Edgar Filing: AMERICAN ELECTRIC POWER CO INC

Unassociated Document

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 June 30, 2008

[ ] 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
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
1-6543	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, a non-accelerated filer, or a smaller reporting company. See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.

Large accelerated filer X Accelerated filer _____

Non-accelerated filer _____ Smaller reporting company ______

Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.
Large accelerated filer _____ Accelerated filer _______ Non-accelerated filer X Smaller reporting company _______

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

Columbus Southern Power Company and Indiana Michigan Power Company 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 July 31, 2008

American Electric Power Company, Inc.			402,258,849
			($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)
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

June 30, 2008

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

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 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


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 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

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 4.	Submission of Matters to a Vote of Security Holders
	Item 5.	Other Information
	Item 6.	Exhibits:
			Exhibit 3(a) (PSO, SWEPCo)
			Exhibit 3(b) (CSPCo, OPCo)
			Exhibit 12 (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
			Exhibit 31(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
			Exhibit 31(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
			Exhibit 32(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
			Exhibit 32(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)

SIGNATURE

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

GLOSSARY OF TERMS

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

Term

Meaning

AEGCo		AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent		American Electric Power Company, Inc.
AEP Consolidated		AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies		APCo, CSPCo, I&M, KPCo and OPCo.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP System or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies		PSO, SWEPCo, TCC and TNC.
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.
APSC		Arkansas Public Service Commission.
CAA		Clean Air Act.
CO2		Carbon Dioxide.
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.).
CTC		Competition Transition Charge.
CWIP		Construction Work in Progress.
DETM		Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE		United States Department of Energy.
E&R		Environmental compliance and transmission and distribution system reliability.
EaR		Earnings at Risk, a method to quantify risk exposure.
EITF		Financial Accounting Standards Board’s Emerging Issues Task Force.
EITF 06-10		EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.”
EPS		Earnings Per Share.
ERCOT		Electric Reliability Council of Texas.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FIN		FASB Interpretation No.
FIN 46R		FIN 46R, “Consolidation of Variable Interest Entities.”
FIN 48		FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”
FSP		FASB Staff Position.
FTR		Financial Transmission Right.
GAAP		Accounting Principles Generally Accepted in the United States of America.
HPL		Houston Pipeline Company, a former AEP subsidiary.

IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement		Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG		JMG Funding LP.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
KPSC		Kentucky Public Service Commission.
kV		Kilovolt.
KWH		Kilowatthour.
LPSC		Louisiana Public Service Commission.
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.
NSR		New Source Review.
NYMEX		New York Mercantile Exchange.
OCC		Corporation Commission of the State of Oklahoma.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement Benefit Plans.
OTC		Over-the-counter.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
REP		Texas Retail Electric Provider.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RSP		Rate Stabilization Plan.
RTO		Regional Transmission Organization.
S&P		Standard and Poor’s.
SCR		Selective Catalytic Reduction.
SEC		United States Securities and Exchange Commission.
SECA		Seams Elimination Cost Allocation.
SFAS		Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71		Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”

SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SIA		System Integration Agreement.
SNF		Spent Nuclear Fuel.
SO2		Sulfur Dioxide.
SPP		Southwest Power Pool.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant.
Sweeny		Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP. AEP’s 50% interest in Sweeny was sold in October 2007.
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.
Turk Plant		John W. Turk, Jr. Plant.
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 and performance 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 (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are canceled) 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 of new investments in generation, distribution and transmission service and environmental compliance).
·	Resolution of litigation (including 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.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to refinance existing debt at attractive rates.
·	Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·	Actions of rating agencies, including changes in the ratings of debt.
·	Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·	Changes in utility regulation, including the implementation of the recently-passed utility law in Ohio and the allocation of costs within RTOs.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust.
·	Prices for power that we generate and sell at wholesale.
·	Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.

The registrants expressly disclaim any obligation to update any forward-looking information.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Base Rate Filings

Our significant base rate filings include:

Operating Company	Jurisdiction	Revised Annual Rate Increase Request			Projected Effective Date of Rate Increase
		(in millions)
APCo	Virginia	$	208		November 2008	(a)
PSO	Oklahoma		117	(b)	February 2009
I&M	Indiana		80		June 2009

(a)	Subject to refund.
(b)	Net of estimated amounts that PSO expects to recover through a generation cost recovery rider which will terminate upon implementation of the new base rates.

Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP). In July 2008, within the parameters of the ESPs, CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year. A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism.

Turk Plant

In July 2008, the PUCT approved a certificate of convenience and necessity for construction of the plant. We expect a written order in August 2008 which will also provide for the conditions of the PUCT’s approval. SWEPCo has received approvals from all of the state commissions that regulate its retail rates and services. However, the APSC approval has been appealed to the Arkansas State Court of Appeals. SWEPCo is working with the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers for approval later this year. Through June 30, 2008, SWEPCo capitalized $407 million in expenditures related to the Turk Plant.

IGCC Plants

Fuel Costs

We currently estimate 2008 coal prices to increase by about 20% due to escalating domestic prices and increased needs, primarily in the east. We had expected coal costs to increase by 13% in 2008. We continue to see increases in prices due to expiring lower priced coal and transportation contracts being replaced with higher priced contracts. Prices for fuel oil are at record highs and remain volatile. We have limited exposure to price risk related to our open positions for coal, natural gas and fuel oil especially since we do not currently have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs. However, under Ohio’s amended restructuring law, we have requested the PUCO to reinstate a fuel cost recovery mechanism effective January 1, 2009. Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

Capital Expenditures

We reduced our projections for capital expenditures to approximately $6.75 billion from $7.35 billion for 2009 through 2010.

RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their related business activities are as follows:

Utility Operations

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

MEMCO Operations

Barging operations that annually transport approximately 35 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lower Mississippi Rivers. Approximately 39% of the barging is for the transportation of agricultural products, 30% for coal, 14% for steel and 17% for other commodities. Effective July 30, 2008, AEP MEMCO LLC's name was changed to AEP River Operations, LLC.

Generation and Marketing

·	Wind farms and marketing and risk management activities primarily in ERCOT.

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss by segment for the three and six months ended June 30, 2008 and 2007.

	Three Months Ended June 30,								Six Months Ended June 30,
	2008				2007				2008			2007
	(in millions)
Utility Operations		$	263			$	238			$	673		$	491
MEMCO Operations			3				7				10			22
Generation and Marketing			26				15				27			14
All Other (a)			(12	)			(3	)			143			1
Income Before Discontinued Operations and Extraordinary Loss		$	280			$	257			$	853		$	528

(a)	All Other includes:
	·	Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
	·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts are financial derivatives which will gradually liquidate and completely expire in 2011.
	·	The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. The cash settlement of $255 million ($163 million, net of tax) is included in Net Income.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP Consolidated

Second Quarter of 2008 Compared to Second Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 increased $23 million compared to 2007 primarily due to an increase in Utility Operations segment earnings of $25 million. The increase in Utility Operations segment earnings primarily relates to rate increases implemented since the second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma, higher off-system sales and unfavorable regulatory provisions recorded in the prior year related to our Virginia and Texas jurisdictions, partially offset by higher operation and maintenance expenses system-wide and higher fuel expenses in Ohio.

Average basic shares outstanding increased to 402 million in 2008 from 399 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans. Actual shares outstanding were 402 million as of June 30, 2008.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 increased $325 million compared to 2007 primarily due to an increase in Utility Operations segment earnings of $182 million and income of $163 million (net of tax) from the cash settlement of a power purchase-and-sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. The increase in Utility Operations segment earnings primarily relates to rate increases implemented since the second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma, higher off-system sales and lower operation and maintenance expenses as a result of a favorable Oklahoma ice storm settlement partially offset by higher interest expense.

Average basic shares outstanding increased to 401 million in 2008 from 398 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans. Actual shares outstanding were 402 million as of June 30, 2008.

Utility Operations

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

Utility Operations Income Summary

For the Three and Six Months Ended June 30, 2008 and 2007

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(in millions)
Revenues	$	3,313	$	2,954	$	6,607	$	5,987
Fuel and Purchased Power		1,374		1,109		2,587		2,228
Gross Margin		1,939		1,845		4,020		3,759
Depreciation and Amortization		365		365		720		748
Other Operating Expenses		1,026		957		1,967		1,948
Operating Income		548		523		1,333		1,063
Other Income, Net		47		27		89		45
Interest Charges and Preferred Stock Dividend Requirements		218		207		428		386
Income Tax Expense		114		105		321		231
Income Before Discontinued Operations and Extraordinary Loss	$	263	$	238	$	673	$	491

Summary of Selected Sales and Weather Data

For Utility Operations

For the Three and Six Months Ended June 30, 2008 and 2007

		Three Months Ended June 30,				Six Months Ended June 30,
Energy/Delivery Summary		2008		2007		2008		2007
		(in millions of KWH)
Energy
Retail:
	Residential		9,829		10,127		24,329		24,267
	Commercial		9,909		10,227		19,456		19,586
	Industrial		15,060		14,848		29,410		28,413
	Miscellaneous		639		632		1,248		1,245
Total Retail			35,437		35,834		74,443		73,511

Wholesale			10,932		9,376		22,597		18,154

Delivery
Texas Wires – Energy delivered to customers served by AEP’s Texas Wires Companies			7,132		6,746		12,955		12,577
Total KWHs			53,501		51,956		109,995		104,242

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.

Summary of Heating and Cooling Degree Days for Utility Operations

For the Three and Six Months Ended June 30, 2008 and 2007

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(in degree days)
Weather Summary
Eastern Region
Actual – Heating (a)		136		222		1,960		2,039
Normal – Heating (b)		175		174		1,943		1,966

Actual – Cooling (c)		272		367		272		382
Normal – Cooling (b)		278		275		281		278

Western Region (d)
Actual – Heating (a)		40		92		989		994
Normal – Heating (b)		35		33		966		991

Actual – Cooling (c)		675		622		700		678
Normal – Cooling (b)		652		656		672		674

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

Second Quarter of 2008 Compared to Second Quarter of 2007

Reconciliation of Second Quarter of 2007 to Second Quarter of 2008

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss

(in millions)

Second Quarter of 2007			$	238

Changes in Gross Margin:
Retail Margins	47
Off-system Sales	40
Transmission Revenues	11
Other Revenues	(4	)
Total Change in Gross Margin				94

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(70	)
Depreciation and Amortization	-
Taxes Other Than Income Taxes	(1	)
Carrying Costs Income	10
Interest Income	6
Other Income, Net	6
Interest and Other Charges	(11	)
Total Change in Operating Expenses and Other				(60	)

Income Tax Expense				(9	)

Second Quarter of 2008			$	263

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $25 million to $263 million in 2008. The key drivers of the increase were a $94 million increase in Gross Margin offset by a $60 million increase in Operating Expenses and Other and a $9 million increase in Income Tax Expense.

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

·	Retail Margins increased $47 million primarily due to the following:
	·	A $39 million increase related to net rate increases implemented in our Ohio jurisdictions, a $17 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $3 million increase in base rates in Texas and a $6 million increase in base rates in Oklahoma.
	·	A $38 million net increase due to adjustments recorded in the prior year related to the 2007 Virginia base rate case which included a second quarter 2007 provision for revenue refund.
	·	A $25 million increase due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.
	·	A $12 million increase related to increased usage by Ormet, an industrial customer in Ohio. See “Ormet” section of Note 3.
	·	An $11 million increase primarily related to higher revenues under formula rate plans at I&M.
	These increases were partially offset by:
	·	A $90 million decrease related to increased fuel, consumable and PJM costs in Ohio which included a $29 million expense resulting from a coal contract amendment.
	·	A $20 million decrease in usage related to weather primarily from a 26% decrease in cooling degree days and a 39% decrease in heating degree days in our eastern region.
·	Margins from Off-system Sales increased $40 million primarily due to higher east physical off-system sales margins mostly due to higher volumes and stronger prices, partially offset by lower trading margins.
·	Transmission Revenues increased $11 million primarily due to increased usage in the SPP and ERCOT regions and increased rates in the SPP region.

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

·	Other Operation and Maintenance expenses increased $70 million primarily due to increases in generation expenses for non-outage maintenance at Cook plant and outage expenses at other plants, transmission reliability expenses, recoverable PJM and customer account expenses in Ohio and administrative and general expenses primarily related to employee benefits.
·	Depreciation and Amortization expense was flat primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, offset by higher depreciable property balances and prior year adjustments related to the 2007 Virginia base rate case.
·	Carrying Costs Income increased $10 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·	Interest and Other Charges increased $11 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·	Income Tax Expense increased $9 million due to an increase in pretax income.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Reconciliation of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss

(in millions)

Six Months Ended June 30, 2007			$	491

Changes in Gross Margin:
Retail Margins	162
Off-system Sales	80
Transmission Revenues	19
Total Change in Gross Margin				261

Changes in Operating Expenses and Other:
Other Operation and Maintenance	11
Gain on Dispositions of Assets, Net	(19	)
Depreciation and Amortization	28
Taxes Other Than Income Taxes	(11	)
Carrying Costs Income	19
Interest Income	17
Other Income, Net	8
Interest and Other Charges	(42	)
Total Change in Operating Expenses and Other				11

Income Tax Expense				(90	)

Six Months Ended June 30, 2008			$	673

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $182 million to $673 million in 2008. The key drivers of the increase were a $261 million increase in Gross Margin and an $11 million decrease in Operating Expenses and Other offset by a $90 million increase in Income Tax Expense.

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

·	Retail Margins increased $162 million primarily due to the following:
	·	An $83 million increase related to net rate increases implemented in our Ohio jurisdictions, a $31 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $12 million increase in base rates in Texas and a $14 million increase in base rates in Oklahoma.
	·	A $33 million increase related to increased usage by Ormet, an industrial customer in Ohio. See “Ormet” section of Note 3.
	·	A $29 million increase related to coal contract amendments in 2008.
	·	A $28 million increase related to increased residential and commercial usage and customer growth.
	·	A $25 million increase due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.
	·	A $21 million increase related to increased sales to municipal, cooperative and other customers primarily a result of new power supply contracts and higher revenues under formula rate plans at I&M.
	These increases were partially offset by:
	·	A $79 million decrease related to increased fuel, consumable and PJM costs in Ohio.
	·	A $23 million decrease in usage related to weather primarily from a 29% decrease in cooling degree days in our eastern region.
·	Margins from Off-system Sales increased $80 million primarily due to higher east physical off-system sales margins mostly due to higher volumes and stronger prices, partially offset by lower trading margins.
·	Transmission Revenues increased $19 million primarily due to increased usage in the SPP and ERCOT regions and increased rates in the SPP region.

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

·	Other Operation and Maintenance expenses decreased $11 million primarily due to deferral of storm restoration costs, net of amortization, of $63 million in Oklahoma as a result of a rate settlement to recover 2007 storm restoration costs partially offset by an increase in generation expenses at Cook plant, the write-off of unrecoverable pre-construction costs for PSO’s canceled Red Rock Generating Facility, recoverable PJM and customer account expenses in Ohio and increases in administrative and general expenses primarily related to employee benefits.
·	Gain on Disposition of Assets, Net decreased $19 million primarily due to the cessation of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002. In 2007, we received the final earnings sharing payment of $20 million.
·	Depreciation and Amortization expense decreased $28 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances and prior year adjustments related to the Virginia base rate case.
·	Taxes Other Than Income Taxes increased $11 million primarily due to favorable adjustments to property tax returns recorded in the prior year.
·	Carrying Costs Income increased $19 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·	Interest Income increased $17 million primarily due to the favorable effect of claims for refund filed with the IRS.
·	Interest and Other Charges increased $42 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·	Income Tax Expense increased $90 million due to an increase in pretax income.

MEMCO Operations

Second Quarter of 2008 Compared to Second Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased to $3 million in 2008 from $7 million in 2007 primarily due to high water conditions and reduced northbound loadings. Fuel consumption and other operating costs were higher due to the sustained high water conditions on all major rivers on which we operate. Northbound loadings continue to be depressed as a result of reduced imports through the Gulf of Mexico.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased to $10 million in 2008 from $22 million in 2007 primarily due to high water conditions and reduced northbound loadings. Fuel consumption and other operating costs were higher due to the sustained high water conditions on all major rivers on which we operate. Northbound loadings continue to be depressed as a result of reduced imports through the Gulf of Mexico.

Generation and Marketing

Second Quarter of 2008 Compared to Second Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $26 million in 2008 from $15 million in 2007 primarily due to favorable marketing contracts in ERCOT, higher gross margins at the Oklaunion plant from optimization activities and an increase in income from wind farm operations.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $27 million in 2008 from $14 million in 2007 primarily due to favorable marketing contracts in ERCOT, higher gross margins at the Oklaunion plant from optimization activities and an increase in income from wind farm operations.

All Other

Second Quarter of 2008 Compared to Second Quarter of 2007

Loss Before Discontinued Operations and Extraordinary Loss from All Other increased to $12 million in 2008 from $3 million in 2007. The increase in the loss primarily relates to lower cash balances yielding lower interest income and higher interest expense due to the AEP Junior Subordinated Debentures issued in March 2008 and increased short-term borrowings.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from All Other increased to $143 million in 2008 from $1 million in 2007. In 2008, we had after-tax income of $163 million from a litigation settlement of a power purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. The settlement was recorded as a pretax credit to Asset Impairments and Other Related Items of $255 million in the accompanying Condensed Consolidated Statements of Income. In 2007, we had a $16 million pretax gain ($10 million, net of tax) on the sale of a portion of our investment in Intercontinental Exchange, Inc. (ICE).

AEP System Income Taxes

Income Tax Expense increased $15 million in the second quarter of 2008 compared to the second quarter of 2007 primarily due to an increase in pretax income.

Income Tax Expense increased $178 million in the six-month period ended June 30, 2008 compared to the six-month period ended June 30, 2007 primarily due to an increase in pretax 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

	June 30, 2008				December 31, 2007
	($ in millions)
Long-term Debt, including amounts due within one year	$	15,753	58.0	%	$	14,994	58.1	%
Short-term Debt		705	2.6			660	2.6
Total Debt		16,458	60.6			15,654	60.7
Common Equity		10,631	39.2			10,079	39.1
Preferred Stock		61	0.2			61	0.2

Total Debt and Equity Capitalization	$	27,150	100.0	%	$	25,794	100.0	%

Our ratio of debt to total capital decreased from 60.7% to 60.6% in 2008 due to our net earnings and increased common equity from stock issuances through stock compensation and dividend reinvestment plans.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability. We are committed to maintaining adequate liquidity. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements and common stock.

Credit Markets

We believe we have adequate liquidity under our credit facilities and the ability to issue long-term debt in the current credit markets. As of June 30, 2008, we had $313 million outstanding of tax-exempt long-term debt sold at auction rates that reset every 35 days. This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial Guaranty Insurance Co. Due to the exposure that these bond insurers have in connection with developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook. These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of our tax-exempt long-term debt. The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures. Through June 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion. We plan to continue the conversion and refunding process for the remaining $313 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, during the second half of 2008 to lower our interest rates as such opportunities arise.

As of June 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 1.45% to 1.68% and $384 million was issued at fixed rates ranging from 4.85% to 5.625%. As of June 30, 2008, trustees held, on our behalf, approximately $400 million of our reacquired auction rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At June 30, 2008, our available liquidity was approximately $3.1 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,500	March 2011
	Revolving Credit Facility		1,500	April 2012
Revolving Credit Facility			650	April 2011
Revolving Credit Facility			350	April 2009
Total			4,000
Cash and Cash Equivalents			218
Total Liquidity Sources			4,218
Less: AEP Commercial Paper Outstanding			698
Letters of Credit Drawn			429

Net Available Liquidity		$	3,091

The revolving credit facilities for commercial paper backup are structured as two $1.5 billion credit facilities. In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

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 June 30, 2008, we had credit facilities totaling $3 billion to support our commercial paper program. The maximum amount of commercial paper outstanding during the first six months of 2008 was $1.2 billion. The weighted-average interest rate of our commercial paper during the first six months of 2008 was 3.22%.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement. Under the facilities, we may issue letters of credit. As of June 30, 2008, $371 million of letters of credit were issued under the 3-year credit agreement to support variable rate demand notes.

Investments in Auction-Rate Securities

During the first six months of 2008, we sold all of our investment in auction-rate securities at par.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements, including the new agreements entered into in April 2008, contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At June 30, 2008, this contractually-defined percentage was 55.9%. Nonperformance of these covenants could result in an event of default under these credit agreements. At June 30, 2008, 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 major 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.

Our revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At June 30, 2008, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910. The Board of Directors declared a quarterly dividend of $0.41 per share in July 2008. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. We have the option to defer interest payments on the $315 million of AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock. We believe that these restrictions will not have a material effect on our results of operations, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

In the first quarter of 2008, Moody’s changed its outlook from stable to negative for APCo, SWEPCo, OPCo and TCC and affirmed its stable outlook for AEP and our other subsidiaries. Also in the first quarter, Fitch downgraded PSO and SWEPCo from A- to BBB+ for senior unsecured debt. In May 2008, Fitch revised APCo’s outlook from stable to negative. 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

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.

	Six Months Ended
	June 30,
	2008				2007
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	178			$	301
Net Cash Flows from Operating Activities			1,197				969
Net Cash Flows Used for Investing Activities			(1,645	)			(2,127	)
Net Cash Flows from Financing Activities			488				1,029
Net Increase (Decrease) in Cash and Cash Equivalents			40				(129	)
Cash and Cash Equivalents at End of Period		$	218			$	172

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs.

Operating Activities

	Six Months Ended
	June 30,
	2008			2007
	(in millions)
Net Income	$	854		$	451
Less Discontinued Operations, Net of Tax		(1	)		(2	)
Income Before Discontinued Operations		853			449
Depreciation and Amortization		736			763
Other		(392	)		(243	)
Net Cash Flows from Operating Activities	$	1,197		$	969

Net Cash Flows from Operating Activities increased in 2008 primarily due to the TEM settlement.

Net Cash Flows from Operating Activities were $1.2 billion in 2008 consisting primarily of Income Before Discontinued Operations of $853 million and $736 million of noncash depreciation and amortization. Other represents 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. Significant changes in other items include an increase in under-recovered fuel reflecting higher natural gas prices.

Net Cash Flows from Operating Activities were $1 billion in 2007 consisting primarily of Income Before Discontinued Operations of $449 million and $763 million of noncash depreciation and amortization. Other represents 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. Significant changes in other items resulted in lower cash from operations due to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.

Investing Activities

	Six Months Ended
	June 30,
	2008			2007
	(in millions)
Construction Expenditures	$	(1,608	)	$	(1,823	)
Acquisition of Darby and Lawrenceburg Plants		-			(427	)
Acquisition of Other Assets		(81	)		-
Proceeds from Sales of Assets		69			74
Other		(25	)		49
Net Cash Flows Used for Investing Activities	$	(1,645	)	$	(2,127	)

Net Cash Flows Used for Investing Activities were $1.6 billion in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan. Construction expenditures decreased compared to 2007 due to a decline in environmental, fossil, hydro and nuclear projects partially offset by increased expenditures for new generation and transmission projects.

Net Cash Flows Used for Investing Activities were $2.1 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan. We paid $427 million to purchase gas-fired generating units to acquire capacity at a cost below that of building a new, comparable plant.

In our normal course of business, we purchase and sell investment securities with cash available for short-term investments. We also purchase and sell investment securities within our nuclear trusts. The net amount of these activities is included in Other.

We forecast approximately $2.2 billion of construction expenditures for the remainder of 2008. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. These construction expenditures will be funded through results of operations and financing activities.

Financing Activities

	Six Months Ended
	June 30,
	2008			2007
	(in millions)
Issuance of Common Stock	$	72		$	90
Issuance/Retirement of Debt, Net		777			1,294
Dividends Paid on Common Stock		(330	)		(311	)
Other		(31	)		(44	)
Net Cash Flows from Financing Activities	$	488		$	1,029

Net Cash Flows from Financing Activities in 2008 were $488 million primarily due to the issuance of additional debt including $315 million of junior subordinated debentures and a net increase of $1 billion in outstanding senior unsecured notes partially offset by the reacquisition of a net $440 million of pollution control bonds and retirements of $53 million of mortgage notes and $75 million of securitization bonds. See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2007 were $1 billion primarily due to issuing $1.1 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings. We paid common stock dividends of $311 million.

Our capital investment plans for 2008 will require additional funding from the capital markets.

Off-balance Sheet Arrangements

Under a limited set of circumstances, we enter into off-balance sheet arrangements 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 are as follows:

	June 30, 2008		December 31, 2007
	(in millions)
AEP Credit Accounts Receivable Purchase Commitments	$	564	$	507
Rockport Plant Unit 2 Future Minimum Lease Payments		2,142		2,216
Railcars Maximum Potential Loss From Lease Agreement		26		30

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 2007 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above and standby letters of credit discussed in “Liquidity” above.

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 2007 Annual Report. The 2007 Annual Report should be read in conjunction with this report in order to understand significant factors which have not materially changed in status since the issuance of our 2007 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP). Electric utilities may file an ESP with a fuel cost recovery mechanism. Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing. A MRO, from the date of its commencement, could transition CSPCo and OPCo to full market rates no sooner than six years and no later than ten years. The PUCO has the authority to approve or modify the utilities’ ESP request. The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than the MRO. Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity. Management has preliminarily concluded, pending the issuance of final rules by the PUCO and the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting. However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to cost-based rate regulation accounting. Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011. CSPCo and OPCo did not file MROs. CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year. A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances. The increases in customer bills related to the fuel cost recovery mechanism would be phased-in over the three year period from 2009 through 2011. Effective January 1, 2009, CSPCo and OPCo will defer the fuel cost under-recoveries and related carrying costs for future recovery over seven years from 2012 through 2018. In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for unexpected costs and reliability costs. The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs. Management expects a PUCO decision on the ESP filings in the fourth quarter of 2008.

Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45 million and $36 million, respectively, for customer choice implementation and line extension carrying costs. In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $28 million and $19 million, respectively. Such costs would be recovered over an 8 year period beginning January 2011. Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future results of operations and cash flows.

Texas Restructuring Appeals

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs of $2.5 billion and is recovering such costs over a period ending in 2020. TCC has refunded its net other true-up items of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider. Cash paid for CTC refunds for the six months ended June 30, 2008 and 2007 was $68 million and $170 million, respectively. TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items. Municipal customers and other intervenors also appealed the PUCT true-up and related orders seeking to further reduce TCC’s true-up recoveries. In March 2007, the Texas District Court judge hearing the appeal of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions. The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration. The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.

TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals. In May 2008, the Texas Court of Appeals affirmed the District Court decision in all but one major respect. It reversed the District Court’s decision finding that the PUCT erred by applying an invalid rule to determine the carrying cost rate. The Texas Court of Appeals denied intervenors’ motion for rehearing. Management expects intervenors to appeal the decision to the Texas Supreme Court. If upheld on appeal, this ruling could have a favorable effect on TCC’s results of operations and cash flows.

Management cannot predict the outcome of these court proceedings and PUCT remand decisions. If TCC ultimately succeeds in its appeals, it could have a favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

FERC Market Power Mitigation

FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate. Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power. In December 2007, AEP filed its most recent triennial update. In March and May 2008, the PUCO filed comments suggesting that FERC should further investigate whether AEP continues to pass FERC’s indicative screens for the lack of market power in PJM. Certain industrial retail customers also urged FERC to further investigate this matter. AEP responded that its market power studies were performed in accordance with FERC’s guidelines, and continue to demonstrate lack of market power. Management is unable to predict the outcome of this proceeding; however, if a further investigation by the FERC limits AEP’s ability to sell power at market based rates in PJM, it would result in an adverse effect on future off-system sales margins, results of operations and cash flows.

New Generation

In 2008, AEP completed or is in various stages of construction of the following generation facilities:

Commercial

Total

Nominal

Operation

Operating

Project

Projected

Date

Company

Name

Location

Cost (a)

CWIP (b)

Fuel Type

Plant Type

Capacity

(Projected)

(in millions)

PSO

Southwestern

(c)

Oklahoma

Gas

Simple-cycle

150

2008

PSO

Riverside

(d)

Oklahoma

Gas

Simple-cycle

150

2008

AEGCo

Dresden

(e)

Ohio

309

(e)

119

Gas

Combined-cycle

580

2010

SWEPCo

Stall

Louisiana

378

106

Gas

Combined-cycle

500

2010

SWEPCo

Turk

(f)

Arkansas

1,522

(f)

407

Coal

Ultra-supercritical

600

(f)

2012

APCo

Mountaineer

(g)

West Virginia

2,230

(g)

Coal

IGCC

629

2012(g)

CSPCo/OPCo

Great Bend

(g)

Ohio

2,700

(g)

Coal

IGCC

629

2017(g)

(a)	Amount excludes AFUDC.
(b)	Amount includes AFUDC. Turk’s CWIP includes joint owners’ share.
(c)	Southwestern Units were placed in service on February 29, 2008.
(d)	The final Riverside Unit was placed in service on June 15, 2008.
(e)	In September 2007, AEGCo purchased the partially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(f)	SWEPCo plans to own approximately 73%, or 440 MW, totaling $1,110 million in capital investment. The increase in the cost estimate disclosed in the 2007 Annual Report relates to cost escalations due to the delay in receipt of permits and approvals. See “Turk Plant” section below.
(g)	Subject to revision; construction of IGCC plants deferred pending regulatory approval. See “IGCC Plants” section below.

Turk Plant

In November 2007, the APSC granted approval to build the Turk Plant. Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals. In March 2008, the LPSC approved the application to construct the Turk Plant. In July 2008, the PUCT approved a certificate of convenience and necessity for construction of the plant. We expect a written order in August 2008 which will also provide for the conditions of the PUCT’s approval.

SWEPCo is working with the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers for approval later this year. A request to stop pre-construction activities at the site was filed in Federal court by the same Arkansas landowners who appealed the APSC decision to the Arkansas State Court of Appeals. In July 2008, the Federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse the joint owners for their share of paid costs. If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements. As of June 30, 2008, including the joint owners’ share, SWEPCo has capitalized approximately $407 million of expenditures and has significant contractual construction commitments for an additional $815 million. As of June 30, 2008, if the plant had been canceled, cancellation fees of $60 million would have been required in order to terminate these construction commitments. If SWEPCo cannot recover its costs, it would have an adverse effect on future results of operations, cash flows and possibly financial condition.

IGCC Plants

We have delayed construction of the West Virginia and Ohio IGCC plants. In May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC's previous denial of APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia. In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant. In July 2008, the IRS awarded $134 million in future tax credits for the IGCC plant. Management continues to pursue the ultimate construction of the IGCC plant. If the West Virginia IGCC plant is canceled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs of $19 million. If the plant is canceled and the deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

In Ohio, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant, but await the result of an Ohio Supreme Court remand to the PUCO regarding recovery of IGCC pre-construction costs. If CSPCo and OPCo were required to refund $24 million collected for IGCC pre-construction costs and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future results of operations and cash flows.

Litigation

In the ordinary course of business, we, along with our subsidiaries, are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and if the loss amount can be estimated. For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 Annual Report. Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to materially affect our results of operations.

Environmental Litigation

New Source Review (NSR) Litigation: The Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. (Duke), modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.

In 2007, the AEP System settled their complaints under a consent decree. CSPCo jointly-owns Beckjord and Stuart Stations with Duke and DP&L. A jury trial in May 2008 returned a verdict of no liability at the jointly-owned Beckjord unit. Settlement discussions are ongoing in the citizen suit action filed by Sierra Club against the jointly-owned units at Stuart Station. We believe we can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or 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 and cash flows.

Environmental Matters

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

·	Requirements under CAA to reduce emissions of SO2, NOx, particulate matter (PM) and mercury from fossil fuel-fired power plants; and
·	Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain of our power plants.

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units. We are also engaged in the development of possible future requirements to reduce CO2 and other greenhouse gases (GHG) emissions to address concerns about global climate change. All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 Annual Report.

Clean Air Act Requirements

As discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various states and environmental organizations challenged the Clean Air Mercury Rule (CAMR) in the D. C. Circuit Court of Appeals. The Court ruled that the Federal EPA’s action delisting fossil fuel-fired power plants did not conform to the procedures specified in the CAA. The Court vacated and remanded the model federal rules for both new and existing coal-fired power plants to the Federal EPA. We are unable to predict how the Federal EPA will respond to the remand. In addition, in 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that requires further reductions in SO2 and NOx emissions and assists states developing new state implementation plans to meet 1997 national ambient air quality standards (NAAQS). CAIR reduces regional emissions of SO2 and NOx (which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia). CAIR requires power plants within these states to reduce emissions of SO2 by 50 percent by 2010, and by 65 percent by 2015. NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015. Reduction of both SO2 and NOx would be achieved through a cap-and-trade program. In July 2008, the D.C. Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal EPA. We are unable to predict how the Federal EPA will respond to the remand which could be stayed or appealed to the U.S. Supreme Court. The Federal EPA also issued revised NAAQS for both ozone and PM 2.5 that are more stringent than the 1997 standards used to establish CAIR, which could increase the levels of SO2 and NOx reductions required from our facilities.

In anticipation of compliance with CAIR in 2009, I&M purchased $8 million of annual CAIR NOx allowances which are included in inventory as of June 30, 2008. The market value of annual CAIR NOx allowances decreased in the weeks following this court decision. Management intends to seek recovery of the cost of purchased allowances. If the recovery is denied, it would have an adverse effect on future results of operations and cash flows. None of AEP’s other subsidiaries purchased any significant number of CAIR allowances. SO2 and seasonal NOx allowances allocated to our facilities under the Acid Rain Program and the NOx SIP Call will still be required to comply with existing CAA programs that were not affected by the court’s decision.

It is too early to determine the full implication of these decisions on our environmental compliance strategy. However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to our recent settlement of the NSR enforcement action, are consistent with the actions included in our least-cost CAIR compliance plan. Consequently, we do not anticipate making any immediate changes in our near-term compliance plans as a result of these court decisions.

Global Climate Change

In July 2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requests comments on a wide variety of issues the agency is considering in formulating its response to the U.S. Supreme Court’s decision in Massachusetts v. EPA. In that case, the Court determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate mobile sources of CO2 emissions under the CAA if appropriate findings are made. The Federal EPA has identified a number of issues that could affect stationary sources, such as electric generating plants, if the necessary findings are made for mobile sources, including the potential regulation of CO2 emissions for both new and existing stationary sources under the NSR programs of the CAA. We plan to submit comments and participate in any subsequent regulatory development processes, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on our business. Also, additional legislative measures to address CO2 and other GHGs have been introduced in Congress, and such legislative actions could impact future decisions by the Federal EPA on CO2 regulation.

In addition, the Federal EPA issued a proposed rule for the underground injection and storage of CO2 captured from industrial processes, including electric generating facilities, under the Safe Drinking Water Act’s Underground Injection Control (UIC) program. The proposed rules provide a comprehensive set of well siting, design, construction, operation, closure and post-closure care requirements. We plan to submit comments and participate in any subsequent regulatory development process, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on our business. Permitting for our demonstration project at the Mountaineer Plant will proceed under the existing UIC rules.

Clean Water Act Regulations

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

In January 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA. In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact. The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is the applicable standard for permitting agencies pending finalization of revised rules by the Federal EPA. We cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states. We sought further review and filed for relief from the schedules included in our permits.

In April 2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting costs against environmental benefits. Management is unable to predict the outcome of this appeal.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 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

In September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (SFAS 157), enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level, an entity includes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption. The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data. In February 2008, the FASB issued FSP FAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors. Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings. The impact of considering our own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption. We partially adopted SFAS 157 effective January 1, 2008. We will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS 157-2. See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.

In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. The statement is applied prospectively upon adoption. We adopted SFAS 159 effective January 1, 2008. At adoption, we did not elect the fair value option for any assets or liabilities.

In March 2007, the FASB ratified EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10), a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy. Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee. In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods. We adopted EITF 06-10 effective January 1, 2008 with a cumulative effect reduction of $16 million ($10 million, net of tax) to beginning retained earnings.

In June 2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on the treatment of income tax benefits of dividends on employee share-based compensation. The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.” Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital. We adopted EITF 06-11 effective January 1, 2008. EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after December 15, 2007. The adoption of this standard had an immaterial impact on our financial statements.

In April 2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1). It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133. It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral. The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period. We adopted FIN 39-1 effective January 1, 2008. This standard changed our method of netting certain balance sheet amounts and reduced assets and liabilities. It requires retrospective application as a change in accounting principle. Consequently, we reduced total assets and liabilities on the December 31, 2007 balance sheet by $47 million each. See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances. 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 Generation and Marketing segment, operating primarily within ERCOT, transacts in wholesale energy trading and marketing contracts. This segment is exposed to certain market risks as a marketer of wholesale electricity. These risks include commodity price risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

All Other includes natural gas operations which holds forward natural gas contracts that were not sold with the natural gas pipeline and storage assets. These contracts are financial derivatives, 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 and financial forward purchase and sale contracts. We engage in risk management of electricity, natural gas, coal, and emissions and to a lesser degree other commodities associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The CORC consists of our President – AEP Utilities, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer. When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

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 adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. We support the work of the CCRO and embrace the disclosure standards applicable to our business activities. The following tables provide information on our risk management activities.

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

The following two tables summarize the various mark-to-market (MTM) positions included on our Condensed Consolidated Balance Sheet as of June 30, 2008 and the reasons for changes in our total MTM value included on our Condensed Consolidated Balance Sheet as compared to December 31, 2007.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

June 30, 2008

(in millions)

	Utility Operations			Generation and Marketing			All Other			Sub-Total MTM Risk Management Contracts			MTM of Cash Flow and Fair Value Hedges			Collateral Deposits			Total
Current Assets	$	653		$	201		$	121		$	975		$	34		$	(118	)	$	891
Noncurrent Assets		309			144			86			539			14			(64	)		489
Total Assets		962			345			207			1,514			48			(182	)		1,380

Current Liabilities		(660	)		(203	)		(124	)		(987	)		(101	)		97			(991	)
Noncurrent Liabilities		(202	)		(75	)		(90	)		(367	)		(5	)		24			(348	)
Total Liabilities		(862	)		(278	)		(214	)		(1,354	)		(106	)		121			(1,339	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	100		$	67		$	(7	)	$	160		$	(58	)	$	(61	)	$	41

MTM Risk Management Contract Net Assets (Liabilities)

Six Months Ended June 30, 2008

(in millions)

	Utility Operations			Generation and Marketing		All Other			Total
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2007	$	156		$	43	$	(8	)	$	191
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(36	)		4		-			(32	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		2			16		-			18
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)		6			3		1			10
Changes in Fair Value Due to Market Fluctuations During the Period (c)		6			1		-			7
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		(34	)		-		-			(34	)
Total MTM Risk Management Contract Net Assets (Liabilities) at June 30, 2008	$	100		$	67	$	(7	)		160
Net Cash Flow and Fair Value Hedge Contracts										(58	)
Collateral Deposits										(61	)
Ending Net Risk Management Assets at June 30, 2008									$	41

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)	Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)	“Change in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.

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

The following table presents the maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM

Risk Management Contract Net Assets (Liabilities)

Fair Value of Contracts as of June 30, 2008

(in millions)

	Remainder 2008			2009			2010			2011			2012			After 2012 (f)		Total
Utility Operations:
Level 1 (a)	$	(6	)	$	1		$	-		$	-		$	-		$	-	$	(5	)
Level 2 (b)		8			47			40			16			6			-		117
Level 3 (c)		(29	)		(5	)		(12	)		(8	)		(4	)		-		(58	)
Total		(27	)		43			28			8			2			-		54

Generation and Marketing:
Level 1 (a)		(36	)		13			(1	)		(1	)		-			-		(25	)
Level 2 (b)		31			(8	)		6			5			5			3		42
Level 3 (c)		(2	)		-			8			9			9			26		50
Total		(7	)		5			13			13			14			29		67

All Other:
Level 1 (a)		-			-			-			-			-			-		-
Level 2 (b)		(1	)		(4	)		(4	)		2			-			-		(7	)
Level 3 (c)		-			-			-			-			-			-		-
Total		(1	)		(4	)		(4	)		2			-			-		(7	)

Total:
Level 1 (a)		(42	)		14			(1	)		(1	)		-			-		(30	)
Level 2 (b)		38			35			42			23			11			3		152
Level 3 (c) (d)		(31	)		(5	)		(4	)		1			5			26		(8	)
Total		(35	)		44			37			23			16			29		114
Dedesignated Risk Management Contracts (e)		7			14			14			6			5			-		46
Total MTM Risk Management Contract Net Assets (Liabilities)	$	(28	)	$	58		$	51		$	29		$	21		$	29	$	160

(a)	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)	Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1, and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)	Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)	A significant portion of the total volumetric position within the consolidated level 3 balance has been economically hedged.
(e)	Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election the MTM value was frozen and no longer fair valued. This will be amortized within Utility Operations Revenues over the remaining life of the contract.
(f)	There is mark-to-market value of $29 million in individual periods beyond 2012. $13 million of this mark-to-market value is in 2013, $8 million is in 2014, $3 million is in 2015, $3 million is in 2016 and $2 million is in 2017.

The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

Maximum Tenor of AEP’s Liquid Portion of Risk Management Contracts

As of June 30, 2008

Commodity	Transaction Class	Market/Region	Tenor
			(in Months)
Natural Gas	Futures	NYMEX / Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	30
	Swaps	Gas East, Mid-Continent, Gulf Coast, Texas	30
	Exchange Option Volatility	NYMEX / Henry Hub	12
Power	Futures	Power East – PJM	36
	Physical Forwards	Power East – Cinergy	54
	Physical Forwards	Power East – PJM West	54
	Physical Forwards	Power East – AEP Dayton (PJM)	54
	Physical Forwards	Power East – ERCOT	42
	Physical Forwards	Power East – Entergy	30
	Physical Forwards	Power West – PV, NP15, SP15, MidC, Mead	42
	Peak Power Volatility (Options)	Cinergy, PJM	12
Emissions	Credits	SO2, NOx	42
Coal	Physical Forwards	PRB, NYMEX, CSX	42

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

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

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

We use foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designate qualifying instruments as cash flow hedges. 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 changes in cash flow hedges from December 31, 2007 to June 30, 2008. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

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

Six Months Ended June 30, 2008

(in millions)

		Power				Interest Rate and Foreign Currency				Total
Beginning Balance in AOCI, December 31, 2007		$	(1	)		$	(25	)		$	(26