Edgar Filing: AMERICAN ELECTRIC POWER CO INC

q109aep10q.htm

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, 2009

[ ] 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. has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes	No

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 has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes

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 April 30, 2009

American Electric Power Company, Inc.			476,760,862
			($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, 2009

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		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.
APB		Accounting Principles Board Opinion.
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.).
CSW Operating Agreement		Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation. This agreement was amended in May 2006 to remove TCC and TNC. AEPSC acts as the agent.
CTC		Competition Transition Charge.
CWIP		Construction Work in Progress.
E&R		Environmental compliance and transmission and distribution system reliability.
EaR		Earnings at Risk, a method to quantify risk exposure.
EIS		Energy Insurance Services, Inc., a protected cell insurance company that AEP consolidates under FIN 46R.
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.”
ENEC		Expanded Net Energy Cost.
ERCOT		Electric Reliability Council of Texas.
ERISA		Employee Retirement Income Security Act of 1974, as amended.
ESP		Electric Security Plan.
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.”

FSP		FASB Staff Position.
FSP FIN 39-1		FSP FIN 39-1, “Amendment of FASB Interpretation No. 39.”
GAAP		Accounting Principles Generally Accepted in the United States of America.
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.
JBR		Jet Bubbling Reactor.
JMG		JMG Funding LP.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
kV		Kilovolt.
KWH		Kilowatthour.
LPSC		Louisiana Public Service Commission.
MISO		Midwest Independent Transmission System Operator.
MLR		Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MMBtu		Million British Thermal Units.
MTM		Mark-to-Market.
MW		Megawatt.
MWH		Megawatthour.
NOx		Nitrogen oxide.
Nonutility Money Pool		AEP Consolidated’s Nonutility Money Pool.
NSR		New Source Review.
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.
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.
SEC		United States Securities and Exchange Commission.

SECA		Seams Elimination Cost Allocation.
SEET		Significant Excess Earnings Test.
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.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC		AEP Texas Central Company, an AEP electric utility subsidiary.
TCRR		Transmission Cost Recovery Rider.
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:

·	The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·	Inflationary or deflationary interest rate trends.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·	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 including our ability to restore Indiana Michigan Power Company’s Donald C. Cook Nuclear Plant Unit 1 in a timely manner.
·	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 and transmission line facilities (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 cancelled) 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.
·	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 regional transmission organizations, including PJM and SPP.
·	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 and the impact on future funding requirements.
·	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.

AEP and its Registrant Subsidiaries 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

Economic Slowdown

The financial struggles of the U.S. economy continue to impact our industrial sales as well as sales opportunities in the wholesale market. Industrial sales in various sections of our service territories are decreasing due to reduced shifts and suspended operations by some of our large industrial customers. Although many sections of our service territories are experiencing slowdowns in new construction, our residential and commercial customer base appears to be stable. As a result of these economic issues, we are currently monitoring the following:

·	Margins from Off-system Sales - Margins from off-system sales continue to decrease due to reductions in sales volumes and weak market power prices, reflecting reduced overall demand for electricity. We currently forecast that off-system sales volumes will decrease by approximately 30% in 2009. These trends will most likely continue until the economy rebounds and electricity demand and prices increase.

·	Industrial KWH Sales - Industrial KWH sales for the quarter ended March 31, 2009 were down 15% in comparison to the quarter ended March 31, 2008. Approximately half of this decrease was due to cutbacks or closures by six of our large metals customers. We also experienced additional significant decreases in KWH sales to customers in the plastics, rubber, auto and paper manufacturing industries. Since our trends for industrial sales are usually similar to the nation’s industrial production, these trends are likely to continue until industrial production improves.

·	Risk of Loss of Major Customers - We monitor the financial strength and viability of each of our major industrial customers individually. We have factored this analysis into our operational planning. Our largest customer, Ormet, an industrial customer with a 520 MW load, recently announced that it is in dispute with its sole customer which could potentially force Ormet to halt production.

Capital Markets

The financial markets remain volatile at both a global and domestic level. This marketplace distress could impact our access to capital, liquidity, asset valuations in our trust funds, the creditworthy status of customers, suppliers and trading partners and our cost of capital. We actively manage these factors with oversight from our risk committee. We cannot predict the length of time the current credit market situation will continue or its impact on future operations and our ability to issue debt at reasonable interest rates. Despite the current volatile markets, we were able to issue approximately $1 billion of long-term debt in the first quarter of 2009 and $1.64 billion (net proceeds) of AEP common stock in April 2009.

We believe that we have adequate liquidity to support our planned business operations and construction program for the remainder of 2009 due to the following:

·	As of March 31, 2009, we had $2.2 billion in aggregate available liquidity under our credit facilities. These credit facilities include 27 different banks with no one bank having more than 10% of our total bank commitments. In April 2009, we allowed $350 million of our credit facility commitments to expire. As of March 31, 2009, cash and cash equivalents were $710 million.
·	Of our $17 billion of long-term debt as of March 31, 2009, approximately $300 million will mature during the remainder of 2009 (approximately 1.8% of our outstanding long-term debt as of March 31, 2009). The $300 million of remaining 2009 maturities exclude payments due for securitization bonds which we recover directly from ratepayers.

In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion. We used $1.25 billion of the proceeds to repay part of the cash drawn under our credit facilities. These transactions improved our debt to capital ratio to 58.1% assuming no other changes from our March 31, 2009 balance sheet. With the remaining proceeds, we intend to pay down other existing debt. These actions will help to support our investment grade ratings and maintain financial flexibility.

We believe that our projected cash flows from operating activities are sufficient to support our ongoing operations.

Approximately $1.7 billion of outstanding long-term debt will mature in 2010, excluding payments due for securitization bonds which we recover directly from ratepayers. We intend to refinance or repay our debt maturities.

We sponsor several trust funds with significant investments intended to provide for future payments of pensions, OPEB, nuclear decommissioning and spent nuclear fuel disposal. Although all of our trust funds’ investments are diversified and managed in compliance with all laws and regulations, the value of the investments in these trusts declined substantially over the past year due to decreases in domestic and international equity markets. Although the asset values are currently lower, this has not affected the funds’ ability to make their required payments. The decline in pension asset values will not require us to make a contribution under ERISA in 2009. We estimate that we will need to make minimum contributions to our pension trust of $475 million in 2010 and $283 million in 2011. However, estimates may vary significantly based on market returns, changes in actuarial assumptions and other factors.

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. Our risk management organization monitors these exposures on a daily basis to limit our economic and financial statement impact on a counterparty basis. At March 31, 2009, our credit exposure net of collateral was approximately $825 million of which approximately 89% is to investment grade counterparties. At March 31, 2009, our exposure to financial institutions was $42 million, which represents 5% of our total credit exposure net of collateral (all investment grade).

Regulatory Activity

In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall and Turk generating facilities. These financing costs are currently being capitalized as AFUDC in Arkansas. A decision is not expected until the fourth quarter of 2009 or the first quarter of 2010.

In March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP filings. If accepted by CSPCo and OPCo, the ESPs would be in effect through 2011. Among other things, the ESP order authorized capped increases to revenues during the three-year ESP period and also authorized a fuel adjustment clause (FAC) which allows CSPCo and OPCo to phase-in and defer actual fuel costs incurred, along with purchased power and related expenses that will be trued-up, subject to annual caps and prudency and accounting reviews. Deferred phase-in regulatory asset balances for fuel costs not currently recovered due to the cap are expected to be material. The projected revenue increases for CSPCo and OPCo are listed below:

	Projected Revenue Increases
	2009			2010			2011
	(in millions)
CSPCo		$	116		$	109		$	116
OPCo			130			125			153

The above revenues include some incremental cost recoveries. In addition to the revenue increases, net income will be positively affected by the material noncash phase-in deferrals from 2009 through 2011. These deferrals will be collected from 2012 through 2018.

For additional details related to the ESPs, see the “Ohio Electric Security Plan Filings” section of “Significant Factors.”

In March 2009, the IURC approved the settlement agreement with I&M with modifications that provides for an annual increase in revenues of $42 million, including a $19 million increase in revenue from base rates and $23 million in additional tracker revenues for certain incurred costs, subject to true-up.

In March 2009, APCo and WPCo filed an annual ENEC filing with the WVPSC for an increase of approximately $442 million for incremental fuel, purchased power and environmental compliance project expenses, to become effective July 2009. In March 2009, the WVPSC issued an order suspending the rate increase request until December 2009. In April 2009, APCo and WPCo filed a motion for approval of a provisional interim ENEC increase of $156 million, effective July 2009 and subject to refund pending the adjudication of the ENEC by December 2009.

Capital Expenditures

Due to recent capital market instability and the economic slowdown, we reduced our planned capital expenditures for 2010 from $3.4 billion to $1.8 billion:

	2010
	Capital Expenditure
	Budget
	(in millions)
New Generation	$	251
Environmental		252
Other Generation		431
Transmission		290
Distribution		552
Corporate		70

Total	$	1,846

We also reduced our 2011 environmental capital expenditure projection from $892 million to $246 million. We intend to keep operation and maintenance expense relatively flat in 2009 in comparison to 2008. We do not believe that these cutbacks will jeopardize the reliability of the AEP System.

Cook Plant Unit 1 Fire and Shutdown

Fuel Costs

For 2009, we expect our coal costs to increase by approximately 12%. With the recent ESP orders for CSPCo and OPCo, we now have active fuel cost recovery mechanisms in all of our jurisdictions. The deferred fuel balances of CSPCo and OPCo at the end of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, CSPCo and OPCo had a combined $83 million under-recovered fuel balance, including carrying costs. We expect this amount to increase significantly over the remainder of 2009. Depending upon certain variables, including the potential escalation of fuel costs and the timing of the economic recovery, this amount may continue to increase in 2010 and 2011.

Recent coal consumption and projected consumption for the remainder of 2009 have decreased significantly. As a result, we are in discussions with our coal suppliers in an effort to better match deliveries with our current consumption trends and to minimize the impact on fuel inventory costs.

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.

AEP River Operations

Commercial barging operations that annually transport approximately 33 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. Approximately 38% of the barging is for the transportation of agricultural products, 30% for coal, 13% for steel and 19% 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, 2009 and 2008.

	Three Months Ended March 31,
	2009				2008
	(in millions)
Utility Operations		$	346			$	413
AEP River Operations			11				7
Generation and Marketing			24				1
All Other (a)			(18	)			155
Net Income		$	363			$	576

(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 2006.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP Consolidated

First Quarter of 2009 Compared to First Quarter of 2008

Net Income in 2009 decreased $213 million compared to 2008 primarily due to income of $164 million (net of tax) in 2008 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 a decrease in Utility Operations segment earnings of $67 million. The decrease in Utility Operations segment net income primarily relates to lower off-system sales margins due to lower sales volumes and lower market prices which reflect weak market demand.

Average basic shares outstanding increased to 407 million in 2009 from 401 million in 2008 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans. In 2008, we contributed 1.25 million shares of common stock held in treasury to the AEP Foundation. The AEP Foundation is an AEP charitable organization created in 2005 for charitable contributions in the communities in which AEP’s subsidiaries operate. Actual shares outstanding were 408 million as of March 31, 2009. In April 2009, we issued 69 million shares of AEP common stock at $24.50 per share for total net proceeds of $1.64 billion.

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,
	2009		2008
	(in millions)
Revenues	$	3,267	$	3,294
Fuel and Purchased Power		1,196		1,213
Gross Margin		2,071		2,081
Depreciation and Amortization		373		355
Other Operating Expenses		994		941
Operating Income		704		785
Other Income, Net		30		43
Interest Charges		220		208
Income Tax Expense		168		207
Net Income	$	346	$	413

Summary of Selected Sales and Weather Data

For Utility Operations

For the Three Months Ended March 31, 2009 and 2008

	2009		2008
Energy Summary	(in millions of KWH)
Retail:
Residential		14,368		14,500
Commercial		9,395		9,547
Industrial		12,126		14,350
Miscellaneous		576		609
Total Retail		36,465		39,006

Wholesale		6,777		11,742

Texas Wires – Energy Delivered to Customers Served by TNC and TCC in ERCOT		5,738		5,823
Total KWHs		48,980		56,571

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income. In general, degree day changes in our eastern region have a larger effect on net income 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, 2009 and 2008 were as follows:

	2009		2008
Weather Summary	(in degree days)
Eastern Region
Actual – Heating (a)		1,900		1,830
Normal – Heating (b)		1,791		1,767

Actual – Cooling (c)		5		-
Normal – Cooling (b)		3		3

Western Region (d)
Actual – Heating (a)		854		941
Normal – Heating (b)		905		931

Actual – Cooling (c)		38		26
Normal – Cooling (b)		20		20

(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 2009 Compared to First Quarter of 2008

Reconciliation of First Quarter of 2008 to First Quarter of 2009

Net Income from Utility Operations

(in millions)

First Quarter of 2008			$	413

Changes in Gross Margin:
Retail Margins	61
Off-system Sales	(136	)
Transmission Revenues	4
Other Revenues	61
Total Change in Gross Margin				(10	)

Changes in Operating Expenses and Other:
Other Operation and Maintenance	(56	)
Gain on Dispositions of Assets, Net	3
Depreciation and Amortization	(18	)
Interest Income	(10	)
Carrying Costs Income	(8	)
Other Income, Net	5
Interest Expense	(12	)
Total Change in Operating Expenses and Other				(96	)

Income Tax Expense				39

First Quarter of 2009			$	346

Net Income from Utility Operations decreased $67 million to $346 million in 2009. The key drivers of the decrease were a $10 million decrease in Gross Margin and a $96 million increase in Operating Expenses and Other, partially offset by a $39 million decrease in Income Tax Expense.

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

·	Retail Margins increased $61 million primarily due to the following:
	·	A $58 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $17 million increase in base rates in Oklahoma, a $13 million increase related to the net increases in Ohio as a result of the PUCO’s approval of our Ohio ESPs and a $5 million net rate increase for I&M.
	·	A $54 million increase resulting from reduced sharing of off-system sales margins with retail customers in our eastern service territory due to a decrease in total off-system sales.
	·	A $6 million increase in fuel margins in Ohio due to the deferral of fuel costs by CSPCo and OPCo in 2009. The PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs allows for the recovery of fuel and related costs during the ESP period. See “Ohio Electric Security Plan Filings” section of Note 3.
	These increases were partially offset by:
	·	A $58 million decrease in fuel margins related to an OPCo coal contract amendment recorded in 2008 which reduced future deliveries to OPCo in exchange for consideration received.
	·	A $32 million decrease in margins from industrial sales due to reduced shifts and suspended operations by some of the large industrial customers in our service territories.
	·	A $20 million decrease in fuel margins due to higher fuel and purchased power costs related to the Cook Plant Unit 1 shutdown. This decrease in fuel margins was offset by a corresponding increase in Other Revenues as discussed below.
·	Margins from Off-system Sales decreased $136 million primarily due to lower physical sales volumes and lower margins in our eastern service territory reflecting lower market prices, partially offset by higher trading margins.
·	Other Revenues increased $61 million primarily due to Cook Plant accidental outage insurance policy proceeds of $54 million. Of these insurance proceeds, $20 million were used to offset fuel costs associated with the Cook Plant Unit 1 shutdown. This increase in revenues was offset by a corresponding decrease in Retail Margins as discussed above. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

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

·	Other Operation and Maintenance expenses increased $56 million primarily due to the following:
	·	An $80 million increase related to the deferral of Oklahoma ice storm costs in 2008 resulting from an OCC order approving recovery of January and December 2007 ice storm expenses.
	·	A $38 million increase related to storm restoration expenses, primarily in our eastern service territory.
	·	A $15 million increase related to an obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs. See “Ohio Electric Security Plan Filings” section of Note 3.
	These increases were partially offset by:
	·	A $34 million decrease in employee-related expenses.
	·	A $14 million decrease in plant outage and other maintenance expenses.
	·	A $13 million decrease in tree trimming, reliability and other transmission and distribution expenses.
	·	A $10 million decrease related to the write-off of the unrecoverable pre-construction costs for PSO’s cancelled Red Rock Generating Facility in the first quarter of 2008.
·	Depreciation and Amortization increased $18 million primarily due to higher depreciable property balances as the result of environmental improvements placed in service at OPCo and various other property additions and higher depreciation rates for OPCo related to shortened depreciable lives for certain generating facilities.
·	Interest Income decreased $10 million primarily due to the 2008 favorable effect of claims for refund filed with the IRS.
·	Carrying Costs Income decreased $8 million primarily due to the completion of reliability deferrals in Virginia in December 2008 and the decrease of environmental deferrals in Virginia in 2009.
·	Interest Expense increased $12 million primarily due to increased long-term debt and higher interest rates on variable rate debt.
·	Income Tax Expense decreased $39 million due to a decrease in pretax income.

AEP River Operations

First Quarter of 2009 Compared to First Quarter of 2008

Net Income from our AEP River Operations segment increased from $7 million in 2008 to $11 million in 2009 primarily due to lower fuel costs and gains on the sale of two older towboats. These increases were partially offset by lower revenues due to reduced import volumes and lower freight rates.

Generation and Marketing

First Quarter of 2009 Compared to First Quarter of 2008

Net Income from our Generation and Marketing segment increased from $1 million in 2008 to $24 million in 2009 primarily due to higher gross margins from marketing activities.

All Other

First Quarter of 2009 Compared to First Quarter of 2008

Net Income from All Other decreased from income of $155 million in 2008 to a loss of $18 million in 2009. In 2008, we had after-tax income of $164 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 Charges of $255 million in the accompanying Condensed Consolidated Statements of Income.

AEP System Income Taxes

Income Tax Expense decreased $114 million in the first quarter of 2009 compared to the first quarter of 2008 primarily due to a decrease in pretax book income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization
	March 31, 2009			December 31, 2008
	($ in millions)
Long-term Debt, including amounts due within one year	$	16,843	56.5%	$	15,983	55.6%
Short-term Debt		1,976	6.6		1,976	6.9
Total Debt		18,819	63.1		17,959	62.5
Preferred Stock of Subsidiaries		61	0.2		61	0.2
AEP Common Equity		10,940	36.6		10,693	37.2
Noncontrolling Interests		18	0.1		17	0.1

Total Debt and Equity Capitalization	$	29,838	100.0%	$	28,730	100.0%

As of March 31, 2009, our ratio of debt-to-total capital was 63.1%. After the issuance of 69 million new common shares and the application of the net proceeds of $1.64 billion to reduce debt, our pro forma ratio of debt-to-capital as of the date of issuance would have been 57.6%.

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.

Capital Markets

In 2008, the domestic and world economies experienced significant slowdowns. The financial markets remain volatile at both a global and domestic level. This marketplace distress could impact our access to capital, liquidity and cost of capital. The uncertainties in the capital markets could have significant implications since we rely on continuing access to capital to fund operations and capital expenditures. We cannot predict the length of time the credit situation will continue or its impact on future operations and our ability to issue debt at reasonable interest rates.

We believe we have adequate liquidity through 2009 under our existing credit facilities. However, the current credit markets could constrain our ability to issue commercial paper. Approximately $300 million (excluding payments due for securitization bonds which we recover directly from ratepayers) of our $17 billion of long-term debt as of March 31, 2009 will mature during the remainder of 2009. We intend to refinance debt maturities. At March 31, 2009, we had $3.9 billion ($3.6 billion after an April expiration of one facility) in aggregate credit facility commitments to support our operations. These commitments include 27 different banks with no one bank having more than 10% of our total bank commitments.

During the first quarter of 2009, we issued $475 million of 7% senior notes due 2019, $350 million of 7.95% senior notes due 2020, $100 million of 6.25% Pollution Control Bonds due 2025 and $34 million of 5.25% Pollution Control Bonds due 2014.

During 2008, we chose to begin eliminating our auction-rate debt position due to market conditions. As of March 31, 2009, $272 million of our auction-rate tax-exempt long-term debt (rates range between 1.676% and 13%) remained outstanding with rates reset every 35 days. 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. Approximately $218 million of the $272 million of outstanding auction-rate debt relates to a lease structure with JMG that we are unable to refinance without JMG’s consent. The rates for this debt are at contractual maximum rates of 13%. The initial term for the JMG lease structure matures on March 31, 2010. We are evaluating whether to terminate this facility prior to maturity. Termination of this facility requires approval from the PUCO.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At March 31, 2009, our available liquidity was approximately $2.2 billion as illustrated in the table below:

	Amount			Maturity
	(in millions)
Commercial Paper Backup:
Revolving Credit Facility	$	1,500		March 2011
Revolving Credit Facility		1,454	(a)	April 2012
Revolving Credit Facility		627	(a)	April 2011
Revolving Credit Facility		338	(a)(b)	April 2009
Total		3,919
Cash and Cash Equivalents		710
Total Liquidity Sources		4,629
Less: Cash Drawn on Credit Facilities		1,969	(c)
Letters of Credit Issued		492

Net Available Liquidity	$	2,168

(a)	Reduced by Lehman Brothers Holdings Inc.’s commitment amount of $81 million following its bankruptcy.
(b)	Expired in April 2009.
(c)	Paid $1.25 billion with proceeds from the equity issuance in April 2009.

The revolving credit facilities for commercial paper backup were structured as two $1.5 billion credit facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy. The credit facilities allow for the issuance of up to $750 million as letters of credit under each credit facility.

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, 2009, we had credit facilities totaling $3 billion to support our commercial paper program. In 2008, we borrowed $2 billion under these credit facilities at a LIBOR rate. In April 2009, we repaid $1.25 billion of the $2 billion borrowed under the credit facilities. The maximum amount of commercial paper outstanding during 2009 was $308 million. The weighted-average interest rate for our commercial paper during 2009 was 1.22%. No commercial paper was outstanding at March 31, 2009.

As of March 31, 2009, under the $650 million 3-year credit agreement reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million following its bankruptcy, letters of credit of $372 million were issued to support variable rate Pollution Control Bonds.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At March 31, 2009, this contractually-defined percentage was 59.1%. Nonperformance of these covenants could result in an event of default under these credit agreements. At March 31, 2009, 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 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, 2009, 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, representing 396 consecutive quarters. The Board of Directors declared a quarterly dividend of $0.41 per share in April 2009. 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 cash flows, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

Our credit ratings as of March 31, 2009 were as follows:

	Moody’s	S&P	Fitch

AEP Short-term Debt	P-2	A-2	F-2
AEP Senior Unsecured Debt	Baa2	BBB	BBB

In 2009, Moody’s:

·	Placed AEP on negative outlook due to concern about overall credit worthiness, pending rate cases and recessionary pressures.
·	Placed OPCo, SWEPCo, TCC and TNC on review for possible downgrade due to concerns about financial metrics and pending cost and construction recoveries.
·	Affirmed the stable rating outlooks for CSPCo, I&M, KPCo and PSO.
·	Changed the rating outlook for APCo from negative to stable due to recent rate recoveries in Virginia and West Virginia.

In 2009, Fitch:

·	Affirmed its stable rating outlook for I&M, PSO and TNC.
·	Changed its rating outlook for TCC from stable to negative.

If we receive a downgrade in our credit ratings by any of the rating agencies, 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,
	2009				2008
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	411			$	178
Net Cash Flows from Operating Activities			317				631
Net Cash Flows Used for Investing Activities			(727	)			(894	)
Net Cash Flows from Financing Activities			709				240
Net Increase (Decrease) in Cash and Cash Equivalents			299				(23	)
Cash and Cash Equivalents at End of Period		$	710			$	155

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,
	2009				2008
	(in millions)
Net Income		$	363			$	576
Depreciation and Amortization			382				363
Other			(428	)			(308	)
Net Cash Flows from Operating Activities		$	317			$	631

Net Cash Flows from Operating Activities decreased in 2009 primarily due to a decline in net income and an increase in fuel inventory.

Net Cash Flows from Operating Activities were $317 million in 2009 consisting primarily of Net Income of $363 million and $382 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 an increase in coal inventory from December 31, 2008.

Net Cash Flows from Operating Activities were $631 million in 2008 consisting primarily of Net Income of $576 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.

Investing Activities

	Three Months Ended
	March 31,
	2009				2008
	(in millions)
Construction Expenditures		$	(897	)		$	(778	)
Proceeds from Sales of Assets			172				18
Other			(2	)			(134	)
Net Cash Flows Used for Investing Activities		$	(727	)		$	(894	)

Net Cash Flows Used for Investing Activities were $727 million in 2009 and $894 million in 2008 primarily due to Construction Expenditures for our new generation, environmental and distribution investment plan. Construction Expenditures increased compared to 2008 due to expenditures for new generation during 2009. Proceeds from Sales of Assets in 2009 primarily includes $104 million in progress payments for Turk Plant construction from the joint owners.

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 $2.6 billion of construction expenditures for all of 2009, excluding AFUDC. 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 net income and financing activities.

Financing Activities

	Three Months Ended
	March 31,
	2009				2008
	(in millions)
Issuance of Common Stock		$	48			$	45
Issuance/Retirement of Debt, Net			854				376
Dividends Paid on Common Stock			(169	)			(167	)
Other			(24	)			(14	)
Net Cash Flows from Financing Activities		$	709			$	240

Net Cash Flows from Financing Activities in 2009 were $709 million primarily due to the issuance of $825 million of senior unsecured notes and $134 million of pollution control bonds. See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2008 were $240 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 $251 million.

Our capital investment plans for the remainder of 2009 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, 2009			December 31, 2008
	(in millions)
AEP Credit Accounts Receivable Purchase Commitments		$	578		$	650
Rockport Plant Unit 2 Future Minimum Lease Payments			2,070			2,070
Railcars Maximum Potential Loss From Lease Agreement			25			25

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 2008 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2008 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above and the drawdowns 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 2008 Annual Report. The 2008 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 2008 Annual Report, but may have a material impact on our future net income, cash flows and financial condition.

Ohio Electric Security Plan Filings

In March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which will be in effect through 2011. The ESP order authorized increases to revenues during the ESP period and capped the overall revenue increases through a phase-in of the fuel adjustment clause (FAC). The ordered increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are 8% in 2009, 7% in 2010 and 8% in 2011. After final PUCO review and approval of conforming rate schedules, CSPCo and OPCo implemented rates for the April 2009 billing cycle. CSPCo and OPCo will collect the 2009 annualized revenue increase over the remainder of 2009.

The order provides a FAC for the three-year period of the ESP. The FAC increase will be phased in to meet the ordered annual caps described above. The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews. The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC balance at the end of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, the FAC deferral balances were $17 million and $66 million for CSPCo and OPCo, respectively, including carrying charges. The PUCO rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins. As a result, CSPCo and OPCo will retain the benefit of their share of the AEP System’s off-system sales. In addition, the ESP order provided for both the FAC deferral credits and the off-system sales margins to be excluded from the methodology for the Significantly Excessive Earnings Test (SEET). The SEET is discussed below.

Additionally, the order addressed several other items, including:

The approval of new distribution riders, subject to true-up for recovery of costs for enhanced vegetation management programs for CSPCo and OPCo and the proposed gridSMART advanced metering initial program roll out in a portion of CSPCo’s service territory. The PUCO proposed that CSPCo mitigate the costs of gridSMART by seeking matching funds under the American Recovery and Reinvestment Act of 2009. As a result, a rider was established to recover 50% or $32 million of the projected $64 million revenue requirement related to gridSMART costs. The PUCO denied the other distribution system reliability programs proposed by CSPCo and OPCo as part of their ESP filings. The PUCO decided that those requests should be examined in the context of a complete distribution base rate case. The order did not require CSPCo and/or OPCo to file a distribution base rate case.

The approval of CSPCo’s and OPCo’s request to recover the incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates. Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings.

·	The approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s Provider of Last Resort charges, respectively, to compensate for the risk of customers changing electric suppliers during the ESP period.

The requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum of $15 million in costs over the ESP period for low-income, at-risk customer programs. This funding obligation was recognized as a liability and an unfavorable adjustment to Other Operation and Maintenance expense for the three-month period ending March 31, 2009.

The deferral of CSPCo’s and OPCo’s request to recover certain existing regulatory assets, including customer choice implementation and line extension carrying costs as part of the ESPs. The PUCO decided it would be more appropriate to consider this request in the context of CSPCo’s and OPCo’s next distribution base rate case. These regulatory assets, which were approved by prior PUCO orders, total $58 million for CSPCo and $40 million for OPCo as of March 31, 2009. In addition, CSPCo and OPCo would recover and recognize as income, when collected, $35 million and $26 million, respectively, of related unrecorded equity carrying costs incurred through March 2009.

Finally, consistent with its decisions on ESP orders of other companies, the PUCO ordered its staff to convene a workshop to determine the methodology for the SEET that will be applicable to all electric utilities in Ohio. The SEET requires the PUCO to determine, following the end of each year of the ESP, if any rate adjustments included in the ESP resulted in excessive earnings as measured by whether the earned return on common equity of CSPCo and OPCo is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that have comparable business and financial risk. If the rate adjustments, in the aggregate, result in significantly excessive earnings in comparison, the PUCO must require that the amount of the excess be returned to customers. The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the second or third quarter of 2010.

In March 2009, intervenors filed a motion to stay a portion of the ESP rates or alternately make that portion subject to refund because the intervenors believed that the ordered ESP rates for 2009 were retroactive and therefore unlawful. In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs effective with the April 2009 billing cycle and rejected the intervenors’ motion. The PUCO also clarified that the reference in its earlier order to the January 1, 2009 date related to the term of the ESP, not to the effective date of tariffs and clarified the tariffs were not retroactive. In March 2009, CSPCo and OPCo implemented the new ESP tariffs effective with the start of the April 2009 billing cycle. In April 2009, CSPCo and OPCo filed a motion requesting rehearing of several issues. In April 2009, several intervenors filed motions requesting rehearing of issues underlying the PUCO’s authorized rate increases and one intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease collecting rates under the order. Certain intervenors also filed a complaint for writ of prohibition with the Ohio Supreme Court to halt any further collection from customers of what the intervenors claim is unlawful retroactive rate increases.

Management will evaluate whether it will withdraw the ESP applications after a final order, thereby terminating the ESP proceedings. If CSPCo and/or OPCo withdraw the ESP applications, CSPCo and/or OPCo may file a Market Rate Offer (MRO) or another ESP as permitted by the law. The revenues collected and recorded in 2009 under this PUCO order are subject to possible refund through the SEET process. Management is unable, due to the decision of the PUCO to defer guidance on the SEET methodology to a future generic SEET proceeding, to estimate the amount, if any, of a possible refund that could result from the SEET process in 2010.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, located in the turbine building, is separate and isolated from the nuclear reactor. The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period. The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship. I&M is working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and facilitate repairs to return the unit to service. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330 million. Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process. The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. I&M is repairing Unit 1 to resume operations as early as October 2009 at reduced power. Should post-repair operations prove unsuccessful, the replacement of parts will extend the outage into 2011.

I&M maintains property insurance through NEIL with a $1 million deductible. As of March 31, 2009, we recorded $34 million in Prepayments and Other on our Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy. I&M received partial reimbursements from NEIL for the cost incurred to date to repair the property damage. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12-week deductible period, I&M is entitled to weekly payments of $3.5 million for the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. I&M began receiving payments under the accidental outage policy in December 2008. In the first quarter of 2009, I&M recorded $54 million in revenues, including $9 million in revenues that were deferred at December 31, 2008, related to the accidental outage policy. In order to hold customers harmless, in the first quarter of 2009, I&M applied $20 million of the accidental outage insurance proceeds to reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were operating. If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

Texas Restructuring Appeals

Pursuant to PUCT orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC refunded net other true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider. Although earnings were not affected by this CTC refund, cash flow was adversely impacted for 2008, 2007 and 2006 by $75 million, $238 million and $69 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 orders seeking to further reduce TCC’s true-up recoveries.

In March 2007, the Texas District Court judge hearing the appeals 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. This remand could potentially have an adverse effect on TCC’s future net income and cash flows if upheld on appeal. The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness which could have a favorable effect on TCC’s future net income and cash flows.

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 two major respects. It reversed the District Court’s unfavorable decision which found that the PUCT erred by applying an invalid rule to determine the carrying cost rate. It also determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs. Management does not believe that TCC will be adversely affected by the Court of Appeals ruling on excess earnings based upon the reasons discussed in the “TCC Excess Earnings” section below. The favorable commercial unreasonableness judgment entered by the District Court was not reversed. The Texas Court of Appeals denied intervenors’ motion for rehearing. In May 2008, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court. Review is discretionary and the Texas Supreme Court has not determined if it will grant review. In January 2009, the Texas Supreme Court requested full briefing of the proceedings.

TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed. The appeal brought by TNC of the final true-up order remains pending in state court.

Management cannot predict the outcome of these court proceedings and PUCT remand decisions. If TCC and/or TNC ultimately succeed in their appeals, it could have a material favorable effect on future net income, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, it could have a material adverse effect on future net income, cash flows and possibly financial condition.

New Generation/Purchase Power Agreement

In 2009, AEP 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)

AEGCo

Dresden

(c)

Ohio

322

189

Gas

Combined-cycle

580

2013

SWEPCo

Stall

Louisiana

385

291

Gas

Combined-cycle

500

2010

SWEPCo

Turk

(d)

Arkansas

1,628

(d)

480

Coal

Ultra-supercritical

600

(d)

2012

APCo

Mountaineer

(e)

West Virginia

(e)

Coal

IGCC

629

(e)

CSPCo/OPCo

Great Bend

(e)

Ohio

(e)

Coal

IGCC

629

(e)

(a)	Amount excludes AFUDC.
(b)	Amount includes AFUDC.
(c)	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.
(d)	SWEPCo plans to own approximately 73%, or 440 MW, totaling $1.2 billion in capital investment. See “Turk Plant” section below.
(e)	Construction of IGCC plants is subject to regulatory approvals. See “IGCC Plants” section below.

Turk Plant

In November 2007, the APSC granted approval to build the Turk Plant. Certain landowners have appealed the APSC’s decision to the Arkansas State Court of Appeals. In March 2008, the LPSC approved the application to construct the Turk Plant.

In August 2008, the PUCT issued an order approving the Turk Plant with the following four conditions: (a) the capping of capital costs for the Turk Plant at the previously estimated $1.522 billion projected construction cost, excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders. In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions. If the cost cap restrictions are upheld and construction or emission costs exceed the restrictions, it could have a material adverse effect on future net income and cash flows. In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers.

A request to stop pre-construction activities at the site was filed in federal court by Arkansas landowners. In July 2008, the federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals. In January 2009, SWEPCo filed a motion to dismiss the appeal. In March 2009, the motion was granted.

In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality and commenced construction. In December 2008, Arkansas landowners filed an appeal with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while an appeal of the Turk Plant’s permit is heard. Hearings on the air permit appeal are scheduled for June 2009. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit. In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands impact on approximately 2.5 acres at the Turk Plant. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas of the Turk Plant. The impact on the construction schedule and workforce is currently being evaluated by management.

In January and July 2008, SWEPCo filed Certificate of Environmental Compatibility and Public Need (CECPN) applications with the APSC to construct transmission lines necessary for service from the Turk Plant. Several landowners filed for intervention status and one landowner also contended he should be permitted to re-litigate Turk Plant issues, including the need for the generation. The APSC granted their intervention but denied the request to re-litigate the Turk Plant issues. In June 2008, the landowner filed an appeal to the Arkansas State Court of Appeals requesting to re-litigate Turk Plant issues. SWEPCo responded and the appeal was dismissed. In January 2009, the APSC approved the CECPN applications.

The Arkansas Governor’s Commission on Global Warming issued its final report to the governor in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build and operate 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 costs incurred plus related shutdown costs. If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements. As of March 31, 2009, SWEPCo has capitalized approximately $480 million of expenditures (including AFUDC) and has contractual construction commitments for an additional $655 million. As of March 31, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $100 million. If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future net income, cash flows and possibly financial condition.

IGCC Plants

The construction of the West Virginia and Ohio IGCC plants are pending regulatory approvals. In April 2008, the Virginia SCC issued an order denying 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. Comments were filed by various parties, including APCo, but the WVPSC has not taken any action. In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant contingent upon the commencement of construction, qualifying expenses being incurred and certification of the IGCC plant prior to July 2010. Through March 2009, APCo deferred for future recovery preconstruction IGCC costs of $20 million. If the West Virginia IGCC plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. If the plant is cancelled and if the deferred costs are not recoverable, it would have an adverse effect on future net income and cash flows.

In Ohio, neither CSPCo nor OPCo are engaged in a continuous course of construction on the IGCC plant. However, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant. In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all pre-construction cost recoveries be refunded to Ohio ratepayers with interest. CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent. If CSPCo and OPCo were required to refund some or all of the $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 net income and cash flows.

PSO Purchase Power Agreement

PSO and Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term purchase power agreement (PPA) for which an application seeking its approval is expected to be filed with the OCC. The PPA is for the purchase of up to 520 MW of electric generation from the 795 MW natural gas-fired Green Country Generating Station, located in Jenks, Oklahoma. The agreement is the result of PSO’s 2008 Request for Proposals following a December 2007 OCC order that found PSO had a need for new baseload generation by 2012.

Litigation

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss 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 2008 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 net income and cash flows.

Environmental Litigation

New Source Review (NSR) Litigation: The Federal EPA, a number of states and certain special interest groups filed complaints alleging that CSPCo, 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.

Litigation continues against Beckjord, a plant jointly-owned by CSPCo, Duke and DP&L, which Duke operates. A jury trial returned a verdict of no liability at the Beckjord unit. In December 2008, however, the court ordered a new trial in the Beckjord case. We are unable to predict the outcome of this case. 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 net income 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 involved 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 2008 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 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 sought further review and filed for relief from the schedules included in our permits.

In April 2009, the U.S. Supreme Court issued a decision that allows the Federal EPA the discretion to rely on cost-benefit analysis in setting national performance standards and in providing for cost-benefit variances from those standards as part of the regulations. We cannot predict if or how the Federal EPA will apply this decision to any revision of the regulations or what effect it may have on similar requirements adopted by the states.

Potential Regulation of CO2 and Other GHG Emissions

As discussed in the 2008 Annual Report, CO2 and other GHG are alleged to contribute to climate change. In April 2009, the Federal EPA issued a proposed endangerment finding under the CAA regarding GHG emissions from motor vehicles. The proposed endangerment finding is subject to public comment. This finding could lead to regulation of CO2 and other gases under existing laws. Congress continues to discuss new legislation related to the control of these emissions. Some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including us. Because of these adverse consequences, management believes that these more extreme policies will not ultimately be adopted. Even if reasonable CO2 and other GHG emission standards are imposed, they will still require us to make material expenditures. Management believes that costs of complying with new CO2 and other GHG emission standards will be treated like all other reasonable costs of serving customers, and should be recoverable from customers as costs of doing business including capital investments with a return on investment.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2008 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

The FASB issued SFAS 141R (revised “Business Combinations” 2007) improving financial reporting about business combinations and their effects. SFAS 141R can affect tax positions on previous acquisitions. We do not have any such tax positions that result in adjustments. We adopted SFAS 141R effective January 1, 2009. We will apply it to any future business combinations.

The FASB issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160), modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. The statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest. We adopted SFAS 160 effective January 1, 2009 and retrospectively applied the standard to prior periods. See Note 2.

The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing disclosure requirements for derivative instruments and hedging activities. The standard requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This standard increased our disclosure requirements related to derivative instruments and hedging activities. We adopted SFAS 161 effective January 1, 2009.

The FASB ratified EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. We adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the effect of initial application included as a change in fair value of the liability.

The FASB ratified EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6), a consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. We prospectively adopted EITF 08-6 effective January 1, 2009 with no impact on our financial statements.

We adopted FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (EITF 03-6-1) effective January 1, 2009. The rule addressed whether instruments granted in share-based payment transactions are participating securities prior to vesting and determined that the instruments need to be included in earnings allocation in computing EPS under the two-class method. The adoption of this standard had an immaterial impact on our financial statements.

The FASB issued FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. We adopted the rule effective January 1, 2009. The guidance is prospectively applied to intangible assets acquired after the effective date. The standard’s disclosure requirements are applied prospectively to all intangible assets as of January 1, 2009. The adoption of this standard had no impact on our financial statements.

The FASB issued SFAS 157-2 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). As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. We adopted SFAS 157-2 effective January 1, 2009. We will apply these requirements to applicable fair value measurements which include new asset retirement obligations and impairment analysis related to long-lived assets, equity investments, goodwill and intangibles. We did not record any fair value measurements for nonrecurring nonfinancial assets and liabilities in the first quarter of 2009.

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 settle 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, coal, natural gas and emission allowances 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.

The Committee of Chief Risk Officers (CCRO) adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. 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 balance sheet as of March 31, 2009 and the reasons for changes in our total MTM value included on our balance sheet as compared to December 31, 2008.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

March 31, 2009

(in millions)

	Utility Operations			Generation and Marketing			All Other			Sub-Total MTM Risk Management Contracts			Cash Flow Hedge Contracts			Collateral Deposits			Total
Current Assets	$	256		$	27		$	4		$	287		$	40		$	(34	)	$	293
Noncurrent Assets		228			221			7			456			1			(40	)		417
Total Assets		484			248			11			743			41			(74	)		710

Current Liabilities		(153	)		(23	)		(9	)		(185	)		(31	)		37			(179	)
Noncurrent Liabilities		(155	)		(85	)		(10	)		(250	)		(4	)		80			(174	)
Total Liabilities		(308	)		(108	)		(19	)		(435	)		(35	)		117			(353	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	176		$	140		$	(8	)	$	308		$	6		$	43		$	357

MTM Risk Management Contract Net Assets (Liabilities)

Three Months Ended March 31, 2009

(in millions)

	Utility Operations			Generation and Marketing			All Other			Total
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2008	$	175		$	104		$	(7	)	$	272
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(27	)		(3	)		1			(29	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		2			51			-			53
Net Option Premiums Paid (Received) for Unexercised or Unexpired Option Contracts Entered During the Period		-			-			-			-
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts		-			-			-			-
Changes in Fair Value Due to Market Fluctuations During the Period (b)		7			(12	)		(2	)		(7	)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		19			-			-			19
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2009	$	176		$	140		$	(8	)		308
Cash Flow Hedge Contracts											6
Collateral Deposits											43
Ending Net Risk Management Assets at March 31, 2009										$	357

(a)	Reflects fair value on long-term structured 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. A significant portion of the total volumetric position has been economically hedged.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	“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 liabilities/assets.

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, 2009

(in millions)

	Remainder 2009			2010			2011		2012			2013		After 2013 (f)		Total
Utility Operations
Level 1 (a)	$	(6	)	$	-		$	-	$	-		$	-	$	-	$	(6	)
Level 2 (b)		62			34			17		(1	)		-		-		112
Level 3 (c)		16			8			5		5			1		-		35
Total		72			42			22		4			1		-		141

Generation and Marketing
Level 1 (a)		(8	)		-			-		-			-		-		(8	)
Level 2 (b)		7			15			16		16			18		25		97
Level 3 (c)		1			1			2		1			3		43		51
Total		-			16			18		17			21		68		140

All Other
Level 1 (a)		-			(1	)		-		-			-		-		(1	)
Level 2 (b)		(4	)		(5	)		2		-			-		-		(7	)
Level 3 (c)		-			-			-		-			-		-		-
Total		(4	)		(6	)		2		-			-		-		(8	)

Total
Level 1 (a)		(14	)		(1	)		-		-			-		-		(15	)
Level 2 (b)		65			44			35		15			18		25		202
Level 3 (c) (d)		17			9			7		6			4		43		86
Total		68			52			42		21			22		68		273
Dedesignated Risk Management Contracts (e)		10			14			6		5			-		-		35
Total MTM Risk Management Contract Net Assets (Liabilities)	$	78		$	66		$	48	$	26		$	22	$	68	$	308

(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 contracts.
(f)	There is mark-to-market value of $68 million in individual periods beyond 2014. $46 million of this mark-to-market value is in periods 2014-2018, $15 million is in periods 2019-2023 and $7 million is in periods 2024-2028.

Credit Risk

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. At March 31, 2009, our credit exposure net of collateral to sub investment grade counterparties was approximately 10.6%, expressed in terms of net MTM assets, 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, 2009, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure		Net Exposure of Counterparties >10%
Counterparty Credit Quality	(in millions, except number of counterparties)
Investment Grade	$	670	$	89	$	581		1	$	133
Split Rating		8		1		7		2		7
Noninvestment Grade		14		-		14		1		13
No External Ratings:
Internal Investment Grade		166		16		150		4		87
Internal Noninvestment Grade		83		10		73		2		55
Total as of March 31, 2009	$	941	$	116	$	825		10	$	295

Total as of December 31, 2008	$	793	$	29	$	764		9	$	284

See Note 7 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.

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, 2009 a near term typical change in commodity prices is not expected to have a material effect on our net income, 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

Twelve Months Ended

March 31, 2009

December 31, 2008

(in millions)

End

High

Average

Low

End

High

Average

Low

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 historical-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 translated into the largest potential MTM 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 $19 million. This amount includes the estimated impact of the April 2009 issuance of AEP common stock.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2009 and 2008

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

(Unaudited)

REVENUES	2009		2008
Utility Operations	$	3,267	$	3,010
Other		191		457