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 March 31, 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, Indiana Michigan Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

			Number of shares of common stock outstanding of the registrants at April 30, 2008

American Electric Power Company, Inc.			401,591,005
			($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

March 31, 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 Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Southwestern Electric Power Company Consolidated:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries


Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Combined Management’s Discussion and Analysis of Registrant Subsidiaries

Controls and Procedures

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings
	Item 1A.	Risk Factors
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
	Item 5.	Other Information
	Item 6.	Exhibits:
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)

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.
AEP Power Pool		Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP 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.
DOJ		United States Department of Justice.
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.”
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.”
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.
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.
PATH		Potomac Appalachian Transmission Highline, LLC and its subsidiaries, a joint venture with Allegheny Energy Inc. formed to own and operate electric transmission facilities in PJM.
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 109		Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.”
SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
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 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 potential for new legislation 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

Regulatory Activity

Updates to our significant regulatory activities in 2008 include:

·	In February 2008, APCo and WPCo filed for an increase of approximately $156 million including a $135 million increase in the Expanded Net Energy Cost recovery mechanism, a $17 million increase in construction cost surcharges and $4 million of reliability expenditures, to all become effective July 2008.
·	In February 2008, the FERC approved a PATH request for a transmission formula rate and ordered that the formula rates go into effect in March 2008. Settlement negotiations began and motions for rehearing were filed by intervening parties in March 2008. PATH requested an incentive return of 14.3% on its equity investment using a 50/50 debt to equity ratio, the recovery of deferred pre-operating, pre-construction costs and the recovery of construction financing costs through the inclusion of CWIP in rate base with a true-up to actual for these costs.
·	In March 2008, the OCC approved a settlement for recovery of 2007 Oklahoma ice storm costs, subject to an audit of December ice storm costs to be filed in July 2008. As a result, PSO recorded an $81 million regulatory asset for actual ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances.
·	In March 2008, PSO and all other parties signed a settlement agreement that provides for recovery of $11 million of pre-construction costs related to PSO’s Red Rock Generating Facility. PSO filed the settlement with the OCC for approval. A hearing on the settlement is scheduled for May 2008. As a result of the settlement, PSO wrote-off $10 million of its remaining unrecoverable deferred pre-construction costs/cancellation fees in the first quarter of 2008.
·	In March 2008, the WVPSC granted APCo a Certificate of Public Convenience and Necessity and recovery of pre-construction and construction financing costs related to the planned construction of the IGCC plant in West Virginia. Various intervenors filed petitions with the WVPSC to reconsider the order. In April 2008, the Virginia SCC denied APCo’s request for approval of the plant and to recover pre-construction and construction financing costs. In April 2008, APCo filed a petition for reconsideration in Virginia.
·	In March 2008, the LPSC approved the application to construct the Turk Plant. In January 2008, a Texas ALJ recommended that SWEPCo’s application be denied and subsequently, in March 2008, the PUCT voted to reopen the record and conduct additional hearings. SWEPCo expects a decision from the PUCT in the last half of 2008.
·	In March 2008, APCo filed a notice with the Virginia SCC that it plans to file a general base rate case no sooner than May 2008. APCo will also file for recovery of $46 million of incremental E&R costs.
·	In April 2008, the LPSC approved a settlement agreement between SWEPCo and the LPSC staff that established a formula rate plan with a three-year term. Beginning August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%.
·	In April 2008, the Ohio legislature passed legislation which allows utilities to set prices by filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option. The PUCO would have authority to approve or modify the utility’s request to set prices. Both alternatives would involve earnings tests monitored by the PUCO. The legislation still must be signed by the Ohio governor and will become law 90 days after the Governor’s signature.

Fuel Costs

We expected coal costs to increase by 13% in 2008, but due to escalating domestic prices and increased needs, our current estimate is in the range of a 14% to 18% increase. 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 very volatile. Going forward, we have some 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, the current pending legislation in Ohio includes a fuel cost recovery mechanism. Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

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.

Generation and Marketing

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

The table below presents our consolidated Net Income by segment for the three months ended March 31, 2008 and 2007.

	Three Months Ended March 31,
	2008			2007
	(in millions)
Utility Operations		$	410		$	253
MEMCO Operations			7			15
Generation and Marketing			1			(1	)
All Other (a)			155			4
Net Income		$	573		$	271

(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 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.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP Consolidated

First Quarter of 2008 Compared to First Quarter of 2007

Net Income in 2008 increased $302 million compared to 2007 primarily due to 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 and an increase in Utility Operations segment earnings of $157 million. The increase in Utility Operations segment earnings primarily relates to lower operation and maintenance expenses as a result of a favorable Oklahoma ice storm settlement and rate increases implemented since the first quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma.

Average basic shares outstanding increased to 401 million in 2008 from 397 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 March 31, 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.

	Three Months Ended
	March 31,
	2008		2007
	(in millions)
Revenues	$	3,294	$	3,033
Fuel and Purchased Power		1,213		1,119
Gross Margin		2,081		1,914
Depreciation and Amortization		355		383
Other Operating Expenses		941		991
Operating Income		785		540
Other Income, Net		42		18
Interest Charges and Preferred Stock Dividend Requirements		210		179
Income Tax Expense		207		126
Net Income	$	410	$	253

Summary of Selected Sales and Weather Data

For Utility Operations

For the Three Months Ended March 31, 2008 and 2007

	2008		2007
Energy Summary	(in millions of KWH)
Retail:
Residential		14,500		14,139
Commercial		9,547		9,359
Industrial		14,350		13,565
Miscellaneous		609		614
Total Retail		39,006		37,677

Wholesale		11,666		8,778

Texas Wires – Energy Delivered to Customers Served by TNC and TCC in ERCOT		5,823		5,831
Total KWHs		56,495		52,286

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on results of operations. In general, degree day changes in our eastern region have a larger effect on results of operations than changes in our western region due to the relative size of the two regions and the associated number of customers within each. Cooling degree days and heating degree days in our service territory for the three months ended March 31, 2008 and 2007 were as follows:

	2008	2007
Weather Summary	(in degree days)
Eastern Region
Actual – Heating (a)	1,824	1,816
Normal – Heating (b)	1,767	1,792

Actual – Cooling (c)	-	14
Normal – Cooling (b)	3	3

Western Region (d)
Actual – Heating (a)	949	902
Normal – Heating (b)	931	959

Actual – Cooling (c)	26	56
Normal – Cooling (b)	20	18

(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.

First Quarter of 2008 Compared to First Quarter of 2007

Reconciliation of First Quarter of 2007 to First Quarter of 2008

Net Income from Utility Operations

(in millions)

First Quarter of 2007			$	253

Changes in Gross Margin:
Retail Margins	114
Off-system Sales	40
Transmission Revenues	8
Other Revenues	5
Total Change in Gross Margin				167

Changes in Operating Expenses and Other:
Other Operation and Maintenance	81
Gain on Dispositions of Assets, Net	(21	)
Depreciation and Amortization	28
Taxes Other Than Income Taxes	(10	)
Carrying Costs Income	10
Interest Income	11
Other Income, Net	3
Interest and Other Charges	(31	)
Total Change in Operating Expenses and Other				71

Income Tax Expense				(81	)

First Quarter of 2008			$	410

Net Income from Utility Operations increased $157 million to $410 million in 2008. The key driver of the increase was a $167 million increase in Gross Margin and a $71 million decrease in Operating Expenses and Other offset by an $81 million increase in Income Tax Expense.

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

·	Retail Margins increased $114 million primarily due to the following:
	·	A $44 million increase related to RSP rate increases implemented in our Ohio jurisdictions with PUCO approval, a $14 million increase related to recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $9 million increase in base rates in Texas and an $8 million increase in base rates in Oklahoma.
	·	A $58 million increase related to an OPCo coal contract amendment which reduced future deliveries to OPCo in exchange for consideration received.
	·	A $23 million increase related to increased residential and commercial usage and customer growth.
	·	A $21 million increase related to increased usage by Ormet, an industrial customer in Ohio. See “Ormet” section of Note 3.
	These increases were partially offset by:
	·	A $55 million decrease related to increased fuel, consumable and allowance costs in Ohio.
·	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.

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

·	Other Operation and Maintenance expenses decreased $81 million primarily due to a deferral of storm restoration costs of $80 million in Oklahoma as a result of a rate settlement to recover 2007 storm restoration costs partially offset by an increase in generation expenses from base operations and the write-off of $10 million of unrecoverable pre-construction costs for PSO’s canceled Red Rock Generating Facility.
·	Gain on Disposition of Assets, Net decreased $21 million 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, Virginia, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances.
·	Taxes Other Than Income Taxes increased $10 million primarily due to higher property taxes related to property additions.
·	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 $31 million primarily due to additional debt issued in 2007 and higher interest rates on variable rate debt.
·	Income Tax Expense increased $81 million due to an increase in pretax income.

MEMCO Operations

First Quarter of 2008 Compared to First Quarter of 2007

Net Income from our MEMCO Operations segment decreased from $15 million in 2007 to $7 million in 2008 primarily due to high water conditions and reduced northbound loadings. Operating costs were higher due to the sustained high water conditions on all major rivers and existing river regulations resulting in reduced tow sizes and restricted operating hours which increased fuel consumption. Northbound loadings continue to be depressed as a result of reduced imports through the Gulf.

Generation and Marketing

First Quarter of 2008 Compared to First Quarter of 2007

Net Income from our Generation and Marketing segment increased to $1 million in 2008 from a loss of $1 million in 2007 primarily due to an increase in income from wind farm operations.

All Other

First Quarter of 2008 Compared to First Quarter of 2007

Net Income from All Other increased from $4 million in 2007 to $155 million in 2008. 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 ($163 million, net of tax). 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 $163 million primarily due to an increase in pretax book income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization

	March 31, 2008				December 31, 2007
	($ in millions)
Long-term Debt, including amounts due within one year	$	15,636	58.8	%	$	14,994	58.1	%
Short-term Debt		409	1.5			660	2.6
Total Debt		16,045	60.3			15,654	60.7
Common Equity		10,489	39.5			10,079	39.1
Preferred Stock		61	0.2			61	0.2

Total Debt and Equity Capitalization	$	26,595	100.0	%	$	25,794	100.0	%

Our ratio of debt to total capital decreased from 60.7% to 60.3% in 2008 due to our 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 or 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 March 31, 2008, we had $1.4 billion outstanding of tax-exempt long-term debt sold at auction rates that reset every 7, 28 or 35 days. This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation, Financial Guaranty Insurance Co., MBIA Insurance Corporation and XL Capital Assurance Inc. 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. During the first quarter of 2008, we reduced our outstanding auction rate securities by redeeming or repurchasing $95 million of such debt securities. In April 2008, we converted, refunded or provided notice to convert or refund $940 million of our outstanding auction rate securities. We plan to continue this conversion and refunding process for the remaining $471 million to other permitted modes, including term-put and fixed-rate structures through the third quarter of 2008. The conversions will likely result in higher interest charges compared to prior year but lower than the failed auction rates for this tax-exempt long-term debt.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At March 31, 2008, our available liquidity was approximately $2.7 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
Total			3,000
Cash and Cash Equivalents			155
Total Liquidity Sources			3,155
Less: AEP Commercial Paper Outstanding			409
	Letters of Credit Drawn		57

Net Available Liquidity		$	2,689

The facilities are structured as two $1.5 billion credit facilities of which $300 million may be issued under each credit facility as letters of credit. In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

In April 2008, we entered into an additional $650 million 3-year credit agreement and another $350 million 364-day credit agreement.

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 March 31, 2008, we had credit facilities totaling $3 billion to support our commercial paper program. The maximum amount of commercial paper outstanding during the first quarter of 2008 was $1.1 billion. The weighted-average interest rate of our commercial paper during the first quarter of 2008 was 3.66%.

Investments in Auction-Rate Securities

As of March 31, 2008, we had $39 million invested in auction-rate securities. During the first quarter of 2008, we transferred $135 million of these securities from fair value hierarchy level 2 to level 3 due to the deterioration of liquidity in the auction-rate security market and subsequently sold $96 million of such securities at par. Issuers have given us notice that they will call a majority of our remaining investments in auction-rate securities at par. Therefore, based on this fact and our review of the underlying credit quality of these securities, we have not recorded an impairment of these investments.

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 March 31, 2008, this contractually-defined percentage was 54.9%. Nonperformance of these covenants could result in an event of default under these credit agreements. At March 31, 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.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At March 31, 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 April 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 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. Moody’s affirmed its stable outlook for AEP and our other subsidiaries. Fitch downgraded PSO and SWEPCo from A- to BBB+ for senior unsecured debt. 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.

	Three Months Ended
	March 31,
	2008				2007
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	178			$	301
Net Cash Flows from Operating Activities			628				351
Net Cash Flows Used for Investing Activities			(894	)			(628	)
Net Cash Flows from Financing Activities			243				235
Net Decrease in Cash and Cash Equivalents			(23	)			(42	)
Cash and Cash Equivalents at End of Period		$	155			$	259

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

	Three Months Ended
	March 31,
	2008				2007
	(in millions)
Net Income		$	573			$	271
Depreciation and Amortization			363				391
Other			(308	)			(311	)
Net Cash Flows from Operating Activities		$	628			$	351

Net Cash Flows from Operating Activities increased in 2008 primarily due to increased income reflecting an improvement in gross margins on energy sales and the TEM settlement.

Net Cash Flows from Operating Activities were $628 million in 2008 consisting primarily of Net Income of $573 million and $363 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 resulted in lower cash from operations due to payment of items accrued at December 31, 2007.

Net Cash Flows from Operating Activities were $351 million in 2007 consisting primarily of Net Income of $271 million and $391 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 resulted in lower cash from operations due to payment of items accrued at December 31, 2006.

Investing Activities

	Three Months Ended
	March 31,
	2008				2007
	(in millions)
Construction Expenditures		$	(778	)		$	(907	)
Proceeds from Sales of Assets			18				68
Other			(134	)			211
Net Cash Flows Used for Investing Activities		$	(894	)		$	(628	)

Net Cash Flows Used for Investing Activities were $894 million in 2008 and $628 million in 2007 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.

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

We forecast approximately $3 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

	Three Months Ended
	March 31,
	2008				2007
	(in millions)
Issuance of Common Stock		$	45			$	54
Issuance/Retirement of Debt, Net			376				355
Dividends Paid on Common Stock			(165	)			(155	)
Other			(13	)			(19	)
Net Cash Flows from Financing Activities		$	243			$	235

Net Cash Flows from Financing Activities in 2008 were $243 million primarily due to the issuance of $315 million of junior subordinated debentures and $500 million of senior unsecured notes partially offset by the retirement of $95 million of pollution control bonds, $52 million of senior unsecured notes and $34 million of mortgage notes and the reduction of our short-term commercial paper outstanding by $250 million. 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 $235 million primarily due to $150 million of short-term commercial paper borrowings under our credit facilities and issuing $251 million of debt securities.

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:

	March 31, 2008			December 31, 2007
	(in millions)
AEP Credit Accounts Receivable Purchase Commitments		$	502		$	507
Rockport Plant Unit 2 Future Minimum Lease Payments			2,216			2,216
Railcars Maximum Potential Loss From Lease Agreement			30			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 discussed in “Cash Flow” 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 Restructuring

The current Ohio restructuring legislation permits CSPCo and OPCo to implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008. The RSP plans include generation rates which are between PUCO approved rates and higher market rates. In April 2008, the Ohio legislature passed legislation which allows utilities to set prices by filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option. The PUCO would have authority to approve or modify the utility’s request to set prices. Both alternatives would involve earnings tests monitored by the PUCO. The legislation still must be signed by the Ohio governor and will become law 90 days after the governor’s signature. Management is analyzing the financial statement implications of the pending legislation on CSPCo’s and OPCo’s generation supply business, more specifically, whether the fuel management operations of CSPCo and OPCo meet the criteria for application of SFAS 71. The financial statement impact of the pending legislation will not be known until the PUCO acts on specific proposals made by CSPCo and OPCo. Management expects a PUCO decision in the fourth quarter of 2008.

Texas Restructuring

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 is also refunding its net other true-up items of $375 million through 2008 via a CTC credit rate rider. 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. However, the District Court did not rule that the carrying cost rate was inappropriate. If the PUCT reevaluates the carrying cost rate on remand and reduces the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition.

The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness. If upheld on appeal, this ruling could have a materially favorable effect on TCC’s results of operations and cash flows.

TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals. Management cannot predict the outcome of these court proceedings. 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, or if TCC has a tax normalization violation, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

New Generation

AEP is in various stages of construction of the following generation facilities. Certain plants are pending regulatory approval:

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

170

2008

PSO

Riverside

Oklahoma

Gas

Simple-cycle

170

2008

AEGCo

Dresden

(d)

Ohio

305

(d)

101

Gas

Combined-cycle

580

2010

SWEPCo

Stall

Louisiana

378

Gas

Combined-cycle

500

2010

SWEPCo

Turk

(e)

Arkansas

1,522

(e)

313

Coal

Ultra-supercritical

600

(e)

2012

APCo

Mountaineer

West Virginia

2,230

Coal

IGCC

629

2012

CSPCo/OPCo

Great Bend

Ohio

2,700

(f)

Coal

IGCC

629

2017

(a)	Amount excludes AFUDC.
(b)	Amount includes AFUDC.
(c)	Southwestern Units were placed in service on February 29, 2008.
(d)	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.
(e)	SWEPCo plans to own approximately 73%, or 440 MW, totaling $1,110 million in capital investment. The increase in the cost estimate relates to cost escalations due to the delay in receipt of permits and approvals. See “Turk Plant” section below.
(f)	Cost estimates, updated to reflect cost escalations due to revised commercial operation date of 2017, are not yet filed with the PUCO. See “Ohio IGCC Plant” section of Note 3.

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas. Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant. SWEPCo will own 73% of the Turk Plant and will operate the facility. During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk facility. The Turk Plant is estimated to cost $1.5 billion with SWEPCo’s portion estimated to cost $1.1 billion, excluding AFUDC. If approved on a timely basis, the plant is expected to be in-service in 2012. As of March 31, 2008, if the plant were to be cancelled then including the joint owners’ share, SWEPCo capitalized approximately $313 million of expenditures and has significant contractual construction commitments for an additional $838 million. As of March 31, 2008, if the plant were to be cancelled, then cancellation fees of $67 million would terminate these construction commitments.

In November 2007, the APSC granted approval to build the plant. Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals. SWEPCo is still awaiting permit approvals from the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers. Both permits are expected to be received by the third quarter of 2008. The PUCT held hearings in October 2007. In January 2008, a Texas ALJ issued a report, which concluded that SWEPCo failed to prove there was a need for the plant. The Texas ALJ recommended that SWEPCo’s application be denied. The PUCT has voted to reopen the record and conduct additional hearings. SWEPCo expects a decision from the PUCT in the last half of 2008. In March 2008, the LPSC approved the certificate to construct the Turk Plant. 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 OMPA, AECC and ETEC 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. If SWEPCo cannot recover its costs, it could have an adverse effect on future results of operations, cash flows and possibly financial condition.

APCo’s IGCC Plant

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV. In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover pre-construction and future construction financing costs associated with the IGCC plant.

In March 2008, the WVPSC granted APCo the CCN to build the plant and the request for cost recovery. Various intervenors filed petitions with the WVPSC to reconsider the order.

The Virginia SCC issued an order in April 2008 denying APCo’s requests on the basis of their belief that the estimated cost may be significantly understated. The Virginia SCC also expressed concern that the $2.2 billion estimated cost of the IGCC plant did not include a retrofitting of carbon capture and sequestration facilities. In April 2008, APCo filed a petition for reconsideration in Virginia. If necessary, APCo will seek recovery of its prudently incurred deferred pre-construction costs.

Through March 31, 2008, APCo deferred for future recovery pre-construction IGCC costs of $16 million. If these deferred costs are not recoverable, 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. Litigation continues against two plants CSPCo jointly-owns with Duke and DP&L, which they operate. We are unable to predict the outcome of these cases. 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 monitoring 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 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 include 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 FASB Staff Position (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 $10 million (net of tax of $6 million) 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 September 15, 2007. The adoption of this standard had an immaterial impact on our financial statements.

In April 2007, the FASB issued FASB Staff Position 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 “FASB Staff Position 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 March 31, 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

March 31, 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	$	411		$	215		$	95		$	721		$	25		$	(48	)	$	698
Noncurrent Assets		199			101			71			371			8			(37	)		342
Total Assets		610			316			166			1,092			33			(85	)		1,040

Current Liabilities		(365	)		(231	)		(96	)		(692	)		(82	)		94			(680	)
Noncurrent Liabilities		(104	)		(43	)		(77	)		(224	)		(3	)		6			(221	)
Total Liabilities		(469	)		(274	)		(173	)		(916	)		(85	)		100			(901	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	141		$	42		$	(7	)	$	176		$	(52	)		15		$	139

MTM Risk Management Contract Net Assets (Liabilities)

Three Months Ended March 31, 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		(28	)		1			-			(27	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		1			-			-			1
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)		4			2			1			7
Changes in Fair Value Due to Market Fluctuations During the Period (c)		3			(4	)		-			(1	)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)		5			-			-			5
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2008	$	141		$	42		$	(7	)	$	176
Net Cash Flow and Fair Value Hedge Contracts											(52	)
Collateral Deposits											15
Ending Net Risk Management Assets at March 31, 2008										$	139

(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 March 31, 2008

(in millions)

	Remainder 2008			2009			2010			2011		2012		After 2012 (f)		Total
Utility Operations:
Level 1 (a)	$	(6	)	$	(3	)	$	-		$	-	$	-	$	-		(9	)
Level 2 (b)		28			43			29			2		1		-		103
Level 3 (c)		-			4			(7	)		-		-		-		(3	)
Total		22			44			22			2		1		-		91

Generation and Marketing:
Level 1 (a)		(21	)		5			-			-		-		-		(16	)
Level 2 (b)		4			(6	)		2			3		3		-		6
Level 3 (c)		-			1			9			9		8		25		52
Total		(17	)		-			11			12		11		25		42

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)		(27	)		2			-			-		-		-		(25	)
Level 2 (b)		31			33			27			7		4		-		102
Level 3 (c) (d)		-			5			2			9		8		25		49
Total	$	4		$	40		$	29		$	16	$	12	$	25	$	126

Dedesignated Risk Management Contracts (e)			11			14			14			6			5			-			50
Total MTM Risk Management Contract Net Assets		$	15		$	54		$	43		$	22		$	17		$	25		$	176

(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 $25 million in individual periods beyond 2012. $8 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 $3 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 the Liquid Portion of Risk Management Contracts

As of March 31, 2008

Commodity	Transaction Class	Market/Region	Tenor
			(in Months)
Natural Gas	Futures	NYMEX / Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	21
	Swaps	Gas East, Mid-Continent, Gulf Coast, Texas	21
	Exchange Option Volatility	NYMEX / Henry Hub	12
Power	Futures	Power East – PJM	36
	Physical Forwards	Power East – Cinergy	45
	Physical Forwards	Power East – PJM West	57
	Physical Forwards	Power East – AEP Dayton (PJM)	57
	Physical Forwards	Power East – ERCOT	33
	Physical Forwards	Power East – Entergy	33
	Physical Forwards	Power West – PV, NP15, SP15, MidC, Mead	57
	Peak Power Volatility (Options)	Cinergy, PJM	12
Emissions	Credits	SO2, NOx	45
Coal	Physical Forwards	PRB, NYMEX, CSX	33

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 transactions denominated in foreign currencies where deemed necessary, and designate qualifying instruments as cash flow hedge strategies. 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 March 31, 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

Three Months Ended March 31, 2008

(in millions)

	Power			Interest Rate and Foreign Currency			Total
Beginning Balance in AOCI, December 31, 2007	$	(1	)	$	(25	)	$	(26	)
Changes in Fair Value		(26	)		(6	)		(32	)
Reclassifications from AOCI for Cash Flow Hedges Settled		2			-			2
Ending Balance in AOCI, March 31, 2008	$	(25	)	$	(31	)	$	(56	)

After Tax Portion Expected to be Reclassified to Earnings During Next 12 Months	$	(31	)	$	(6	)	$	(37	)

Credit Risk

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

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of March 31, 2008, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 11.8%, expressed in terms of net MTM assets and net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of March 31, 2008, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure		Net Exposure of Counterparties >10%
Investment Grade	$	659	$	75	$	584		1	$	93
Split Rating		15		-		15		4		14
Noninvestment Grade		100		47		53		1		48
No External Ratings:
Internal Investment Grade		125		-		125		3		95
Internal Noninvestment Grade		47		3		44		2		42
Total as of March 31, 2008	$	946	$	125	$	821		11	$	292

Total as of December 31, 2007	$	673	$	42	$	631		6	$	74

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2010. This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information

Estimated Next Three Years

As of March 31, 2008

	Remainder
	2008	2009	2010
Estimated Plant Output Hedged	89%	89%	91%

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at March 31, 2008, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

VaR Model

Three Months Ended March 31, 2008				Twelve Months Ended December 31, 2007
(in millions)				(in millions)
End	High	Average	Low	End	High	Average	Low
$2	$2	$1	$1	$1	$6	$2	$1

We back-test our VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Our backtesting results show that our actual performance exceeded VaR far fewer than once every 20 trading days. As a result, we believe our VaR calculation is conservative.

As our VaR calculation captures recent price moves, we also perform regular stress testing of the portfolio to understand our exposure to extreme price moves. We employ a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translates into the largest potential mark-to-market loss. We then research the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on our debt portfolio was $36 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2008 and 2007

(in millions, except per-share amounts and shares outstanding)

(Unaudited)

	2008			2007
REVENUES
Utility Operations	$	3,010		$	2,886
Other		457			283
TOTAL		3,467			3,169

EXPENSES
Fuel and Other Consumables Used for Electric Generation		980			886
Purchased Energy for Resale		263			246
Other Operation and Maintenance		878			938
Gain on Disposition of Assets, Net		(3	)		(23	)
Asset Impairments and Other Related Items		(255	)		-
Depreciation and Amortization		363			391
Taxes Other Than Income Taxes		198			186
TOTAL		2,424			2,624

OPERATING INCOME		1,043			545

Interest and Investment Income		16			23
Carrying Costs Income		17			8
Allowance For Equity Funds Used During Construction		10			8

INTEREST AND OTHER CHARGES
Interest Expense		220			186
Preferred Stock Dividend Requirements of Subsidiaries		1			1
TOTAL		221			187

INCOME BEFORE INCOME TAX EXPENSE, MINORITY INTEREST EXPENSE AND EQUITY EARNINGS		865			397

Income Tax Expense		293			130
Minority Interest Expense		1			1
Equity Earnings of Unconsolidated Subsidiaries		2			5

NET INCOME	$	573		$	271

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		400,797,993			397,314,642

BASIC EARNINGS PER SHARE	$	1.43		$	0.68

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		402,072,098			398,552,113

DILUTED EARNINGS PER SHARE	$	1.43		$	0.68

CASH DIVIDENDS PAID PER SHARE	$	0.41		$	0.39

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2008 and December 31, 2007

(in millions)

(Unaudited)

	2008			2007
CURRENT ASSETS
Cash and Cash Equivalents	$	155		$	178
Other Temporary Investments		339			365
Accounts Receivable:
Customers		662			730
Accrued Unbilled Revenues		343			379
Miscellaneous		88			60
Allowance for Uncollectible Accounts		(43	)		(52	)
Total Accounts Receivable		1,050			1,117
Fuel, Materials and Supplies		947			967
Risk Management Assets		698			271
Margin Deposits		51			47
Prepayments and Other		121			81
TOTAL		3,361			3,026

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		20,502			20,233
Transmission		7,498			7,392
Distribution		12,217			12,056
Other (including coal mining and nuclear fuel)		3,472			3,445
Construction Work in Progress		3,001			3,019
Total		46,690			46,145
Accumulated Depreciation and Amortization		16,319			16,275
TOTAL - NET		30,371			29,870

OTHER NONCURRENT ASSETS