 2006	$	1,740

Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s true-up and securitization orders, the PUCT reduced net stranded generation plant costs and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generating assets. (See Reduction for the Present Value of ADITC and EDFIT Benefits of $61 million in the table above.) TCC testified that the sharing of these tax benefits with customers might be a violation of the Internal Revenue Code’s normalization provisions.

TCC filed a request for a private letter ruling from the IRS in June 2005 to determine whether the PUCT’s action would result in a normalization violation. The IRS issued its private letter ruling on May 9, 2006 which stated that the PUCT’s flow through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. TCC informed the PUCT on May 10, 2006 of the adverse ruling, however, the PUCT did not change its order on rehearing. TCC filed an appeal with the PUCT. As discussed below in the “CTC Proceeding for Other True-up Items” section of this note, TCC proposed, and the PUCT agreed, to defer refunding the amount of the present value of its ADITC and EDFIT benefits through its CTC until this normalization issue is resolved upon the IRS issuance of final normalization regulations.

If a normalization violation occurs, it could result in the repayment of TCC’s ADITC on all property, including transmission and distribution property, which approximates $104 million as of September 30, 2006 and also a loss of the right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows through the appeal of the PUCT’s true-up order and through a CTC deferral.

CTC Proceeding for Other True-up Items

In June 2006, TCC filed to implement a negative CTC to refund its other true-up items over eight years. TCC will incur interest expense on the other true-up regulatory liability balances until it is fully refunded. The principal components of the CTC refund liability are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance.

The differences between the components of TCC’s Recorded Net Regulatory Liabilities - Other True-up Items of $238 million as of September 30, 2006 (including interest expense) and its Net CTC Refund Proposed of $357 million are detailed below:

	(in millions)
Wholesale Capacity Auction True-up	$	61
Carrying Costs on Wholesale Capacity Auction True-up		31
Retail Clawback including Carrying Costs		(65	)
Deferred Over-recovered Fuel Balance		(184	)
Retrospective ADFIT Benefit		(77	)
Other		(4	)
Recorded Net Regulatory Liabilities - Other True-up Items		(238	)
Unrecorded Prospective ADFIT Benefit		(240	)
Gross CTC Refund Proposed		(478	)
FERC Jurisdictional Fuel Refund Deferral		16
ADITC and EDFIT Benefit Refund Deferral		98
Net CTC Refund Proposed, After Deferrals		(364	)
True-up Proceeding Expense Surcharge		7
Net CTC Refund Proposed, After Deferrals and Expenses	$	(357	)

TCC requested that a portion of the refund be deferred, pending the outcome of two contingent federal matters related to the refund of $16 million of FERC jurisdictional fuel over-recoveries (discussed below) and $98 million (including carrying costs) related to potential tax normalization violation matters related to the refund of ADITC and EDFIT benefits (discussed above). Under TCC’s proposal, (a) if the two contingent federal matters are resolved consistent with the PUCT’s treatment, TCC will then refund the $16 million and the $98 million plus carrying costs or (b) if these two issues are not resolved consistent with the PUCT’s treatment, the deferred refunds will not be made in order to avoid a normalization violation and the violation of a Federal court order. Management cannot predict the final outcome of this filing.

Although TCC proposed to refund the $357 million over eight years, certain intervenors supported accelerated refunds. In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that TCC began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) to residential customers by the end of 2006. The CTC refund to the other customer classes during the interim period will be as proposed by TCC, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Fuel Balance Recoveries

In September 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding regarding the PUCT’s reallocation of off-system sales margins. In August 2006, TCC also received an order from the Federal District Court, Western District of Texas precluding the PUCT from enforcing its ruling regarding the PUCT’s reallocation of off-system sales margins in connection with TCC’s final fuel reconciliation. The favorable Federal District Court order, if upheld on appeal, could result in reductions to the over-recovered fuel principal balances of $8 million for TNC and $14 million ($16 million with carrying costs) for TCC. The PUCT appealed the TCC and TNC Federal Court decision to the United States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal court system, the PUCT may file a complaint at the FERC to address the allocation issue. We are unable to predict if the Federal District Court’s decision will be upheld or whether the PUCT will file a complaint at the FERC. Pending further clarification, TCC and TNC have not reversed their related provisions for fuel over-recovery. If the PUCT or another party were to file a complaint at the FERC that results in the PUCT’s decisions being reinstated, it could result in an adverse effect on results of operations and cash flows for the AEP East companies because an unfavorable FERC ruling may result in a reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits.

Carrying Costs on Net True-up Regulatory Assets Impacting Securitization and CTC Proceedings

In TCC’s True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79% overall pretax weighted average cost of capital rate approved in its unbundled cost of service rate proceeding. The recorded embedded debt component of this carrying cost rate is 8.12%. Through September 30, 2006, TCC recorded $400 million of debt-related carrying costs on stranded generation plant costs included in the securitization proceeding. Equity carrying costs of $224 million related to amounts securitized will be recognized in income as collected. TCC will accrue interest expense until its net CTC refund is fully refunded. The interest expense on the net CTC refund totals $9 million and $11 million for the three and nine months ended September 30, 2006, respectively, and is included in Interest Expense on the Condensed Consolidated Statements of Operations.

In June 2006, the PUCT adopted a proposed rule that prospectively changes the interest rate applied to TCC’s CTC refund balance. TCC anticipates that the rule change will reduce the rate TCC will pay on its CTC balance from 11.79% to 7.47%. TCC anticipates that the change will reduce its annual refund by approximately $8 million. The rule also provides for adjustments to the rate during subsequent rate case proceedings.

TNC True-up Proceeding

TNC filed a CTC proceeding in August 2005 to establish a rate to refund its net true-up regulatory liability. In December 2005, that proceeding was abated, pending a final ruling from TNC’s appeal to the federal court regarding the fuel proceeding (described above). In August 2006, the parties to TNC’s CTC proceeding filed a settlement that recommended implementing an interim refund of the true-up regulatory liability totaling $13 million, net of the amounts at issue in the federal court proceeding, over six months beginning in September 2006. In late August 2006, the PUCT approved the settlement and the net refund began in September 2006. TNC accrues interest expense on the unrefunded balance and will continue to do so until the balance is fully refunded.

Excess Earnings

As noted in our 2005 Annual Report, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings was unlawful under the Texas Restructuring Legislation. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. Management is unable to predict the ultimate outcome of these proceedings.

Summary

Our recorded securitizable true-up regulatory asset at September 30, 2006 of $1.57 billion, net of the recorded net regulatory liabilities for other true-up items of $238 million, reflects the PUCT’s orders in TCC’s True-up Proceeding and its securitization proceeding. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in any subsequent proceedings or court rulings, TCC will amortize its total securitizable true-up regulatory asset commensurate with recovery over the 14-year term of the securitized bonds issued in October 2006. If we determine, as a result of future PUCT orders or appeal court rulings, that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. Based on advice of Texas rate counsel, TCC appealed the PUCT orders seeking relief in both state and federal court where TCC believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. Municipal customers and other intervenors also appealed the same PUCT orders seeking to further reduce TCC’s true-up recoveries.

Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings or court appeals. If TCC succeeds in future appeals, it could have a material favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, or if the PUCT does not approve TCC’s CTC filing as filed and, as a result, causes a normalization violation, it could have a material adverse effect on future results of operations, cash flows and financial condition.

Texas Restructuring - SPP

In August 2006, the PUCT adopted a rule delaying customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s business operate in SPP. Approximately 3% of TNC’s operations are located in the SPP territory, with $13 million in net assets in SPP. We filed a petition in May 2006, requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) and TNC’s customers, facilities and certificated service located in the SPP area to SWEPCo. If this petition is successful, SWEPCo will be our only subsidiary affected by the delay in the SPP area.

OHIO RESTRUCTURING

Rate Stabilization Plans

In January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008 provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the request for additional revenues for specified costs. CSPCo’s potential for the additional annual 4% generation rate increases is diminished by approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008 due to the power acquisition rider approved by the PUCO in the Monongahela Power service territory acquisition proceeding and the recovery of pre-construction costs for its share of the jointly-owned IGCC plant (see “IGCC Plant” section of this note below). OPCo’s potential for additional annual 4% generation rate increases is diminished in 2006 by approximately one-quarter and to a lesser extent in 2007 due to the recovery of pre-construction costs for its share of the jointly-owned IGCC plant. The RSPs also provide that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004 and 2005 deferred environmental carrying costs and PJM-related administrative costs and congestion costs net of financial transmission rights (FTR) revenue related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $10 million and $26 million for CSPCo and $20 million and $58 million for OPCo in the third quarter and first nine months of 2006, respectively, from the RSP rate increases net of the amortization of RSP regulatory assets. These increases also include the recognition of equity carrying costs. As of September 30, 2006, unrecognized equity carrying costs from 2004 and 2005, which are recognized over the three-year RSP recovery period totaled $32 million. As of September 30, 2006, the unamortized RSP regulatory assets to be recovered through December 31, 2008 were $43 million.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the RSPs and also argued that there was no POLR obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover any POLR charges. In DP&L’s proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, supporting the Ohio companies’ position that they can recover a POLR charge. In an appeal concerning First Energy companies’ RSP, the Ohio Supreme Court held that the PUCO’s decision to eliminate the offer to customers of a price determined through competitive bids was unlawful. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for the Ohio companies, which also did not include a competitive bid process, and remanded the case to the PUCO for further proceedings, not inconsistent with the decision in the appeal of the First Energy companies’ RSP. In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continued to collect RSP revenues. In accordance with the PUCO directive, in September 2006, CSPCo and OPCo submitted their proposal to provide additional options for customer participation in the electric market.

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

IGCC Plant

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases: Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery, or refund, in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power costs. The proposed recoveries in Phases 1 and 2 would be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008 under their RSPs. Through September 30, 2006, the Ohio companies deferred pre-construction IGCC costs totaling $16 million and recovered $6 million of those costs.  We are currently recovering the remaining deferred amounts through June 30, 2007.

In April 2006, the PUCO issued an order authorizing the Ohio companies to implement Phase 1 of the cost recovery proposal. In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over no more than a twelve-month period effective July 1, 2006. In its June order, the PUCO indicated if the Ohio companies have not commenced continuous construction of the IGCC plant within five years of the order, all charges collected for pre-construction costs, which are assignable to other jurisdictions, must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. No date for a further hearing has been set.

In June 2006, the Industrial Energy Users - Ohio (IEU), an intervenor in the PUCO proceeding, filed a Complaint for Writ of Prohibition at the Ohio Supreme Court to prohibit the use of the PUCO’s authorization by the Ohio companies to enforce the collection of the Phase 1 rates and to prohibit the PUCO from further entertaining any increase in rates for the IGCC project. The Court subsequently granted a PUCO motion to dismiss the Complaint for Writ of Prohibition.

In August 2006, IEU, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio companies believe that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. The Ohio companies, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, future results of operations and cash flows will be adversely affected.

Transmission Rate Filing

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders for the Ohio companies. The transmission cost recovery riders are subject to an annual true-up process with over/under recovery mechanisms. In February 2006, the Ohio companies filed a request with the PUCO to incorporate all transmission costs and rates in their transmission cost recovery riders and institute a two-step increase to reflect the increases in the FERC-approved rates. In the filing, the first increase would be effective April 1, 2006 to reflect the Ohio companies’ share of the loss of SECA revenues and the second increase would be effective August 1, 2006 to recover their share of the cost of the new Wyoming-Jacksons Ferry 765 kV line. In May 2006, the PUCO issued an order approving a two-step increase in the transmission cost recovery riders with over/under recovery mechanisms, effective April 1, 2006. The new tariffs were filed with the PUCO and implemented in June 2006.

In October 2006, the Ohio companies filed for initial true-ups under the transmission cost recovery riders’ over/under recovery mechanisms. The filings reflect the refund of regulatory liabilities as of September 30, 2006 of $12 million and $16 million for CSPCo and OPCo, respectively, including carrying charges. These over-recoveries were reflected as part of the new transmission cost recovery rider filed to be effective January 2007. We anticipate the net effect of the new transmission cost recovery riders will result in increased cost recoveries over 2005 levels for CSPCo and OPCo of $27 million and $36 million, respectively, in 2006 and $15 million and $16 million, respectively, in 2007.

Distribution Service Reliability and Restoration Costs

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

In March 2006, the Ohio companies filed an application with the PUCO to implement tariff riders to recover a portion of previously expensed incremental costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. CSPCo and OPCo each requested recovery of approximately $12 million of such costs, which was approved by the PUCO in August 2006. Effective September 1, 2006, the Ohio companies implemented the storm cost recovery riders, which will continue until they have collected the authorized amounts or one year, whichever is shorter. In September 2006, the Ohio Consumers’ Counsel filed a request for rehearing with the PUCO, which was denied in October 2006.

As a result of the above, in September 2006 the Ohio companies recorded regulatory assets of $14 million, favorably affecting earnings.

Ormet

Ormet Primary Aluminum Corporation and Ormet Primary Mill Products Corporation (together, Ormet) was a customer of OPCo until 2000. Beginning in 2000, at Ormet’s request, the PUCO authorized a modification of the certified service territories of OPCo and South Central Power Company (SCP), a nonaffiliate, so that Ormet became a customer of SCP. SCP agreed to let Ormet access the electric generation market for the vast majority of its 520 MW load. Ormet filed a request with the PUCO to return to being served by OPCo at the industrial tariff rate. OPCo opposed the request because it would likely require the purchase of capacity and energy from the market at prices above the industrial RSP tariff rate in order to serve Ormet, as well as substantially reduce our ability to sell energy into the wholesale market at the higher market prices.

In June 2006, the PUCO found that SCP was not providing or proposing to provide physically adequate service to Ormet. In October 2006, the PUCO convened a hearing to determine if an electric supplier, other than SCP, should be authorized to serve Ormet’s significant load.

Subsequent to the hearing, the Ohio companies together with Ormet, its employees’ union and certain other interested parties filed a settlement agreement with the PUCO for approval. The settlement agreement provides for the reallocation of the service territories of CSPCo, OPCo and SCP so that Ormet’s Hannibal, Ohio facilities are located in a joint CSPCo/OPCo certified territory effective January 1, 2007. The settlement also provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH paid by Ormet and a to-be-determined market price submitted by management and reviewed by the PUCO.  The recovery is accomplished by the amortization to income of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient, an increase in RSP generation rates under the additional 4% provision of the RSP. The $43 per MWH price for generation services is above the industrial RSP generation tariff but below current market prices.

Customer Choice Deferrals

As provided in stipulation agreements approved by the PUCO in 2000, the Ohio companies defer customer choice implementation costs and related carrying costs in excess of $20 million each. The agreements provide for the deferral of these costs as regulatory assets until the next distribution base rate cases. Through September 30, 2006, we incurred $97 million of such costs and deferred $48 million of such costs for probable future recovery in distribution rates. We have not recorded $9 million of equity carrying costs, which are not recognized until collected. Pursuant to the RSPs, recovery of these amounts is subject to PUCO review and is deferred until the next distribution rate filing to change rates after the December 31, 2008 end of the RSP period. We believe that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates. 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.

         5.COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within our 2005 Annual Report, we continue to be involved in various legal matters. The 2005 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 2005 Annual Report. See disclosure below for significant matters and changes in status subsequent to the disclosure made in our 2005 Annual Report.

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation

The Federal EPA and a number of states alleged that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The 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. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

The Federal EPA and eight northeastern states each filed an additional complaint containing additional allegations against the Amos and Conesville plants. APCo and CSPCo filed an answer to the northeastern states’ complaint and the Federal EPA’s complaint, denying the allegations and stating their defenses. Cases are also pending that could affect CSPCo’s share of jointly-owned units at Beckjord, Zimmer and Stuart stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees.

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

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 of 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

In July 2004, two special interest groups, Sierra Club and Public Citizen, 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. In March 2005, the special interest groups filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at the Welsh Plant. SWEPCo filed a response to the complaint in May 2005. Other preliminary motions have been filed and are pending before the Court.

In July 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, financial condition or cash flows.

Carbon Dioxide (CO₂) 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, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. That same day, the Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint in the same court against the same defendants. The actions alleged that CO₂ emissions from the defendants’ power plants 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. The trial court’s dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have been completed. We believe the actions are without merit and intend to defend against the claims.

Ontario Litigation

In June 2005, we, along with nineteen nonaffiliated utilities, were named as defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. We have not been served with the lawsuit. The time limit for serving the defendants expired, but the case has not been dismissed. 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, emitted NO_X, SO₂ and particulate matter that harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $49 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 against it.

OPERATIONAL

Power Generation Facilityand TEM Litigation

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

Juniper is a nonaffiliated limited partnership, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing. Juniper arranged to finance the Facility. The Facility is collateral for Juniper’s debt financing. Due to the treatment of the Facility as a financing of an owned asset, we recognized all of Juniper’s funded obligations as a liability. Upon expiration of the lease, our actual cash obligation could range from $0 to $415 million based on the fair value of the assets at that time. However, if we default under the Juniper lease, our maximum cash payment could be as much as $525 million. Because we report Juniper’s funded obligations totaling $525 million related to the Facility on our Condensed Consolidated Balance Sheets, the fair value of the liability for our guarantee (the $415 million payment discussed above) is not separately reported.

In August 2006, we reached an agreement with Dow to sell the Facility to them. We expect the sale to close during the fourth quarter of 2006 following receipt of federal regulatory approvals. Upon closing, we will repay our recorded $525 million lease financing obligation, which is included in Long-term Debt Due Within One Year on our Condensed Consolidated Balance Sheet at September 30, 2006. The approved sale resulted in a third quarter pretax impairment of approximately $209 million (see Note 8).

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo 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 (approximately 270 MW). 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 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 U.S. District Court for the Southern District of New York. We alleged that TEM breached the PPA, and we sought a determination of our rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of AEP’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In April 2004, OPCo gave notice to TEM that OPCo (a) was suspending performance of its obligations under the PPA; (b) would seek a declaration from the District Court that the PPA was terminated; and (c) would pursue TEM and SUEZ-TRACTEBEL S.A. under the guaranty, seeking 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 breached the contract and awarded us damages of $123 million plus prejudgment 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 (a) award a termination payment to us under the terms of the PPA; (b) grant our attorneys’ fees; and (c) 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 January 2006, the trial judge granted our motion for reconsideration concerning TEM’s parent guaranty and increased our judgment against TEM to $173 million plus prejudgment interest, and denied the remaining motions for reconsideration. In March 2006, the trial judge amended the January 2006 order eliminating the additional $50 million damage award.

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. Oral argument is scheduled for December 2006. If the PPA is deemed terminated or found 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 (if our sale of the Facility to Dow does not close) and to the extent we do not fully recover the claimed termination value damages from TEM.

Enron Bankruptcy

In connection with our 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. In 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 trial court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In August 2006, the Court of Appeals for the First District of Texas vacated the trial court’s judgment and dismissed the BOA Syndicate’s case. The BOA Syndicate did not seek review of this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to continue to defend 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. In April 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York. HPL and BOA filed motions for summary judgment in the case pending in the Southern District of New York.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right-to-use agreement and other incidental agreements. We objected to Enron’s attempted rejection of these agreements and filed an adversary proceeding contesting Enron’s right to reject these agreements.

In 2005, we sold our interest in HPL. We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price. The determination of the gain on sale and the recognition of the gain are dependent on the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter (see Note 8).

In June and July 2006, we held mediation discussions with BOA and Enron concerning these gas disputes. No further discussions are scheduled at this time. Although management is unable to predict the outcome of the remaining lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows and financial condition.

Shareholder Lawsuits

In the fourth quarter of 2002 and the first quarter of 2003, three putative class action lawsuits were filed against AEP, certain executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions were pending in Federal District Court, Columbus, Ohio. In July 2006, the Court entered judgment denying plaintiff’s motion for class certification and dismissing all claims without prejudice. In August 2006, plaintiff filed a notice of appeal to the United States Court of Appeals for the Sixth Circuit. Briefing of this appeal is scheduled for completion in December 2006.

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 an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were filed in California. In addition, a number of other cases 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 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 and in December 2005, the judge dismissed two additional cases on the same ground. Plaintiffs in these cases appealed the decisions. We will continue to defend 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. These cases were consolidated. In January 2004, plaintiffs filed an amended consolidated complaint. The defendants filed a motion to dismiss the complaint which the Court denied. In October 2005, the Court granted the plaintiffs motion for class certification. We intend to continue to defend against these claims.

FERC Long-term Contracts

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that we sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the Nevada utilities’ complaint, held that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. The Nevada utilities’ request for a rehearing was denied. The Nevada utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals for the Ninth Circuit. Management is unable to predict the outcome of this proceeding and its impact on future results of operations and cash flows.

         6.GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

LETTERS OF CREDIT

We enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. As the parent company, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries. At September 30, 2006, the maximum future payments for all the LOCs are approximately $34 million with maturities ranging from October 2006 to July 2007.

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 agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). If Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $68 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 provides guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and final reclamation is completed. At September 30, 2006, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036. We estimate the cost for final reclamation during the period 2029 through 2036 at approximately $39 million.

INDEMNIFICATIONS AND OTHER GUARANTEES

Contracts

We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. Prior to September 30, 2006, we entered into several sale agreements. The status of certain sales agreements is discussed in Note 8. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $2.1 billion (approximately $1 billion relates to the BOA litigation, see “Enron Bankruptcy” section of Note 5). There are no material liabilities recorded for any indemnifications.

Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At September 30, 2006, the maximum potential loss for these lease agreements was approximately $54 million ($35 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 BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years.

At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years, (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value, or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. We intend to renew the lease for the full twenty years.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least the lessee obligation amount specified in the lease, which declines over the current lease term from approximately 86% to 77% of the projected fair market value of the equipment. At September 30, 2006, the maximum potential loss was approximately $31 million ($20 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. We have other railcar lease arrangements that do not utilize this type of structure.

         7.COMPANY-WIDE STAFFING AND BUDGET REVIEW

As a result of a company-wide staffing and budget review in the second quarter of 2005, we identified approximately 500 positions for elimination. Pretax severance benefits expense of $24 million and $4 million was recorded (primarily in Maintenance and Other Operation within the Utility Operations segment) in the second and third quarters of 2005, respectively.

The following table shows the accrual as of December 31, 2005 (reflected primarily in Current Liabilities - Other on our Condensed Consolidated Balance Sheets) and the activity during the first nine months of 2006, which eliminated the accrual as of June 30, 2006:

	Amount (in millions)
Accrual at December 31, 2005	$	12
Less: Total Payments		8
Less: Accrual Adjustments		4
Accrual at September 30, 2006	$	-

The favorable accrual adjustments were recorded primarily in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations.

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

ACQUISITIONS

2005

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.

DISPOSITIONS

2006

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. We received an indicative offer for Bajio in September 2005, which resulted in a pretax other-than-temporary impairment charge of approximately $7 million. The impairment amount is classified in Investment Value Losses on our Condensed Consolidated Statements of Operations. We completed the sale in February 2006 for approximately $29 million with no effect on our 2006 results of operations.

2005

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

During 2005, we sold our interest in HPL, 30 billion cubic feet (BCF) of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. Although the assets were legally transferred, it is not possible to determine all costs associated with the transfer until the Bank of America (BOA) litigation is resolved. Accordingly, we recorded the excess of the sales price over the carrying cost of the net assets transferred as a deferred gain of $379 million as of September 30, 2006 and December 31, 2005, which is reflected in Deferred Credits and Other on our Condensed Consolidated Balance Sheets. We provided an indemnity to the purchaser in an amount up to the purchase price for damages, if any, arising from litigation with BOA and a potential resulting inability to use the cushion gas (see “Enron Bankruptcy” section of Note 5). The HPL operations did not meet the criteria to be shown as discontinued operations due to continuing involvement associated with various contractual obligations. Significant continuing involvement includes cash flows from long-term gas contracts with the buyer through 2008 and the cushion gas arrangement. In addition, we continue holding forward gas contracts, with expirations through 2011, not sold with the gas pipeline and storage assets.  We manage the commodity price risk associated with these forward gas contracts to limit our price risk exposure principally by entering into equal and offsetting contracts.  For the nine months ended September 30, 2006, the change in the mark-to-market value of these positions was less than $100,000.

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 and was amended through a series of agreements that AEP and Centrica entered in March 2005. Also in March 2005, we received payments related to the ESM of $45 million and $70 million for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in 2005. In March 2006, we received a payment of $70 million related to the ESM for 2005. The ESM payment for 2006 is contingent on Centrica’s future operating results and is contractually capped at $20 million. The payments are reflected in Gain/Loss on Disposition of Assets, Net on our Condensed Consolidated Statements of Operations.

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 classified as shown in the following table (in millions):

Three Months ended September 30, 2006 and 2005:
	SEEBOARD (a)		U.K. Generation(b)			Total
2006 Revenue	$	-	$	-		$	-
2006 Pretax Income		-		-			-
2006 Earnings, Net of Tax		-		-			-
2005 Revenue	$	13	$	-		$	13
2005 Pretax Income		13		-			13
2005 Earnings, Net of Tax		20		2			22
Nine Months ended September 30, 2006 and 2005:
	SEEBOARD (a)		U.K. Generation(c)			Total
2006 Revenue	$	-	$	-		$	-
2006 Pretax Income		-		9			9
2006 Earnings, Net of Tax		-		6			6
2005 Revenue (Expense)	$	13	$	(8	)	$	5
2005 Pretax Income (Loss)		13		(8	)		5
2005 Earnings (Loss), Net of Tax		29		(3	)		26

(a)	The amounts relate to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD.
(b)	The amount relates to a tax adjustment from the sale.
(c)	The 2006 amounts relate to a release of accrued liabilities for the London office lease and tax adjustments from the sale. Amounts in 2005 relate to purchase price true-up adjustments and tax adjustments from the sale.

There were no cash flows used for or provided by operating, investing or financing activities related to our discontinued operations for the nine months ended September 30, 2006 and 2005.

ASSETS HELD FOR SALE AND ASSET IMPAIRMENTS

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In January 2004, we signed an agreement to sell TCC’s 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004, we received notice from the nonaffiliated co-owners announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, we entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. Golden Spread challenged these agreements in State District Court in Dallas County. Golden Spread alleges that the Public Utilities Board of the City of Brownsville exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the nonaffiliated co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread in October 2005. TCC and the nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth District at Dallas. In May 2006, the Court of Appeals for the Fifth District at Dallas reversed the trial court’s judgment in favor of Golden Spread and held that the City of Brownsville properly exercised its right of first refusal to acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the matter, and its petition was denied. Golden Spread then appealed to the Supreme Court of Texas and in August 2006, the court requested a response from the Oklahoma Municipal Power Authority, the Public Utilities Board of the City of Brownsville and us. Responses were due October 27, 2006. We cannot predict when these issues will be resolved. We do not expect the sale to have a significant effect on the terms of the future results of operations. TCC’s assets related to the Oklaunion Power Station are classified as Assets Held for Sale on our Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by our Registrant Subsidiaries.

Power Generation Facility (Investments - Other segment)

In August 2006, we reached an agreement to sell our Plaquemine Cogeneration Facility (the Facility) to Dow Chemical Company (Dow) for $64 million. We expect the sale to close in the fourth quarter of 2006. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on the terms of the agreement to sell the Facility to Dow. We recorded the impairment in Asset Impairments and Other Related Charges on our Condensed Consolidated Statements of Operations. We classified the Facility’s assets as Assets Held for Sale on our Condensed Consolidated Balance Sheet at September 30, 2006. The Facility does not meet the criteria for discontinued operations reporting.

In addition to the cash proceeds, the sale agreement allows us to participate in gross margin sharing on the Facility for five years. Dow will reduce an existing below-current-market long-term power supply contract with us in Texas by 50 MW, and we retain the right to any judgment paid by TEM for breaching the original PPA, as discussed in Note 5.

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.

We recognized a pretax charge of approximately $39 million in the third quarter of 2005 related to our decision to retire the units. We classified the impairment amount in Asset Impairments and Other Related Charges on our Condensed Consolidated Statements of Operations.

Assets Held for Sale at September 30, 2006 and December 31, 2005 are as follows:

September 30, 2006	Texas Plants		Power Generation Facility		Total
Assets:	(in millions)
Other Current Assets	$	2	$	-	$	2
Property, Plant and Equipment, Net		44		64		108
Total Assets Held for Sale	$	46	$	64	$	110

December 31, 2005	Texas Plants
Assets:	(in millions)
Other Current Assets	$	1
Property, Plant and Equipment, Net		43
Total Assets Held for Sale	$	44

         9.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

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, 2006 and 2005:

	Pension Plans						Other Postretirement Benefit Plans
Three Months Ended September 30, 2006 and 2005:	2006			2005			2006			2005
	(in millions)
Service Cost	$	23		$	23		$	10		$	10
Interest Cost		57			57			26			26
Expected Return on Plan Assets		(82	)		(77	)		(24	)		(23	)
Amortization of Transition (Asset) Obligation		-			(1	)		7			6
Amortization of Net Actuarial Loss		20			13			5			5
Net Periodic Benefit Cost	$	18		$	15		$	24		$	24

	Pension Plans						Other Postretirement Benefit Plans
Nine Months Ended September 30, 2006 and 2005:	2006			2005			2006			2005
	(in millions)
Service Cost	$	71		$	69		$	30		$	31
Interest Cost		171			169			76			79
Expected Return on Plan Assets		(248	)		(232	)		(70	)		(68	)
Amortization of Transition (Asset) Obligation		-			(1	)		21			20
Amortization of Net Actuarial Loss		59			40			15			19
Net Periodic Benefit Cost	$	53		$	45		$	72		$	81

        10.STOCK-BASED COMPENSATION

As previously approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the Plan) authorizes the use of 19,200,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. A maximum of 9,000,000 shares may be used under this plan for full value share awards, which include performance units, restricted shares and restricted stock units. The Board of Directors and shareholders both adopted the original Plan in 2000 and the amended and restated version in 2005.  We have not granted options as part of our regular stock-based compensation program since 2003.  However, we have used stock options in limited circumstances totaling 149,000 options in 2004, 10,000 options in 2005 and none during 2006.  The following sections provide further information regarding each type of stock-based compensation award the Board of Directors has granted.

We adopted SFAS 123R, effective January 1, 2006. See the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2 for additional information.

Stock Options

For all stock options previously granted, the exercise price equaled or exceeded the market price of AEP’s common stock on the date of grant. Historically the Board of Directors has granted stock options with a ten-year term that generally vest, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1^st of the year following the first, second and third anniversary of the grant date. Compensation cost for stock options is recorded over the vesting period based on the fair value on the grant date. The Plan does not specify a maximum contractual term for stock options.

CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled, expired or forfeited. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date.

The Board of Directors did not award any stock options during the nine months ended September 30, 2006.

The total fair value of stock options vested and the total intrinsic value of options exercised during the nine months ended September 30, 2006 was $3.7 million and $2.3 million, respectively. Intrinsic value is calculated as market price at exercise date less the option exercise price.

A summary of AEP stock option transactions during the nine months ended September 30, 2006 is as follows:

	Options			Weighted Average Exercise Price
	(in thousands)
Outstanding at January 1, 2006		6,222		$	34.16
Granted		-			-
Exercised/Converted		(369	)		30.17
Expired		-			-
Forfeited		(209	)		41.62
Outstanding at September 30, 2006		5,644			34.15
Exercisable at September 30, 2006		5,384		$	34.41

The following table summarizes information about AEP stock options outstanding at September 30, 2006.

Options Outstanding

2006 Range of Exercise Prices	Number Exercisable		Weighted Average Remaining Life		Weighted Average Exercise Price		Aggregate Intrinsic Value
	(in thousands)		(in years)				(in thousands)
$25.73 - $27.95		1,359		5.9	$	27.38	$	12,220
$30.76 - $38.65		3,917		3.2		35.44		3,665
$43.79 - $49.00		368		4.6		45.43		-
		5,644		4.0		34.15	$	15,885

The following table summarizes information about AEP stock options exercisable at September 30, 2006.

Options Exercisable

2006 Range of Exercise Prices	Number Exercisable		Weighted Average Remaining Life		Weighted Average Exercise Price		Aggregate Intrinsic Value
	(in thousands)		(in years)				(in thousands)
$25.73 - $27.95		1,158		5.7	$	27.29	$	10,519
$30.76 - $35.63		3,858		3.2		35.49		3,386
$43.79 - $49.00		368		4.6		45.43		-
		5,384		3.8		34.41	$	13,905

The proceeds received from exercised stock options are included in common stock and paid-in capital. For options issued through December 31, 2005, the grant date fair value of each option award was estimated using a Black-Scholes option-pricing model with weighted average assumptions. Expected volatilities are estimated using the historical monthly volatility of our common stock for the 36-month period prior to each grant. A seven-year average expected term is also assumed. The risk-free rate is the yield for U.S. Treasury securities with a remaining life equal to the expected seven-year term of AEP stock options on the grant date.

Performance Units

Our performance units are equal in value to an equivalent number of shares of AEP common stock. The number of performance units held is multiplied by a performance score to determine the actual number of performance units realized. The performance score is determined at the end of the performance period based on performance measure(s) established for each grant at the beginning of the performance period by the Human Resources Committee of the Board of Directors (HR Committee) and can range from 0 percent to 200 percent. Performance units are typically paid in cash at the end of a three-year performance and vesting period, unless they are needed to satisfy a participant’s stock ownership requirement, in which case they are mandatorily deferred as phantom stock units (AEP Career Shares) until after the end of the participant’s AEP career. AEP Career Shares have a value equivalent to the market value of an equal number of AEP common shares and are generally paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP Career Shares accrue as additional units. The compensation cost for performance units is recorded over the vesting period and the liability for both the performance units and AEP Career Shares is adjusted for changes in value. The vesting period of all performance units is three years.

Our Board of Directors awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the nine months ended September 30, 2006 as follows:

Performance Units
Awarded Units (in thousands)	864
Unit Fair Value at Grant Date	$	37.36
Vesting Period (years)		3

Performance Units and AEP Career Shares (Reinvested Dividends Portion)
Awarded Units (in thousands)	91
Weighted Average Grant Date Fair Value	$	35.37
Vesting Period (years) (a)		3

(a) Vesting Period (years) range from 0 to 3 years. The Vesting Period of the reinvested dividends is equal to the remaining life of the related performance units and AEP Career Shares.

In January 2006, the HR Committee certified a performance score of 49% for performance units originally granted for the 2003 through 2005 performance period. As a result, 108,486 performance units were earned. Of this amount 33,296 were mandatorily deferred as AEP Career Shares, 4,360 were voluntarily deferred into the Incentive Compensation Deferral Program and the remainder were paid in cash.

The cash payouts for the nine months ended September 30, 2006 were $2.6 million for performance units and $1.0 million for AEP Career Share distributions.

The performance unit scores for all open performance periods are dependent on two equally-weighted performance measures: three-year total shareholder return measured relative to the S&P Utilities Index and three-year cumulative earnings per share measured relative to a board-approved target. The value of each performance unit earned equals the average closing price of AEP common stock for the last 20 days of the performance period.

The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation.

Restricted Shares and Restricted Stock Units

Our Board of Directors granted 300,000 restricted shares to the Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment. Of these restricted shares, 50,000 vested on January 1, 2005 and 50,000 vested on January 1, 2006. The remaining 200,000 restricted shares vest, subject to his continued employment, in approximately equal thirds on November 30, 2009, 2010 and 2011. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of shares granted by the grant date market price. The maximum term for these restricted shares is eight years. The Board of Directors has not granted other restricted shares. Dividends on our restricted shares are paid in cash.

Our Board of Directors may also grant restricted stock units, which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments on the anniversaries of the grant date. Amounts equivalent to dividends paid on AEP shares accrue as additional restricted stock units that vest on the last vesting date associated with the underlying units. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of units granted by the grant date market price. The maximum contractual term of these restricted stock units is six years.

In January 2006, our Board of Directors also granted restricted stock units with performance vesting conditions to certain employees who are integral to our project to design and build an IGCC power plant. Twenty percent of these awards vest on each of the first three anniversaries of the grant date. An additional 20% vest on the date the IGCC plant achieves commercial operations. The remaining 20% vest one year after the IGCC plant achieves commercial operations, subject to achievement of plant availability targets.

Our Board of Directors awarded 47,050 restricted stock units, including units awarded for dividends, with a weighted average grant date fair value of $35.58 per unit, for the nine months ended September 30, 2006.

The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the nine months ended September 30, 2006 was $3.9 million and $4.6 million, respectively.

A summary of the status of our nonvested restricted shares and restricted stock units as of September 30, 2006, and changes during the nine months ended September 30, 2006 are as follows:

Nonvested Restricted Shares and Restricted Stock Units	Shares/Units			Weighted Average Grant Date Fair Value
	(in thousands)
Nonvested at January 1, 2006		497		$	32.19
Granted		47			35.58
Vested		(127	)		30.56
Forfeited		(22	)		35.52
Nonvested at September 30, 2006		395			32.93

The total aggregate intrinsic value of nonvested restricted shares and restricted stock units as of September 30, 2006 was $14.4 million and the weighted average remaining contractual life was 3.03 years.

Share-based Compensation Plans

Compensation cost, the actual tax benefit realized for the tax deductions from compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the nine months ended September 30, 2006 were as follows:

Share-based Compensation Plans	(in thousands)
Compensation Cost for Share-based Payment Arrangements (a)	$	16,671
Actual Tax Benefit Realized		5,835
Total Compensation Cost Capitalized		3,746

(a) Compensation cost for share-based payment arrangements is included in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations.

During the nine months ended September 30, 2006, there were no significant modifications affecting any of our share-based payment arrangements.

As of September 30, 2006, there was $49.1 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the Plan. Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the liability is revalued each period and forfeitures for all award types are realized. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.57 years.

Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the nine months ended September 30, 2006 was $11.1 million and $0.8 million, respectively.

Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and restricted stock unit vesting. Although we do not currently anticipate any changes to this practice, we could use reacquired shares, shares acquired in the open market specifically for distribution under the Plan or any combination thereof for this purpose. The number of new shares issued to fulfill vesting restricted stock units is generally reduced, at the participant’s election, to offset AEP’s tax withholding obligation.

         11.INCOME TAXES

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, we reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006 we recorded a net reduction to Deferred Income Taxes on the Condensed Consolidated Balance Sheet of $48 million of which $2 million was credited to Income Tax Expense and $46 million credited to Regulatory Assets based upon the related rate-making treatment.

        12.BUSINESS SEGMENTS

As outlined in our 2005 Annual Report, our business strategy and the core of our business are to focus on domestic electric utility operations. Our previous decision to no longer pursue business interests outside of our domestic core utility assets led us to divest such noncore assets. Consequently, the significance of our three Investments segments has declined.

Our segments and their related business activities are as follows:

Utility Operations

· Generation of electricity for sale to U.S. retail and wholesale customers.

· Electricity transmission and distribution in the U.S.

Investments - Gas Operations

· Gas pipeline and storage services.

· Gas marketing and risk management activities.

· We disposed of our gas pipeline and storage assets in 2005 with the sale of HPL (see “Dispositions” section of Note 8).

Investments - UK Operations

· International generation of electricity for sale to wholesale customers.

· Coal procurement and transportation to our plants.

· We classified UK Operations as Discontinued Operations during 2003 and sold them in 2004.

Investments - Other

· Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.

The tables below present segment income statement information for the three and nine months ended September 30, 2006 and 2005 and balance sheet information as of September 30, 2006 and December 31, 2005. These amounts include certain estimates and allocations where necessary. Prior year amounts have been reclassified to conform to the current year’s presentation.

				Investments
	Utility Operations			Gas Operations			UK Operations		Other			All Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Three Months Ended
September 30, 2006
Revenues from:
External Customers	$	3,485		$	(47	)	$	-	$	156		$	-		$	-		$	3,594
Other Operating Segments		(44	)		51			-		4			1			(12	)		-
Total Revenues	$	3,441		$	4		$	-	$	160		$	1		$	(12	)	$	3,594
Net Income (Loss)	$	379		$	(3	)	$	-	$	(109	)	$	(2	)	$	-		$	265

			Investments
	Utility Operations		Gas Operations			UK Operations		Other		All Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Three Months Ended
September 30, 2005
Revenues from:
External Customers	$	3,152	$	73		$	-	$	103	$	-		$	-		$	3,328
Other Operating Segments		85		(77	)		-		3		1			(12	)		-
Total Revenues	$	3,237	$	(4	)	$	-	$	106	$	1		$	(12	)	$	3,328
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

				Investments
	Utility Operations			Gas Operations			UK Operations		Other			All Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Nine Months Ended
September 30, 2006
Revenues from:
External Customers	$	9,282		$	(80	)	$	-	$	436		$	-		$	-		$	9,638
Other Operating Segments		(73	)		89			-		9			2			(27	)		-
Total Revenues	$	9,209		$	9		$	-	$	445		$	2		$	(27	)	$	9,638
Income (Loss) Before Discontinued   Operations	$	904		$	(2	)	$	-	$	(80	)	$	(7	)	$	-		$	815
Discontinued Operations, Net of Tax		-			-			6		-			-			-			6
Net Income (Loss)	$	904		$	(2	)	$	6	$	(80	)	$	(7	)	$	-		$	821

			Investments
	Utility Operations		Gas Operations			UK Operations			Other		All Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Nine Months Ended
September 30, 2005
Revenues from:
External Customers	$	8,437	$	449		$	-		$	326	$	-		$	-		$	9,212
Other Operating Segments		186		(167	)		-			12		2			(33	)		-
Total Revenues	$	8,623	$	282		$	-		$	338	$	2		$	(33	)	$	9,212
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

			Investments
	Utility Operations		Gas Operations			UK Operations			Other		All Other (b)		Reconciling Adjustments (b)			Consolidated
																		(in millions)
As of September 30, 2006
Total Property, Plant and Equipment	$	40,397	$	1		$	-		$	567	$	3	$	-		$	40,968
Accumulated Depreciation and Amortization		15,014		-			-			130		2		-			15,146
Total Property, Plant and Equipment - Net	$	25,383	$	1		$	-		$	437	$	1	$	-		$	25,822
Total Assets	$	35,185	$	591	(c)	$	639	(d)	$	72	$	10,372	$	(10,474	)	$	36,385
Assets Held for Sale		46		-			-			64		-		-			110

			Investments
	Utility Operations		Gas Operations			UK Operations			Other		All Other (b)		Reconciling Adjustments (b)			Consolidated
	(in millions)
As of December 31, 2005
Total Property, Plant and Equipment	$	38,283	$	2		$	-		$	833	$	3	$	-		$	39,121
Accumulated Depreciation and Amortization		14,723		1			-			112		1		-			14,837
Total Property, Plant and Equipment - Net	$	23,560	$	1		$	-		$	721	$	2	$	-		$	24,284
Total Assets	$	34,339	$	1,199	(e)	$	632	(f)	$	509	$	9,463	$	(9,970	)	$	36,172
Assets Held for Sale		44		-			-			-		-		-			44

(a)	All Other includes the parent company’s guarantee revenue, interest income and expense, as well as other nonallocated costs.
(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 (included in All Other) in subsidiary companies.
(c)	Total Assets of $591 million for the Investments-Gas Operations segment include $321 million in affiliated accounts receivable related to the corporate borrowing program and risk management contracts that are eliminated in consolidation. The majority of the remaining $270 million in assets represents third party risk management contracts, margin deposits and accounts receivable.
(d)	Total Assets of $639 million for the Investments-UK Operations segment include $625 million in affiliated accounts receivable related mainly to federal income taxes that are eliminated in consolidation. The majority of the remaining $14 million in assets represents cash equivalents.
(e)	Total Assets of $1.2 billion for the Investments-Gas Operations segment include $429 million in affiliated accounts receivable related to the corporate borrowing program and risk management contracts that are eliminated in consolidation. The majority of the remaining $770 million in assets represents third party risk management contracts, margin deposits, and accounts receivable.
(f)	Total Assets of $632 million for the Investments-UK Operations segment include $613 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 and value-added tax receivables.

        13.   FINANCING ACTIVITIES

Long-term Debt

Our outstanding long-term debt is as follows:

	September 30,			December 31,
Type of Debt	2006			2005
	(in millions)
Pollution Control Bonds	$	2,051		$	1,935
Senior Unsecured Notes		8,827			8,226
First Mortgage Bonds		96			196
Defeased First Mortgage Bonds (a)		26			26
Notes Payable		872			904
Securitization Bonds		596			648
Notes Payable To Trust		113			113
Other Long-Term Debt (b)		247			236
Unamortized Discount (net)		(65	)		(58	)
Total Long-term Debt Outstanding		12,763			12,226
Less Portion Due Within One Year		1,789			1,153
Long-term Portion	$	10,974		$	11,073

(a)

In May 2004, we deposited cash and treasury securities with a trustee to defease all of TCC’s outstanding First Mortgage Bonds. The defeased TCC First Mortgage Bonds had a balance of $18 million at both September 30, 2006 and December 31, 2005. Trust fund assets related to this obligation of $2 million are included in Other Temporary Cash Investments at both September 30, 2006 and December 31, 2005 and $21 million is included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets at both September 30, 2006 and December 31, 2005. In December 2005, we deposited cash and treasury securities with a trustee to defease the remaining TNC outstanding First Mortgage Bond. The defeased TNC First Mortgage Bond had a balance of $8 million at both September 30, 2006 and December 31, 2005. Trust fund assets related to this obligation of $9 million and $1 million at September 30, 2006 and December 31, 2005, respectively, are included in Other Temporary Cash Investments and $0 and $8 million are included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005, respectively. Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.

(b)

Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets of $270 million and $264 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts in the Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005, respectively.

Long-term debt issued, retired and principal payments made during the first nine months of 2006 are shown in the tables below.

Company	Type of Debt	Principal Amount			Interest Rate	Due Date
		(in millions)			(%)
Issuances:
APCo	Pollution Control Bonds	$	50		Variable	2036
APCo	Senior Unsecured Notes		250		5.55	2011
APCo	Senior Unsecured Notes		250		6.375	2036
I&M	Pollution Control Bonds		50		Variable	2025
OPCo	Pollution Control Bonds		65		Variable	2036
OPCo	Senior Unsecured Notes		350		6.00	2016
PSO	Senior Unsecured Notes		150		6.15	2016
SWEPCo	Pollution Control Bonds		82		Variable	2018
Total Issuances		$	1,247	(a)

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

(a) Amount indicated on statement of cash flows of $1,229 million is net of issuance costs and unamortized premium or discount.

Company	Type of Debt	Principal Amount Paid		Interest Rate	Due Date
		(in millions)		(%)
Retirements and Principal Payments:
AEP	Senior Unsecured Notes	$	396	6.125	2006
APCo	First Mortgage Bonds		100	6.80	2006
I&M	Pollution Control Bonds		50	6.55	2025
OPCo	Notes Payable		4	6.81	2008
OPCo	Notes Payable		7	6.27	2009
SWEPCo	Notes Payable		5	4.47	2011
SWEPCo	Notes Payable		2	Variable	2008
SWEPCo	Pollution Control Bonds		82	6.10	2018
TCC	Securitization Bonds		52	5.01	2010
Non-Registrant:
AEP subsidiaries	Notes Payable		9	Variable	2017
CSW Energy, Inc.	Notes Payable		4	5.88	2011
Total Retirements and Principal  Payments		$	711

In October 2006, TCC issued $1.74 billion in securitization bonds as follows:

Principal		Interest	Scheduled Final
Amount		Rate	Payment Date
	(in millions)	(%)
$	217	4.98	2010
	341	4.98	2013
	250	5.09	2015
	437	5.17	2018
	495	5.3063	2020

The proceeds will be used to retire TCC debt and equity, which are no longer needed to support stranded costs.

In October 2006, I&M had a required remarketing of $65 million of 2.625% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo had a required remarketing of $30 million of 2.80% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo issued $17.5 million of variable rate pollution control bonds and retired $17.5 million, 2.70% pollution control bonds due in 2007.

In November 2006, $100.6 million of pollution control bonds were put back to TCC on the put date of November 1, 2006. TCC intends to hold these bonds for reissuance at a later date.

Credit Facilities

In April 2006, we amended the terms and increased the size of our credit facilities from $2.7 billion to $3 billion. The amended facilities are structured as two $1.5 billion credit facilities, with an option in each to issue up to $200 million as letters of credit, expiring separately in March 2010 and April 2011. We also terminated an existing $200 million letter of credit facility.

AEP GENERATING COMPANY

AEP GENERATING COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As co-owner of the Rockport Plant, we engage in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. I&M is the operator and co-owner of the Rockport Plant.

We derive operating revenues from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for a FERC-approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Under the terms of the unit power agreements, we accumulate all expenses monthly and prepare bills for our affiliates. In the month the expenses are incurred, we recognize the billing revenues and establish a receivable from the affiliated companies. We divide costs of operating the plant between the co-owners.

Results of Operations

Net Income was unchanged for the third quarter of 2006 compared with the third quarter of 2005. Net Income increased $0.6 million for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005. The fluctuation in Net Income is a result of terms in the unit power agreements which allow for a return on total capital of the Rockport Plant which is calculated and adjusted monthly.

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	2.2
Change in Gross Margin:
Wholesale Sales				0.2
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(0.7	)
Taxes Other Than Income Taxes	0.7
Interest Expense	(0.1	)
Total Change in Operating Expenses and Other				(0.1	)
Income Tax Expense				(0.1	)
Third Quarter of 2006			$	2.2

Gross Margin, defined as Operating Revenues less Fuel for Electric Generation, increased $0.2 million primarily due to recovery of higher expenses.

Other Operation and Maintenance expenses increased primarily due to increased costs at the Rockport Plant for steam plant operation and maintenance of structures.

Taxes Other Than Income Taxes decreased primarily due to lower real and personal property taxes as the prior year accrual was adjusted to the actual amount paid.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	6.8
Changes in Gross Margin:
Wholesale Sales				3.2
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(2.0	)
Taxes Other Than Income Taxes	0.7
Interest Expense	(0.3	)
Total Change in Operating Expenses and Other				(1.6	)
Income Tax Expense				(1.0	)
Nine Months Ended September 30, 2006			$	7.4

Gross Margin, defined as Operating Revenues less Fuel for Electric Generation, increased $3.2 million primarily due to recovery of higher expenses and higher returns earned on plant and capital investment.

Other Operation and Maintenance expenses increased $2.0 million primarily due to increased maintenance cost at the Rockport Plant during a planned outage in 2006 and credits allocated to us in February 2005 from the cancellation and settlement of corporate owned life insurance policies.

Taxes Other Than Income Taxes decreased $0.7 million primarily due to lower real and personal property taxes as the prior year accrual was adjusted to the actual amount paid.

Income Taxes

Income Tax Expense increased $1.0 million primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Off-Balance Sheet Arrangements

In prior years, we entered into an off-balance sheet arrangement for the lease of Rockport Plant Unit 2. Our current guidelines restrict the use of off-balance sheet financing entities or structures to allow only 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 2005 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

In July 2006, we remarketed $45 million of pollution control bonds at a rate of 4.15% compared to a previous rate of 4.05% until July 14, 2011, the next remarketing date.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 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, 2006 and 2005

(Unaudited)

(in thousands)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
OPERATING REVENUES	$	74,756		$	69,640		$	230,102		$	201,268
EXPENSES
Fuel for Electric Generation		42,354			37,403			131,402			105,771
Rent - Rockport Plant Unit 2		17,070			17,070			51,212			51,212
Other Operation		3,381			2,803			9,598			8,376
Maintenance		2,522			2,421			7,238			6,411
Depreciation and Amortization		5,951			5,956			17,858			17,901
Taxes Other Than Income Taxes		368			1,074			2,466			3,149
TOTAL		71,646			66,727			219,774			192,820
OPERATING INCOME		3,110			2,913			10,328			8,448
Other Income (Expense):
Interest Income		-			-			-			24
Allowance for Equity Funds Used During Construction		-			-			24			60
Interest Expense		(774	)		(652	)		(2,137	)		(1,848	)
INCOME BEFORE INCOME TAXES		2,336			2,261			8,215			6,684
Income Tax Expense (Credit)		117			22			848			(144	)
NET INCOME	$	2,219		$	2,239		$	7,367		$	6,828

CONDENSED STATEMENTS OF RETAINED EARNINGS

For the Three and Nine Months Ended September 30, 2006 and 2005

(Unaudited)

(in thousands)

	Three Months Ended				Nine Months Ended
	2006		2005		2006		2005
BALANCE AT BEGINNING OF PERIOD	$	27,176	$	26,947	$	26,038	$	24,237
Net Income		2,219		2,239		7,367		6,828
Cash Dividends Declared		-		3,015		4,010		4,894
BALANCE AT END OF PERIOD	$	29,395	$	26,171	$	29,395	$	26,171

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(Unaudited)

(in thousands)

	2006		2005
CURRENT ASSETS
Accounts Receivable - Affiliated Companies	$	24,356	$	29,671
Fuel		24,139		14,897
Materials and Supplies		7,913		7,017
Accrued Tax Benefits		2,009		2,074
Prepayments and Other		105		9
TOTAL		58,522		53,668
PROPERTY, PLANT AND EQUIPMENT
Electric - Production		686,025		684,721
Other		2,385		2,369
Construction Work in Progress		11,391		12,252
Total		699,801		699,342
Accumulated Depreciation and Amortization		393,529		382,925
TOTAL - NET		306,272		316,417
Noncurrent Assets		7,738		6,618
TOTAL ASSETS	$	372,532	$	376,703

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

CONDENSED BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006		2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	14,938	$	35,131
Accounts Payable:
General		1,311		926
Affiliated Companies		21,018		22,161
Long-term Debt Due Within One Year		-		44,828
Accrued Taxes		5,880		3,055
Accrued Rent - Rockport Plant Unit 2		23,427		4,963
Other		805		1,228
TOTAL		67,379		112,292
NONCURRENT LIABILITIES
Long-term Debt		44,835		-
Deferred Income Taxes		20,852		23,617
Asset Retirement Obligations		1,399		1,370
Regulatory Liabilities and Deferred Investment Tax Credits		82,331		82,689
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		90,155		94,333
Obligations Under Capital Leases		11,752		11,930
TOTAL		251,324		213,939
TOTAL LIABILITIES		318,703		326,231
Commitments and Contingencies (Note 5)
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		29,395		26,038
TOTAL		53,829		50,472
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	372,532	$	376,703

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	7,367		$	6,828
Adjustments for Noncash Items:
Depreciation and Amortization		17,858			17,901
Deferred Income Taxes		(3,468	)		(3,539	)
Deferred Investment Tax Credits		(2,482	)		(2,501	)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		(4,178	)		(4,178	)
Deferred Property Taxes		(893	)		(1,010	)
Changes in Other Noncurrent Assets		(2,885	)		(1,736	)
Changes in Other Noncurrent Liabilities		2,776			2,201
Changes in Components of Working Capital:
Accounts Receivable		5,315			(2,469	)
Fuel, Materials and Supplies		(10,138	)		4,278
Accounts Payable		(758	)		(1,188	)
Accrued Taxes, Net		2,890			(2,982	)
Rent Accrued - Rockport Plant Unit 2		18,464			18,464
Other Current Assets		(96	)		(17	)
Other Current Liabilities		(423	)		(363	)
Net Cash Flows From Operating Activities		29,349			29,689
INVESTING ACTIVITIES
Construction Expenditures		(4,978	)		(9,041	)
FINANCING ACTIVITIES
Change in Advances from Affiliates, Net		(20,193	)		(15,601	)
Principal Payments for Capital Lease Obligations		(168	)		(153	)
Dividends Paid		(4,010	)		(4,894	)
Net Cash Flows Used For Financing Activities		(24,371	)		(20,648	)
Net Change in Cash and Cash Equivalents		-			-
Cash and Cash Equivalents at Beginning of Period		-			-
Cash and Cash Equivalents at End of Period	$	-		$	-
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	2,413		$	2,104
Net Cash Paid for Income Taxes		6,037			11,025
Noncash Acquisitions Under Capital Leases		78			31

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to AEGCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the 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
Company-wide Staffing and Budget Review	Note 7
Business Segments	Note 11
Financing Activities	Note 12

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Allocation Agreement between AEP East companies and AEP West companies

Under the Texas Restructuring Legislation, we are completing the final stage of exiting the generation business and have ceased serving retail load. Based on the corporate separation and generation divestiture activities underway, the nature of our business is no longer compatible with our participation in the CSW Operating Agreement and the SIA since these agreements involve the coordinated planning and operation of power supply facilities. Accordingly, on behalf of the AEP East companies and the AEP West companies, AEPSC filed with the FERC to remove us from those agreements. The FERC approved the filing in March 2006. The SIA includes a methodology for sharing trading and marketing margins among the AEP East companies and the AEP West companies. Our sharing of margins ceased effective May 1, 2006, which affects our future results of operations and cash flows. We will continue to have margin and collateral deposits, risk management assets and liabilities and trading gains or losses to the extent that we have contracts dedicated specifically to us. As of September 30, 2006, we have no dedicated contracts.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	40
Changes in Gross Margin:
Texas Supply	(4	)
Texas Wires	(1	)
Off-system Sales	(18	)
Transmission Revenues	(3	)
Other	(3	)
Total Change in Gross Margin				(29	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	1
Carrying Costs Income	10
Other Income	(7	)
Interest Expense	(11	)
Total Change in Operating Expenses and Other				(7	)
Income Tax Expense				13
Third Quarter of 2006			$	17

Net Income decreased $23 million to $17 million in 2006. The key drivers of the decrease were a $29 million decrease in Gross Margin and a $7 million increase in Operating Expenses and Other, partially offset by a reduction in Income Tax Expense of $13 million. We substantially exited the generation market with the sale of STP in May 2005.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Texas Supply margins decreased $4 million primarily due to lower nonaffiliated sales of $3 million.

· Margins from Off-system Sales decreased $18 million due to an $11 million decrease in margin sharing under the SIA (no current margin sharing under the CSW Operating Agreement and the SIA) and a $7 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $3 million primarily due to lower ERCOT transmission rates and reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.

· Other revenues decreased $3 million primarily due to lower securitization revenues of $3 million. Securitization revenues represent amounts collected to recover securitization bond principal and interest payments related to our securitized transition assets and are fully offset by amortization and interest expenses.

Operating Expenses and Other changed between years as follows:

· Carrying Costs Income increased $10 million primarily due to a negative adjustment of $8 million made in the third quarter of 2005 related to our True-up Proceeding orders received from the PUCT.

· Other Income decreased $7 million primarily due to interest income recorded in the prior year related to the 2005 Texas Court of Appeals order (see “Texas Restructuring - Excess Earnings” section of Note 4).

· Interest Expense increased $11 million primarily due to a $9 million increase in accrued interest related to the Texas competition transition charge liability (See “Texas Restructuring - CTC Proceeding for Other True-up Items” section of Note 4).

Income Taxes

The decrease in Income Tax Expense of $13 million is primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	70
Changes in Gross Margin:
Texas Supply	(78	)
Texas Wires	14
Off-system Sales	(21	)
Transmission Revenues	(12	)
Other	(9	)
Total Change in Gross Margin				(106	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	50
Depreciation and Amortization	(6	)
Taxes Other Than Income Taxes	6
Carrying Costs Income	35
Other Income	(13	)
Interest Expense	(8	)
Total Change in Operating Expenses and Other				64
Income Tax Expense				10
Nine Months Ended September 30, 2006			$	38

Net Income decreased $32 million to $38 million in 2006. The key driver of the decrease was a $106 million decrease in Gross Margin, partially offset by a reduction in Other Operation and Maintenance expenses of $50 million and increased Carrying Costs Income of $35 million. We substantially exited the generation market with the sale of STP in May 2005.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Texas Supply margins decreased $78 million primarily due to the sale of STP, which resulted in lower nonaffiliated sales of $101 million and a $6 million provision for refund primarily due to the fuel reconciliation adjustment in 2005. These decreases were partially offset by lower fuel and purchased power expenses of $30 million.

· Texas Wires revenues increased $14 million primarily due to favorable prices and a five percent increase in degree days.

· Margins from Off-system Sales decreased $21 million due to a $15 million decrease in margin sharing under the SIA and a $6 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $12 million primarily due to lower ERCOT transmission rates and reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.

· Other revenues decreased $9 million primarily due to lower third party construction project revenues of $4 million related to work performed for the Lower Colorado River Authority and reduced securitization revenues of $6 million. Securitization revenues represent amounts collected to recover securitization bond principal and interest payments related to our securitized transition assets and are fully offset by amortization and interest expenses.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $50 million primarily due to a $12 million decrease in plant operations, a $14 million decrease in plant maintenance, a $6 million decrease in administrative and general expenses and the absence of $7 million in accretion expense all related to the sale of STP. An additional $4 million decrease resulted from lower expenses related to construction activities performed for third parties, primarily the Lower Colorado River Authority.

· Depreciation and Amortization expense increased $6 million primarily related to the refund and amortization of excess earnings credits in 2005 partially offset by the recovery and amortization of securitized assets.

· Taxes Other Than Income Taxes decreased $6 million primarily due to lower property-related taxes as a result of the sale of STP in 2005 and the favorable settlement of a state use tax audit in 2006.

· Carrying Costs Income increased $35 million primarily due to negative adjustments of $29 million and $8 million made in the first and third quarters of 2005, respectively, related to our True-up Proceeding orders received from the PUCT.

· Other Income decreased $13 million primarily due to interest income recorded in the prior year related to the 2005 Texas Court of Appeals order (See “Texas Restructuring - Excess Earnings” section of Note 4).

· Interest Expense increased $8 million primarily due to a $12 million increase in accrued interest related to the Texas CTC liability (see “Texas Restructuring - CTC Proceeding for Other True-up Items” section of Note 4) partially offset by a $2 million decrease in interest expense associated with securitization revenues.

Income Taxes

The decrease in Income Tax Expense of $10 million is primarily due to a decrease in pretax book income, offset in part by tax reserve adjustments, a decrease in the amortization of investment tax credits due to the sale in May 2005 of STP and a decrease in consolidated tax savings from AEP.

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, 2006 and 2005 were as follows:

	2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	-		$	26
Net Cash Flows From (Used For):
Operating Activities		137,471			(95,431	)
Investing Activities		(197,269	)		293,461
Financing Activities		59,803			(198,053	)
Net Increase (Decrease) in Cash and Cash Equivalents		5			(23	)
Cash and Cash Equivalents at End of Period	$	5		$	3

Operating Activities

Net Cash Flows From Operating Activities were $137 million during the first nine months of 2006. We produced Net Income of $38 million during the period and incurred noncash items of $111 million for Depreciation and Amortization and $(65) million for Carrying Costs on Stranded Cost Recovery. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items; the most significant are decreases in Accounts Receivable, Net partially offset by a decrease in Accounts Payable. Accounts Receivable, Net decreased $159 million primarily due to cash received for the retail clawback of $61 million and 2005 storm restoration performed for nonaffiliated companies of $12 million. In addition, our removal from the SIA and CSW Operating Agreement effective May 1, 2006 resulted in fewer energy-related receivables. Accounts Payable decreased $108 million primarily due to lower energy-related transactions resulting from our removal from the SIA and CSW Operating Agreement.

Net Cash Flows Used For Operating Activities were $95 million during 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 activity in these asset and liability accounts relate to a number of items; the most significant is a decrease in Accrued Taxes, Net. Accrued Taxes, Net decreased $111 million primarily as a result of taxes remitted to the government related to prior year and current year tax accruals.

Investing Activities

Net Cash Flows Used For Investing Activities in 2006 were $197 million primarily due to $203 million of Construction Expenditures focused mainly on improved service reliability projects for transmission and distribution systems. For the remainder of 2006, we expect $83 million in Construction Expenditures.

Net Cash Flows From Investing Activities in 2005 were $293 million primarily due to $314 million of net proceeds from the sale of the STP nuclear plant and a reduction in Other Cash Deposits, Net of $93 million primarily for the retirement of defeased first mortgage bonds of $66 million. These cash inflows were partially offset by cash used for construction expenditures of $109 million related to projects for transmission and distribution service reliability.

Financing Activities

Net Cash Flows From Financing Activities in 2006 were $60 million primarily due to the issuance of $195 million of affiliated notes with AEP. This increase in long-term debt was partially offset by a decrease in Advances from Affiliates, Net of $82 million and the retirement of $52 million of securitization bonds.

Net Cash Flows Used for Financing Activities in 2005 were $198 million 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.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Notes Payable - Affiliated	$	125,000	5.14	2007
Notes Payable - Affiliated		70,000	5.86	2007

Retirements

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Securitization Bonds	$	52,265	5.01	2010

In October 2006 TCC issued $1.74 billion in securitization bonds, as follows:

Principal		Interest	Scheduled Final
Amount		Rate	Payment Date
	(in thousands)	(%)
$	217,000	4.98	2010
	341,000	4.98	2013
	250,000	5.09	2015
	437,000	5.17	2018
	494,700	5.3063	2020

The proceeds will generally be used to retire TCC debt and equity, which are no longer needed to support stranded costs.

In October 2006, we retired $345 million in intercompany notes payable as follows:

Principal Amount		Interest	Due
		Rate	Date
	(in thousands)	(%)
$	150,000	4.58	2007
	125,000	5.14	2007
	70,000	5.86	2007

In November 2006, $100.6 million of pollution control bonds were put back to TCC on the put date of November 1, 2006. TCC intends to hold these bonds for reissuance at a later date.

In October 2006, we also paid a special dividend of $585 million to AEP.

Liquidity

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

We will use proceeds received from the securitization to pay down a portion of our equity and debt and to pay any necessary accelerated refunds related to the CTC (discussed below under Texas Restructuring).

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed above.

Significant Factors

Texas Restructuring

In June 2006, we filed to implement a CTC refund of $357 million for our other true-up items over eight years. The differences between the components of our Recorded Net Regulatory Liabilities - Other True-up Items as of September 30, 2006 (including interest) and our Net CTC Refund Proposed are detailed below:

	(in millions)
Wholesale Capacity Auction True-up	$	61
Carrying Costs on Wholesale Capacity Auction True-up		31
Retail Clawback including Carrying Costs		(65	)
Deferred Over-recovered Fuel Balance		(184	)
Retrospective ADFIT Benefit		(77	)
Other		(4	)
Recorded Net Regulatory Liabilities - Other True-up Items		(238	)
Unrecorded Prospective ADFIT Benefit		(240	)
Gross CTC Refund Proposed		(478	)
FERC Jurisdictional Fuel Refund Deferral		16
ADITC and EDFIT Benefit Refund Deferral		98
Net CTC Refund Proposed, After Deferrals		(364	)
True-up Proceeding Expense Surcharge		7
Net CTC Refund Proposed, After Deferrals and Expenses	$	(357	)

In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that we began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) to residential customers by the end of 2006. The CTC refund to the other customer classes during the interim period will be as proposed by us, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with our request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Municipal customers and other intervenors appealed the PUCT orders seeking to further reduce our true-up recoveries. If we determine, as a result of future PUCT orders or appeal court rulings, that it is probable we cannot recover a portion of our recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. We appealed the PUCT orders seeking relief in both state and federal court where we believe the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law.  The significant items appealed by TCC are:

· the PUCT ruled that TCC did not comply with the statute and PUCT rules regarding the auction of 15% of its Texas jurisdictional installed capacity,

· that TCC acted in a manner that was commercially unreasonable because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled gas units with the sale of its coal unit,

· and two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation.

These appeals could take years to resolve and could result in material effects on future results of operations. If the PUCT rejects our deferral proposal and a normalization violation occurs, future results of operations and cash flows could be adversely affected by the recapture of $104 million of our ADITC and the loss of future accelerated tax depreciation election. The estimated future impact on earnings of the Texas Restructuring as of September 30, 2006, exclusive of a possible normalization violation and any effects of appeal litigation, over the 14-year securitization net recovery period assuming the PUCT approves our CTC filing, including the interim refund, is detailed below:

	(in millions)
ADITC and EDFIT Benefits Reducing Securitization	$	98
ADFIT Benefit Applied to Reduce 2002 Securitization of Regulatory Assets		(60	)
Securitization Settlement		(77	)
Unrecorded Prospective ADFIT Benefit Increasing the CTC Refund		(240	)
Unrecorded Equity Carrying Costs Recognized as Collected		224
Future Interest Payable on Proposed CTC Refund		(19	)
Deferred Fuel - Federal Jurisdictional Issue		16
Net Adverse Earnings Impact Over 14 Years	$	(58	)

If the PUCT changes its oral decision regarding the proposed CTC deferral and the two contingent federal matters are refunded to customers, the future adverse impact on results of operations over the next 14 years will increase to $181 million. This potential adverse impact on results of operations over the next 14 years would be more than offset by the annual cost of money benefit from the $2.2 billion in net proceeds that resulted from the sale of bonds in connection with the initial regulatory asset securitization in 2002 of $797 million and from the $1.74 billion sale of securitization bonds in October 2006 less the proposed $357 million CTC refund over the next eight years.

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

Our MTM Risk Management Contract Net Assets are zero as of September 30, 2006. For further explanation, see “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.

The following table summarizes the reasons for changes in our total MTM value as compared to December 31, 2005.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	5,426
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(1,175	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		-
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts		-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		(3,868	)
Changes Due to SIA and CSW Operating Agreement (c)		(383	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		-
Total MTM Risk Management Contract Net Assets		-
Net Cash Flow Hedge Contracts		-
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	-

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.

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

Our MTM Risk Management Contracts Net Assets are zero as of September 30, 2006. Therefore, there is no maturity and source of fair value to report.

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

As a result of changes made to the Allocation Agreement between AEP East companies and AEP West companies in the second quarter of 2006, we are no longer exposed to market fluctuations in energy commodity prices. Therefore, we have no contracts designated as cash flow hedges on our September 30, 2006 Condensed Consolidated Balance Sheet.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power
Beginning Balance in AOCI December 31, 2005	$	(224	)
Changes in Fair Value		-
Impact Due to Changes in SIA (a)		218
Reclassifications from AOCI to Net Income for Cash Flow    Hedges Settled		6
Ending Balance in AOCI September 30, 2006	$	-

(a) See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$-	$11	$2	$-	$111	$184	$88	$32

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $70 million and $93 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	162,902		$	192,932		$	435,801		$	559,822
Sales to AEP Affiliates		1,559			2,528			4,703			12,794
Other - Nonaffiliated		9,462			7,905			30,196			34,432
TOTAL		173,923			203,365			470,700			607,048
EXPENSES
Fuel and Other Consumables for Electric Generation		2,006			1,915			4,728			12,047
Purchased Electricity for Resale		725			1,691			3,557			27,057
Other Operation		61,057			64,408			183,241			221,741
Maintenance		10,679			8,782			27,255			38,254
Depreciation and Amortization		40,298			40,342			110,848			105,062
Taxes Other Than Income Taxes		23,387			22,828			60,421			66,282
TOTAL		138,152			139,966			390,050			470,443
OPERATING INCOME		35,771			63,399			80,650			136,605
Other Income (Expense):
Interest Income		560			8,295			1,592			15,722
Carrying Costs Income		25,443			15,349			65,279			30,146
Allowance for Equity Funds Used During Construction		667			(59	)		1,671			641
Interest Expense		(36,746	)		(25,374	)		(93,401	)		(85,095	)
INCOME BEFORE INCOME TAXES		25,695			61,610			55,791			98,019
Income Tax Expense		8,460			21,134			17,808			28,038
NET INCOME		17,235			40,476			37,983			69,981
Preferred Stock Dividend Requirements		60			60			181			181
EARNINGS APPLICABLE TO COMMON STOCK	$	17,175		$	40,416		$	37,802		$	69,800

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

      See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
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
DECEMBER 31, 2005	$	55,292	$	132,606	$	760,884		$	(1,152	)	$	947,630
Preferred Stock Dividends						(181	)					(181	)
TOTAL												947,449
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $121									224			224
NET INCOME						37,983						37,983
TOTAL COMPREHENSIVE INCOME												38,207
SEPTEMBER 30, 2006	$	55,292	$	132,606	$	798,686		$	(928	)	$	985,656

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	5		$	-
Other Cash Deposits		41,728			66,153
Advances to Affiliates		25,304			-
Accounts Receivable:
Customers		65,875			209,957
Affiliated Companies		8,633			23,486
Accrued Unbilled Revenues		25,350			25,606
Allowance for Uncollectible Accounts		(217	)		(143	)
Total Accounts Receivable		99,641			258,906
Unbilled Construction Costs		6,352			19,440
Materials and Supplies		24,995			13,897
Risk Management Assets		-			14,311
Prepayments and Other		5,645			5,231
TOTAL		203,670			377,938
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission		900,774			817,351
Distribution		1,559,593			1,476,683
Other		232,023			233,361
Construction Work in Progress		126,418			129,800
Total		2,818,808			2,657,195
Accumulated Depreciation and Amortization		637,517			636,078
TOTAL - NET		2,181,291			2,021,117
OTHER NONCURRENT ASSETS
Regulatory Assets		1,710,352			1,688,787
Securitized Transition Assets		557,520			593,401
Long-term Risk Management Assets		-			11,609
Employee Benefits and Pension Assets		112,594			114,733
Deferred Charges and Other		57,276			53,011
TOTAL		2,437,742			2,461,541
Assets Held for Sale - Texas Generation Plants		45,863			44,316
TOTAL ASSETS	$	4,868,566		$	4,904,912

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006			2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	-		$	82,080
Accounts Payable:
General		20,889			82,666
Affiliated Companies		18,160			65,574
Long-term Debt Due Within One Year - Nonaffiliated		153,364			152,900
Long-term Debt Due Within One Year - Affiliated		345,000			-
Risk Management Liabilities		-			13,024
Accrued Taxes		74,887			54,566
Accrued Interest		16,011			32,497
Other		32,500			45,927
TOTAL		660,811			529,234
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		1,498,031			1,550,596
Long-term Debt - Affiliated		-			150,000
Long-term Risk Management Liabilities		-			7,857
Deferred Income Taxes		1,014,840			1,048,372
Regulatory Liabilities and Deferred Investment Tax Credits		684,566			652,143
Deferred Credits and Other		18,723			13,140
TOTAL		3,216,160			3,422,108
TOTAL LIABILITIES		3,876,971			3,951,342
Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,939			5,940
Commitments and Contingencies (Note 5)
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		798,686			760,884
Accumulated Other Comprehensive Income (Loss)		(928	)		(1,152	)
TOTAL		985,656			947,630
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,868,566		$	4,904,912

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	37,983		$	69,981
Adjustments for Noncash Items:
Depreciation and Amortization		110,848			105,062
Accretion of Asset Retirement Obligations		55			7,549
Deferred Income Taxes		5,770			(63,426	)
Carrying Costs on Stranded Cost Recovery		(65,279	)		(30,146	)
Mark-to-Market of Risk Management Contracts		5,426			(1,139	)
Over/Under Fuel Recovery		7,225			(2,000	)
Deferred Property Taxes		(8,296	)		(7,600	)
Change in Other Noncurrent Assets		17,653			(9,777	)
Change in Other Noncurrent Liabilities		(17,249	)		(1,390	)
Changes in Components of Working Capital:
Accounts Receivable, Net		159,265			(22,504	)
Fuel, Materials and Supplies		(11,508	)		(1,763	)
Accounts Payable		(107,505	)		(10,533	)
Customer Deposits		(6,461	)		12,844
Accrued Taxes, Net		16,387			(110,975	)
Accrued Interest		(16,486	)		(24,495	)
Other Current Assets		16,611			(13,709	)
Other Current Liabilities		(6,968	)		8,590
Net Cash Flows From (Used For) Operating Activities		137,471			(95,431	)
INVESTING ACTIVITIES
Construction Expenditures		(203,116	)		(109,372	)
Change in Other Cash Deposits, Net		25,068			93,427
Change in Advances to Affiliates, Net		(25,304	)		-
Purchases of Investment Securities		-			(154,364	)
Sales of Investment Securities		-			149,804
Proceeds from Sale of Assets		6,083			313,966
Net Cash Flows From (Used For) Investing Activities		(197,269	)		293,461
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		-			276,663
Issuance of Long-term Debt - Affiliated		195,000			150,000
Change in Advances from Affiliates, Net		(82,080	)		11,814
Retirement of Long-term Debt		(52,265	)		(486,007	)
Retirement of Preferred Stock		(1	)		-
Principal Payments for Capital Lease Obligations		(670	)		(342	)
Dividends Paid on Common Stock		-			(150,000	)
Dividends Paid on Cumulative Preferred Stock		(181	)		(181	)
Net Cash Flows From (Used For) Financing Activities		59,803			(198,053	)
Net Increase (Decrease) in Cash and Cash Equivalents		5			(23	)
Cash and Cash Equivalents at Beginning of Period		-			26
Cash and Cash Equivalents at End of Period	$	5		$	3
SUPPLEMENTAL DISCLOSURE
Cash Paid for Interest, Net of Capitalized Amounts	$	93,165		$	95,066
Net Cash Paid (Received) for Income Taxes		(2,764	)		207,079
Noncash Acquisitions Under Capital Leases		3,282			277
Construction Expenditures Included in Accounts Payable at September 30,		9,351			8,797

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to TCC’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the 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
Company-wide Staffing and Budget Review	Note 7
Acquisitions, Assets Held for Sale and Asset Impairments	Note 8
Benefit Plans	Note 9
Income Taxes	Note 10
Business Segments	Note 11
Financing Activities	Note 12

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Allocation Agreement between AEP East companies and AEP West companies

Under the Texas Restructuring Legislation, we are completing the final stage of exiting the generation business and have ceased serving retail load. Based on the corporate separation and generation divestiture activities underway, the nature of our business is no longer compatible with our participation in the CSW Operating Agreement and the SIA since these agreements involve the coordinated planning and operation of power supply facilities. Accordingly, on behalf of the AEP East companies and the AEP West companies, AEPSC filed with the FERC to remove us from those agreements. The FERC approved the filing in March 2006. The SIA includes a methodology for sharing trading and marketing margins among the AEP East companies and the AEP West companies. Our sharing of margins ceased effective May 1, 2006, which affects our future results of operations and cash flows. We will continue to have margin and collateral deposits, risk management assets and liabilities and trading gains or losses to the extent that we have contracts dedicated specifically to us.

AEP Texas North Generation Company, LLC

In the third quarter of 2006, we created a new wholly-owned subsidiary, AEP Texas North Generation Company, LLC (TNGC). Following the creation of this subsidiary, we transferred all of our mothballed generation assets and related liabilities to this new subsidiary, substantially completing the business separation requirement of the Texas Restructuring Legislation. Subsequently, TNGC became a participant in the Nonutility Money Pool. The creation of TNGC did not have a significant impact on our results of operations or financial condition.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	22
Changes in Gross Margin:
Texas Supply	(12	)
Texas Wires	(1	)
Off-system Sales	(10	)
Transmission Revenues	1
Total Change in Gross Margin				(22	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance				1
Income TaxExpense				7
Third Quarter of 2006			$	8

Net Income decreased $14 million to $8 million in 2006 primarily due to a decrease in Gross Margin of $22 million, partially offset by a reduction in Income Tax Expense of $7 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Texas Supply margins decreased $12 million primarily due to a $28 million decrease in dedicated energy and capacity sales, offset by $16 million of lower fuel and purchased power costs. This decrease in Texas Supply margins was affected by market conditions within ERCOT.

· Margins from Off-system Sales decreased $10 million due to a $5 million decrease in margin sharing under the SIA (no current margin sharing under the CSW Operating Agreement and the SIA) and a $5 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

Income Taxes

The decrease in Income Tax Expense of $7 million is primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	42
Changes in Gross Margin:
Texas Supply	(29	)
Texas Wires	(2	)
Off-system Sales	(11	)
Transmission Revenues	(5	)
Other	(39	)
Total Change in Gross Margin				(86	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	38
Interest Expense	1
Total Change in Operating Expenses and Other				39
Income TaxExpense				17
Nine Months Ended September 30, 2006			$	12

Net Income decreased $30 million to $12 million in 2006 primarily due to a decrease in Gross Margin of $86 million partially offset by a reduction in Other Operation and Maintenance expenses of $38 million and a reduction in Income Tax Expense of $17 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Texas Supply margins decreased $29 million primarily due to a $58 million decrease in dedicated energy and capacity sales, offset by $28 million of lower fuel and purchased power costs. This decrease in Texas Supply margins was affected by market conditions within ERCOT.

· Margins from Off-system Sales decreased $11 million due to a $6 million decrease in margin sharing under the SIA and a $5 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $5 million primarily due to reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.

· Other revenues decreased $39 million primarily resulting from the completion of certain third party construction projects related to work performed for the Lower Colorado River Authority.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $38 million primarily due to lower expenses related to the completion of certain third party construction projects related to work performed for the Lower Colorado River Authority.

Income Taxes

The decrease in Income Tax Expense of $17 million is primarily due to a decrease in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook, except for Fitch which has us on a negative outlook. Our current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	A3	BBB	A
Senior Unsecured Debt	Baa1	BBB	A-

Financing Activity

There were no long-term debt issuances or retirements during the first nine months of 2006.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt or refinance long-term debt maturities. In addition, TNC participates in the Utility Money Pool and TNGC participates in the Nonutility Money Pool, both of which provide access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end except for Energy and Capacity Purchase Contracts. We exited both the SIA and CSW Operating Agreement, eliminating our future obligation for Energy and Capacity Purchase Contracts. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed consolidated balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow Hedges			Total
Current Assets	$	-		$	-		$	-
Noncurrent Assets		-			-			-
Total MTM Derivative Contract Assets		-			-			-
Current Liabilities		(2,138	)		-			(2,138	)
Noncurrent Liabilities		-			(2,057	)		(2,057	)
Total MTM Derivative Contract Liabilities		(2,138	)		(2,057	)		(4,195	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	(2,138	)	$	(2,057	)	$	(4,195	)

MTM Risk Management Contract Net Assets (Liabilities)

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	2,698
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(585	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		-
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		(3,437	)
Changes Due to SIA and CSW Operating Agreement (c)		(814	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		-
Total MTM Risk Management Contract Net Assets (Liabilities)		(2,138	)
Net Cash Flow Hedge Contracts		(2,057	)
Total MTM Risk Management Contract Net Assets (Liabilities) at September 30, 2006	$	(4,195	)

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.

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

	Remainder 2006			2007		2008		2009		2010		After 2010		Total
Prices Actively Quoted - Exchange Traded Contracts	$	-		$	-	$	-	$	-	$	-	$	-	$	-
Prices Provided by Other External Sources - OTC Broker   Quotes (a)		(2,138	)		-		-		-		-		-		(2,138	)
Prices Based on Models and Other Valuation Methods (b)		-			-		-		-		-		-		-
Total	$	(2,138	)	$	-	$	-	$	-	$	-	$	-	$	(2,138	)

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power
Beginning Balance in AOCI December 31, 2005	$	(111	)
Changes in Fair Value		(1,337	)
Impact Due to Change in SIA (a)		98
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		13
Ending Balance in AOCI September 30, 2006	$	(1,337	)

(a) See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is zero.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$-	$23	$4	$-	$55	$92	$44	$16

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $11 million and $13 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	79,805		$	111,107		$	219,681		$	280,195
Sales to AEP Affiliates		7,711			13,019			25,596			37,189
Other		246			1,971			149			42,324
TOTAL		87,762			126,097			245,426			359,708
EXPENSES
Fuel and Other Consumables for Electric Generation		14,016			13,433			33,175			37,772
Purchased Electricity for Resale		14,606			34,425			60,343			88,367
Purchased Electricity from AEP Affiliates		2,436			1			3,978			23
Other Operation		19,003			18,878			59,192			97,135
Maintenance		5,088			5,954			15,505			15,093
Depreciation and Amortization		10,767			10,435			31,172			30,952
Taxes Other Than Income Taxes		5,478			6,047			16,874			17,465
TOTAL		71,394			89,173			220,239			286,807
OPERATING INCOME		16,368			36,924			25,187			72,901
Other Income (Expense):
Interest Income		203			890			542			1,688
Allowance for Equity Funds Used During Construction		146			137			636			366
Interest Expense		(4,472	)		(4,931	)		(13,351	)		(14,784	)
INCOME BEFORE INCOME TAXES		12,245			33,020			13,014			60,171
Income Tax Expense		3,799			10,716			1,326			18,469
NET INCOME		8,446			22,304			11,688			41,702
Preferred Stock Dividend Requirements		26			26			78			78
Gain on Reacquired Preferred Stock		-			-			2			-
EARNINGS APPLICABLE TO COMMON STOCK	$	8,420		$	22,278		$	11,612		$	41,624

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

      See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	137,214	$	2,351	$	170,984		$	(128	)	$	310,421
Common Stock Dividends						(20,827	)					(20,827	)
Preferred Stock Dividends						(78	)					(78	)
TOTAL												289,516
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $698									(1,296	)		(1,296	)
NET INCOME						41,702						41,702
TOTAL COMPREHENSIVE INCOME												40,406
SEPTEMBER 30, 2005	$	137,214	$	2,351	$	191,781		$	(1,424	)	$	329,922
DECEMBER 31, 2005	$	137,214	$	2,351	$	174,858		$	(504	)	$	313,919
Common Stock Dividends						(12,750	)					(12,750	)
Preferred Stock Dividends						(78	)					(78	)
Gain on Reacquired Preferred Stock						2						2
TOTAL												301,093
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $660									(1,226	)		(1,226	)
NET INCOME						11,688						11,688
TOTAL COMPREHENSIVE INCOME												10,462
SEPTEMBER 30, 2006	$	137,214	$	2,351	$	173,720		$	(1,730	)	$	311,555

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	-		$	-
Other Cash Deposits		9,087			1,432
Advances to Affiliates		4,383			34,286
Accounts Receivable:
Customers		23,367			77,678
Affiliated Companies		11,910			26,149
Accrued Unbilled Revenues		2,567			5,016
Allowance for Uncollectible Accounts		(24	)		(18	)
Total Accounts Receivable		37,820			108,825
Fuel		5,528			2,636
Materials and Supplies		8,459			6,858
Risk Management Assets		-			7,114
Prepayments and Other		1,537			3,772
TOTAL		66,814			164,923
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		290,391			288,934
Transmission		324,724			289,029
Distribution		507,307			492,878
Other		165,403			167,849
Construction Work in Progress		31,991			46,424
Total		1,319,816			1,285,114
Accumulated Depreciation and Amortization		486,131			478,519
TOTAL - NET		833,685			806,595
OTHER NONCURRENT ASSETS
Regulatory Assets		8,920			9,787
Long-term Risk Management Assets		-			5,772
Employee Benefits and Pension Assets		45,409			46,289
Deferred Charges and Other		7,153			10,468
TOTAL		61,482			72,316
TOTAL ASSETS	$	961,981		$	1,043,834

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006			2005
CURRENT LIABILITIES	(in thousands)
Accounts Payable:
General	$	9,151		$	19,739
Affiliated Companies		27,854			84,923
Long-term Debt Due Within One Year - Nonaffiliated		8,151			-
Risk Management Liabilities		2,138			6,475
Accrued Taxes		29,458			21,212
Other		11,203			21,050
TOTAL		87,955			153,399
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		268,762			276,845
Long-term Risk Management Liabilities		2,057			3,906
Deferred Income Taxes		123,991			132,335
Regulatory Liabilities and Deferred Investment Tax Credits		143,506			139,732
Deferred Credits and Other		21,806			21,341
TOTAL		560,122			574,159
TOTAL LIABILITIES		648,077			727,558
Cumulative Preferred Stock Not Subject to Mandatory Redemption		2,349			2,357
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - $25 Par Value Per Share:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares		137,214			137,214
Paid-in Capital		2,351			2,351
Retained Earnings		173,720			174,858
Accumulated Other Comprehensive Income (Loss)		(1,730	)		(504	)
TOTAL		311,555			313,919
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	961,981		$	1,043,834

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	11,688		$	41,702
Adjustments for Noncash Items:
Depreciation and Amortization		31,172			30,952
Deferred Income Taxes		(4,667	)		(313	)
Mark-to-Market of Risk Management Contracts		4,836			(452	)
Deferred Property Taxes		(4,359	)		(4,072	)
Change in Other Noncurrent Assets		(5,173	)		(1,109	)
Change in Other Noncurrent Liabilities		(630	)		(71	)
Changes in Components of Working Capital:
Accounts Receivable, Net		71,005			9,366
Fuel, Materials and Supplies		(4,493	)		922
Accounts Payable		(66,653	)		16,834
Customer Deposits		(3,571	)		5,471
Accrued Taxes, Net		7,984			(10,097	)
Other Current Assets		2,496			11,189
Other Current Liabilities		(5,304	)		(551	)
Net Cash Flows From Operating Activities		34,331			99,771
INVESTING ACTIVITIES
Construction Expenditures		(52,366	)		(44,865	)
Change in Other Cash Deposits, Net		979			1,508
Change In Advances to Affiliates, Net		29,903			(36,147	)
Proceeds from Sale of Assets		250			1,033
Net Cash Flows Used For Investing Activities		(21,234	)		(78,471	)
FINANCING ACTIVITIES
Retirement of Preferred Stock		(6	)		-
Principal Payments for Capital Lease Obligations		(263	)		(180	)
Dividends Paid on Common Stock		(12,750	)		(20,827	)
Dividends Paid on Cumulative Preferred Stock		(78	)		(78	)
Net Cash Flows Used For Financing Activities		(13,097	)		(21,085	)
Net Increase in Cash and Cash Equivalents		-			215
Cash and Cash Equivalents at Beginning of Period		-			-
Cash and Cash Equivalents at End of Period	$	-		$	215
SUPPLEMENTAL DISCLOSURE
Cash Paid for Interest, Net of Capitalized Amounts	$	13,988		$	15,192
Net Cash Paid (Received) for Income Taxes		(252	)		30,486
Noncash Acquisitions Under Capital Leases		1,178			193
Construction Expenditures Included in Accounts Payable at September 30,		2,155			2,289

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

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

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	37
Changes in Gross Margin:
Retail Margins	(23	)
Off-system Sales	33
Transmission Revenues	(10	)
Other	16
Total Change in Gross Margin				16
Changes in Operating Expenses and Other:
Other Operation and Maintenance	6
Depreciation and Amortization	(11	)
Carrying Costs Income (Expense)	(29	)
Other Income	7
Interest Expense	(2	)
Total Change in Operating Expenses and Other				(29	)
Income Tax Expense				7
Third Quarter of 2006			$	31

Net Income decreased $6 million to $31 million in 2006. The key driver of the decrease was a $29 million net increase in Operating Expenses and Other offset by a net increase in Gross Margin of $16 million and a $7 million decrease in Income Tax Expense.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail Margins decreased $23 million in comparison to 2005 primarily due to:

· a $28 million decrease related to an increase in sharing of off-system sales margins with retail customers due to higher off-system sales. This sharing mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case. Retail Margins further decreased due to;

· a $13 million decrease in revenues related to financial transmission rights, net of congestion, primarily due to fewer transmission constraints in the PJM market partially offset by;

· a $19 million increase in fuel recovery caused by the activation of the West Virginia fuel clause in July 2006.

· Off-system Sales increased $33 million primarily due to $19 million increase in physical sales margins and an $18 million increase from lower sharing of off-system sales margins under the SIA slightly offset by a $3 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $10 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenue increased $16 million primarily due to a write off of previously deferred gains on sales of allowances associated with the Virginia Environmental and Reliability Costs (E&R) case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $6 million mainly due to a decrease in expenses associated with the Transmission Equalization Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006. This decrease was partially offset by a write off of deferred maintenance expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

· Depreciation and Amortization expenses increased $11 million primarily due to a write off of previously deferred depreciation expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

· Carrying Costs Income (Expense) decreased $29 million primarily due to a write off of previously recorded carrying costs income associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

· Other Income increased $7 million primarily due to interest income related to an increase in Advances to Affiliates and an increase in allowance for funds during construction (AFUDC).

Income Taxes

The decrease in Income Tax Expense of $7 million is primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis, offset in part by an increase in state income taxes.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	108
Changes in Gross Margin:
Retail Margins	12
Off-system Sales	34
Transmission Revenues	(27	)
Other	15
Total Change in Gross Margin				34
Changes in Operating Expenses and Other:
Other Operation and Maintenance	9
Depreciation and Amortization	(11	)
Taxes Other Than Income Taxes	1
Carrying Costs Income (Expense)	(19	)
Other Income	12
Interest Expense	(13	)
Total Change in Operating Expenses and Other				(21	)
Income Tax Expense				(7	)
Nine Months Ended September 30, 2006			$	114

Net Income increased $6 million to $114 million in 2006. The key driver of the increase was a $34 million net increase in Gross Margin offset by a $21 million net increase in Operating Expenses and Other and a $7 million increase in Income Tax Expense.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail Margins increased $12 million in comparison to 2005 primarily due to:

· a $16 million increase in retail revenues primarily related to two new industrial customers;

· a $14 million reduction in capacity settlement payments under the Interconnection Agreement due to our lower member load ratio (MLR) share and our increased generation capacity and;

· an $11 million increase in revenues related to financial transmission rights, net of congestion. The increase in financial transmission rights revenue is due to improved management of price risk related to serving retail load under current transmission constraints. Retail Margin increases were partially offset by;

 ·   a $28 million decrease related to an increase in sharing of off-system sales margins with retail customers due to higher off-system sales.  This sharing mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case.

· Off-system Sales increased $34 million primarily due to $42 million increase in physical sales margins and a $22 million increase from lower sharing of off-system sales margins under the SIA offset by a $30 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $27 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $5 million for potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenue increased $15 million primarily due to a write off of previously deferred gains on sales of allowances associated with the E&R case and higher gains on sales of allowances. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

 Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses decreased $9 million mainly due to a decrease in expenses associated with the Transmission Equalization Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006, partially offset by a write off of previously deferred maintenance expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

· Depreciation and Amortization expenses increased $11 million primarily due to a write off of previously deferred depreciation expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

· Carrying Costs Income (Expense) decreased $19 million primarily due to write off of previously recorded carrying costs income associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

· Other Income increased $12 million primarily due to interest income related to an increase in Advances to Affiliates and an increase in AFUDC.

· Interest Expense increased $13 million primarily due to long-term debt issuances in 2006, partially offset by an increase in allowance for borrowed funds used during construction and a write off of previously deferred AFUDC associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

Income Taxes

The increase in Income Tax Expense of $7 million is primarily due to an increase in pretax book income and state income taxes offset in part by changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	Baa2	BBB	BBB+

Cash Flow

Cash flows for the nine months ended September 30, 2006 and 2005 were as follows:

	2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,741		$	1,543
Net Cash Flows From (Used For):
Operating Activities		436,795			180,504
Investing Activities		(725,650	)		(479,420	)
Financing Activities		288,363			298,938
Net Increase (Decrease) in Cash and Cash Equivalents		(492	)		22
Cash and Cash Equivalents at End of Period	$	1,249		$	1,565

Operating Activities

Net Cash Flows From Operating Activities were $437 million in 2006. We produced Net Income of $114 million during the period and a noncash expense item of $158 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital had no significant items.

Net Cash Flows From Operating Activities were $181 million in 2005. We produced Net Income of $108 million during the period and a noncash expense item of $147 million for Depreciation and Amortization partially offset by Pension Contributions to Qualified Plan Trusts of $60 million. The other changes in assets and liabilities represent items that had a prior period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital had no significant items.

Investing Activities

Net Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect our construction expenditures of $633 million and $422 million, respectively. Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades for both periods. In 2006 and 2005, capital projects for transmission expenditures primarily relate to the Wyoming-Jacksons Ferry 765 kV line placed in service in June 2006. Environmental upgrades include the flue gas desulphurization (FGD) projects at the Amos and Mountaineer Plants. For the remainder of 2006, we expect $300 million of construction expenditures. In addition, we invested $94 million and $68 million into the Utility Money Pool in 2006 and 2005, respectively.

Financing Activities

Net Cash Flows From Financing Activities were $288 million in 2006. We issued $500 million in Senior Unsecured Notes and $50 million in Pollution Control Bonds. We also retired a First Mortgage Bond of $100 million. We repaid short-term borrowings from the Utility Money Pool of $194 million. In addition, we received funds of $68 million related to a long-term coal purchase contract amended in March 2006, partially offset by repayments of $18 million. See “Coal Contract Amendment” within “Significant Factors” for additional information.

Net Cash Flows From Financing Activities were $299 million in 2005. We issued four Senior Unsecured Notes totaling $850 million. We also issued Notes Payable - Affiliates of $100 million and received a capital contribution from our parent of $150 million. We retired $450 million of Senior Unsecured Notes and three First Mortgage Bonds totaling $125 million. In addition, we repaid $211 million of advances from the Utility Money Pool.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Senior Unsecured Notes	$	250,000	5.55	2011
Senior Unsecured Notes		250,000	6.375	2036
Pollution Control Bonds		50,275	Variable	2036

Retirements

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
First Mortgage Bonds	$	100,000	6.80	2006
Other Debt		8	13.718	2026

In November 2006, we issued $17.5 million of variable rate Pollution Control Bonds and retired $17.5 million, 2.70% pollution control bonds due in 2007.

In November 2006, we had a required remarketing of $30 million of 2.80% Pollution Control Bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new 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 2005 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed above.

Significant Factors

Coal Contract Amendment

We negotiated an amendment to a nonderivative coal contract that was assigned to a new owner of a coal supplier to which we were contractually obligated. The amended contract includes adjustments in the quantity related to the shortfall of tons in prior years, escalated tonnage deliveries in 2006 and a pricing change related to future coal deliveries. In March 2006, the new owner agreed to pay us $80 million for the settlement, release and amendment of the original contract. With respect to prior years’ undelivered coal, the new owner paid us $12 million for the shortfall tons. With respect to deliveries of coal in 2006-2007, the third party paid us the remaining $68 million for the agreed upon price increase.

The receipt of funds reduces the risk that the third party will short future deliveries. However, if they fail to deliver, we are not contractually obligated to repay any portion of the settlement payment. Our net coal price will not materially change from the original contract price as a result of the $68 million payment that we received for future coal deliveries through 2007.

Since there are no further requirements related to the liquidation of the shortfall tons, we recognized the $12 million shortfall payment in the first quarter of 2006. We recorded a $5 million reduction in Regulatory Assets on our Condensed Consolidated Balance Sheet and recorded the remaining $7 million as a reduction to Fuel and Other Consumables for Electric Generation on our Condensed Consolidated Statement of Income. We recorded the $68 million payment within Deferred Credits and Other on our Condensed Consolidated Balance Sheet. To the extent tons are received, payment of the higher contracted price per ton will effectively result in a repayment of funds to the coal supplier.

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed consolidated balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow & Fair Value Hedges			DETM Assignment (a)			Total
Current Assets	$	85,654		$	7,481		$	-		$	93,135
Noncurrent Assets		107,705			510			-			108,215
Total MTM Derivative Contract Assets		193,359			7,991			-			201,350
Current Liabilities		(64,432	)		(1,979	)		(1,881	)		(68,292	)
Noncurrent Liabilities		(70,002	)		(699	)		(9,138	)		(79,839	)
Total MTM Derivative Contract Liabilities		(134,434	)		(2,678	)		(11,019	)		(148,131	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	58,925		$	5,313		$	(11,019	)	$	53,219

(a) See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	56,407
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(6,079	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		121
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(315	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		316
Changes in Fair Value Due to Market Fluctuations During the Period (b)		6,107
Changes due to SIA Agreement (c)		(6,533	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		8,901
Total MTM Risk Management Contract Net Assets		58,925
Net Cash Flow & Fair Value Hedge Contracts		5,313
DETM Assignment (e)		(11,019	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	53,219

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006			2007			2008		2009		2010		After 2010		Total
Prices Actively Quoted - Exchange Traded Contracts	$	1,794		$	12,885		$	4,663	$	-	$	-	$	-	$	19,342
Prices Provided by Other External Sources - OTC Broker   Quotes (a)		4,076			11,246			4,922		7,304		-		-		27,548
Prices Based on Models and Other Valuation Methods (b)		(43	)		(4,690	)		1,149		4,648		8,331		2,640		12,035
Total	$	5,827		$	19,441		$	10,734	$	11,952	$	8,331	$	2,640	$	58,925

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

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

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

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power			Foreign Currency			Interest Rate			Total
Beginning Balance in AOCI December 31, 2005	$	(1,480	)	$	(171	)	$	(14,770	)	$	(16,421	)
Changes in Fair Value		4,482			-			4,951			9,433
Impact due to Changes in SIA (a)		(442	)		-			-			(442	)
Reclassifications from AOCI to Net Income for Cash Flow   Hedges Settled		2,261			5			1,757			4,023
Ending Balance in AOCI September 30, 2006	$	4,821		$	(166	)	$	(8,062	)	$	(3,407	)

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,919 thousand gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$655	$1,915	$683	$365	$732	$1,216	$579	$209

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $141 million and $142 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	588,684		$	468,558		$	1,612,735		$	1,380,928
Sales to AEP Affiliates		57,177			99,551			177,557			237,648
Other		2,740			2,013			7,338			6,343
TOTAL		648,601			570,122			1,797,630			1,624,919
EXPENSES
Fuel and Other Consumables for Electric Generation		184,275			161,154			506,368			402,057
Purchased Electricity for Resale		41,027			24,217			98,622			79,182
Purchased Electricity from AEP Affiliates		130,826			108,008			356,682			341,994
Other Operation		63,259			78,421			210,914			228,916
Maintenance		53,874			44,865			138,381			129,321
Depreciation and Amortization		61,160			50,284			157,518			146,734
Taxes Other Than Income Taxes		24,464			23,696			70,355			71,127
TOTAL		558,885			490,645			1,538,840			1,399,331
OPERATING INCOME		89,716			79,477			258,790			225,588
Other Income (Expense):
Interest Income		2,463			662			6,228			1,667
Carrying Costs Income (Expense)		(27,316	)		1,255			(13,532	)		5,320
Allowance for Equity Funds Used During Construction		6,748			1,791			13,307			6,559
Interest Expense		(27,103	)		(24,976	)		(89,024	)		(76,320	)
INCOME BEFORE INCOME TAXES		44,508			58,209			175,769			162,814
Income Tax Expense		13,972			20,837			61,992			54,557
NET INCOME		30,536			37,372			113,777			108,257
Preferred Stock Dividend Requirements Including Capital StockExpense and Other		238			238			714			1,940
EARNINGS APPLICABLE TO COMMON STOCK	$	30,298		$	37,134		$	113,063		$	106,317

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	260,458	$	722,314	$	508,618		$	(81,672	)	$	1,409,718
Capital Contribution From Parent				150,000								150,000
Preferred Stock Dividends						(600	)					(600	)
Capital Stock Expense and Other				2,485		(1,340	)					1,145
TOTAL												1,560,263
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $8,340									(15,490	)		(15,490	)
NET INCOME						108,257						108,257
TOTAL COMPREHENSIVE INCOME												92,767
SEPTEMBER 30, 2005	$	260,458	$	874,799	$	614,935		$	(97,162	)	$	1,653,030
DECEMBER 31, 2005	$	260,458	$	924,837	$	635,016		$	(16,610	)	$	1,803,701
Common Stock Dividends						(7,500	)					(7,500	)
Preferred Stock Dividends						(600	)					(600	)
Capital Stock Expense and Other				118		(114	)					4
TOTAL												1,795,605
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Taxof $7,007									13,014			13,014
NET INCOME						113,777						113,777
TOTAL COMPREHENSIVE INCOME												126,791
SEPTEMBER 30, 2006	$	260,458	$	924,955	$	740,579		$	(3,596	)	$	1,922,396

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	1,249		$	1,741
Advances to Affiliates		93,764			-
Accounts Receivable:
Customers		165,193			141,810
Affiliated Companies		126,586			153,453
Accrued Unbilled Revenues		29,073			51,201
Miscellaneous		4,326			527
Allowance for Uncollectible Accounts		(4,415	)		(1,805	)
Total Accounts Receivable		320,763			345,186
Fuel		61,892			64,657
Materials and Supplies		54,286			54,967
Risk Management Assets		93,135			132,247
Accrued Tax Benefits		3,470			32,979
Regulatory Asset for Under-Recovered Fuel Costs		34,028			30,697
Prepayments and Other		13,230			44,432
TOTAL		675,817			706,906
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		2,836,442			2,798,157
Transmission		1,595,963			1,266,855
Distribution		2,218,402			2,141,153
Other		336,999			323,158
Construction Work in Progress		784,644			647,638
Total		7,772,450			7,176,961
Accumulated Depreciation and Amortization		2,458,665			2,524,855
TOTAL - NET		5,313,785			4,652,106
OTHER NONCURRENT ASSETS
Regulatory Assets		419,891			457,294
Long-term Risk Management Assets		108,215			176,231
Deferred Charges and Other		237,113			261,556
TOTAL		765,219			895,081
TOTAL ASSETS	$	6,754,821		$	6,254,093

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006			2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	-		$	194,133
Accounts Payable:
General		274,165			230,570
Affiliated Companies		113,461			85,941
Long-term Debt Due Within One Year - Nonaffiliated		141,696			146,999
Risk Management Liabilities		68,292			121,165
Customer Deposits		56,263			79,854
Accrued Taxes		63,395			49,833
Accrued Interest		59,394			28,614
Other		86,917			80,132
TOTAL		863,583			1,017,241
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		2,356,175			1,904,379
Long-term Debt - Affiliated		100,000			100,000
Long-term Risk Management Liabilities		79,839			147,117
Deferred Income Taxes		937,835			952,497
Regulatory Liabilities and Deferred Investment Tax Credits		315,346			201,230
Deferred Credits and Other		161,884			110,144
TOTAL		3,951,079			3,415,367
TOTAL LIABILITIES		4,814,662			4,432,608
Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,763			17,784
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares		260,458			260,458
Paid-in Capital		924,955			924,837
Retained Earnings		740,579			635,016
Accumulated Other Comprehensive Income (Loss)		(3,596	)		(16,610	)
TOTAL		1,922,396			1,803,701
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,754,821		$	6,254,093

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	113,777		$	108,257
Adjustments for Noncash Items:
Depreciation and Amortization		157,518			146,734
Deferred Income Taxes		(7,753	)		25,103
Carrying Costs (Income) Expense		13,532			(5,320	)
Mark-to-Market of Risk Management Contracts		(3,817	)		(21,412	)
Pension Contributions to Qualified Plan Trusts		-			(59,812	)
Over/Under Fuel Recovery, Net		830			(21,001	)
Change in Other Noncurrent Assets		8,466			361
Change in Other Noncurrent Liabilities		20,187			(10,306	)
Changes in Components of Working Capital:
Accounts Receivable, Net		24,423			2,899
Fuel, Materials and Supplies		3,446			(7,467	)
Margin Deposits		27,103			(38,634	)
Accounts Payable		22,063			54,994
Customer Deposits		(23,591	)		52,302
Accrued Taxes, Net		43,071			(39,022	)
Accrued Interest		30,780			15,467
Other Current Assets		4,972			(20,482	)
Other Current Liabilities		1,788			(2,157	)
Net Cash Flows From Operating Activities		436,795			180,504
INVESTING ACTIVITIES
Construction Expenditures		(633,164	)		(421,544	)
Change in Other Cash Deposits, Net		(873	)		(24	)
Change in Advances to Affiliates, Net		(93,764	)		(67,532	)
Proceeds from Sales of Assets		2,151			9,680
Net Cash Flows Used For Investing Activities		(725,650	)		(479,420	)
FINANCING ACTIVITIES
Capital Contributions from Parent		-			150,000
Issuance of Long-term Debt - Nonaffiliated		544,364			840,469
Issuance of Long-term Debt - Affiliated		-			100,000
Change in Advances from Affiliates, Net		(194,133	)		(211,060	)
Retirement of Long-term Debt - Nonaffiliated		(100,008	)		(575,007	)
Retirement of Preferred Stock		(16	)		-
Principal Payments for Capital Lease Obligations		(4,008	)		(4,864	)
Funds From Amended Coal Contract, Net		50,264			-
Dividends Paid on Common Stock		(7,500	)		-
Dividends Paid on Cumulative Preferred Stock		(600	)		(600	)
Net Cash Flows From Financing Activities		288,363			298,938
Net Increase (Decrease) in Cash and Cash Equivalents		(492	)		22
Cash and Cash Equivalents at Beginning of Period		1,741			1,543
Cash and Cash Equivalents at End of Period	$	1,249		$	1,565
SUPPLEMENTAL DISCLOSURE
Cash Paid for Interest, Net of Capitalized Amounts	$	51,537		$	56,253
Net Cash Paid for Income Taxes		12,047			61,514
Noncash Acquisitions Under Capital Leases		2,598			1,087
Construction Expenditures Included in Accounts Payable at September 30,		131,692			54,380

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Financing Activities	Note 12

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	34
Changes in Gross Margin:
Retail Margins	36
Off-system Sales	20
Transmission Revenues	(6	)
Other	(2	)
Total Change in Gross Margin				48
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(2	)
Depreciation and Amortization	(14	)
Asset Impairments and Other Related Charges	39
Taxes Other Than Income Taxes	5
Carrying Costs Income	(1	)
Interest Expense	(2	)
Total Change in Operating Expenses and Other				25
Income Tax Expense				(23	)
Third Quarter of 2006			$	84

Net Income increased $50 million to $84 million in 2006. The key drivers of the increase were a $48 million increase in Gross Margin and a $39 million asset impairment of units 1 and 2 at our Conesville Plant in 2005, partially offset by a $23 million increase in Income Tax Expense and a $14 million increase in Depreciation and Amortization.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emission allowances, and purchased power, were as follows:

· Retail Margins were $36 million higher than the prior period primarily due to Rate Stabilization Plan (RSP) and Transition Regulatory Asset rate increases effective January 1, 2006 as well as the addition of Monongahela Power’s Ohio customers on December 31, 2005, partially offset by an increase in delivered fuel costs.

· Off-system Sales increased $20 million primarily due to $13 million increase in physical sales margins and a $10 million increase from lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $6 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

Operating Expenses and Other changed between years as follows:

· Depreciation and Amortization expense increased $14 million due to the increase in the amortization of regulatory assets and a greater depreciable base resulting primarily from the acquisitions of the Waterford Plant and Monongahela Power’s Ohio assets in late 2005.

· Asset Impairments and Other Related Charges of $39 million were recorded last year due to the 2005 retirement of units 1 and 2 at our Conesville Plant.

· Taxes Other Than Income Taxes decreased $5 million due to favorable accrual adjustments to property taxes in 2006 and unfavorable accrual adjustments in 2005 partially offset by the increase in property taxes associated with the Waterford and Monongahela asset additions.

Income Tax

The increase of $23 million in Income Tax Expense is primarily due to an increase in pretax book income offset in part by a decrease in state income taxes.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	116
Changes in Gross Margin:
Retail Margins	93
Off-system Sales	29
Transmission Revenues	(13	)
Other	6
Total Change in Gross Margin				115
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(19	)
Depreciation and Amortization	(41	)
Asset Impairments and Other Related Charges	39
Taxes Other Than Income Taxes	(7	)
Carrying Costs Income	(6	)
Interest Expense	(8	)
Total Change in Operating Expenses and Other				(42	)
Income Tax Expense				(21	)
Nine Months Ended September 30, 2006			$	168

Net Income increased $52 million to $168 million in 2006. The key drivers of the increase were a $115 million increase in Gross Margin and a $39 million asset impairment of units 1 and 2 at our Conesville Plant in 2005, partially offset by a $41 million increase in Depreciation and Amortization, a $19 million increase in Other Operation and Maintenance and a $21 million increase in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emission allowances, and purchased power, were as follows:

· Retail Margins increased $93 million primarily due to the RSP and Transition Regulatory Asset rate increases effective January 1, 2006, lower capacity settlement costs, and the addition of Monongahela Power’s Ohio customers on December 31, 2005, partially offset by an increase in delivered fuel costs.

· Off-system Sales increased $29 million due to $30 million increase in physical sales margins and a $12 million increase from lower sharing of off-system sales margins under the SIA offset by a decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $13 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $3 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenues increased $6 million primarily due to higher gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance increased $19 million due to an increase in PJM administrative fees, an increase in transmission expenses related to the AEP Transmission Equalization Agreement, favorable adjustments in the prior year related to the corporate owned life insurance policy and increased expenses related to factored receivables and uncollectible accounts. The increases were partially offset by the recognition of a regulatory asset related to recent PUCO orders regarding distribution service reliability and restoration costs. 

· Depreciation and Amortization expense increased $41 million primarily due to the increase in the amortization of regulatory assets and a greater depreciable base resulting primarily from the acquisitions of the Waterford Plant and Monongahela Power’s Ohio assets. In addition, the 2005 RSP order resulted in a reversal of unused shopping credits of $18 million offset by the establishment of a $7 million regulatory liability to benefit low-income customers and for economic development.

· Asset Impairments and Other Related Charges in the amount of $39 million were recorded last year due to the 2005 retirement of units 1 and 2 at our Conesville Plant.

· Taxes Other Than Income Taxes increased $7 million due to the increase in property taxes associated with the Waterford and Monongahela asset additions partially offset by accrual adjustments to property taxes that were favorable in 2006 and unfavorable in 2005.

· Carrying Costs Income decreased $6 million primarily due to the completion of deferrals of carrying costs on environmental capital expenditures from 2004 and 2005 that are now recovered during 2006 through 2008 according to the RSP.

· Interest Expense increased $8 million primarily due to a new long-term debt issuance during the fourth quarter of 2005.

Income Tax

The increase of $21 million in Income Tax Expense is primarily due to an increase in pretax book income offset in part by a decrease in state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	A3	BBB	A-

Financing Activity

There were no long-term debt issuances or retirements during the first nine months of 2006.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new 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 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed consolidated balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow Hedges			DETM Assignment (a)			Total
Current Assets	$	53,028		$	4,782		$	-		$	57,810
Noncurrent Assets		68,304			326			-			68,630
Total MTM Derivative Contract Assets		121,332			5,108			-			126,440
Current Liabilities		(39,606	)		(743	)		(1,202	)		(41,551	)
Noncurrent Liabilities		(44,001	)		(8	)		(5,841	)		(49,850	)
Total MTM Derivative Contract Liabilities		(83,607	)		(751	)		(7,043	)		(91,401	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	37,725		$	4,357		$	(7,043	)	$	35,039

(a) See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	33,322
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(5,405	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		146
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(138	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		381
Changes in Fair Value Due to Market Fluctuations During the Period (b)		12,996
Changes Due to SIA (c)		(3,864	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		287
Total MTM Risk Management Contract Net Assets		37,725
Net Cash Flow Hedge Contracts		4,357
DETM Assignment (e)		(7,043	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	35,039

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006		2007			2008		2009		2010		After 2010		Total
Prices Actively Quoted - Exchange Traded Contracts	$	1,146	$	8,236		$	2,981	$	-	$	-	$	-	$	12,363
Prices Provided by Other External Sources - OTC Broker   Quotes (a)		2,425		6,394			3,095		4,669		-		-		16,583
Prices Based on Models and Other Valuation Methods (b)		4		(2,247	)		1,039		2,971		5,324		1,688		8,779
Total	$	3,575	$	12,383		$	7,115	$	7,640	$	5,324	$	1,688	$	37,725

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power
Beginning Balance in AOCI December 31, 2005	$	(859	)
Changes in Fair Value		2,853
Impact due to Changes in SIA (a)		(261	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		1,348
Ending Balance in AOCI September 30, 2006	$	3,081

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,875 thousand gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$418	$1,224	$414	$233	$424	$705	$335	$121

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $64 million and $86 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our consolidated results of operations or financial position.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	513,643		$	406,525		$	1,321,422		$	1,074,099
Sales to AEP Affiliates		24,806			46,698			60,337			103,939
Other		1,449			1,345			4,016			3,653
TOTAL		539,898			454,568			1,385,775			1,181,691
EXPENSES
Fuel and Other Consumables for Electric Generation		90,510			72,550			231,543			191,188
Purchased Electricity for Resale		35,449			9,016			87,902			26,922
Purchased Electricity from AEP Affiliates		102,669			109,274			272,334			284,221
Other Operation		66,195			56,276			180,022			152,833
Maintenance		14,704			21,863			56,140			63,947
Asset Impairments and Other Related Charges		-			39,109			-			39,109
Depreciation and Amortization		51,149			37,454			143,495			102,985
Taxes Other Than Income Taxes		38,586			43,422			119,875			112,657
TOTAL		399,262			388,964			1,091,311			973,862
OPERATING INCOME		140,636			65,604			294,464			207,829
Other Income (Expense):
Interest Income		989			1,038			1,919			2,666
Carrying Costs Income		1,046			1,800			3,082			8,716
Allowance for Equity Funds Used During Construction		659			229			1,466			1,036
Interest Expense		(15,813	)		(13,508	)		(50,247	)		(42,089	)
INCOME BEFORE INCOME TAXES		127,517			55,163			250,684			178,158
Income Tax Expense		43,496			20,938			83,064			61,814
NET INCOME		84,021			34,225			167,620			116,344
Capital Stock Expense		39			254			118			2,366
EARNINGS APPLICABLE TO COMMON STOCK	$	83,982		$	33,971		$	167,502		$	113,978

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	41,026	$	577,415	$	341,025		$	(60,816	)	$	898,650
Common Stock Dividends						(85,500	)					(85,500	)
Capital Stock Expense and Other				2,366		(2,366	)					-
TOTAL												813,150
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $3,655									(6,789	)		(6,789	)
NET INCOME						116,344						116,344
TOTAL COMPREHENSIVE INCOME												109,555
SEPTEMBER 30, 2005	$	41,026	$	579,781	$	369,503		$	(67,605	)	$	922,705
DECEMBER 31, 2005	$	41,026	$	580,035	$	361,365		$	(880	)	$	981,546
Common Stock Dividends						(67,500	)					(67,500	)
Capital Stock Expense				118		(118	)					-
TOTAL												914,046
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,121									3,940			3,940
NET INCOME						167,620						167,620
TOTAL COMPREHENSIVE INCOME												171,560
SEPTEMBER 30, 2006	$	41,026	$	580,153	$	461,367		$	3,060		$	1,085,606

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	1,251		$	940
Advances to Affiliates		60,417			-
Accounts Receivable:
Customers		54,517			43,143
Affiliated Companies		51,218			67,694
Accrued Unbilled Revenues		15,687			10,086
Miscellaneous		5,185			2,012
Allowance for Uncollectible Accounts		(1,380	)		(1,082	)
Total Accounts Receivable		125,227			121,853
Fuel		33,556			28,579
Materials and Supplies		30,742			27,519
Emission Allowances		7,070			20,181
Risk Management Assets		57,810			76,507
Accrued Tax Benefits		-			36,838
Prepayments and Other		11,284			23,546
TOTAL		327,357			335,963
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		1,889,414			1,874,652
Transmission		478,513			457,937
Distribution		1,451,842			1,380,722
Other		191,599			184,096
Construction Work in Progress		224,854			129,246
Total		4,236,222			4,026,653
Accumulated Depreciation and Amortization		1,589,465			1,500,858
TOTAL - NET		2,646,757			2,525,795
OTHER NONCURRENT ASSETS
Regulatory Assets		216,339			231,599
Long-term Risk Management Assets		68,630			101,512
Deferred Charges and Other		187,915			237,925
TOTAL		472,884			571,036
TOTAL ASSETS	$	3,446,998		$	3,432,794

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006		2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	-	$	17,609
Accounts Payable:
General		104,090		59,134
Affiliated Companies		57,910		59,399
Risk Management Liabilities		41,551		69,036
Customer Deposits		32,448		47,013
Accrued Taxes		111,910		157,729
Other		47,351		50,229
TOTAL		395,260		460,149
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		1,097,222		1,096,920
Long-term Debt - Affiliated		100,000		100,000
Long-term Risk Management Liabilities		49,850		84,291
Deferred Income Taxes		494,805		498,232
Regulatory Liabilities and Deferred Investment Tax Credits		177,801		165,344
Deferred Credits and Other		46,454		46,312
TOTAL		1,966,132		1,991,099
TOTAL LIABILITIES		2,361,392		2,451,248
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - No Par Value Per Share:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares		41,026		41,026
Paid-in Capital		580,153		580,035
Retained Earnings		461,367		361,365
Accumulated Other Comprehensive Income (Loss)		3,060		(880	)
TOTAL		1,085,606		981,546
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	3,446,998	$	3,432,794

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	167,620		$	116,344
Adjustments for Noncash Items:
Depreciation and Amortization		143,495			102,985
Deferred Income Taxes		(5,097	)		(9,441	)
Asset Impairments and Other Related Charges		-			39,109
Carrying Costs Income		(3,082	)		(8,716	)
Mark-to-Market of Risk Management Contracts		(4,502	)		(12,767	)
Pension Contributions to Qualified Plan Trusts		-			(37,832	)
Deferred Property Taxes		49,518			47,640
Change in Other Noncurrent Assets		(24,297	)		(24,839	)
Change in Other Noncurrent Liabilities		11,752			14,747
Changes in Components of Working Capital:
Accounts Receivable, Net		(3,374	)		(7,748	)
Fuel, Materials and Supplies		(8,200	)		8,611
Accounts Payable		31,765			2,215
Customer Deposits		(14,565	)		30,760
Accrued Taxes, Net		(8,981	)		(94,788	)
Other Current Assets		26,838			(14,809	)
Other Current Liabilities		(2,878	)		(10,471	)
Net Cash Flows From Operating Activities		356,012			141,000
INVESTING ACTIVITIES
Construction Expenditures		(207,875	)		(118,222	)
Change in Advances to Affiliates, Net		(60,417	)		141,550
Purchase of Waterford Plant		-			(218,356	)
Other		8			4,639
Net Cash Flows Used For Investing Activities		(268,284	)		(190,389	)
FINANCING ACTIVITIES
Change in Advances from Affiliates, Net		(17,609	)		138,541
Principal Payments for Capital Lease Obligations		(2,308	)		(2,642	)
Dividends Paid on Common Stock		(67,500	)		(85,500	)
Net Cash Flows From (Used For) Financing Activities		(87,417	)		50,399
Net Increase (Decrease) in Cash and Cash Equivalents		311			1,010
Cash and Cash Equivalents at Beginning of Period		940			58
Cash and Cash Equivalents at End of Period	$	1,251		$	1,068
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	52,958		$	50,095
Net Cash Paid for Income Taxes		35,561			109,382
Noncash Acquisitions Under Capital Leases		2,130			520
Construction Expenditures Included in Accounts Payable at September 30,		22,955			4,974
Assumption of Liabilities in Connection with Waterford Plant Acquisition		-			2,295

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

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

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	53
Changes in Gross Margin:
Retail Margins	(44	)
Off-system Sales (a)	34
Transmission Revenues	(4	)
Other	2
Total Change in Gross Margin				(12	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(17	)
Depreciation and Amortization	(5	)
Other Income (Expense)	3
Interest Expense	(1	)
Total Change in Operating Expenses and Other				(20	)
Income Tax Expense				14
Third Quarter of 2006			$	35

(a) Includes firm wholesale sales to municipals and cooperatives.

Net Income decreased $18 million to $35 million in 2006. The key drivers of the decrease were a $12 million decrease in Gross Margin and a $17 million increase in Other Operation and Maintenance expenses, partially offset by a $14 million decrease in Income Tax Expense.

The major components of our decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail Margins decreased $44 million primarily due to lower fuel recovery as fuel cost increases could not be recovered due to the Indiana fuel cap and a reduction in capacity revenues of $22 million under the Interconnection Agreement. Capacity revenues declined due to our new peak demand in July 2006 and our affiliates’ addition of generating capacity in 2005.

· Off-system Sales increased $34 million primarily due to the addition of new municipal contracts including new rates and increased demand beginning January 2006, a $13 million increase in physical sales margins and a $10 million increase from lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $4 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $17 million primarily due to the abandonment of digital turbine control equipment at the Cook Plant.

· Depreciation and Amortization increased $5 million primarily due to higher expense related to capital additions.

Income Taxes

Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	128
Changes in Gross Margin:
Retail Margins	(55	)
Off-system Sales (a)	63
Transmission Revenues	(11	)
Other	11
Total Change in Gross Margin				8
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(12	)
Depreciation and Amortization	(9	)
Taxes Other Than Income Taxes	(3	)
Other Income (Expense)	4
Interest Expense	(4	)
Total Change in Operating Expenses and Other				(24	)
Income Tax Expense				9
Nine Months Ended September 30, 2006			$	121

(a) Includes firm wholesale sales to municipals and cooperatives.

Net Income decreased $7 million to $121 million in 2006. The key driver of the decrease was a $12 million increase in Other Operation and Maintenance expenses, partially offset by a $9 million decrease in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail Margins decreased $55 million primarily due to lower fuel recovery as fuel cost increases could not be recovered due to the Indiana fuel cap and a reduction in capacity settlement revenues of $27 million under the Interconnection Agreement. Capacity revenues declined due to our new peak demand in July 2006 and our affiliates’ addition of generating capacity in 2005.

· Off-system Sales increased $63 million primarily due to the addition of new municipal contracts including new rates and increased demand beginning January 2006, a $33 million increase in physical sales margins and a $12 million increase from lower sharing of off-system sales margins under the SIA, offset by a $12 million decrease in margins from reduced optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $11 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a $3 million provision for potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenues increased $11 million primarily due to increased River Transportation Division (RTD) revenues for barging coal and gains on sales of emission allowances. Related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in our earning only a return approved under regulatory order.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $12 million primarily due to the abandonment of digital turbine control equipment at the Cook Plant and an increase in RTD expenses.

· Depreciation and Amortization increased $9 million primarily due to higher expense related to capital additions.

Income Taxes

Income Tax Expense decreased $9 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings, unchanged since the first quarter of 2003, are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	Baa2	BBB	BBB

Cash Flow

Cash flows for the nine months ended September 30, 2006 and 2005 were as follows:

	2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	854		$	511
Net Cash Flows From (Used For):
Operating Activities		456,313			276,523
Investing Activities		(355,252	)		(238,875	)
Financing Activities		(101,209	)		(37,428	)
Net Increase (Decrease) in Cash and Cash Equivalents		(148	)		220
Cash and Cash Equivalents at End of Period	$	706		$	731

Operating Activities

Net Cash Flows From Operating Activities were $456 million in 2006. We produced Net Income of $121 million during the period and a noncash expense item of $137 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items; the most significant are increases related to accounts receivable, accounts payable and accrued taxes. We collected receivables from our affiliates related to power sales, settled litigation and emission allowances. Accounts payable and accrued taxes increased related to timing of payments.

Net Cash Flows From Operating Activities were $277 million in 2005. We produced Net Income of $128 million during the period and a noncash expense item of $128 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items; the most significant relates to a $86 million change in accrued taxes reflecting taxes paid during 2005. We also contributed $46 million to our pension trust.

Investing Activities

Net Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect our construction expenditures of $241 million and $190 million and acquisition of nuclear fuel of $73 million and $28 million, respectively. Construction expenditures for the nuclear plant and transmission and distribution assets are to upgrade or replace equipment and improve reliability. We also invested in capital projects to improve air quality and water intake systems. For the remainder of 2006, we expect Construction Expenditures of approximately $90 million.

Financing Activities

Net Cash Flows Used For Financing Activities were $101 million in 2006. We used cash from operations to repay $66 million of Advances from Affiliates and pay $30 million of common stock dividends. We also refinanced a series of pollution control bonds.

Net Cash Flows Used For Financing Activities were $37 million in 2005. We retired $61 million of preferred stock and paid $52 million of common stock dividends, partially offset by the increase in Advances from Affiliates of $81 million.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Pollution Control Bonds	$	50,000	Variable	2025

Retirements

	Principal Amount Paid		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Pollution Control Bonds	$	50,000	6.55	2025

In October 2006, we had a required remarketing of $65 million of 2.625% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

Liquidity

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

Off-Balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current guidelines restrict the use of off-balance sheet financing entities or structures to allow only traditional operating lease arrangements and sales of customer accounts receivable that are entered in the normal course of business. Our off-balance sheet arrangements have not changed significantly since year-end. For complete information on our off-balance sheet arrangements including the lease of Rockport Plant Unit 2 see “Off-balance Sheet Arrangements” in the “Management’s Financial Discussion and Analysis” section of our 2005 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

Cook Plant Outage

In September 2006, Cook Plant Unit 1 began a regular refueling outage. This outage includes the replacement of major components, including the reactor vessel head. Installation of capital projects exceeding $100 million will be completed during this outage and were included in our capital forecast. The improvements and replacement of major components should increase unit capacity and efficiency.  We expect to restart Cook Plant Unit 1 during early November 2006 as planned. We refueled Cook Plant Unit 2 during March and April 2006 and plan to replace its vessel head during its next refueling outage in the fall of 2007.

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our Condensed Consolidated Balance Sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow & Fair Value Hedges			DETM Assignment (a)			Total
Current Assets	$	55,747		$	5,010		$	-		$	60,757
Noncurrent Assets		71,650			342			-			71,992
Total MTM Derivative Contract Assets		127,397			5,352			-			132,749
Current Liabilities		(42,116	)		(15,586	)		(1,259	)		(58,961	)
Noncurrent Liabilities		(46,349	)		(8	)		(6,120	)		(52,477	)
Total MTM Derivative Contract Liabilities		(88,465	)		(15,594	)		(7,379	)		(111,438	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	38,932		$	(10,242	)	$	(7,379	)	$	21,311

(a) See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	33,932
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(538	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(137	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		(310	)
Changes Due to SIA (c)		(3,940	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		9,925
Total MTM Risk Management Contract Net Assets		38,932
Net Cash Flow & Fair Value Hedge Contracts		(10,242	)
DETM Assignment (e)		(7,379	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	21,311

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in our Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006		2007			2008		2009		2010		After 2010		Total
Prices Actively Quoted - Exchange Traded Contracts	$	1,202	$	8,629		$	3,123	$	-	$	-	$	-	$	12,954
Prices Provided by Other External Sources - OTC Broker   Quotes (a)		2,395		6,585			3,260		4,892		-		-		17,132
Prices Based on Models and Other Valuation Methods (b)		-		(2,602	)		988		3,113		5,579		1,768		8,846
Total	$	3,597	$	12,612		$	7,371	$	8,005	$	5,579	$	1,768	$	38,932

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments 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 derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power			Interest Rate			Total
Beginning Balance in AOCI December 31, 2005	$	(877	)	$	(2,590	)	$	(3,467	)
Changes in Fair Value		2,978			(9,382	)		(6,404	)
Impact due to Changes in SIA (a)		(267	)		-			(267	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		1,394			241			1,635
Ending Balance in AOCI September 30, 2006	$	3,228		$	(11,731	)	$	(8,503	)

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,120 thousand gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$438	$1,283	$427	$242	$433	$720	$343	$124

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $69 million and $55 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	449,259		$	391,361		$	1,224,609		$	1,095,621
Sales to AEP Affiliates		54,793			103,141			223,728			277,223
Other - Affiliated		12,903			11,745			37,838			34,215
Other - Nonaffiliated		8,580			8,832			24,593			23,139
TOTAL		525,535			515,079			1,510,768			1,430,198
EXPENSES
Fuel and Other Consumables for Electric Generation		98,135			93,557			283,734			253,255
Purchased Electricity for Resale		20,450			11,784			46,993			35,786
Purchased Electricity from AEP Affiliates		92,052			82,763			259,304			228,756
Other Operation		125,170			122,927			357,882			343,239
Maintenance		56,960			42,300			142,531			144,988
Depreciation and Amortization		47,895			42,726			136,681			127,695
Taxes Other Than Income Taxes		18,472			18,268			56,343			53,246
TOTAL		459,134			414,325			1,283,468			1,186,965
OPERATING INCOME		66,401			100,754			227,300			243,233
Other Income (Expense):
Interest Income		1,102			586			2,459			1,437
Allowance for Equity Funds Used During Construction		2,517			563			5,881			3,252
Interest Expense		(17,228	)		(16,343	)		(52,663	)		(48,427	)
INCOME BEFORE INCOME TAXES		52,792			85,560			182,977			199,495
Income Tax Expense		18,231			32,548			62,013			71,221
NET INCOME		34,561			53,012			120,964			128,274
Preferred Stock Dividend Requirements including Capital Stock Expense		85			86			255			311
EARNINGS APPLICABLE TO COMMON STOCK	$	34,476		$	52,926		$	120,709		$	127,963

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	56,584	$	858,835	$	221,330		$	(45,251	)	$	1,091,498
Common Stock Dividends						(52,000	)					(52,000	)
Preferred Stock Dividends						(255	)					(255	)
Capital Stock Expense and Other				2,455		(56	)					2,399
TOTAL												1,041,642
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,900									(5,385	)		(5,385	)
NET INCOME						128,274						128,274
TOTAL COMPREHENSIVE INCOME												122,889
SEPTEMBER 30, 2005	$	56,584	$	861,290	$	297,293		$	(50,636	)	$	1,164,531
DECEMBER 31, 2005	$	56,584	$	861,290	$	305,787		$	(3,569	)	$	1,220,092
Common Stock Dividends						(30,000	)					(30,000	)
Preferred Stock Dividends						(255	)					(255	)
TOTAL												1,189,837
COMPREHENSIVE INCOME
Other Comprehensive Loss,Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,712									(5,036	)		(5,036	)
NET INCOME						120,964						120,964
TOTAL COMPREHENSIVE INCOME												115,928
SEPTEMBER 30, 2006	$	56,584	$	861,290	$	396,496		$	(8,605	)	$	1,305,765

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	706		$	854
Accounts Receivable:
Customers		72,718			62,614
Affiliated Companies		80,334			127,981
Miscellaneous		2,463			1,982
Allowance for Uncollectible Accounts		(1,204	)		(898	)
Total Accounts Receivable		154,311			191,679
Fuel		38,531			25,894
Materials and Supplies		126,067			118,039
Risk Management Assets		60,757			78,134
Accrued Tax Benefits		16,951			51,846
Margin Deposits		1,258			17,115
Prepayments and Other		9,072			14,188
TOTAL		407,653			497,749
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		3,217,437			3,128,078
Transmission		1,041,725			1,028,496
Distribution		1,084,530			1,029,498
Other (including nuclear fuel and coal mining)		523,502			465,130
Construction Work in Progress		283,714			311,080
Total		6,150,908			5,962,282
Accumulated Depreciation, Depletion and Amortization		2,909,705			2,822,558
TOTAL - NET		3,241,203			3,139,724
OTHER NONCURRENT ASSETS
Regulatory Assets		217,070			222,686
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds		1,191,142			1,133,567
Long-term Risk Management Assets		71,992			103,645
Deferred Charges and Other		144,890			164,938
TOTAL		1,625,094			1,624,836
TOTAL ASSETS	$	5,273,950		$	5,262,309

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006			2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	27,616		$	93,702
Accounts Payable:
General		137,157			139,334
Affiliated Companies		59,163			60,324
Long-term Debt Due Within One Year		349,627			364,469
Risk Management Liabilities		58,961			71,032
Customer Deposits		34,943			49,258
Accrued Taxes		49,964			56,567
Other		138,352			112,839
TOTAL		855,783			947,525
NONCURRENT LIABILITIES
Long-term Debt		1,104,274			1,080,471
Long-term Risk Management Liabilities		52,477			86,159
Deferred Income Taxes		336,194			335,264
Regulatory Liabilities and Deferred Investment Tax Credits		714,663			710,015
Asset Retirement Obligations		774,061			737,959
Deferred Credits and Other		122,651			136,740
TOTAL		3,104,320			3,086,608
TOTAL LIABILITIES		3,960,103			4,034,133
Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,082			8,084
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares		56,584			56,584
Paid-in Capital		861,290			861,290
Retained Earnings		396,496			305,787
Accumulated Other Comprehensive Income (Loss)		(8,605	)		(3,569	)
TOTAL		1,305,765			1,220,092
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,273,950		$	5,262,309

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	120,964		$	128,274
Adjustments for Noncash Items:
Depreciation and Amortization		136,681			127,695
Accretion of Asset Retirement Obligations		36,309			35,742
Deferred Income Taxes		7,734			2,269
Deferred Investment Tax Credits		(5,460	)		(5,496	)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net		(20,673	)		10,506
Amortization of Nuclear Fuel		37,839			41,613
Mark-to-Market of Risk Management Contracts		(4,915	)		(11,275	)
Pension Contributions to Qualified Plan Trusts		-			(46,051	)
Deferred Property Taxes		10,854			9,814
Change in Other Noncurrent Assets		25,260			11,650
Change in Other Noncurrent Liabilities		5,071			13,961
Changes in Components of Working Capital:
Accounts Receivable, Net		37,368			14,441
Fuel, Materials and Supplies		(20,665	)		4,303
Accounts Payable		29,483			4,065
Accrued Taxes, Net		28,292			(85,750	)
Customer Deposits		(14,315	)		28,233
Accrued Interest		11,534			10,358
Rent Accrued - Rockport Plant Unit 2		18,464			18,464
Other Current Assets		20,997			(36,068	)
Other Current Liabilities		(4,509	)		(225	)
Net Cash Flows From Operating Activities		456,313			276,523
INVESTING ACTIVITIES
Construction Expenditures		(240,806	)		(190,171	)
Change in Advances to Affiliates, Net		-			5,093
Purchases of Investment Securities		(559,803	)		(473,802	)
Sales of Investment Securities		517,017			434,639
Acquisitions of Nuclear Fuel		(72,614	)		(28,188	)
Proceeds from Sales of Assets		954			13,554
Net Cash Flows Used For Investing Activities		(355,252	)		(238,875	)
FINANCING ACTIVITIES
Issuance of Long-term Debt		49,745			-
Change in Advances from Affiliates, Net		(66,086	)		81,101
Retirement of Long-term Debt		(50,000	)		-
Retirement of Cumulative Preferred Stock		(1	)		(61,445	)
Principal Payments for Capital Lease Obligations		(4,612	)		(4,829	)
Dividends Paid on Common Stock		(30,000	)		(52,000	)
Dividends Paid on Cumulative Preferred Stock		(255	)		(255	)
Net Cash Flows Used For Financing Activities		(101,209	)		(37,428	)
Net Increase (Decrease) in Cash and Cash Equivalents		(148	)		220
Cash and Cash Equivalents at Beginning of Period		854			511
Cash and Cash Equivalents at End of Period	$	706		$	731
SUPPLEMENTAL DISCLOSURE
Cash Paid for Interest, Net of Capitalized Amounts	$	37,708		$	34,999
Net Cash Paid for Income Taxes		20,180			149,058
Noncash Acquisitions Under Capital Leases		4,359			1,465
Construction Expenditures Included in Accounts Payable at September 30,		29,755			25,008

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Financing Activities	Note 12

KENTUCKY POWER COMPANY

KENTUCKY POWER COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	8
Changes in Gross Margin:
Retail Margins	1
Off-system Sales	8
Transmission Revenues	(3	)
Total Change in Gross Margin				6
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(3	)
Taxes Other Than Income Taxes	1
Total Change in Operating Expenses and Other				(2	)
Income Tax Expense				(2	)
Third Quarter of 2006			$	10

Net Income increased $2 million to $10 million in 2006. The key driver of the increase was a $6 million increase in Gross Margin.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail Margins increased $1 million primarily due to $12 million of rate relief from the March 2006 approval of the settlement agreement in our base rate case. The rate increase was partially offset by the effect of:

· a 23% decrease in cooling degree days as a result of mild weather on residential and commercial sales,

· a decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints in the PJM market and

· increased capacity charges due to changes in the relative peak demands and generating capacity of the AEP Power Pool members.

· Off-system Sales increased $8 million due to $4 million increase in physical sales margins and a $4 million increase from lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $3 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $3 million primarily due to maintenance of overhead lines.

Income Taxes

The increase in Income Tax Expense of $2 million is primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	20
Changes in Gross Margin:
Retail Margins	8
Off-system Sales	9
Transmission Revenues	(6	)
Other	3
Total Change in Gross Margin				14
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(4	)
Depreciation and Amortization	(1	)
Total Change in Operating Expenses and Other				(5	)
Income Tax Expense				(4	)
Nine Months Ended September 30, 2006			$	25

Net Income increased $5 million to $25 million in 2006. The key driver of the increase was a $14 million increase in Gross Margin, partially offset by a $5 million increase in Operating Expenses and Other.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail Margins increased $8 million primarily due to rate relief from the March 2006 approval of the settlement agreement in our base rate case as well as favorable financial transmission rights revenue, net of congestion. The above was partially offset by increased capacity charges due to changes in the relative peak demands and generating capacity of the AEP Power Pool members.

· Off-system Sales increased $9 million primarily due to $10 million increase in physical sales margins and a $5 million increase from lower sharing of off-system sales margins under the SIA offset by a $5 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $6 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $1 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenues increased $3 million primarily due to a $3 million unfavorable adjustment of the Demand Side Management Program regulatory asset in March 2005.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $4 million primarily due to maintenance of overhead lines.

Income Taxes

The increase in Income Tax Expense of $4 million is primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	Baa2	BBB	BBB

Financing Activities

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

None

Retirements

	Principal		Interest	Due
Type of Debt	Amount		Rate	Date
	(in thousands)		(%)
Notes Payable-Affiliated	$	40,000	6.501	2006

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt 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 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

Big Sandy Plant Scrubber

Completion of construction of a scrubber at our Big Sandy Plant was previously scheduled for 2010. We suspended the project in the second quarter of 2006 after a generation engineering evaluation determined that there was a substantially higher estimated capital cost due to increases in labor and material costs, refinements of preliminary costs estimates and an increase in cost per ton of removed SO₂. We currently estimate the project to have an in-service date of 2020.  Management continues to review its emission compliance plans given changing market conditions and the evolving legistative and regulatory environment. 

We transferred the total project expenditures of $16 million during the second quarter of 2006 from Construction Work in Progress to Deferred Charges and Other on our Condensed Balance Sheet. If management does not resume the project, the balance of incurred expenditures would negatively impact future earnings unless a regulatory asset could be established due to probable recovery through rates.

Our 2006 estimated construction expenditures of $100 million, as reported in Note 7 - Commitments and Contingencies in our 2005 Annual Report, has been revised to $54 million due to the delay of the project.

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow & Fair Value Hedges			DETM Assignment (a)			Total
Current Assets	$	19,926		$	1,916		$	-		$	21,842
Noncurrent Assets		25,640			122			-			25,762
Total MTM Derivative Contract Assets		45,566			2,038			-			47,604
Current Liabilities		(14,945	)		(1,156	)		(451	)		(16,552	)
Noncurrent Liabilities		(16,550	)		(2	)		(2,192	)		(18,744	)
Total MTM Derivative Contract Liabilities		(31,495	)		(1,158	)		(2,643	)		(35,296	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	14,071		$	880		$	(2,643	)	$	12,308

(a) See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	13,518
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		32
Fair Value of New Contracts at Inception When Entered During the Period (a)		-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(70	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		(462	)
Changes Due to SIA (c)		(1,565	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		2,618
Total MTM Risk Management Contract Net Assets		14,071
Net Cash Flow & Fair Value Hedge Contracts		880
DETM Assignment (e)		(2,643	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	12,308

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006		2007			2008		2009		2010		After 2010		Total
Prices Actively Quoted - Exchange Traded Contracts	$	430	$	3,090		$	1,118	$	-	$	-	$	-	$	4,638
Prices Provided by Other External Sources - OTC Broker Quotes (a)		905		2,379			1,164		1,752		-		-		6,200
Prices Based on Models and Other Valuation Methods (b)		1		(885	)		372		1,114		1,998		633		3,233
Total	$	1,336	$	4,584		$	2,654	$	2,866	$	1,998	$	633	$	14,071

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments 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 derivative transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power			Interest Rate			Total
Beginning Balance in AOCI December 31, 2005	$	(352	)	$	158		$	(194	)
Changes in Fair Value		1,072			-			1,072
Impact Due to Changes in SIA (a)		(106	)		-			(106	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		543			(66	)		477
Ending Balance in AOCI September 30, 2006	$	1,157		$	92		$	1,249

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,164 thousand gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$157	$459	$164	$87	$174	$289	$138	$50

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $11 million and $13 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.

KENTUCKY POWER COMPANY

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	138,554		$	120,321		$	397,248		$	337,912
Sales to AEP Affiliates		13,466			23,341			41,543			55,598
Other		299			334			678			1,255
TOTAL		152,319			143,996			439,469			394,765
EXPENSES
Fuel and Other Consumables for Electric Generation		39,580			43,603			115,336			104,271
Purchased Electricity for Resale		3,974			1,563			6,938			5,473
Purchased Electricity from AEP Affiliates		48,755			45,300			149,204			131,049
Other Operation		15,176			14,352			42,662			42,549
Maintenance		9,607			7,180			26,041			21,578
Depreciation and Amortization		11,574			11,318			34,603			33,695
Taxes Other Than Income Taxes		1,807			2,457			6,761			7,101
TOTAL		130,473			125,773			381,545			345,716
OPERATING INCOME		21,846			18,223			57,924			49,049
Other Income (Expense):
Interest Income		159			189			518			456
Allowance for Equity Funds Used During Construction		236			37			249			209
Interest Expense		(6,581	)		(7,227	)		(21,317	)		(21,665	)
INCOME BEFORE INCOME TAXES		15,660			11,222			37,374			28,049
Income Tax Expense		5,791			3,495			12,624			7,991
NET INCOME	$	9,869		$	7,727		$	24,750		$	20,058

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	50,450	$	208,750	$	70,555		$	(8,775	)	$	320,980
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,534									(2,848	)		(2,848	)
NET INCOME						20,058						20,058
TOTAL COMPREHENSIVE INCOME												17,210
SEPTEMBER 30, 2005	$	50,450	$	208,750	$	90,613		$	(11,623	)	$	338,190
DECEMBER 31, 2005	$	50,450	$	208,750	$	88,864		$	(223	)	$	347,841
Common Stock Dividends						(10,000	)					(10,000	)
TOTAL												337,841
COMPREHENSIVE INCOME
Other Comprehensive Income,Net of Taxes:
Cash Flow Hedges, Net of Tax of $777									1,443			1,443
NET INCOME						24,750						24,750
TOTAL COMPREHENSIVE INCOME												26,193
SEPTEMBER 30, 2006	$	50,450	$	208,750	$	103,614		$	1,220		$	364,034

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	479		$	526
Accounts Receivable:
Customers		23,776			26,533
Affiliated Companies		14,337			23,525
Accrued Unbilled Revenues		1,004			6,311
Miscellaneous		554			35
Allowance for Uncollectible Accounts		(253	)		(147	)
Total Accounts Receivable		39,418			56,257
Fuel		10,780			8,490
Materials and Supplies		8,854			10,181
Risk Management Assets		21,842			31,437
Accrued Tax Benefits		2,535			6,598
Margin Deposits		453			6,895
Prepayments and Other		1,955			6,324
TOTAL		86,316			126,708
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		477,777			472,575
Transmission		391,671			386,945
Distribution		470,606			456,063
Other		60,607			63,382
Construction Work in Progress		30,436			35,461
Total		1,431,097			1,414,426
Accumulated Depreciation and Amortization		438,023			425,817
TOTAL - NET		993,074			988,609
OTHER NONCURRENT ASSETS
Regulatory Assets		111,089			117,432
Long-term Risk Management Assets		25,762			41,810
Deferred Charges and Other		54,607			45,467
TOTAL		191,458			204,709
TOTAL ASSETS	$	1,270,848		$	1,320,026

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED BALANCE SHEETS

LIABILITIES AND SHAREHOLDER’S EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006		2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	24,507	$	6,040
Accounts Payable:
General		31,118		32,454
Affiliated Companies		18,045		29,326
Long-term Debt Due Within One Year - Nonaffiliated		124,123		-
Long-term Debt Due Within One Year - Affiliated		-		39,771
Risk Management Liabilities		16,552		28,770
Customer Deposits		15,849		21,643
Accrued Taxes		9,322		8,805
Accrued Interest		9,897		7,428
Other		15,967		14,096
TOTAL		265,380		188,333
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		302,861		427,219
Long-term Debt - Affiliated		20,000		20,000
Long-term Risk Management Liabilities		18,744		35,302
Deferred Income Taxes		240,423		234,719
Regulatory Liabilities and Deferred Investment Tax Credits		50,500		56,794
Deferred Credits and Other		8,906		9,818
TOTAL		641,434		783,852
TOTAL LIABILITIES		906,814		972,185
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - $50 Par Value Per Share:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares		50,450		50,450
Paid-in Capital		208,750		208,750
Retained Earnings		103,614		88,864
Accumulated Other Comprehensive Income (Loss)		1,220		(223	)
TOTAL		364,034		347,841
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	1,270,848	$	1,320,026

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	24,750		$	20,058
Adjustments for Noncash Items:
Depreciation and Amortization		34,603			33,695
Deferred Income Taxes		2,742			1,836
Mark-to-Market of Risk Management Contracts		(842	)		(5,204	)
Pension Contributions to Qualified Plan Trusts		-			(9,137	)
Over/Under Fuel Recovery		3,608			(4,453	)
Change in Other Noncurrent Assets		5,666			(4	)
Change in Other Noncurrent Liabilities		2,629			10,333
Changes in Components of Working Capital:
Accounts Receivable, Net		16,839			(2,592	)
Fuel, Materials and Supplies		(963	)		(4,200	)
Accounts Payable		(8,149	)		12,876
Customer Deposits		(5,794	)		12,776
Accrued Taxes, Net		4,580			(553	)
Other Current Assets		7,726			(14,231	)
Other Current Liabilities		3,819			2,297
Net Cash Flows From Operating Activities		91,214			53,497
INVESTING ACTIVITIES
Construction Expenditures		(59,264	)		(38,837	)
Change in Advances to Affiliates, Net		-			6,486
Other		465			191
Net Cash Flows Used For Investing Activities		(58,799	)		(32,160	)
FINANCING ACTIVITIES
Change in Advances from Affiliates, Net		18,467			-
Retirement of Long-term Debt - Affiliated		(40,000	)		(20,000	)
Principal Payments for Capital Lease Obligations		(929	)		(1,122	)
Dividends Paid on Common Stock		(10,000	)		-
Net Cash Flows Used For Financing Activities		(32,462	)		(21,122	)
Net Increase (Decrease) in Cash and Cash Equivalents		(47	)		215
Cash and Cash Equivalents at Beginning of Period		526			132
Cash and Cash Equivalents at End of Period	$	479		$	347
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	18,242		$	17,250
Net Cash Paid for Income Taxes		4,573			7,466
Noncash Acquisitions Under Capital Leases		551			273
Construction Expenditures Included in Accounts Payable at September 30,		2,085			1,386

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to KPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to KPCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Financing Activities	Note 12

OHIO POWER COMPANY CONSOLIDATED

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	56
Changes in Gross Margin:
Retail Margins	47
Off-system Sales	23
Transmission Revenues	(9	)
Other	(7	)
Total Change in Gross Margin				54
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(5	)
Depreciation and Amortization	(9	)
Taxes Other Than Income Taxes	6
Other Income	(1	)
Carrying Costs Income	(6	)
Interest Expense	4
Total Change in Operating Expenses and Other				(11	)
Income Tax Expense				(16	)
Third Quarter of 2006			$	83

Net Income increased $27 million to $83 million in 2006. The key driver of the increase was a $54 million increase in Gross Margin offset by a $16 million increase in Income Tax Expense and an $11 million increase in Operating Expenses and Other.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emission allowances, and purchased power, were as follows:

· Retail Margins were $47 million higher than the prior period primarily due to the Rate Stabilization Plan (RSP) rate increase effective January 1, 2006, favorable capacity settlements, and lower consumable expenses. These increases were partially offset by lower residential revenue due to mild weather and lower industrial revenue due to the transfer of a significant customer to an affiliate.

· Off-system Sales increased $23 million primarily due to $19 million increase in physical sales margins and a $14 million increase from lower sharing of off-system sales margins under the SIA offset by a $10 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $9 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues.  See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenue decreased $7 million primarily due to the expiration of a contract to sell supplemental demand to Buckeye Power and a decrease in rental revenue.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expense increased $5 million partially due to an increase in maintenance from planned and forced outages at the Muskingum and Sporn plants related to major turbine overhaul and boiler tube inspections and repairs. The increase was partially offset by the recognition of a regulatory asset related to recent PUCO orders regarding distribution service reliability and restoration costs.

· Depreciation and Amortization increased $9 million due to increased amortization of regulatory assets and a greater depreciable base in electric utility plant.

· Taxes Other Than Income Taxes decreased $6 million primarily due an adjustment in 2005 to true-up 2004 and 2005 property taxes.

· Carrying Costs Income decreased $6 million primarily due to the completion of deferrals of the environmental carrying costs from 2004 and 2005 that are now being recovered during 2006 through 2008 according to the RSP.

Income Taxes

The increase in Income Tax Expense of $16 million is primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	227
Changes in Gross Margin:
Retail Margins	42
Off-system Sales	29
Transmission Revenues	(19	)
Other	4
Total Change in Gross Margin				56
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(65	)
Depreciation and Amortization	(12	)
Taxes Other than Income Taxes	1
Carrying Costs Income	(28	)
Interest Expense	8
Total Change in Operating Expenses and Other				(96	)
Income Tax Expense				15
Nine Months Ended September 30, 2006			$	202

Net Income decreased $25 million to $202 million in 2006. The key driver of the decrease was a $96 million increase of Operating Expenses and Other offset by a $56 million increase in Gross Margin and a $15 million decrease in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emission allowances, and purchased power, were as follows:

· Retail Margins increased $42 million primarily due to the RSP rate increase effective January 1, 2006, favorable capacity settlements, and lower consumable expenses. The increase is partially offset by lower fuel margins, a decrease in residential revenue due to mild weather and lower industrial revenue due to the transfer of a significant customer to an affiliate.

· Off-System Sales increased $29 million primarily due to $48 million increase in physical sales margins and a $17 million increase from lower sharing of off-system sales margins under the SIA offset by a $35 million decrease in margins related to optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $19 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $4 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

· Other revenue increased $4 million partially due to an increase in gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expense increased $65 million primarily due to an increase in maintenance from planned and forced outages at the Gavin, Muskingum River, Kammer, and Sporn plants related to major boiler and turbine overhauls and boiler tube inspections and related removal costs and PJM administrative fees. The increase was partially offset by the recognition of a regulatory asset related to recent PUCO orders regarding distribution service reliabiltiy and restoration costs and major ice storm expenses in the prior year. 

· Depreciation and Amortization increased $12 million primarily due to increased amortization of regulatory assets and a greater depreciable base in electric utility plant.

· Carrying Costs Income decreased $28 million primarily due to the completion of deferrals of the environmental carrying costs from 2004 and 2005 that are now being recovered during 2006 through 2008 according to the RSP.

· Interest Expense decreased $8 million primarily due to an increase in allowance for borrowed funds used during construction partially offset by interest on long-term debt issuances subsequent to September 2005.

Income Taxes

The decrease in Income Tax Expense of $15 million is primarily due to a decrease in pretax book income and state income taxes, offset in part by changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	A3	BBB	BBB+

Cash Flow

Cash flows for the nine months ended September 30, 2006 and 2005 were as follows:

	2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,240		$	9,337
Net Cash Flows From (Used For):
Operating Activities		476,382			319,579
Investing Activities		(709,752	)		(325,415	)
Financing Activities		233,455			(2,121	)
Net Increase (Decrease) in Cash and Cash Equivalents		85			(7,957	)
Cash and Cash Equivalents at End of Period	$	1,325		$	1,380

Operating Activities

Net Cash Flows From Operating Activities were $476 million in 2006. We produced Net Income of $202 million during the period and a noncash expense item of $239 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital primarily relates to two items, Accounts Receivable, Net and Accounts Payable. Accounts Receivable, Net decreased $78 million due to the collection of receivables related to power sales to affiliates. Accounts Payable decreased $45 million primarily due to timing differences for payments to affiliates related to emission allowances and the AEP Power Pool.

Net Cash Flows From Operating Activities were $320 million in 2005. We produced Net Income of $227 million during the period and a noncash expense item of $228 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital primarily relates two items, Accrued Taxes and Accounts Payable. Accrued Taxes decreased $115 million due primarily to the payment of 2004 federal income tax liability during 2005 and personal property tax. Accounts Payable increased $58 million, due to higher fuel and allowance acquisition costs not paid at September 30, 2005.

Investing Activities

Net Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect our Construction Expenditures of $715 million and $460 million, respectively. Construction expenditures are primarily for environmental upgrades, as well as projects to improve service reliability for transmission and distribution for both periods. In 2005, Construction Expenditures of $460 million were partially offset by an increase in Advances to Affiliates, Net. For the remainder of 2006, we expect our Construction Expenditures to be approximately $350 million.

Financing Activities

Net Cash Flows From Financing Activities were $233 million for 2006. We issued $350 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds. We retired Notes Payable-Affiliated of $200 million. We received a capital contribution from our Parent of $70 million.

Net Cash Flows Used For Financing Activities were $2 million for 2005. We issued Pollution Control Bonds of $353 million. We retired Pollution Control Bonds of $353 million.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

		Principal	Interest	Due
Type of Debt		Amount	Rate	Date
		(in thousands)	(%)
Pollution Control Bonds	$	65,000	Variable	2036
Senior Unsecured Notes		350,000	6.00	2016

Retirements and Principal Payments

		Principal	Interest	Due
Type of Debt		Amount	Rate	Date
		(in thousands)	(%)
Notes Payable - Nonaffiliated	$	4,390	6.81	2008
Notes Payable - Nonaffiliated		6,500	6.27	2009
Notes Payable - Affiliated		200,000	3.32	2006

Liquidity

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

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end, other than the debt issuances, retirements and principal payments discussed above.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

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

Muskingum River Project Deferral

Completion of construction of the Muskingum River Unit 5 flue gas desulphurization (FGD) project was previously scheduled for 2008. We suspended the project in the third quarter of 2006 following a review of a new SO₂ and mercury compliance plan evaluation, updated coal market information reflecting the contraction of the low sulfur versus high sulfur price differentials and the latest project costs. We currently estimate the project to have an in-service date of 2015.  Management continues to review its emission compliance plans given changing market conditions and the evolving legislative and regulatory environment. 

We transferred the total project expenditures of $35 million from Construction Work in Progress to Deferred Charges and Other on our Condensed Consolidated Balance Sheet. If management does not resume the project, the balance of incurred expenditures would negatively impact future earnings unless a regulatory asset could be established due to probable recovery through rates.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of Combined Management’s Discussion and Analysis of Registrant Subsidiaries in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed consolidated balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow Hedges			DETM Assignment (a)			Total
Current Assets	$	66,808		$	5,639		$	-		$	72,447
Noncurrent Assets		82,034			386			-			82,420
Total MTM Derivative Contract Assets		148,842			6,025			-			154,867
Current Liabilities		(55,074	)		(881	)		(1,425	)		(57,380	)
Noncurrent Liabilities		(55,004	)		(9	)		(6,923	)		(61,936	)
Total MTM Derivative Contract Liabilities		(110,078	)		(890	)		(8,348	)		(119,316	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	38,764		$	5,135		$	(8,348	)	$	35,551

(a) See “Natural Gas Contracts with DETM” section of Note 17 in the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	40,894
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(2,331	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		173
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(427	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		451
Changes in Fair Value Due to Market Fluctuations During the Period (b)		4,664
Changes Due to SIA (c)		(4,984	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		324
Total MTM Risk Management Contract Net Assets		38,764
Net Cash Flow Hedge Contracts		5,135
DETM Assignment (e)		(8,348	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	35,551

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006			2007			2008		2009		2010		After 2010		Total
Prices Actively Quoted - Exchange Traded Contracts	$	1,359		$	9,761		$	3,533	$	-	$	-	$	-	$	14,653
Prices Provided by Other External Sources - OTC Broker Quotes (a)		1,850			6,345			3,856		5,534		-		-		17,585
Prices Based on Models and Other Valuation Methods (b)		(38	)		(5,390	)		119		3,521		6,314		2,000		6,526
Total	$	3,171		$	10,716		$	7,508	$	9,055	$	6,314	$	2,000	$	38,764

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments 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 derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power			Foreign Currency			Interest Rate			Total
Beginning Balance in AOCI December 31, 2005	$	(392	)	$	(344	)	$	1,491		$	755
Changes in Fair Value		3,413			-			2,761			6,174
Impact due to Change in SIA (a)		(337	)		-			-			(337	)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		950			10			(497	)		463
Ending Balance in AOCI September 30, 2006	$	3,634		$	(334	)	$	3,755		$	7,055

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $4,189 thousand gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$496	$1,451	$519	$276	$583	$968	$461	$166

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $103 million and $111 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	558,490		$	468,795		$	1,556,193		$	1,413,796
Sales to AEP Affiliates		198,640			204,063			502,547			544,016
Other - Affiliated		4,400			5,333			11,975			12,534
Other - Nonaffiliated		3,378			8,949			12,806			22,947
TOTAL		764,908			687,140			2,083,521			1,993,293
EXPENSES
Fuel and Other Consumables for Electric Generation		280,593			272,468			727,261			721,559
Purchased Electricity for Resale		28,324			12,345			76,351			53,530
Purchased Electricity from AEP Affiliates		35,423			36,012			92,086			86,723
Other Operation		100,274			93,067			286,107			238,916
Maintenance		44,503			46,481			163,443			145,435
Depreciation and Amortization		82,746			73,799			239,407			227,687
Taxes Other Than Income Taxes		47,945			53,531			143,634			144,671
TOTAL		619,808			587,703			1,728,289			1,618,521
OPERATING INCOME		145,100			99,437			355,232			374,772
Other Income (Expense):
Interest Income		840			930			2,072			2,402
Carrying Costs Income		3,502			8,882			10,336			38,431
Allowance for Equity Funds Used During Construction		755			1,952			1,891			2,684
Interest Expense		(24,610	)		(28,416	)		(72,461	)		(80,418	)
INCOME BEFORE INCOME TAXES		125,587			82,785			297,070			337,871
Income Tax Expense		42,245			26,377			95,297			110,499
NET INCOME		83,342			56,408			201,773			227,372
Preferred Stock Dividend Requirements including Capital Stock   Expense and Other Expense		183			183			549			723
EARNINGS APPLICABLE TO COMMON STOCK	$	83,159		$	56,225		$	201,224		$	226,649

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	321,201	$	462,485	$	764,416		$	(74,264	)	$	1,473,838
Common Stock Dividends						(22,499	)					(22,499	)
Preferred Stock Dividends						(549	)					(549	)
Other				4,151		(174	)					3,977
TOTAL												1,454,767
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $4,739									(8,802	)		(8,802	)
NET INCOME						227,372						227,372
TOTAL COMPREHENSIVE INCOME												218,570
SEPTEMBER 30, 2005	$	321,201	$	466,636	$	968,566		$	(83,066	)	$	1,673,337
DECEMBER 31, 2005	$	321,201	$	466,637	$	979,354		$	755		$	1,767,947
Capital Contribution From Parent				70,000								70,000
Preferred Stock Dividends						(549	)					(549	)
Gain on Reacquired Preferred Stock				2								2
TOTAL												1,837,400
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $3,393									6,300			6,300
NET INCOME						201,773						201,773
TOTAL COMPREHENSIVE INCOME												208,073
SEPTEMBER 30, 2006	$	321,201	$	536,639	$	1,180,578		$	7,055		$	2,045,473

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	1,325		$	1,240
Accounts Receivable:
Customers		107,329			125,404
Affiliated Companies		122,993			167,579
Accrued Unbilled Revenues		13,771			14,817
Miscellaneous		2,313			15,644
Allowance for Uncollectible Accounts		(2,786	)		(1,517	)
Total Accounts Receivable		243,620			321,927
Fuel		115,992			97,600
Materials and Supplies		67,920			60,937
Emission Allowances		12,738			39,251
Risk Management Assets		72,447			115,020
Accrued Tax Benefits		1,463			39,965
Prepayments and Other		19,271			27,439
TOTAL		534,776			703,379
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		4,388,325			4,278,553
Transmission		1,016,000			1,002,255
Distribution		1,308,532			1,258,518
Other		296,005			293,794
Construction Work in Progress		1,121,259			690,168
Total		8,130,121			7,523,288
Accumulated Depreciation and Amortization		2,805,417			2,738,899
TOTAL - NET		5,324,704			4,784,389
OTHER NONCURRENT ASSETS
Regulatory Assets		347,457			398,007
Long-term Risk Management Assets		82,420			144,015
Deferred Charges and Other		276,752			300,880
TOTAL		706,629			842,902
TOTAL ASSETS	$	6,566,109		$	6,330,670

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006		2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	48,163	$	70,071
Accounts Payable:
General		250,280		210,752
Affiliated Companies		105,916		147,470
Short-term Debt - Nonaffiliated		7,103		10,366
Long-term Debt Due Within One Year - Nonaffiliated		12,354		12,354
Long-term Debt Due Within One Year - Affiliated		-		200,000
Risk Management Liabilities		57,380		108,797
Customer Deposits		28,811		51,209
Accrued Taxes		92,539		158,774
Other		138,777		147,778
TOTAL		741,323		1,117,571
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		2,186,023		1,787,316
Long-term Debt - Affiliated		200,000		200,000
Long-term Risk Management Liabilities		61,936		119,247
Deferred Income Taxes		972,867		987,386
Regulatory Liabilities and Deferred Investment Tax Credits		182,647		168,492
Deferred Credits and Other		142,616		154,770
TOTAL		3,746,089		3,417,211
TOTAL LIABILITIES		4,487,412		4,534,782
Minority Interest		16,593		11,302
Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,631		16,639
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - No Par Value Per Share:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares		321,201		321,201
Paid-in Capital		536,639		466,637
Retained Earnings		1,180,578		979,354
Accumulated Other Comprehensive Income		7,055		755
TOTAL		2,045,473		1,767,947
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,566,109	$	6,330,670

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	201,773		$	227,372
Adjustments for Noncash Items:
Depreciation and Amortization		239,407			227,687
Deferred Income Taxes		(18,399	)		11,492
Carrying Costs Income		(10,336	)		(38,431	)
Mark-to-Market of Risk Management Contracts		668			(10,841	)
Pension Contributions to Qualified Plan Trusts		-			(60,020	)
Deferred Property Taxes		54,073			47,803
Change in Other Noncurrent Assets		7,958			(12,979	)
Change in Other Noncurrent Liabilities		15,923			6,746
Changes in Components of Working Capital:
Accounts Receivable, Net		78,307			(54,418	)
Fuel, Materials and Supplies		(25,375	)		(25,840	)
Accounts Payable		(44,817	)		57,644
Accrued Taxes, Net		(27,733	)		(114,998	)
Other Current Assets		36,333			28,559
Other Current Liabilities		(31,400	)		29,803
Net Cash Flows From Operating Activities		476,382			319,579
INVESTING ACTIVITIES
Construction Expenditures		(715,200	)		(460,282	)
Change in Advances to Affiliates, Net		-			125,971
Other		5,448			8,896
Net Cash Flows Used For Investing Activities		(709,752	)		(325,415	)
FINANCING ACTIVITIES
Capital Contributions from Parent Company		70,000			-
Issuance of Long-term Debt - Nonaffiliated		405,841			348,237
Change in Short-term Debt, Net - Nonaffiliated		(3,264	)		(8,133	)
Change in Advances from Affiliates, Net		(21,908	)		55,508
Retirement of Long-term Debt - Nonaffiliated		(10,890	)		(363,890	)
Retirement of Long-term Debt - Affiliated		(200,000	)		-
Retirement of Preferred Stock		(7	)		(5,000	)
Principal Payments for Capital Lease Obligations		(5,768	)		(5,795	)
Dividends Paid on Common Stock		-			(22,499	)
Dividends Paid on Cumulative Preferred Stock		(549	)		(549	)
Net Cash Flows From (Used For) Financing Activities		233,455			(2,121	)
Net Increase (Decrease) in Cash and Cash Equivalents		85			(7,957	)
Cash and Cash Equivalents at Beginning of Period		1,240			9,337
Cash and Cash Equivalents at End of Period	$	1,325		$	1,380
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	71,666		$	92,073
Net Cash Paid for Income Taxes		72,175			158,627
Noncash Acquisitions Under Capital Leases		2,529			7,591
Construction Expenditures Included in Accounts Payable at September 30,		117,638			73,895

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries .

OHIO POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Customer Choice and Industry Restructuring	Note 4
Commitments and Contingencies	Note 5
Guarantees	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Business Segments	Note 11
Financing Activities	Note 12

PUBLIC SERVICE COMPANY OF OKLAHOMA

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Allocation Agreement between AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved AEP’s proposed methodology to be used effective April 1, 2006 and beyond. The approved 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 generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of SWEPCo and us. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies. The impact on future results of operations, financial condition and cash flows will depend upon the level of future margins and risk management activity by region.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	49
Changes in Gross Margin:
Retail and Off-system Sales Margins	(2	)
Transmission Revenues	(3	)
Total Change in Gross Margin				(5	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(8	)
Depreciation and Amortization	(1	)
Taxes Other Than Income Taxes	6
Interest Expense	(2	)
Total Change in Operating Expenses and Other				(5	)
Income Tax Expense				3
Third Quarter of 2006			$	42

Net Income decreased $7 million to $42 million in 2006. The key drivers of the decrease were a $5 million decrease in Gross Margin and a $5 million increase in Operating Expenses and Other, partially offset by a $3 million decrease in Income Tax Expense.

The major components of our decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail and Off-system Sales Margins decreased $2 million primarily due to a $4 million decrease in retail margins resulting from lower sales to industrial customers due to the price mix and an increase in non-recoverable fuel items including an accrual for an unfavorable FERC ruling on an SPP Reactive Power dispute with Calpine, partially offset by an increase in Distribution Vegetation Management (DVM) recovery. The decrease in retail margins was partially offset by a $2 million increase in off-system sales margins, comprised of a $16 million increase in margins from optimization activities partially offset by a $14 million decrease primarily related to lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Transmission Revenues decreased $3 million due to lower point-to-point transmission services within SPP.

Operating Expenses and Other increased between years as follows:

· Other Operation and Maintenance expenses increased $8 million due to a $6 million increase in distribution maintenance primarily related to increased DVM expenses.

· Taxes Other Than Income Taxes decreased $6 million due to an adjustment to the provision for state sales and use tax.

Income Taxes

The $3 million decrease in Income Tax Expense is primarily due to the decrease in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	68
Changes in Gross Margin:
Retail and Off-system Sales Margins	12
Transmission Revenues	(1	)
Other	3
Total Change in Gross Margin				14
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(35	)
Depreciation and Amortization	1
Taxes Other Than Income Taxes	2
Interest Expense	(5	)
Total Change in Operating Expenses and Other				(37	)
Income Tax Expense				6
Nine Months Ended September 30, 2006			$	51

Net Income decreased $17 million to $51 million in 2006. The key driver of the decrease was a $37 million increase in Operating Expenses and Other, partially offset by a $14 million increase in Gross Margin and a $6 million decrease in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail and Off-system Sales Margins increased $12 million primarily due to a $20 million increase in retail margins resulting from a 29% increase in cooling degree days and an increase in DVM recovery, partially offset by an increase in non-recoverable fuel items including an accrual for an unfavorable FERC ruling on an SPP Reactive Power dispute with Calpine. The increase in retail margins was partially offset by an $8 million decrease in off-system sales margins comprised of a $17 million decrease primarily related to lower sharing of off-system sales margins under the SIA, partially offset by a $9 million increase in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Other revenue increased $3 million partially due to a 2006 settlement received from an electric cooperative.

Operating Expenses and Other increased between years as follows:

· Other Operation and Maintenance expenses increased $35 million due to a $15 million increase in distribution maintenance primarily related to increased DVM expenses, a $7 million increase in forced and scheduled power plant maintenance, a $6 million increase in administration and general expenses, mostly related to increased pension and other postemployment benefits expense, a $5 million increase in expenses related to the factoring of accounts receivable and a $4 million increase in expenses related to power plant operations.

· Interest Expense increased $5 million primarily due to increased affiliated short-term borrowings during the period and the issuance of long-term debt in 2006.

Income Taxes

The $6 million decrease in Income Tax Expense is primarily due to the decrease in pretax book income, offset in part by tax reserve adjustments.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	Baa1	BBB	A-

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Senior Unsecured Notes	$	150,000	6.15	2016

Retirements

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Notes Payable - Affiliated	$	50,000	3.35	2006

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new 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 2005 Annual Report and has not changed significantly from year-end except for Energy and Capacity Purchase Contracts. We increased our future obligation in Energy and Capacity Purchase Contracts applicable to our optimization and off-system sales activities by approximately $10 million annually due to changes within the SIA and CSW Operating Agreement. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

New Generation

In September 2005, we sought proposals for new peaking generation to be online in 2008 and in December 2005 we sought proposals for base load generation to be online in 2011. We received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from neutral third parties. In March 2006, we announced plans to add 170 MW of peaking generation to our Riverside Station plant in Jenks, Oklahoma where we will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, we announced plans to add 170 MW of peaking generation to our Southwestern Station plant in Anadarko, Oklahoma where we will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Combined preliminary cost estimates for these additions are approximately $120 million. In July 2006, we announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. We will own 50% of the new unit. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion. The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Form 10-K included cost estimates for the peaking additions and the base load facility. These new facilities are subject to regulatory approval from the OCC. We expect to begin construction on all of these additions in 2007.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow Hedges		DETM Assignment (a)			Total
Current Assets	$	71,635		$	-	$	-		$	71,635
Noncurrent Assets		32,354			-		-			32,354
Total MTM Derivative Contract Assets		103,989			-		-			103,989
Current Liabilities		(75,244	)		-		(96	)		(75,340	)
Noncurrent Liabilities		(22,869	)		-		(467	)		(23,336	)
Total MTM Derivative Contract Liabilities		(98,113	)		-		(563	)		(98,676	)
Total MTM Derivative Contract Net Assets	$	5,876		$	-	$	(563	)	$	5,313

(a) Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading and marketing margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	14,214
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		817
Fair Value of New Contracts at Inception When Entered During the Period (a)		-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(386	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		148
Changes Due to SIA and CSW Operating Agreement (c)		10,185
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		(19,102	)
Total MTM Risk Management Contract Net Assets		5,876
Net Cash Flow Hedge Contracts		-
DETM Assignment (e)		(563	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	5,313

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006			2007			2008			2009			2010		After 2010			Total
Prices Actively Quoted - Exchange Traded Contracts	$	(3,194	)	$	(21,390	)	$	3,101		$	(383	)	$	-	$	-		$	(21,866	)
Prices Provided by Other External Sources - OTC Broker   Quotes (a)		(6,056	)		27,924			5,533			(490	)		-		-			26,911
Prices Based on Models and Other Valuation Methods (b)		(143	)		(216	)		(131	)		1,313			42		(34	)		831
Total	$	(9,393	)	$	6,318		$	8,503		$	440		$	42	$	(34	)	$	5,876

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments 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 derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power			Interest Rate			Total
Beginning Balance in AOCI December 31, 2005	$	(629	)	$	(483	)	$	(1,112	)
Changes in Fair Value		-			-			-
Impact Due to Change in SIA (a)		506			-			506
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		123			(633	)		(510	)
Ending Balance in AOCI September 30, 2006	$	-		$	(1,116	)	$	(1,116	)

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $183 thousand loss.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$1,175	$1,786	$647	$58	$311	$517	$246	$89

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ERCOT region.

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $36 million and $34 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	443,593		$	415,558		$	1,116,507		$	937,985
Sales to AEP Affiliates		14,034			16,032			40,647			32,314
Other		814			1,043			3,062			2,018
TOTAL		458,441			432,633			1,160,216			972,317
EXPENSES
Fuel and Other Consumables for Electric Generation		202,836			192,968			566,985			456,690
Purchased Electricity for Resale		68,547			39,186			158,122			84,111
Purchased Electricity from AEP Affiliates		17,706			26,643			54,817			64,877
Other Operation		40,756			40,029			117,721			107,168
Maintenance		25,072			17,809			67,412			43,321
Depreciation and Amortization		22,103			20,842			64,724			65,708
Taxes Other Than Income Taxes		3,844			9,769			23,997			25,507
TOTAL		380,864			347,246			1,053,778			847,382
OPERATING INCOME		77,577			85,387			106,438			124,935
Other Income (Expense):
Interest Income		828			658			1,734			729
Allowance for Equity Funds Used During Construction		222			206			96			542
Interest Expense		(10,954	)		(8,677	)		(29,723	)		(25,173	)
INCOME BEFORE INCOME TAXES		67,673			77,574			78,545			101,033
Income Tax Expense		25,650			28,920			27,241			33,304
NET INCOME		42,023			48,654			51,304			67,729
Preferred Stock Dividend Requirements		53			53			159			159
EARNINGS APPLICABLE TO COMMON STOCK	$	41,970		$	48,601		$	51,145		$	67,570

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

  See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	157,230	$	230,016	$	141,935		$	75		$	529,256
Common Stock Dividends						(27,000	)					(27,000	)
Preferred Stock Dividends						(159	)					(159	)
TOTAL												502,097
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,581									(4,794	)		(4,794	)
NET INCOME						67,729						67,729
TOTAL COMPREHENSIVE INCOME												62,935
SEPTEMBER 30, 2005	$	157,230	$	230,016	$	182,505		$	(4,719	)	$	565,032
DECEMBER 31, 2005	$	157,230	$	230,016	$	162,615		$	(1,264	)	$	548,597
Preferred Stock Dividends						(159	)					(159	)
TOTAL												548,438
COMPREHENSIVE INCOME
Other Comprehensive Loss,Net of Taxes:
Cash Flow Hedges, Net of Tax of $2									(4	)		(4	)
NET INCOME						51,304						51,304
TOTAL COMPREHENSIVE INCOME												51,300
SEPTEMBER 30, 2006	$	157,230	$	230,016	$	213,760		$	(1,268	)	$	599,738

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	2,277		$	1,520
Advances to Affiliates		43,538			-
Accounts Receivable:
Customers		59,153			37,740
Affiliated Companies		54,535			73,321
Miscellaneous		10,105			10,501
Allowance for Uncollectible Accounts		(82	)		(240	)
Total Accounts Receivable		123,711			121,322
Fuel		15,301			16,431
Materials and Supplies		46,665			38,545
Risk Management Assets		71,635			40,383
Accrued Tax Benefits		61			11,972
Regulatory Asset for Under-Recovered Fuel Costs		31,794			108,732
Margin Deposits		35,862			10,051
Prepayments and Other		8,058			4,236
TOTAL		378,902			353,192
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		1,083,390			1,072,928
Transmission		499,175			479,272
Distribution		1,196,071			1,140,535
Other		239,625			211,805
Construction Work in Progress		82,724			90,455
Total		3,100,985			2,994,995
Accumulated Depreciation and Amortization		1,192,825			1,175,858
TOTAL - NET		1,908,160			1,819,137
OTHER NONCURRENT ASSETS
Regulatory Assets		76,543			50,723
Long-term Risk Management Assets		32,354			33,566
Employee Benefits and Pension Assets		79,701			82,559
Deferred Charges and Other		22,372			16,287
TOTAL		210,970			183,135
TOTAL ASSETS	$	2,498,032		$	2,355,464

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006			2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	-		$	75,883
Accounts Payable:
General		130,260			130,627
Affiliated Companies		89,834			89,786
Long-term Debt Due Within One Year - Affiliated		-			50,000
Risk Management Liabilities		75,340			38,243
Customer Deposits		51,107			53,844
Accrued Taxes		59,354			22,420
Other		37,793			51,548
TOTAL		443,688			512,351
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		669,953			521,071
Long-term Risk Management Liabilities		23,336			22,582
Deferred Income Taxes		418,846			436,382
Regulatory Liabilities and Deferred Investment Tax Credits		309,818			284,640
Deferred Credits and Other		27,391			24,579
TOTAL		1,449,344			1,289,254
TOTAL LIABILITIES		1,893,032			1,801,605
Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,262			5,262
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - $15 Par Value Per Share:
Authorized - 11,000,000 Shares
Issued - 10,482,000 Shares
Outstanding - 9,013,000 Shares		157,230			157,230
Paid-in Capital		230,016			230,016
Retained Earnings		213,760			162,615
Accumulated Other Comprehensive Income (Loss)		(1,268	)		(1,264	)
TOTAL		599,738			548,597
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,498,032		$	2,355,464

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	51,304		$	67,729
Adjustments for Noncash Items:
Depreciation and Amortization		64,724			65,708
Deferred Income Taxes		(18,661	)		32,661
Mark-to-Market of Risk Management Contracts		8,901			(2,954	)
Deferred Property Taxes		(8,098	)		(8,123	)
Change in Other Noncurrent Assets		18,186			(34,576	)
Change in Other Noncurrent Liabilities		(24,838	)		26,798
Changes in Components of Working Capital:
Accounts Receivable, Net		(2,389	)		(1,687	)
Fuel, Materials and Supplies		(6,990	)		(3,873	)
Margin Deposits		(25,811	)		(16,121	)
Accounts Payable		1,585			69,794
Customer Deposits		(2,737	)		24,404
Accrued Taxes, Net		48,845			480
Over/Under Fuel Recovery		76,938			(81,808	)
Other Current Assets		(3,828	)		(7,253	)
Other Current Liabilities		(13,755	)		(6,099	)
Net Cash Flows From Operating Activities		163,376			125,080
INVESTING ACTIVITIES
Construction Expenditures		(140,998	)		(87,804	)
Change in Other Cash Deposits, Net		6			(6	)
Change in Advances to Affiliates, Net		(43,538	)		-
Net Cash Flows Used For Investing Activities		(184,530	)		(87,810	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		148,747			74,405
Change in Advances from Affiliates, Net		(75,883	)		(32,401	)
Retirement of Long-term Debt - Nonaffiliated		-			(50,000	)
Retirement of Long-term Debt - Affiliated		(50,000	)		-
Principal Payments for Capital Lease Obligations		(794	)		(483	)
Dividends Paid on Common Stock		-			(27,000	)
Dividends Paid on Cumulative Preferred Stock		(159	)		(159	)
Net Cash Flows From (Used For) Financing Activities		21,911			(35,638	)
Net Increase in Cash and Cash Equivalents		757			1,632
Cash and Cash Equivalents at Beginning of Period		1,520			279
Cash and Cash Equivalents at End of Period	$	2,277		$	1,911
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	25,491		$	21,954
Net Cash Paid for Income Taxes		7,471			14,241
Noncash Acquisitions Under Capital Leases		2,639			798
Construction Expenditures Included in Accounts Payable at September 30,		6,591			3,482

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments and Contingencies	Note 5
Guarantees	Note 6
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Income Taxes	Note 10
Business Segments	Note 11
Financing Activities	Note 12

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Allocation Agreement between AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved AEP’s proposed methodology to be used effective April 1, 2006 and beyond. The approved 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 generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and us. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies. The impact on future results of operations, financial condition and cash flows will depend upon the level of future margins and risk management activities by region and the status of cost recovery mechanisms by state.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income

(in millions)

Third Quarter of 2005			$	50
Changes in Gross Margin:
Retail and Off-system Sales Margins (a)	(9	)
Transmission Revenues	(1	)
Other	6
Total Change in Gross Margin				(4	)
Changes in Operating Expenses and Other:
Other Operation and Maintenance	6
Taxes Other Than Income Taxes	1
Interest Expense	(1	)
Total Change in Operating Expenses and Other				6
Income Tax Expense				(2	)
Third Quarter of 2006			$	50

(a) Includes firm wholesale sales to municipals and cooperatives.

Net Income remained flat in the third quarter of 2006 compared to the third quarter of 2005.

The major components of our decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail and Off-system Sales Margins decreased $9 million primarily due to a $4 million non-recoverable accrual for an unfavorable FERC ruling on an SPP Reactive Power Contract with Calpine as well as an $8 million decrease in off-system sales margins primarily due to lower sharing of off-system sales margins under the SIA. Partially offsetting these decreases was a $3 million increase in wholesale revenues due to higher usage and favorable prices. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Other revenues increased $6 million primarily due to gains on sales of emission allowances.

Operating Expenses and Other decreased between years as follows:

· Other Operation and Maintenance decreased $6 million primarily due to a $3 million decrease in transmission operation expense resulting from favorable changes to the SPP fee structure as well as a $3 million decrease in overhead line maintenance expense primarily related to the absence of 2005 hurricane-related expenses.

Income Taxes

The $2 million increase in Income Tax Expense is primarily due to the increase in pretax book income and state income taxes.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to

Nine Months Ended September 30, 2006 Net Income

(in millions)

Nine Months Ended September 30, 2005			$	81
Changes in Gross Margin:
Retail and Off-system Sales Margins (a)	15
Transmission Revenues	1
Other	22
Total Change in Gross Margin				38
Changes in Operating Expenses and Other:
Other Operation and Maintenance	(8	)
Interest Expense	(2	)
Total Change in Operating Expenses and Other				(10	)
Income Tax Expense				(13	)
Nine Months Ended September 30, 2006			$	96

(a) Includes firm wholesale sales to municipals and cooperatives.

Net Income increased $15 million to $96 million in 2006. The key driver of the increase was a $38 million increase in Gross Margin, partially offset by a $10 million increase in Operating Expenses and Other and a $13 million increase in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power, were as follows:

· Retail and Off-system Sales Margins increased $15 million primarily due to a $17 million increase in wholesale margins resulting from higher prices, increased usage and new wholesale contracts, as well as a $15 million increase primarily due to increased wholesale fuel recovery. These increases were partially offset by a $17 million decrease in off-system sales margins primarily due to lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

· Other revenues increased $22 million primarily due to gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $8 million primarily due to a $5 million increase in employee-related expenses, a $3 million increase in mining operations expense resulting from increased production and a $2 million increase in expenses related to the factoring of customer accounts receivable, offset by the absence of $4 million of 2005 hurricane-related expenses.

Income Taxes

The $13 million increase in Income Tax Expense is primarily due to the increase in pretax book income and state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	A3	A-	A
Senior Unsecured Debt	Baa1	BBB	A-

Cash Flow

Cash flows for the nine months ended September 30, 2006 and 2005 were as follows:

	2006			2005
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	3,049		$	3,715
Net Cash Flows From (Used For):
Operating Activities		242,721			163,705
Investing Activities		(186,631	)		(67,857	)
Financing Activities		(56,343	)		(95,759	)
Net Increase (Decrease) in Cash and Cash Equivalents		(253	)		89
Cash and Cash Equivalents at End of Period	$	2,796		$	3,804

Operating Activities

Net Cash Flows From Operating Activities were $243 million in 2006. We produced Net Income of $96 million during the period and noncash expense items of $98 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $54 million inflow from Accounts Payable was the result of higher energy purchases. The $28 million outflow for Margin Deposits was due to increased trading-related deposits resulting from the amended SIA. In addition, our $64 million inflow related to Over/Under Fuel Recovery was primarily due to the new fuel surcharges effective December 2005 in our Arkansas service territory and in January 2006 in our Texas service territory. The $27 million outflow from Fuel, Materials and Supplies was the result of increased fuel purchases.

Net Cash Flows From Operating Activities were $164 million in 2005. We produced Net Income of $81 million during the period and noncash expense items of $99 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The $42 million inflow from Accounts Payable was due to higher vendor-related payables and increased energy transactions. The $66 million outflow related to Over/Under Fuel Recovery was due to our increasing cumulative under-recovery of rising fuel costs.

Investing Activities

Cash Flows Used For Investing Activities during 2006 and 2005 were $187 million and $68 million, respectively. The cash flows during 2006 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability as well as projects related to generation facilities. For the remainder of 2006, we expect $140 million in Construction Expenditures. During 2005, Construction Expenditures were $110 million, also comprised primarily of spending for transmission and distribution service reliability. Additionally, we decreased our Advances to Affiliates by $39 million.

Financing Activities

Cash Flows Used For Financing Activities were $56 million during 2006. We refinanced $82 million of Pollution Control Bonds. Long-term debt retirements were $89 million. In addition, we repaid $28 million to the Utility Money Pool. We also paid $30 million in Common Stock Dividends.

Cash Flows Used For Financing Activities were $96 million during 2005. We issued $150 million of Senior Unsecured Notes for the purpose of funding the July 2005 maturity of our $200 million of Senior Unsecured Notes. We paid $40 million in Common Stock Dividends.

Financing Activity

Long-term debt issuances, retirements and principal payments during the first nine months of 2006 were:

Issuances

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Pollution Control Bonds	$	81,700	Variable	2018

Retirements and Principal Payments

	Principal Amount		Interest	Due
Type of Debt			Rate	Date
		(in thousands)	(%)
Notes Payable	$	5,039	4.47	2011
Notes Payable		2,250	Variable	2008
Pollution Control Bonds		81,700	6.10	2018

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt and refinance short-term or 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 2005 Annual Report and has not changed significantly from year-end except for Energy and Capacity Purchase Contracts. We increased our future obligation in Energy and Capacity Purchase Contracts applicable to our optimization and off-system sales activities by approximately $10 million annually due to changes within the SIA and CSW Operating Agreement. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

New Generation

In December 2005, we sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, we announced plans to construct new generation to satisfy the demands of our customers. We will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural gas fired plant at our existing Arsenal Hill Power Plant in Shreveport, Louisiana. We also plan to build a new 600 MW base load coal plant in Hempstead County, Arkansas by 2011 to meet the longer-term generation needs of our customers. Preliminary cost estimates for the new facilities are approximately $1.4 billion (this total excludes the related transmission investment). The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Form 10-K included cost estimates for these new facilities. These new facilities are subject to regulatory approvals from our three state commissions. Construction is expected to begin in 2007.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed consolidated balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

As of September 30, 2006

(in thousands)

	MTM Risk Management Contracts			Cash Flow Hedges			DETM Assignment (a)			Total
Current Assets	$	84,685		$	-		$	-		$	84,685
Noncurrent Assets		38,252			-			-			38,252
Total MTM Derivative Contract Assets		122,937			-			-			122,937
Current Liabilities		(89,430	)		(4,097	)		(114	)		(93,641	)
Noncurrent Liabilities		(27,326	)		(28	)		(550	)		(27,904	)
Total MTM Derivative Contract Liabilities		(116,756	)		(4,125	)		(664	)		(121,545	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	6,181		$	(4,125	)	$	(664	)	$	1,392

(a) Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading and marketing margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

MTM Risk Management Contract Net Assets

Nine Months Ended September 30, 2006

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005	$	16,387
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		655
Fair Value of New Contracts at Inception When Entered During the Period (a)		52
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period		(452	)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts		139
Changes in Fair Value Due to Market Fluctuations During the Period (b)		(7,302	)
Changes Due to SIA and CSW Operating Agreement (c)		11,900
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		(15,198	)
Total MTM Risk Management Contract Net Assets		6,181
Net Cash Flow Hedge Contracts		(4,125	)
DETM Assignment (e)		(664	)
Total MTM Risk Management Contract Net Assets at September 30, 2006	$	1,392

(a)	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.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)	“Changes in Fair Value 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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)	Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading and marketing margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

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

The following table presents:

· The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).

· The maturity, by year, of our net assets/liabilities 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, 2006

(in thousands)

	Remainder 2006			2007			2008			2009			2010		After 2010			Total
Prices Actively Quoted - Exchange Traded Contracts	$	(3,762	)	$	(25,203	)	$	3,654		$	(451	)	$	-	$	-		$	(25,762	)
Prices Provided by Other External Sources - OTC Broker Quotes (a)		(7,187	)		32,724			6,546			(577	)		-		-			31,506
Prices Based on Models and Other Valuation Methods (b)		(173	)		(636	)		(310	)		1,546			50		(40	)		437
Total	$	(11,122	)	$	6,885		$	9,890		$	518		$	50	$	(40	)	$	6,181

(a)

“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.

(b)

“Prices Based on Models and Other Valuation Methods” is used in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.

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

We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments 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 derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Nine Months Ended September 30, 2006

(in thousands)

	Power			Interest Rate			Total
Beginning Balance in AOCI December 31, 2005	$	(736	)	$	(5,116	)	$	(5,852	)
Changes in Fair Value		-			(2,655	)		(2,655	)
Impact due to Change in SIA (a)		591			-			591
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		145			403			548
Ending Balance in AOCI September 30, 2006	$	-		$	(7,368	)	$	(7,368	)

(a) See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $727 thousand loss.

Credit Risk

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

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended September 30, 2006				Twelve Months Ended December 31, 2005
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$1,385	$2,104	$758	$68	$363	$604	$287	$104

The High VaR for the nine months ended September 30, 2006 occurred in the third quarter due to volatility in the ERCOT region.

VaR Associated with Debt Outstanding

We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $21 million and $31 million at September 30, 2006 and December 31, 2005, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	2006			2005			2006			2005
REVENUES
Electric Generation, Transmission and Distribution	$	440,542		$	459,220		$	1,084,185		$	1,015,074
Sales to AEP Affiliates		14,692			14,614			34,871			38,573
Other		1,466			449			2,260			698
TOTAL		456,700			474,283			1,121,316			1,054,345
EXPENSES
Fuel and Other Consumables for Electric Generation		158,992			179,904			367,924			386,719
Purchased Electricity for Resale		61,816			45,194			135,918			91,377
Purchased Electricity from AEP Affiliates		18,140			27,363			58,303			55,230
Other Operation		55,256			60,229			158,338			152,340
Maintenance		21,120			22,353			68,008			65,713
Depreciation and Amortization		32,996			32,930			98,406			98,580
Taxes Other Than Income Taxes		17,107			18,175			49,254			49,725
TOTAL		365,427			386,148			936,151			899,684
OPERATING INCOME		91,273			88,135			185,165			154,661
Other Income (Expense):
Interest Income		822			250			2,277			1,167
Allowance for Equity Funds Used During Construction		287			516			400			1,849
Interest Expense		(13,844	)		(12,346	)		(40,688	)		(38,027	)
										��
INCOME BEFORE INCOME TAXES AND MINORITY   INTEREST EXPENSE		78,538			76,555			147,154			119,650
Income Tax Expense		27,873			25,789			49,187			35,675
Minority Interest Expense		959			1,035			2,077			2,735
NET INCOME		49,706			49,731			95,890			81,240
Preferred Stock Dividend Requirements		57			57			172			172
EARNINGS APPLICABLE TO COMMON STOCK	$	49,649		$	49,674		$	95,718		$	81,068

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004	$	135,660	$	245,003	$	389,135		$	(1,180	)	$	768,618
Common Stock Dividends						(40,000	)					(40,000	)
Preferred Stock Dividends						(172	)					(172	)
TOTAL												728,446
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $4,827									(8,965	)		(8,965	)
NET INCOME						81,240						81,240
TOTAL COMPREHENSIVE INCOME												72,275
SEPTEMBER 30, 2005	$	135,660	$	245,003	$	430,203		$	(10,145	)	$	800,721
DECEMBER 31, 2005	$	135,660	$	245,003	$	407,844		$	(6,129	)	$	782,378
Common Stock Dividends						(30,000	)					(30,000	)
Preferred Stock Dividends						(172	)					(172	)
TOTAL												752,206
COMPREHENSIVE INCOME
Other Comprehensive Loss,Net of Taxes:
Cash Flow Hedges, Net of Tax of $817									(1,516	)		(1,516	)
NET INCOME						95,890						95,890
TOTAL COMPREHENSIVE INCOME												94,374
SEPTEMBER 30, 2006	$	135,660	$	245,003	$	473,562		$	(7,645	)	$	846,580

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2006 and December 31, 2005

(in thousands)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	2,796		$	3,049
Advances to Affiliates		7,018			-
Accounts Receivable:
Customers		65,274			47,515
Affiliated Companies		40,779			49,226
Miscellaneous		8,260			7,984
Allowance for Uncollectible Accounts		(264	)		(548	)
Total Accounts Receivable		114,049			104,177
Fuel		58,785			40,333
Materials and Supplies		43,108			34,821
Risk Management Assets		84,685			47,319
Regulatory Asset for Under-Recovered Fuel Costs		-			51,387
Margin Deposits		42,232			13,740
Prepayments and Other		19,129			20,270
TOTAL		371,802			315,096
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		1,697,764			1,660,392
Transmission		662,009			645,297
Distribution		1,200,577			1,153,026
Other		458,905			443,749
Construction Work in Progress		137,128			104,175
Total		4,156,383			4,006,639
Accumulated Depreciation and Amortization		1,825,110			1,776,216
TOTAL - NET		2,331,273			2,230,423
OTHER NONCURRENT ASSETS
Regulatory Assets		101,273			81,776
Long-term Risk Management Assets		38,252			39,796
Employee Benefits and Pension Assets		79,770			83,330
Deferred Charges and Other		54,333			46,926
TOTAL		273,628			251,828
TOTAL ASSETS	$	2,976,703		$	2,797,347

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

September 30, 2006 and December 31, 2005

(Unaudited)

	2006			2005
CURRENT LIABILITIES	(in thousands)
Advances from Affiliates	$	-		$	28,210
Accounts Payable:
General		94,188			71,138
Affiliated Companies		82,937			53,019
Short-term Debt - Nonaffiliated		15,676			1,394
Long-term Debt Due Within One Year - Nonaffiliated		108,926			15,755
Risk Management Liabilities		93,641			45,098
Customer Deposits		48,931			50,848
Accrued Taxes		89,311			42,799
Other		79,223			82,699
TOTAL		612,833			390,960
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated		578,575			678,886
Long-term Debt - Affiliated		50,000			50,000
Long-term Risk Management Liabilities		27,904			27,083
Deferred Income Taxes		379,470			409,513
Regulatory Liabilities and Deferred Investment Tax Credits		343,954			320,066
Deferred Credits and Other		131,017			131,477
TOTAL		1,510,920			1,617,025
TOTAL LIABILITIES		2,123,753			2,007,985
Minority Interest		1,672			2,284
Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,698			4,700
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock - $18 Par Value Per Share:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares		135,660			135,660
Paid-in Capital		245,003			245,003
Retained Earnings		473,562			407,844
Accumulated Other Comprehensive Income (Loss)		(7,645	)		(6,129	)
TOTAL		846,580			782,378
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,976,703		$	2,797,347

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2006 and 2005

(in thousands)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	95,890		$	81,240
Adjustments for Noncash Items:
Depreciation and Amortization		98,406			98,580
Deferred Income Taxes		(24,642	)		11,552
Mark-to-Market of Risk Management Contracts		10,870			(3,141	)
Deferred Property Taxes		(9,438	)		(9,579	)
Change in Other Noncurrent Assets		20,982			(16,262	)
Change in Other Noncurrent Liabilities		(33,256	)		10,149
Changes in Components of Working Capital:
Accounts Receivable, Net		(9,872	)		(3,337	)
Fuel, Materials and Supplies		(26,739	)		6,254
Margin Deposits		(28,492	)		(18,766	)
Accounts Payable		54,264			41,775
Customer Deposits		(1,917	)		26,571
Accrued Taxes, Net		45,514			4,655
Over/Under Fuel Recovery, Net		63,862			(66,173	)
Other Current Assets		2,635			(3,859	)
Other Current Liabilities		(15,346	)		4,046
Net Cash Flows From Operating Activities		242,721			163,705
INVESTING ACTIVITIES
Construction Expenditures		(179,117	)		(110,209	)
Change in Advances to Affiliates, Net		(7,018	)		39,106
Other		(496	)		3,246
Net Cash Flows Used For Investing Activities		(186,631	)		(67,857	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		80,593			154,642
Change in Short-term Debt, Net - Nonaffiliated		14,282			-
Change in Advances from Affiliates, Net		(28,210	)		605
Retirement of Long-term Debt - Nonaffiliated		(88,989	)		(208,122	)
Retirement of Preferred Stock		(2	)		-
Principal Payments for Capital Lease Obligations		(3,845	)		(2,712	)
Dividends Paid on Common Stock		(30,000	)		(40,000	)
Dividends Paid on Cumulative Preferred Stock		(172	)		(172	)
Net Cash Flows Used For Financing Activities		(56,343	)		(95,759	)
Net Increase (Decrease) in Cash and Cash Equivalents		(253	)		89
Cash and Cash Equivalents at Beginning of Period		3,049			3,715
Cash and Cash Equivalents at End of Period	$	2,796		$	3,804
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	37,372		$	33,748
Net Cash Paid for Income Taxes		53,509			49,176
Noncash Acquisitions Under Capital Leases		17,110			4,414
Construction Expenditures Included in Accounts Payable at September 30,		8,924			5,075

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.

	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
Company-wide Staffing and Budget Review	Note 7
Benefit Plans	Note 9
Income Taxes	Note 10
Business Segments	Note 11
Financing Activities	Note 12

CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:
1.	Significant Accounting Matters	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2.	New Accounting Pronouncements	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3.	Rate Matters	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4.	Customer Choice and Industry Restructuring	CSPCo, OPCo, SWEPCo, TCC, TNC
5.	Commitments and Contingencies	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6.	Guarantees	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7.	Company-wide Staffing and Budget Review	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
8.	Acquisitions, Assets Held for Sale and Asset Impairments	CSPCo, TCC
9.	Benefit Plans	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10.	Income Taxes	PSO, SWEPCo, TCC, TNC
11.	Business Segments	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
12.	Financing Activities	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

        1.SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (SEC). Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations, financial position and cash flows for the interim periods for each Registrant Subsidiary. The results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of results that may be expected for the year ending December 31, 2006. The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 2005 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2005 as filed with the SEC on March 1, 2006.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the condensed balance sheets in the common shareholder’s equity section. The components of Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries as of September 30, 2006 and December 31, 2005 are shown in the following table.

	September 30,			December 31,
	2006			2005
	(in thousands)
Components
Cash Flow Hedges:
APCo	$	(3,407	)	$	(16,421	)
CSPCo		3,081			(859	)
I&M		(8,503	)		(3,467	)
KPCo		1,249			(194	)
OPCo		7,055			755
PSO		(1,116	)		(1,112	)
SWEPCo		(7,368	)		(5,852	)
TCC		-			(224	)
TNC		(1,337	)		(111	)
Minimum Pension Liability:
APCo	$	(189	)	$	(189	)
CSPCo		(21	)		(21	)
I&M		(102	)		(102	)
KPCo		(29	)		(29	)
PSO		(152	)		(152	)
SWEPCo		(277	)		(277	)
TCC		(928	)		(928	)
TNC		(393	)		(393	)

Accounting for Asset Retirement Obligations (ARO)

The Registrant Subsidiaries implemented SFAS 143 effective January 1, 2003. SFAS 143 requires entities to record a liability at fair value for any legal obligations for future asset retirements when the related assets are acquired or constructed. Upon establishment of a legal liability, SFAS 143 requires a corresponding ARO asset to be established, which will be depreciated over its useful life. ARO accounting is being followed for regulated and nonregulated property that has a legal obligation related to asset retirement. Upon settlement of an ARO, any difference between the ARO liability and actual costs is recognized as income or expense.

The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets, as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

The following is a reconciliation of the September 30, 2006 aggregate carrying amount of ARO for SWEPCo. The changes in components of ARO during 2006 are immaterial for all other Registrant Subsidiaries.

	ARO at December 31, 2005		Accretion Expense		Liabilities Incurred		Liabilities Settled			Revisions in Cash Flow Estimates			ARO at September 30, 2006
	(in thousands)
SWEPCo	$	43,077	$	1,781	$	4,200	$	(4,967	)	$	(763	)	$	43,328

SWEPCo’s September 30, 2006 and December 31, 2005 aggregate carrying amounts include ARO related to ash ponds, asbestos removal, Sabine Mining Company and Dolet Hills Lignite Company, LLC. The current portion of SWEPCo’s ARO totaling approximately $1 million and $2 million at September 30, 2006 and December 31, 2005, respectively, is included in Other in the Current Liabilities section of SWEPCo’s Condensed Consolidated Balance Sheets.

Related Party Transactions

The amounts of power purchased from Ohio Valley Electric Corporation, which is 43.47 % owned by AEP and CSPCo, were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2006		2005		2006		2005
	(in thousands)
APCo	$	19,555	$	19,501	$	62,209	$	54,763
CSPCo		5,536		5,103		17,100		14,752
I&M		9,784		7,920		28,848		22,704
OPCo		19,303		16,703		58,626		47,757

CSPCo entered into a ten year Power Purchase Agreement (PPA) with Sweeny, on behalf of the AEP West companies, from January 1, 2005 to December 31, 2014. The PPA is for unit contingent power up to a maximum of 315 MW. The delivery point for the power under the PPA is in TCC’s system. The power is sold in ERCOT. Prior to May 1, 2006, the purchase of Sweeny power and its sale to nonaffiliates were shared among the AEP West companies under the CSW Operating Agreement. After May 1, 2006, the purchases and sales are shared between PSO and SWEPCo. See “Allocation Agreement between AEP East Companies and AEP West Companies and CSW Operating Agreement” section of Note 3. Also see Note 17 of the 2005 Annual Report for a discussion of the CSW Operating Agreement. The purchases from Sweeny were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2006		2005		2006		2005
	(in thousands)
PSO	$	13,750	$	11,051	$	39,886	$	31,160
SWEPCo		16,170		13,189		46,925		27,570
TCC		-		5,548		703		20,120
TNC		-		8,559		4,229		19,638

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation. These revisions had no impact on previously reported results of operations, financial condition or changes in shareholders’ equity.

The Registrant Subsidiaries’ Statements of Operations were converted from a utility format presentation where only regulated cost-of-service items were reflected in Operating Income to a commercial format presentation where nonutility items are reflected as components of Operating Income.

        2.NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine its relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented in 2006 that we determined relate to our operations.

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

In December 2004, the FASB issued SFAS 123R. 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 Registrant Subsidiaries recorded insignificant cumulative effects of a change in accounting principle in the first quarter of 2006 for the effects of initially applying the statement, primarily reflected in Other Operation on their financial statements.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued three FASB Staff Positions (FSP) during 2005 and one in February 2006 that provided additional implementation guidance. The Registrant Subsidiaries applied the principles of SAB 107 and the applicable FSPs in conjunction with their adoption of SFAS 123R.

The Registrant Subsidiaries adopted SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires them to record compensation expense for all awards granted after the time of adoption and 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 is based on the grant-date fair value of the equity award. Stock-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense recognized in the Registrant Subsidiaries’ financial statements for the three and nine months ended September 30, 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested as of, January 1, 2006 based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123 and compensation expense for the share-based payment awards granted subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Implementation of SFAS 123R did not materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.

SFAS 157 “Fair Value Measurements”

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

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. Management is currently in the process of determining the effect this standard will have on the Registrant Subsidiaries’ financial statements. Although SFAS 157 is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. SFAS 157 will be effective for the Registrant Subsidiaries starting January 1, 2008.

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

In September 2006, the FASB issued SFAS 158. SFAS 158 amends previous standards. It requires employers to fully recognize the obligations associated with defined benefit pension, retiree healthcare and other postretirement (OPEB) plans in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to SFAS 87, “Employers’ Accounting for Pensions,” or SFAS 106, “Employer’s Accounting for Postretirement Benefits Other Than Pensions.” It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit postretirement plan affects net periodic benefit costs for the next fiscal year.

The effect of SFAS 158 is to adjust AOCI at the end of each year, for both underfunded and overfunded pension and OPEB plans, to an amount equal to the remaining unrecognized SFAS 87 and SFAS 106 deferrals for unamortized actuarial losses or gains, prior service costs, or transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition.

The year-end AOCI measure is volatile based on fluctuating investment returns and discount rates. Favorable changes include higher returns that increase plan assets and higher discount rates that reduce the discounted benefit obligation.

SFAS 158 is effective for initial recognition of a defined benefit postretirement plan and related disclosure for fiscal years ending after December 15, 2006. Management has not completed the process of determining the effect of this standard on the Registrant Subsidiaries’ financial statements, including whether a portion of the adjustment required by SFAS 158 can be deferred as a regulatory asset under SFAS 71.

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

In June 2006, the EITF reached a consensus on the income statement presentation of various types of taxes. The scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes. The presentation of taxes within the scope of this issue on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22, “Disclosure of Accounting Policies.” The EITF’s decision on gross/net presentation requires that any such taxes reported on a gross basis be disclosed on an aggregate basis in interim and annual financial statements, for each period for which an income statement is presented, if those amounts are significant.

EITF 06-3 is effective for fiscal years beginning after December 15, 2006. As disclosed in Note 1 of the 2005 Annual Report, the Registrant Subsidiaries act as agents for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on customers. The Registrant Subsidiaries present these taxes on a net basis and do not recognize these taxes as revenues or expenses. Therefore, this issue will not have a material impact on their financial statements.

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

In July 2006, the FASB issued FIN 48 which clarifies the application of SFAS 109, “Accounting for Income Taxes.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements. It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately. FIN 48 is effective for fiscal years beginning after December 15, 2006. Management has not completed the process of determining the effect of this interpretation on the financial statements.

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

In September 2006, the SEC staff issued SAB 108. SAB 108 addresses the diversity in practice when quantifying the effect of an error on financial statements. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying misstatements in current year financial statements. The Registrant Subsidiaries will be required to adopt the provisions of SAB 108 effective December 31, 2006. Management believes that the adoption of SAB 108 will not have a material impact on the financial statements.

Future Accounting Changes

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

        3.RATE MATTERS

The Rate Matters note within the 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations and cash flows. Rate matters that are not believed to be reasonably likely to affect future results of operations and cash flows are not included in this report or the 2005 Annual Report. The following sections discuss ratemaking developments in 2006 updating the 2005 Annual Report.

APCo Virginia Environmental and Reliability Costs - Affecting APCo

The Virginia Electric Restructuring Act (the statute) includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred on and after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 2004 through September 2005. Through August 31, 2006, APCo deferred as a regulatory asset $47 million of incremental E&R costs incurred since July 1, 2004 based on a legal opinion that such costs were probable of recovery under the law.

In January 2006, the Virginia SCC staff proposed that APCo be allowed to increase its electric rates at an ongoing level of $20 million to recover current, rather than past, incremental E&R costs. The staff proposal would effectively disallow the recovery of costs incurred prior to the authorization and implementation of new rates, including all incremental E&R costs that were deferred as a regulatory asset. At the E&R hearings, which concluded in March 2006, the staff amended its testimony to recommend a $24 million increase in APCo’s ongoing rates. In September 2006, the Hearing Examiner issued a report recommending adoption of the staff proposal with minor modifications, which would result in (a) an on-going level of E&R cost recovery of $29 million only if the Virginia SCC decides that any rate increase from the base rate case (described below) does not include the $29 million ongoing level of E&R costs, and (b) the disallowance of all previously deferred incremental E&R costs. In the third quarter of 2006, management concluded that the Virginia SCC might not grant recovery of actual incremental E&R costs incurred during the period from July 2004 through September 2006. Accordingly, APCo wrote off all of the E&R regulatory asset, adversely affecting pretax earnings by $36 million, net of the reinstatement of related AFUDC and capitalized interest. Management believes that the staff’s proposal and the Hearing Examiner’s recommendation are contrary to the statute. The Virginia SCC’s final order in this proceeding is pending.

If the Virginia SCC properly implements the statute as interpreted in its October 2005 order and as supported by the Virginia Attorney General’s office in October 2006, APCo should be able to recover all of its incremental E&R costs prudently incurred since July 1, 2004. If the Virginia SCC adopts the Hearing Examiner's findings, based on advice of counsel, APCo will appeal the decision.

APCo Virginia Base Rate Case - Affecting APCo

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%. In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to the fuel factor where they can be adjusted annually. APCo also proposed to share the off-system sales margins with the customers with 40% going to reduce rates and 60% being retained by APCo. This resultant proposed off-system sales fuel rate credit, which is estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in revenues of $198 million. The major components of the $225 million rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity. In May 2006, the Virginia SCC issued an order, consistent with Virginia law, placing the net requested base rate increase of $198 million into effect October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed their direct testimony recommending a base rate increase of $13 million. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo plans to file rebuttal testimony in November 2006. Hearings are scheduled to begin in December 2006. Management is unable to predict the ultimate effect of this filing on APCo’s future revenues, cash flows and financial condition.

APCo West Virginia Rate Case - Affecting APCo

In July 2006, the WVPSC approved the settlement agreement APCo and WPCo reached with the WVPSC staff and intervenors in the West Virginia rate case filed in 2005. The settlement agreement provided for an initial overall increase in APCo’s rates of $40 million effective July 28, 2006 comprised of:

· A $50 million increase in Expanded Net Energy Cost (ENEC) for fuel, purchased power expenses, off-system sales credits and other energy-related costs;

· A $21 million special construction surcharge providing recovery of the costs of scrubbers and the Wyoming-Jacksons Ferry 765 kV line to date;

· A $16 million general base rate reduction resulting predominantly from a reduction in the return on equity to 10.5% and a $9 million reduction in depreciation expense which affects cash flows but not earnings; and

· A $15 million credit to refund a portion of deferred prior over-recoveries of ENEC recorded in regulatory liabilities on APCo’s Condensed Consolidated Balance Sheets, which will impact cash flows but not earnings.

In addition, the agreement provides a surcharge mechanism that allows APCo to adjust its rates annually for the timely recovery in each of the next three years of the incremental cost of ongoing environmental investments in scrubbers at Mountaineer and John Amos power plants and the costs of the new Wyoming-Jackson Ferry 765 kV line. Although the amount of these annual surcharge increases cannot be determined until the incremental costs are known and reviewed by the WVSPC, management estimates that they will result in an annual increase in APCo’s revenues of $32 million effective July 1, 2007, $13 million effective July 1, 2008 and $16 million effective July 1, 2009.

The settlement further provides for the reinstatement of the ENEC mechanism effective July 1, 2006 with over/under recovery deferral accounting and annual ENEC proceedings to affect annual rate adjustments for changes in fuel and purchased power costs beginning in 2007. The settlement provides for the return to customers of the remaining portion of the prior ENEC regulatory liability plus interest at LIBOR rate on the unrefunded balance in future ENEC proceedings.

I&M Depreciation Study Filing- Affecting I&M

In December 2005, I&M filed a petition with the IURC seeking authorization to revise its book depreciation rates applicable to its electric utility plant in service effective January 1, 2006. Based on a depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. A public hearing was held in May 2006 and the final brief was filed in June 2006. As proposed by I&M, the book depreciation expense reduction would increase its earnings, but would not impact its cash flows until electric service rates are revised.

An order issued by the IURC on October 19, 2006 does not dispute I&M's revised depreciation accounting rates but, nevertheless, denied I&M’s request to revise its book depreciation rates between base rate cases.  The IURC believes that depreciation rates for an electric utility should not be changed between general rate cases unless it was “absolutely essential” and a direct benefit to customers was shown. I&M has twenty days in which to file for a rehearing or reconsideration. I&M has not yet decided whether it will file for a rehearing or reconsideration or if and when it will file to adjust base rates to reflect the depreciation study.

KPCo Environmental Surcharge Filing - Affecting KPCo

In July 2006, KPCo filed its third annual environmental compliance plan seeking additional annual revenues of $2 million in 2007 and $6 million in 2008. The filing seeks recovery of KPCo’s share of AEP System Power Pool charges for the annual cost of retrofitting pollution control additions to affiliated AEP System east zone power plants. No intervenor testimony was filed in the case. Management expects the KPSC will rule on the filing in early 2007. Management is unable to predict the ultimate effect this filing will have on KPCo’s revenues and results of operations.

KPCo Rate Filing - Affecting KPCo

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

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

In 2002, PSO under-recovered $44 million of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO proposed collection of those reallocated costs over 18 months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 through 2003 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with their proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from their recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. The United States District Court for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals and will defend its position. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs or offsets under-recovered fuel deferrals with additional reallocated off-system sales margins, PSO’s future results of operations and cash flows could be adversely affected. However, if the position taken by the federal court in Texas applies to PSO’s case, the OCC could be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party may file a complaint at the FERC alleging the allocation of off-system sales margins adopted by PSO is improper which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies. Management is unable to predict the ultimate effect, if any, of these Oklahoma fuel clause proceedings and any future FERC proceedings on the AEP East companies’ and AEP West companies’ future results of operations, cash flows and financial condition.

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

In February 2006, a law was enacted requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served. PSO is subject to the required biennial reviews. The OCC staff indicated that it expects the review process to begin late 2006 or early 2007.

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

PSO Rate Filing - Affecting PSO

In September 2006, PSO filed a notice of its intent to file in November 2006 a plan to modify the base rates of PSO’s Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007.

SWEPCo Louisiana Fuel Inquiry - Affecting SWEPCo

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

SWEPCo PUCT Staff Review of Earnings - Affecting SWEPCo

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

SWEPCo Louisiana Compliance Filing - Affecting SWEPCo

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. In April 2004, at the request of the LPSC, SWEPCo filed updated financial information with a test year ending December 31, 2003. Both filings indicated that SWEPCo’s rates should not be reduced. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed updated financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorized return on equity of 11.1%.

In July 2006, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, based on a proposed 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain ongoing operations and maintenance expense levels and the recommended base rate reduction does not include the impact of a proposed consolidated federal income tax adjustment, which, if approved, would increase the proposed rate reduction. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. Hearings are expected to occur late in the fourth quarter of 2006. A decision is not expected until 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ultimately ordered, it would adversely impact SWEPCo’s future results of operations and cash flows.

TCC and TNC Rate Filings - Affecting TCC and TNC

In September 2006, TCC and TNC announced that each will file transmission and distribution wires rate cases in Texas in late 2006. Management anticipates requesting an $83 million annual increase for TCC and a $25 million annual increase for TNC. Both requests include the impact of the expiration of the CSW merger savings credits.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC

Several parties including the Office of Public Utility Counsel and cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s former affiliated REPs, respectively). In June 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued in July 2005, the Texas Court of Appeals reversed the District Court. The cities appealed the appeals court decision to the Supreme Court of Texas, which has ordered full briefing, but has not granted review. Management cannot predict the outcome of further appeals, but a reversal of the favorable court of appeals decision regarding the loss of load issue could result in the issue being returned to the PUCT for further consideration. If that were to happen and if the PUCT orders refunds of PTB revenues, it could adversely impact TCC’s and TNC’s results of operations and cash flows for the portion of the refund applicable to the period of time that they owned the REPs.

RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo and OPCo

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. The total amortization related to such costs was $1 million in both the third quarter of 2006 and 2005. In the first nine months of 2006 and 2005, total amortization related to such costs was $4 million and $3 million, respectively.

The AEP East companies’ deferred unamortized RTO formation/integration costs were as follows:

	September 30, 2006				December 31, 2005
	PJM-Billed Integration Costs		Non-PJM Billed Formation/ Integration Costs		PJM-Billed Integration Costs		Non-PJM Billed Formation/ Integration Costs
	(in millions)
APCo	$	3.7	$	4.8	$	4.1	$	4.9
CSPCo		1.5		1.9		1.7		1.9
I&M		3.0		3.4		3.2		3.7
KPCo		0.9		1.1		1.0		1.1
OPCo		4.3		5.0		4.7		5.1

In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs and related carrying costs not billed by PJM of $2 million per year. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone. As a result, the AEP East companies will need to recover the 85% through their retail rates.

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

As a result of recently approved rate increases, CSPCo, OPCo and KPCo recover the amortization of RTO formation/integration costs billed to the AEP East companies in Ohio and Kentucky. APCo received approval to include the amortization of RTO formation/integration costs in retail rates in West Virginia effective July 28, 2006. In Virginia, APCo filed a base rate case, which includes recovery of these costs when rates became effective October 2, 2006, subject to refund. In Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded from recovering its share of the deferred RTO costs until that date or until it can file for a rate increase in Indiana. I&M has not yet filed for recovery in Michigan.

Until I&M can adjust its retail rates in Indiana and Michigan to recover the amortization of its deferred RTO formation/integration costs, its results of operations and cash flows will be adversely affected. If the Virginia, Indiana or Michigan commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs, it could adversely impact APCo’s and/or I&M’s future results of operations and cash flows. In the event of a disallowance, management would appeal that decision to the appropriate state or federal courts.

Transmission Rate Proceedings at the FERC - Affecting APCo, CSPCo, I&M, KPCo and OPCo

SECA Revenue Subject to Refund

In accordance with FERC orders, the AEP East companies collected SECA rates to mitigate lost through-and-out transmission service (T&O) revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected subject to refund or surcharge. The AEP East companies also paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid.

The AEP East companies recognized gross SECA revenues as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006 (a)		2005
	(in millions)
APCo	$	-	$	13.6	$	13.4	$	39.1
CSPCo		-		7.7		7.9		20.8
I&M		-		8.0		8.1		22.5
KPCo		-		3.2		3.2		9.3
OPCo		-		10.6		10.4		28.8

(a) Represents revenues through March 31, 2006, when SECA rates expired, and excludes the provision for refund recorded in the second quarter of 2006 discussed below.

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

A hearing in the SECA case was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates were not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory, and that new compliance filings and refunds should be made. The ALJ also found that unpaid SECA rates must be paid in the recommended reduced amount.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund, and have reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. It would also provide refunds of SECA rates paid by the AEP East companies in considerably less significant amounts.

The AEP East companies provided for net refunds, most of which were recorded in the second quarter of 2006 as shown in the following table.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in thousands)
APCo	$	-	$	0.3	$	6.1	$	0.7
CSPCo		-		0.2		3.4		0.4
I&M		-		0.2		3.6		0.4
KPCo		-		0.1		1.4		0.2
OPCo		-		0.3		4.6		0.5

AEP, together with Exelon and DP&L, filed an extensive brief noting exceptions to the initial ALJ decision and asking the FERC to reverse the decision in large part. Reply briefs were filed in October 2006. Management believes that the FERC should reject the initial ALJ decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. As a result, the AEP East companies have not provided for a possible refund of SECA rates in excess of current provisions. If the FERC does adopt the ALJ’s recommendations, AEP will appeal the decision to the courts. Although AEP believes it has meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on the AEP East companies’ future results of operations and cash flows.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement which allowed increases in wholesale transmission OATT rates in three steps: first, beginning retroactively on November 1, 2005, second, beginning on April 1, 2006 when the SECA revenues were eliminated and third, beginning on August 1, 2006 when the new Wyoming-Jacksons Ferry 765 kV line went into service. Management estimates that this rate increase will increase wholesale transmission revenues by $22 million in 2006 and $28 million in 2007.

The Elimination of T&O and SECA Rates and the FERC PJM Regional Transmission Rate Proceeding

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

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

· AEP/AP proposed a Highway/Byway rate design in which:

           · The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.

           · The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.

· Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues than the AEP/AP proposal.

· In a competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues than the AEP/AP proposal.

· In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues than the AEP/AP proposal.

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

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

From the elimination of T&O rates in December 2004 through the expiration of SECA rates on March 31, 2006, SECA transition rates failed to fully compensate the AEP East companies for their lost T&O revenues. Effective with the expiration of the SECA transition rates on March 31, 2006, the increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone was not sufficient to replace the prior T&O revenues or the lower temporary SECA transition rate revenues; however, a favorable outcome in the PJM regional transmission rate proceeding, made retroactive to April 1, 2006 could mitigate a large portion of the shortfall. Full mitigation of the effects of eliminated T&O revenues and the less favorable terminated SECA revenues will require cost recovery through state retail rate proceedings pending any resolution that may result from the above FERC regional transmission rate proceeding. The status of such state retail rate proceedings is as follows:

· In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.

· In Ohio, CSPCo and OPCo recover the FERC-approved OATT which reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.

· In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.

· In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.

· In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.

· In Michigan, I&M has not yet filed to seek recovery of the lost transmission revenues.

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

Management believes that the AEP/AP proposal of the Postage Stamp proposal combined with the retail rate recovery discussed above would be an effective replacement for the eliminated T&O and SECA rates.

Management is unable to predict whether the FERC will approve either the ALJ’s decision or another regional rate design. The AEP East companies’ future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues and the resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates in Indiana and Michigan.

Calpine Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From SPP - Affecting PSO and SWEPCo

In April 2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate schedule to charge SPP for reactive power from Calpine’s generating facility. The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCO and a small portion of TNC operate in SPP. An ALJ initially ruled against Calpine and management concluded that the likelihood of the FERC awarding Calpine a reactive power capacity rate was remote. In September 2006, the FERC issued its decision reversing the ALJ decision, granting Calpine’s request and requiring Calpine to make a compliance filing within 30 days. PSO’s, SWEPCo’s and TNC’s share of this SPP expense could be approximately 90% of the total amount billed by Calpine. Based on this information, PSO and SWEPCo recorded expense provisions, including interest, of $4 million and $4 million, respectively, in September 2006 for the retroactive reactive power liability. AEP will seek rehearing at the FERC and may appeal the decision if the FERC either denies rehearing or rules in favor of Calpine on rehearing.

Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement - Affecting the AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved our proposed methodology effective April 1, 2006 and beyond. The approved allocation methodology for the AEP East companies and AEP West companies is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies, which effectively allowed the AEP West companies to share in PJM and MISO regional margins. In February 2006, AEP filed with the FERC to remove TCC and TNC from the SIA and CSW Operating Agreement because they are in the final stages of exiting the generation business and have already ceased serving retail load. The FERC approved the removal of TCC and TNC from the SIA and CSW Operating Agreement effective May 1, 2006. The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of expanded net energy fuel clause recovery mechanisms and related off-system sales sharing mechanisms by state.

        4.CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

The Customer Choice and Industry Restructuring note in the 2005 Annual Report should be read in conjunction with this report 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 in those states and updates the 2005 Annual Report.

TEXAS RESTRUCTURING - Affecting TCC, TNC and SWEPCo

In February 2006, the PUCT issued an order in TCC’s $2.4 billion True-up Proceeding, which determined that TCC’s true-up regulatory asset was $1.475 billion including carrying costs through September 2005. In December 2005, TCC adjusted its recorded net true-up regulatory asset to comply with the order. The PUCT issued an order on rehearing in April 2006, which made minor changes to, but otherwise affirmed, the February 2006 order. TCC appealed, seeking additional recovery consistent with the Texas Restructuring Legislation and related rules. Other parties appealed the PUCT’s true-up order claiming it permits TCC to over-recover stranded generation costs and other true-up items.

TCC Securitization Proceeding

TCC filed an application in March 2006 requesting recovery through securitization of $1.8 billion of net stranded generation plant costs and related carrying costs through August 31, 2006. The $1.8 billion request did not include TCC’s negative other true-up items, which total $478 million. See “CTC Proceeding for Other True-up Items” section of this note. Intervenors and the PUCT staff filed testimony regarding TCC’s securitization request in April 2006. In May 2006, TCC filed a letter with the PUCT reducing its request by $6 million of current carrying costs and reduced the recorded net recoverable regulatory asset by the recorded debt-related component. In May 2006, TCC and the other parties filed a settlement with the PUCT, which further reduced the securitizable amount by $77 million and settled several issues that would have delayed the sale of the securitization bonds. The PUCT approved the settlement in June 2006 authorizing $1.697 billion including carrying costs through August 31, 2006, the assumed securitization date, plus estimated issuance costs of $23 million, for a total of $1.72 billion. TCC issued its securitization bonds on October 11, 2006 for $1.74 billion, including additional issuance costs and carrying costs to October 11, 2006.

TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT. TCC determined that the projected cash flows from the securitization less the proposed CTC refund would be more than sufficient to recover its recorded net true-up regulatory asset due to the existence of $224 million of unrecorded equity-related carrying costs which are not recorded until collected in regulated rates. As a result, no additional impairment was recorded for the approved reduction in the amount to be securitized. However, the $77 million agreed upon reduction in the securitizable amount will have a negative impact on future earnings.

Consistent with certain prior securitization determinations, the PUCT issued a specific order in the securitization proceeding that calculated a $315 million cost-of-money benefit from true-up related ADFIT through August 2006, of which $75 million ($77 million through September 30, 2006) relates to the recorded benefit prior to the date of securitization and $240 million relates to the unrecorded benefit subsequent to the date of securitization. The PUCT included the $315 million ADFIT-related stranded cost benefit in the CTC refund of $478 million. In June 2006, TCC transferred the effects of the ADFIT on recorded carrying costs from the securitizable asset to the CTC refund, thereby increasing the carrying costs identified to the securitizable assets in the table below.

The differences between the securitization amount ordered by the PUCT of $1.74 billion and the Recorded Securitizable True-up Regulatory Asset of $1.57 billion by component at September 30, 2006 are detailed in the table below:

	(in millions)
Stranded Generation Plant Costs	$	974
Net Generation-related Regulatory Asset		249
Excess Earnings		(49	)
Recorded Net Stranded Generation Plant Costs		1,174
Recorded Debt Carrying Costs on Net Stranded Generation Plant Costs		400
Recorded Securitizable True-up Regulatory Asset		1,574
Unrecorded But Recoverable Equity Carrying Costs		224
Unrecorded Estimated October 2006 Debt Carrying Costs		3
Unrecorded Excess Earnings, Related Carrying Costs and Other		53
Unrecorded Settlement Reduction		(77	)
Reduction for the Present Value of ADITC and EDFIT Benefits		(61	)
Approved Securitizable Amount as of October 11, 2006		1,716
Unrecorded Securitization Bond Issuance Costs		24
Amount Securitized on October 11, 2006	$	1,740

Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s true-up and securitization orders, the PUCT reduced net stranded generation plant costs and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generating assets. (See Reduction for the Present Value of ADITC and EDFIT Benefits of $61 million in the table above.) TCC testified that the sharing of these tax benefits with customers might be a violation of the Internal Revenue Code’s normalization provisions.

TCC filed a request for a private letter ruling from the IRS in June 2005 to determine whether the PUCT’s action would result in a normalization violation. The IRS issued its private letter ruling on May 9, 2006 which stated that the PUCT’s flow through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. TCC informed the PUCT on May 10, 2006 of the adverse ruling, however, the PUCT did not change its order on rehearing. TCC filed an appeal with the PUCT. As discussed below in the “CTC Proceeding for Other True-up Items” section of this note, TCC proposed, and the PUCT agreed, to defer refunding the amount of the present value of its ADITC and EDFIT benefits through its CTC until this normalization issue is resolved upon the IRS issuance of final normalization regulations.

If a normalization violation occurs, it could result in the repayment of TCC’s ADITC on all property, including transmission and distribution property, which approximates $104 million as of September 30, 2006 and also a loss of the right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows through the appeal of the PUCT’s true-up order and through a CTC deferral.

CTC Proceeding for Other True-up Items

In June 2006, TCC filed to implement a negative CTC to refund its other true-up items over eight years. TCC will incur interest expense on the other true-up regulatory liability balances until it is fully refunded. The principal components of the CTC refund liability are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance.

The differences between the components of TCC’s Recorded Net Regulatory Liabilities - Other True-up Items of $238 million as of September 30, 2006 (including interest expense) and its Net CTC Refund Proposed of $357 million are detailed below:

	(in millions)
Wholesale Capacity Auction True-up	$	61
Carrying Costs on Wholesale Capacity Auction True-up		31
Retail Clawback including Carrying Costs		(65	)
Deferred Over-recovered Fuel Balance		(184	)
Retrospective ADFIT Benefit		(77	)
Other		(4	)
Recorded Net Regulatory Liabilities - Other True-up Items		(238	)
Unrecorded Prospective ADFIT Benefit		(240	)
Gross CTC Refund Proposed		(478	)
FERC Jurisdictional Fuel Refund Deferral		16
ADITC and EDFIT Benefit Refund Deferral		98
Net CTC Refund Proposed, After Deferrals		(364	)
True-up Proceeding Expense Surcharge		7
Net CTC Refund Proposed, After Deferrals and Expenses	$	(357	)

TCC requested that a portion of the refund be deferred, pending the outcome of two contingent federal matters related to the refund of $16 million of FERC jurisdictional fuel over-recoveries (discussed below) and $98 million (including carrying costs) related to potential tax normalization violation matters related to the refund of ADITC and EDFIT benefits (discussed above). Under TCC’s proposal, (a) if the two contingent federal matters are resolved consistent with the PUCT’s treatment, TCC will then refund the $16 million and the $98 million plus carrying costs or (b) if these two issues are not resolved consistent with the PUCT’s treatment, the deferred refunds will not be made in order to avoid a normalization violation and the violation of a Federal court order. Management cannot predict the final outcome of this filing.

Although TCC proposed to refund the $357 million over eight years, certain intervenors supported accelerated refunds. In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that TCC began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) to residential customers by the end of 2006. The CTC refund to the other customer classes during the interim period will be as proposed by TCC, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Fuel Balance Recoveries

In September 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding regarding the PUCT’s reallocation of off-system sales margins. In August 2006, TCC also received an order from the Federal District Court, Western District of Texas precluding the PUCT from enforcing its ruling regarding the PUCT’s reallocation of off-system sales margins in connection with TCC’s final fuel reconciliation. The favorable Federal District Court order, if upheld on appeal, could result in reductions to the over-recovered fuel principal balances of $8 million for TNC and $14 million ($16 million with carrying costs) for TCC. The PUCT appealed the TCC and TNC Federal Court decision to the United States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal court system, the PUCT may file a complaint at the FERC to address the allocation issue. TCC and TNC are unable to predict if the Federal District Court’s decision will be upheld or whether the PUCT will file a complaint at the FERC. Pending further clarification, TCC and TNC have not reversed their related provisions for fuel over-recovery. If the PUCT or another party were to file a complaint at the FERC that results in the PUCT’s decisions being reinstated, it could result in an adverse effect on results of operations and cash flows for the AEP East companies because an unfavorable FERC ruling may result in a reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits.

Carrying Costs on Net True-up Regulatory Assets Impacting Securitization and CTC Proceedings

In TCC’s True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79% overall pretax weighted average cost of capital rate approved in its unbundled cost of service rate proceeding. The recorded embedded debt component of this carrying cost rate is 8.12%. Through September 30, 2006, TCC recorded $400 million of debt-related carrying costs on stranded generation plant costs included in the securitization proceeding. Equity carrying costs of $224 million related to amounts securitized will be recognized in income as collected. TCC will accrue interest expense until its net CTC refund is fully refunded. The interest expense on the net CTC refund totals $9 million and $11 million for the three and nine months ended September 30, 2006, respectively, and is included in Interest Expense on TCC’s Condensed Consolidated Statements of Income.

In June 2006, the PUCT adopted a proposed rule that prospectively changes the interest rate applied to TCC’s CTC refund balance. TCC anticipates that the rule change will reduce the rate TCC will pay on its CTC balance from 11.79% to 7.47%. TCC anticipates that the change will reduce its annual refund by approximately $8 million. The rule also provides for adjustments to the rate during subsequent rate case proceedings.

TNC True-up Proceeding

TNC filed a CTC proceeding in August 2005 to establish a rate to refund its net true-up regulatory liability. In December 2005, that proceeding was abated, pending a final ruling from TNC’s appeal to the federal court regarding the fuel proceeding (described above). In August 2006, the parties to TNC’s CTC proceeding filed a settlement that recommended implementing an interim refund of the true-up regulatory liability totaling $13 million, net of the amounts at issue in the federal court proceeding, over six months beginning in September 2006. In late August 2006, the PUCT approved the settlement and the net refund began in September 2006. TNC accrues interest expense on the unrefunded balance and will continue to do so until the balance is fully refunded.

Excess Earnings

As noted in the 2005 Annual Report, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings was unlawful under the Texas Restructuring Legislation. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. Management is unable to predict the ultimate outcome of these proceedings.

Summary

TCC’s recorded securitizable true-up regulatory asset at September 30, 2006 of $1.57 billion, net of the recorded net regulatory liabilities for other true-up items of $238 million, reflects the PUCT’s orders in TCC’s True-up Proceeding and its securitization proceeding. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in any subsequent proceedings or court rulings, TCC will amortize its total securitizable true-up regulatory asset commensurate with recovery over the 14-year term of the securitized bonds issued in October 2006. If TCC determines, as a result of future PUCT orders or appeal court rulings, that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and TCC is able to estimate the amount of a resultant impairment, it would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. Based on advice of Texas rate counsel, TCC appealed the PUCT orders seeking relief in both state and federal court where TCC believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. Municipal customers and other intervenors also appealed the same PUCT orders seeking to further reduce TCC’s true-up recoveries.

Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings or court appeals. If TCC succeeds in future appeals, it could have a material favorable effect on TCC’s future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, or if the PUCT does not approve TCC’s CTC filing as filed and, as a result, causes a normalization violation, it could have a material adverse effect on TCC’s future results of operations, cash flows and financial condition.

Texas Restructuring - SPP

In August 2006, the PUCT adopted a rule delaying customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s business operate in SPP. Approximately 3% of TNC’s operations are located in the SPP territory, with $13 million in net assets in SPP. A petition was filed in May 2006, requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) and TNC’s customers, facilities and certificated service located in the SPP area to SWEPCo. If this petition is successful, SWEPCo will be AEP’s only subsidiary affected by the delay in the SPP area.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo

Rate Stabilization Plans

In January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008 provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the request for additional revenues for specified costs. CSPCo’s potential for the additional annual 4% generation rate increases is diminished by approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008 due to the power acquisition rider approved by the PUCO in the Monongahela Power service territory acquisition proceeding and the recovery of pre-construction costs for its share of the jointly-owned IGCC plant (see “IGCC Plant” section of this note below). OPCo’s potential for additional annual 4% generation rate increases is diminished in 2006 by approximately one-quarter and to a lesser extent in 2007 due to the recovery of pre-construction costs for its share of the jointly-owned IGCC plant. The RSPs also provide that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004 and 2005 deferred environmental carrying costs and PJM-related administrative costs and congestion costs net of financial transmission rights (FTR) revenue related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $10 million and $26 million for CSPCo and $20 million and $58 million for OPCo in the third quarter and first nine months of 2006, respectively, from the RSP rate increases net of the amortization of RSP regulatory assets. These increases also include the recognition of equity carrying costs. As of September 30, 2006, CSPCo’s and OPCo’s unrecognized equity carrying costs from 2004 and 2005, which are recognized over the three-year RSP period, totaled $4 million and $28 million, respectively. As of September 30, 2006, CSPCo’s and OPCo’s unamortized RSP regulatory assets to be recovered through December 31, 2008 were $7 million and $36 million, respectively.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the RSPs and also argued that there was no POLR obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover any POLR charges. In DP&L’s proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, supporting the Ohio companies’ position that they can recover a POLR charge. In an appeal concerning First Energy companies’ RSP, the Ohio Supreme Court held that the PUCO’s decision to eliminate the offer to customers of a price determined through competitive bids was unlawful. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for the Ohio companies, which also did not include a competitive bid process, and remanded the case to the PUCO for further proceedings, not inconsistent with the decision in the appeal of the First Energy companies’ RSP. In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continued to collect RSP revenues. In accordance with the PUCO directive, in September 2006, CSPCo and OPCo submitted their proposal to provide additional options for customer participation in the electric market.

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

IGCC Plant

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases: Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery, or refund, in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power costs. The proposed recoveries in Phases 1 and 2 would be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008 under their RSPs. As of September 30, 2006, CSPCo and OPCo each deferred $8 million and each recovered $3 million of pre-construction IGCC costs. We are currently recovering the remaining deferred amounts through June 30, 2007.

In April 2006, the PUCO issued an order authorizing the Ohio companies to implement Phase 1 of the cost recovery proposal. In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over no more than a twelve-month period effective July 1, 2006. In its June order, the PUCO indicated if the Ohio companies have not commenced continuous construction of the IGCC plant within five years of the order, all charges collected for pre-construction costs, which are assignable to other jurisdictions, must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. No date for a further hearing has been set.

In June 2006, the Industrial Energy Users - Ohio (IEU), an intervenor in the PUCO proceeding, filed a Complaint for Writ of Prohibition at the Ohio Supreme Court to prohibit the use of the PUCO’s authorization by the Ohio companies to enforce the collection of the Phase 1 rates and to prohibit the PUCO from further entertaining any increase in rates for the IGCC project. The Court subsequently granted a PUCO motion to dismiss the Complaint for Writ of Prohibition.

In August 2006, IEU, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio companies believe that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. The Ohio companies, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, the Ohio companies’ future results of operations and cash flows will be adversely affected.

Transmission Rate Filing

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders for the Ohio companies. The transmission cost recovery riders are subject to an annual true-up process with over/under recovery mechanisms. In February 2006, the Ohio companies filed a request with the PUCO to incorporate all transmission costs and rates in their transmission cost recovery riders and institute a two-step increase to reflect the increases in the FERC-approved rates. In the filing, the first increase would be effective April 1, 2006 to reflect the Ohio companies’ share of the loss of SECA revenues and the second increase would be effective August 1, 2006 to recover their share of the cost of the new Wyoming-Jacksons Ferry 765 kV line. In May 2006, the PUCO issued an order approving a two-step increase in the transmission cost recovery riders with over/under recovery mechanisms, effective April 1, 2006. The new tariffs were filed with the PUCO and implemented in June 2006.

In October 2006, the Ohio companies filed for initial true-ups under the transmission cost recovery riders’ over/under recovery mechanisms. The filings reflect the refund of regulatory liabilities as of September 30, 2006 of $12 million and $16 million for CSPCo and OPCo, respectively, including carrying charges. These over-recoveries were reflected as part of the new transmission cost recovery rider filed to be effective January 2007. The Ohio companies anticipate the net effect of the new transmission cost recovery riders will result in increased cost recoveries over 2005 levels for CSPCo and OPCo of $27 million and $36 million, respectively, in 2006 and $15 million and $16 million, respectively, in 2007.

Distribution Service Reliability and Restoration Costs 

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

In March 2006, the Ohio companies filed an application with the PUCO to implement tariff riders to recover a portion of previously expensed incremental costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. CSPCo and OPCo each requested recovery of approximately $12 million of such costs, which was approved by the PUCO in August 2006. Effective September 1, 2006, the Ohio companies implemented the storm cost recovery riders, which will continue until they have collected the authorized amounts or one year, whichever is shorter. In September 2006, the Ohio Consumers’ Counsel filed a request for rehearing with the PUCO, which was denied in October 2006.

As a result of the above, in September 2006 CSPCo and OPCo each recorded regulatory assets of $7 million, favorably affecting earnings.

Ormet

In June 2006, the PUCO found that South Central Power Company (SCP), a nonaffiliate, was not providing or proposing to provide physically adequate service to Ormet Primary Aluminum Corporation and Ormet Primary Mill Products Corporation (together, Ormet). In October 2006, the PUCO convened a hearing to determine if an electric supplier, other than SCP, should be authorized to serve Ormet’s 520 MW load.

Subsequent to the hearing, the Ohio companies together with Ormet, its employees’ union and certain other interested parties filed a settlement agreement with the PUCO for approval. The settlement agreement provides for the reallocation of the service territories of CSPCo, OPCo and SCP so that Ormet’s Hannibal, Ohio facilities are located in a joint CSPCo/OPCo certified territory effective January 1, 2007. The settlement also provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH paid by Ormet and a to-be-determined market price submitted by management and reviewed by the PUCO. The recovery is accomplished by the amortization to income of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient, an increase in RSP generation rates under the additional 4% provision of the RSP. The $43 per MWH price for generation services is above the industrial RSP generation tariff but below current market prices.

Customer Choice Deferrals

As provided in stipulation agreements approved by the PUCO in 2000, the Ohio companies defer customer choice implementation costs and related carrying costs in excess of $20 million each. The agreements provide for the deferral of these costs as regulatory assets until the next distribution base rate cases. Through September 30, 2006, CSPCo and OPCo incurred $48 million and $49 million, respectively, of such costs and, accordingly, deferred $24 million each of such costs for probable future recovery in distribution rates. CSPCo and OPCo have not recorded $4 million and $5 million, respectively, of equity carrying costs, which are not recognized until collected. Pursuant to the RSPs, recovery of these amounts is subject to PUCO review and is deferred until the next distribution rate filing to change rates after the December 31, 2008 end of the RSP period. Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on the Ohio companies’ future results of operations and cash flows.

        5.COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within the 2005 Annual Report, certain Registrant Subsidiaries continue to be involved in various legal matters. The 2005 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since their disclosure in the 2005 Annual Report. See disclosure below for significant matters and changes in status subsequent to the disclosure made in the 2005 Annual Report.

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA and a number of states alleged that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The 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. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

The Federal EPA and eight northeastern states each filed an additional complaint containing additional allegations against the Amos and Conesville plants. APCo and CSPCo filed an answer to the northeastern states’ complaint and the Federal EPA’s complaint, denying the allegations and stating their defenses. Cases are also pending that could affect CSPCo’s share of jointly-owned units at Beckjord (12.5% owned), Zimmer (25.4% owned) and Stuart (26% owned) stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees.

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

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

Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo

In July 2004, two special interest groups, Sierra Club and Public Citizen, 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. In March 2005, the special interest groups filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005. Other preliminary motions have been filed and are pending before the Court.

In July 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, financial condition or cash flows.

Carbon Dioxide Public Nuisance Claims - Affecting AEP East Companies and AEP West Companies

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, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. That same day, the Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint in the same court against the same defendants. The actions alleged that CO₂ emissions from the defendants’ power plants 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. The trial court’s dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have been completed. Management believes the actions are without merit and intends to defend against the claims.

Ontario Litigation - Affecting CSPCo and OPCo

In June 2005, CSPCo, OPCo and nineteen nonaffiliated utilities were named as defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. CSPCo and OPCo have not been served with the lawsuit. The time limit for serving the defendants expired but the case has not been dismissed. 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, emitted NO_X, SO₂ and particulate matter that harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $49 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. Management believes CSPCo and OPCo have meritorious defenses to this action and intend to defend against it.

OPERATIONAL

Power Generation Facility and TEM Litigation - Affecting OPCo

AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA. In September 2006, AEP agreed to sell the Facility to Dow.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo 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 (approximately 270 MW). 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 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 U.S. District Court for the Southern District of New York. AEP alleged that TEM breached the PPA and sought a determination of its rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of AEP’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In April 2004, OPCo gave notice to TEM that OPCo (a) was suspending performance of its obligations under the PPA; (b) would seek a declaration from the District Court that the PPA was terminated; and (c) would pursue TEM and SUEZ-TRACTEBEL S.A. under the guaranty, seeking 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 breached the contract and awarded damages to AEP of $123 million plus prejudgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. AEP asked the court to modify the judgment to (a) award a termination payment to AEP under the terms of the PPA; (b) grant AEP’s attorneys’ fees; and (c) 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 January 2006, the trial judge granted AEP’s motion for reconsideration concerning TEM’s parent guaranty and increased AEP’s judgment against TEM to $173 million plus prejudgment interest, and denied the remaining motions for reconsideration. In March 2006, the trial judge amended the January 2006 order eliminating the additional $50 million damage award.

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. Oral argument is scheduled for December 2006. If the PPA is deemed terminated or found unenforceable by the court ultimately deciding the case, OPCo could be adversely affected to the extent OPCo is unable to find other purchasers of the power with similar contractual terms (if AEP’s sale of the Facility does not close) and to the extent claimed termination value damages are not fully recovered from TEM.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, disputed transportation costs for coal received between July 2000 and the present time. The joint plant remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded provisions for possible loss in 2004, 2005 and 2006. The provision was deferred as a regulatory asset under PSO’s fuel mechanism and immaterially affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.

Coal Transportation Rate Dispute - Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate, determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. At the end of 1991, PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board in January 2006. The arbitration board filed its decision in April 2006, which denied BNSF’s underpayments claim. In May 2006, PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court. In August 2006, PSO filed its response, to which BNSF filed its reply. Management continues to work toward mitigating the disputed amounts to the extent possible.

FERC Long-term Contracts - Affecting AEP East Companies and AEP West Companies

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in AEP’s favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the Nevada utilities' complaint, held that the markets for future delivery were not dysfunctional and that the Nevada utilities failed to demonstrate that the public interest required changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. The Nevada utilities’ request for a rehearing was denied. The Nevada utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals for the Ninth Circuit. Management is unable to predict the outcome of this proceeding and its impact on future results of operations and cash flows.

COMMITMENTS

Construction - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. The following table shows the revised estimated construction expenditures by Registrant Subsidiary for 2006:

	(in millions)
AEGCo	$	12
APCo		928
CSPCo		319
I&M		330
KPCo		54
OPCo		1,065
PSO		262
SWEPCo		315
TCC		286
TNC		72

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, legal reviews and the ability to access capital.

        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 of Others.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

Certain Registrant Subsidiaries have entered into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At September 30, 2006, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from December 2006 to March 2007.

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). If Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $68 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 provides guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and final reclamation is completed. At September 30, 2006, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036. The cost for final reclamation during the period 2029 through 2036 is estimated at approximately $39 million.

Indemnifications and Other Guarantees

Contracts

All of the Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Prior to September 30, 2006, TCC entered into sales agreements with a maximum indemnification exposure of $443 million related to the sale price of its generation assets. See “Texas Plants - South Texas Project” and “Texas Plants - TCC and TNC Generation Assets” sections of Note 10 of the 2005 Annual Report. There are no material liabilities recorded for any indemnifications.

AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Operating Lease

Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary has committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At September 30, 2006, the maximum potential loss by subsidiary for these lease agreements, assuming the fair market value of the equipment is zero at the end of the lease term, is as follows:

Maximum Potential Loss
Subsidiary	(in millions)
APCo	$	7
CSPCo		4
I&M		5
KPCo		2
OPCo		7
PSO		5
SWEPCo		5
TCC		6
TNC		3

     7.COMPANY-WIDE STAFFING AND BUDGET REVIEW

The following table shows the severance benefits expense recorded in 2005 (primarily in Maintenance and Other Operation) resulting from a company-wide staffing and budget review, including the allocation of approximately $19.2 million of severance benefits expense associated with AEPSC employees among the Registrant Subsidiaries. AEGCo has no employees but received allocated expenses.

	Three Months Ended Sept. 30, 2005		Nine Months Ended Sept. 30, 2005
Company	(in millions)
AEGCo	$	0.1	$	0.3
APCo		0.6		4.5
CSPCo		0.3		2.6
I&M		0.7		4.7
KPCo		0.4		1.1
OPCo		0.5		3.9
PSO		0.2		1.4
SWEPCo		0.2		1.8
TCC		0.5		4.3
TNC		0.2		1.3

Remaining accruals, reflected primarily in Current Liabilities - Other, ranged from $8 thousand to $1.1 million as of December 31, 2005, and were settled by June 30, 2006. Payments and accrual adjustments recorded during 2006 were immaterial.

     8.ACQUISITIONS, ASSETS HELD FOR SALE AND ASSET IMPAIRMENTS

ACQUISITIONS

Waterford Plant - Affecting CSPCo

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford, Ohio. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million.

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station - Affecting TCC

In January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004, TCC received notice from the nonaffiliated co-owners announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, TCC entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. Golden Spread challenged these agreements in State District Court in Dallas County. Golden Spread alleges that the Public Utilities Board of the City of Brownsville exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the nonaffiliated co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread in October 2005. TCC and the nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth District at Dallas. In May 2006, the Court of Appeals for the Fifth District at Dallas reversed the trial court’s judgment in favor of Golden Spread and held that the City of Brownsville properly exercised its right of first refusal to acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the matter, and its petition was denied. Golden Spread then appealed to the Supreme Court of Texas and in August 2006, the court requested a response from TCC, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville. Responses were due October 27, 2006. TCC cannot predict when these issues will be resolved. TCC does not expect the sale to have a significant effect on its future results of operations. TCC’s assets related to the Oklaunion Power Station are classified as Assets Held for Sale - Texas Generation Plants on TCC’s Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by the Registrant Subsidiaries.

Assets Held for Sale at September 30, 2006 and December 31, 2005 are as follows:

Texas Plants (TCC)	September 30, 2006		December 31, 2005
Assets:	(in millions)
Other Current Assets	$	2	$	1
Property, Plant and Equipment, Net		44		43
Total Assets Held for Sale - Texas Generation Plants	$	46	$	44

ASSET IMPAIRMENTS

Conesville Units 1 and 2 - Affecting CSPCo

In the third quarter of 2005, following an extensive review of the commercial viability of CSPCo’s Conesville Units 1 and 2, CSPCo committed to a plan to retire these units before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were considered retired as of the third quarter of 2005.

CSPCo recognized a pretax charge of approximately $39 million in the third quarter of 2005 related to its decision to retire the units. CSPCo classified the impairment amount in Asset Impairments and Other Related Charges on its Condensed Consolidated Statements of Income.

        9.BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.

The following tables provide the components of AEP’s net periodic benefit cost for the plans for the three and nine months ended September 30, 2006 and 2005:

Three Months Ended September 30, 2006 and 2005:	Pension Plans						Other Postretirement Benefit Plans
	2006			2005			2006			2005
	(in millions)
Service Cost	$	23		$	23		$	10		$	10
Interest Cost		57			57			26			26
Expected Return on Plan Assets		(82	)		(77	)		(24	)		(23	)
Amortization of Transition (Asset) Obligation		-			(1	)		7			6
Amortization of Net Actuarial Loss		20			13			5			5
Net Periodic Benefit Cost	$	18		$	15		$	24		$	24

Nine Months Ended September 30, 2006 and 2005:	Pension Plans						Other Postretirement Benefit Plans
	2006			2005			2006			2005
	(in millions)
Service Cost	$	71		$	69		$	30		$	31
Interest Cost		171			169			76			79
Expected Return on Plan Assets		(248	)		(232	)		(70	)		(68	)
Amortization of Transition (Asset) Obligation		-			(1	)		21			20
Amortization of Net Actuarial Loss		59			40			15			19
Net Periodic Benefit Cost	$	53		$	45		$	72		$	81

The following table provides the net periodic benefit cost (credit) for the three and nine months ended September 30, 2006 and 2005:

Three Months Ended September 30, 2006 and 2005:	Pension Plans					Other Postretirement Benefit Plans
	2006		2005			2006		2005
	(in thousands)
APCo	$	1,469	$	1,848		$	4,487	$	4,756
CSPCo		205		534			1,807		1,928
I&M		2,331		2,365			2,949		3,134
KPCo		360		376			512		515
OPCo		823		1,206			3,395		3,353
PSO		979		72			1,588		1,661
SWEPCo		1,222		364			1,578		1,642
TCC		772		(219	)		1,699		1,789
TNC		326		41			715		784

Nine Months Ended September 30, 2006 and 2005:	Pension Plans					Other Postretirement Benefit Plans
	2006		2005			2006		2005
	(in thousands)
APCo	$	4,406	$	5,544		$	13,465	$	15,248
CSPCo		615		1,602			5,417		6,273
I&M		6,992		7,095			8,855		10,229
KPCo		1,076		1,128			1,538		1,689
OPCo		2,478		3,618			10,187		10,812
PSO		2,935		216			4,764		5,329
SWEPCo		3,672		1,092			4,734		5,244
TCC		2,317		(657	)		5,091		5,732
TNC		978		123			2,145		2,507

        10.INCOME TAXES

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, management reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006 the following adjustments were recorded (in thousands):

Company	Decrease in SFAS 109 Regulatory Asset, Net		Decrease in State Income Tax Expense		Decrease in Deferred State Income Tax Liabilities
TCC	$	36,315	$	-	$	36,315
TNC		4,801		1,265		6,066
PSO		-		3,273		3,273
SWEPCo		4,438		501		4,939

        11.BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment. The one reportable segment is an integrated electricity generation, transmission and distribution business except AEGCo, which is an electricity generation business. All of the Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on the business process, cost structures and operating results.

        12.FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2006 were:

Company	Type of Debt	Principal Amount		Interest Rate	Due Date
		(in thousands)		(%)
Issuances:
APCo	Pollution Control Bonds	$	50,275	Variable	2036
APCo	Senior Unsecured Notes		250,000	5.55	2011
APCo	Senior Unsecured Notes		250,000	6.375	2036
I&M	Pollution Control Bonds		50,000	Variable	2025
OPCo	Pollution Control Bonds		65,000	Variable	2036
OPCo	Senior Unsecured Notes		350,000	6.00	2016
PSO	Senior Unsecured Notes		150,000	6.15	2016
SWEPCo	Pollution Control Bonds		81,700	Variable	2018

Company	Type of Debt		Principal Amount		Interest Rate	Due Date
			(in thousands)		(%)
Retirements and Principal Payments:
APCo	First Mortgage Bonds		$	100,000	6.80	2006
APCo	Other			8	13.718	2026
I&M	Pollution Control Bonds			50,000	6.55	2025
OPCo	Notes Payable			4,390	6.81	2008
OPCo	Notes Payable			6,500	6.27	2009
SWEPCo	Notes Payable			5,039	4.47	2011
SWEPCo	Notes Payable			2,250	Variable	2008
SWEPCo	Pollution Control Bonds			81,700	6.10	2018
TCC	Securitization Bonds	��		52,265	5.01	2010

In addition to the transactions reported in the tables above, the following table lists intercompany issuances and retirements of debt due to AEP:

Company	Type of Debt	Principal Amount		Interest Rate	Due Date
		(in thousands)		(%)
Issuances:
TCC	Notes Payable	$	125,000	5.14	2007
TCC	Notes Payable		70,000	5.86	2007
Retirements:
KPCo	Notes Payable		40,000	6.501	2006
OPCo	Notes Payable		200,000	3.32	2006
PSO	Notes Payable		50,000	3.35	2006

In October 2006, TCC issued $1.74 billion in securitization bonds as follows:

Principal Amount		Interest	Scheduled Final Payment
		Rate	Date
	(in thousands)	(%)
$	217,000	4.98	2010
	341,000	4.98	2013
	250,000	5.09	2015
	437,000	5.17	2018
	494,700	5.3063	2020

The proceeds will be used to retire TCC debt and equity, which are no longer needed to support stranded costs.

In October 2006, TCC retired $345 million in intercompany notes payable as follows:

Principal Amount		Interest	Due
		Rate	Date
	(in thousands)	(%)
$	150,000	4.58	2007
	125,000	5.14	2007
	70,000	5.86	2007

In October 2006, I&M had a required remarketing of $65 million of 2.625% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo had a required remarketing of $30 million of 2.80% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo issued $17.5 million of variable rate pollution control bonds and retired $17.5 million, 2.70% pollution control bonds due in 2007.

In November 2006, $100.6 million of pollution control bonds were put back to TCC on the put date of November 1, 2006. TCC intends to hold these bonds for reissuance at a later date.

Lines of Credit - AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. The AEP System corporate borrowing program operates in accordance with the terms and conditions approved in a regulatory order. The Utility Money Pool participants’ money pool activity and corresponding authorized limits for the nine months ended September 30, 2006 are described in the following table:

Company	Maximum Borrowings from Utility Money Pool		Maximum Loans to Utility Money Pool		Average Borrowings from Utility Money Pool		Average Loans to Utility Money Pool		Loans (Borrowings) to/from Utility Money Pool as of September 30, 2006			Authorized Short-Term Borrowing Limit
	(in thousands)
AEGCo	$	58,209	$	2,247	$	21,005	$	2,247	$	(14,938	)	$	125,000
APCo		283,872		314,064		200,248		194,781		93,764			600,000
CSPCo		48,337		95,977		15,133		35,929		60,417			350,000
I&M		128,071		-		64,123		-		(27,616	)		500,000
KPCo		46,156		11,993		24,285		4,384		(24,507	)		200,000
OPCo		351,302		40,382		100,212		15,845		(48,163	)		600,000
PSO		167,456		146,657		97,332		94,937		43,538			300,000
SWEPCo		127,291		24,209		56,984		10,722		7,018			350,000
TCC		117,429		49,193		44,416		23,779		25,304			600,000
TNC		22,218		34,574		6,269		8,381		(9,492	)		250,000
TNC (a)		10		13,947		8		13,834		13,875			-

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the nine months ended September 30, 2006 were 5.41% and 3.63%. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the nine months ended September 30, 2005 were 3.93% and 1.63%. The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2006 and 2005 are summarized for all Registrant Subsidiaries in the following table:

Company	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Nine Months Ended September 30, 2006		Average Interest Rate for Funds Borrowed from the Utility Money Pool for Nine Months Ended September 30, 2005		Average Interest Rate for Funds Loaned to the Utility Money Pool for Nine Months Ended September 30, 2006		Average Interest Rate for Funds Loaned to the Utility Money Pool for Nine Months Ended September 30, 2005
	(in percentage)
AEGCo		4.85		2.91		5.11		3.14
APCo		4.62		3.30		4.98		2.72
CSPCo		4.73		3.92		4.63		2.76
I&M		4.81		3.25		-		2.12
KPCo		4.92		3.52		4.97		2.54
OPCo		4.83		3.67		5.12		2.40
PSO		5.02		2.62		4.36		3.52
SWEPCo		5.01		3.64		4.36		2.60
TCC		4.79		3.07		4.71		2.43
TNC		4.81		-		4.56		3.13
TNC (a)		5.36		-		5.33		-

(a) In the third quarter of 2006, TNC created a new wholly-owned subsidiary, AEP Texas North Generation Company, LLC. Following the creation of this subsidiary, TNC transferred all of its mothballed generation assets and related liabilities to this new subsidiary, effectively completing the business separation requirement of the Texas Restructuring Legislation. Subsequently, AEP Texas North Generation Company, LLC became a participant in the Nonutility Money Pool. For the nine months ended September 30, 2006, the maximum and minimum interest rates for funds either borrowed from or loaned to the Nonutility Money Pool were 5.39% and 5.28% respectively.

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the management’s discussion and analysis of Registrant Subsidiaries. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and results of operations and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, and (iii) footnotes of each individual registrant. The Combined Management’s Discussion and Analysis of Registrants Subsidiaries section of the 2005 Annual Report should also be read in conjunction with this report.

Construction Expenditures

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. The following table shows the revised estimated construction expenditures by Registrant Subsidiary for 2006:

	(in millions)
AEGCo	$	12
APCo		928
CSPCo		319
I&M		330
KPCo		54
OPCo		1,065
PSO		262
SWEPCo		315
TCC		286
TNC		72

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, legal reviews and the ability to access capital.

Environmental Matters

The Registrant Subsidiaries have committed to substantial capital investments and additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

· Requirements under the CAA to reduce emissions of SO₂, NO_x, particulate matter, and mercury from fossil fuel-fired power plants;

· Requirements under the Clean Water Act to reduce the impacts of water intake structures on aquatic species at certain power plants; and

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

In addition, the Registrant Subsidiaries are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites, and incur costs for disposal of spent nuclear fuel and future decommissioning of I&M’s nuclear units.

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. A separate lawsuit, initiated by certain environmental intervenor groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and 2000 against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at our power plants occurred over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

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

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

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

Adoption of New Accounting Pronouncements

Beginning in 2006, the Registrant Subsidiaries adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, did not materially affect the Registrant Subsidiaries’ quarter-over-quarter and year-to-date net income (loss). See Note 2 - New Accounting Pronouncements in the Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries for further discussion.

CONTROLS AND PROCEDURES

During the third quarter of 2006, management, including the principal executive officer and principal financial officer of each of AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2006, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see Note 5, Commitments and Contingencies, incorporated herein by reference.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2005 includes a detailed discussion of our risk factors. The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in our 2005 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

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

In September 2006, based on a report by the Hearing Examiner in our Virginia Environmental and Reliability costs rate case, we wrote off all of the regulatory asset related to environmental controls, transmission costs (including line construction) and other system reliability work incurred July 2004 through September 2006, adversely affecting pretax earnings by $36 million.

In addition, APCo filed a request with the Virginia SCC in May 2006 seeking an increase in base rates of $225 million to recover increasing costs, including a return on equity of 11.5%. APCo also requested to apply off-system sales margins (currently credited to customers through base rates) to the fuel factor where they can be adjusted annually. APCo also requested to retain a portion of the off-system sales margins. This proposed off-system sales fuel rate credit is projected to be $27 million annually. It would partially offset the $225 million requested increase in base rates for a net increase in revenues of $198 million. In May 2006, the Virginia SCC issued an order placing the full requested base rate increase into effect as of October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed their direct testimony recommending a base rate increase of $13 million. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo plans to file rebuttal testimony in November 2006. Hearings are scheduled to begin in December 2006.

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

The West Virginia Public Service Commission approved our pending West Virginia base rate case settlement agreement in July 2006. Therefore, this risk factor is no longer applicable.

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

The Kentucky Public Service Commission approved our pending Kentucky base rate case settlement agreement in March 2006. Therefore, this risk factor is no longer applicable.

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

In October 2005, the staff of the PUCT reported results of its review of SWEPCo’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 engaged SWEPCo in discussions to reconcile the earnings calculation and consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo in April 2006 that they would not pursue the matter further.

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

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

Risks Related to Owning and Operating Generating Assets and Selling Power

The amount we charge third parties for using our transmission facilities may be reduced and not recovered.(Applies to AEP and AEP’s East zone public utility subsidiaries.)

In July 2003, the FERC issued an order directing PJM and the MISO to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed MISO and PJM expanded regions (Combined Footprint). The elimination of the T&O rates reduces the transmission service revenues collected by the RTOs and thereby reduces the revenues received by transmission owners under the RTOs’ revenue distribution protocols. To mitigate the impact of lost T&O revenues, the FERC approved SECA transition rates beginning in December 2004 and extending through March 2006. SECA fees of $220 million were collected subject to refund.

A hearing in the SECA case was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates were not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory, and that new compliance filings and refunds should be made. The ALJ also found that unpaid SECA rates must be paid in the recommended reduced amount.

We have reached settlements with certain customers related to approximately $70 million of SECA revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. It would also provide refunds of SECA rates paid by the AEP East companies in considerably less significant amounts. Based on the completed settlements, and before the issuance of the ALJ’s initial decision, the AEP East companies provided for $22 million in net refunds, of which $18 million was recorded in the second quarter of 2006 in Utility Operations Revenues on the Condensed Consolidated Statements of Operations.  

Approximately $19 million of these recorded SECA revenues billed by PJM were never collected. The AEP East companies filed a motion with the FERC to force payment of these SECA billings. The FERC has not yet acted on the motion.

Although we believe we have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.

SECA transition rates have not fully compensated AEP for lost T&O revenues. SECA transition rates expired at the end of March 2006, and all transmission costs that would otherwise have been covered by T&O rates in the Combined Footprint are now subject to recovery from native load customers of AEP’s East zone public utility subsidiaries.

Management is unable to predict whether the FERC will approve either the ALJ’s decision or when, and if, the effect of the loss of T&O/SECA transmission revenues will be recoverable on a timely basis in each of the AEP East state retail jurisdictions and/or from transmission users within the PJM region.

Risks Relating to State Restructuring

Our Rate Stabilization Plans in Ohio may be modified by the PUCO such that our deferred costs may not be recovered and rates may be reduced. (Applies to AEP, OPCo and CSPCo)

In January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and OPCo. The RSPs provide, among other things, for CSPCo and OPCo to raise their generation rates on an annual basis through 2008 by 3% and 7%, respectively. The RSPs also provide for possible additional annual generation rate increases of up to an average of 4% per year for specified costs. The RSPs also provide that CSPCo and OPCo can recover certain environmental carrying costs, PJM-related administrative costs and certain congestion costs. As of September 30, 2006, the unamortized RSP deferrals were $7 million for CSPCo and $36 million for OPCo.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the validity of the RSPs under Ohio’s electricity restructuring law. In May 2006, the Ohio Supreme Court remanded the rate stabilization plan of First Energy on the grounds that it failed to provide customers with a competitive bid generation supply option, as contemplated by the restructuring law. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for CSPCo and OPCo, which did not include a competitive process, and remanded the case to the PUCO for further proceedings.

In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continued to collect RSP revenues. In the first nine months of 2006, CSPCo and OPCo have collected an additional $89 million and $87 million, respectively, as a result of the RSPs. In accordance with the PUCO directive, in September 2006, CSPCo and OPCo submitted their proposal to provide additional options for customer participation in the electric market.

We are contractually required to operate a power generation facility that may indirectly force us to sell the facility’s excess energy at a loss. (Applies to AEP.)

We have agreed to lease from Juniper Capital L.P. a merchant power generation facility (“Facility”) near Plaquemine, Louisiana. We sublease the Facility to Dow. We operate the Facility for Dow. Dow uses a portion of the energy produced by the Facility and sells the excess power to us. We have agreed to sell up to all of the excess 800 MW to Tractebel at a price that is currently in excess of market. Tractebel alleged that the power purchase agreement was unenforceable. This agreement is now being litigated. A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that Tractebel had breached the contract and awarded us damages of $123 million plus prejudgment interest. Both parties have filed appeals. In January 2006, the trial court increased AEP’s judgment against Tractebel to $173 million plus prejudgment interest. In March 2006, the trial judge amended the January 2006 order to eliminate the additional $50 million damage award. If the trial award is reversed or if Tractebel does not pay the judgment, our cash flow will be adversely affected.

In August 2006, we reached an agreement to sell the Facility to Dow for $64 million. We expect the sale to close in November 2006. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on our agreement to sell the Facility to Dow. The sale agreement also allows us to participate in gross margin sharing on the Facility for five years. In addition, Dow will reduce an existing below-current-market long-term power supply contract with us in Texas by 50 MW. We also retain the right to any judgment paid by TEM for breaching the original PPA, as discussed above.

If the sale of the Facility to Dow does not close, we will be required to find new purchasers for up to 800 MW. There can be no assurance that the power produced will be sold at prices that will exceed our costs to produce it. If that were the case, as a result of our obligations to Dow, we would be required to operate the Facility at a loss.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP (or its publicly-traded subsidiaries) during the quarter ended September 30, 2006 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased				Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
07/01/06 - 07/31/06		-			$	-		-	$	-
08/01/06 - 08/31/06		12	(a	)		73.00		-		-
09/01/06 - 09/30/06		30	(b	)		79.75		-		-

(a)	I&M repurchased 12 shares of its 4-1/8% cumulative preferred stock, in a privately-negotiated transaction outside of an announced program.
(b)	APCo repurchased 30 shares of its 4-1/2% cumulative preferred stock, in a privately-negotiated transaction outside of an announced program.

Item 5. Other Information

NONE

Item 6. Exhibits

AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP

31(a) - Certification of AEP Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(c) - Certification of AEP Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

31(b) - Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(d) - Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

32(a) - Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

32(b) - Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

AEP GENERATING COMPANY

AEP TEXAS CENTRAL COMPANY

AEP TEXAS NORTH COMPANY

APPALACHIAN POWER COMPANY

COLUMBUS SOUTHERN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

KENTUCKY POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

By: /s/Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

Date: November 6, 2006