Edgar Filing: AMERICAN ELECTRIC POWER CO INC

Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended June 30, 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 X	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 July 30, 2009

American Electric Power Company, Inc.			476,790,811
			($6.50 par value)
Appalachian Power Company			13,499,500
			(no par value)
Columbus Southern Power Company			16,410,426
			(no par value)
Indiana Michigan Power Company			1,400,000
			(no par value)
Ohio Power Company			27,952,473
			(no par value)
Public Service Company of Oklahoma			9,013,000
			($15 par value)
Southwestern Electric Power Company			7,536,640
			($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO QUARTERLY REPORTS ON FORM 10-Q

June 30, 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 4.	Submission Matters to a Vote of Security Holders
	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.
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.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
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.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo		Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW		Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement		Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing 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.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo that is consolidated under FIN 46R.
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.
ETT		Electric Transmission Texas, LLC, a 50% equity interest joint venture with MidAmerican Energy Holdings Company formed to own and operate electric transmission facilities in ERCOT.

FAC		Fuel Adjustment Clause.
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.”
FSP SFAS 107-1 and APB 28-1		FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement		Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
JBR		Jet Bubbling Reactor.
JMG		JMG Funding LP.
KGPCo		Kingsport Power Company, an AEP electric distribution 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.
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 I&M’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, including the Turk Plant, 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

Our residential and commercial KWH sales appear to be relatively stable; nevertheless, some segments of our service territories are experiencing slowdowns. We are currently monitoring the following trends:

·	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 34% in 2009 in comparison to 2008.

·	Industrial KWH Sales - Industrial KWH sales for the quarter ended June 30, 2009 and the six months ended June 30, 2009 were down 21% and 18%, respectively. Approximately half of the decrease in the first six months of 2009 was due to cutbacks or closures by seven of our large metals producing customers. We also experienced additional significant decreases in KWH sales to customers in the plastics, rubber, auto and paper manufacturing industries. When the economy and export markets recover, we expect to see a return to more normal levels of industrial KWH sales.

·	Risk of Loss of Major Customers - We monitor the financial strength and viability of each of our major industrial customers individually. We factor our industrial customer analyses into our operational planning. In July 2009, Ormet, a major industrial customer currently operating at a reduced load of approximately 400 MW, announced that it will substantially curtail operations starting in September 2009.

Regulatory Activity

Our significant 2009 rate proceedings include:

·	Arkansas - In February 2009, SWEPCo filed an application with the APSC for an annual base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to recover, in current rates, financing costs related to the construction of the Stall Unit and the Turk Plant. A decision is not expected until the fourth quarter of 2009 or the first quarter of 2010.

·	Indiana - In March 2009, the IURC approved the settlement agreement with I&M with modifications that provide 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.

Ohio - In March 2009, and as amended in July 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP filings. 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 FAC costs incurred in excess of the caps, that will be trued-up, subject to annual caps. The projected revenue increases for CSPCo and OPCo are listed below:

	Projected Revenue Increases
	2009		2010		2011
	(in millions)
CSPCo	$	94	$	109	$	116
OPCo		103		125		153

In addition to the revenue increases, net income will be positively affected by the material noncash FAC phase-in deferrals from 2009 through 2011. These deferrals will be collected through a non-bypassable surcharge from 2012 through 2018.

·	Virginia - In July 2009, APCo filed a base rate case with the Virginia SCC requesting an increase in the generation and distribution portions of base rates of $169 million annually based on a 13.35% return on common equity which includes a 0.85% return on equity performance incentive increase as permitted by law. The new generation and distribution base rates will be effective, subject to refund, no later than December 2009. In July 2009, APCo filed a motion with the Virginia SCC requesting permission to file, in August 2009, supplemental schedules and testimony reflecting a recent Virginia SCC’s order in an unaffiliated utility’s base rate case concerning the appropriate capital structure to be used in the determination of the revenue requirement. In May 2009, APCo filed an application with the Virginia SCC to increase its fuel adjustment charge by approximately $227 million from July 2009 through August 2010. Due to the significance of the estimated required increase in fuel rates, APCo’s application proposed an alternative that would allow APCo to recover applicable costs over the period July 2009 through August 2011. In August 2009, the Virginia SCC issued an order which provides for a $130 million fuel revenue increase.

·	West Virginia - In March 2009, APCo and WPCo filed an annual ENEC filing with the WVPSC for an increase of approximately $442 million (later adjusted to $398 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. APCo and WPCo expect a decision from the WVPSC on the 2009 ENEC filing during the third quarter of 2009.

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant. SWEPCo owns 73% of the Turk Plant and will operate the completed facility.

In November 2007, March 2008 and August 2008, the APSC, LPSC and PUCT, respectively, approved SWEPCo’s application to build the Turk Plant. In June 2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld by the Arkansas Supreme Court, would reverse the APSC’s grant of the Certificate of Environmental Compatibility and Public Need (CECPN) permitting construction of the Turk Plant to serve Arkansas retail customers. Both SWEPCo and the APSC petitioned the Arkansas Supreme Court to review the Arkansas Court of Appeals decision. While the appeals are pending, SWEPCo is continuing construction of the Turk Plant. Should the appeal be unsuccessful, additional proceedings or alternative contractual ownership and operational responsibilities could be required.

For additional details related to the Turk Plant, see the “Turk Plant” section of “Significant Factors.”

Capital Markets

Although the financial markets remain volatile at both a global and domestic level, we issued $1.1 billion of long-term debt in the first six months of 2009 and $1.64 billion (net proceeds) of AEP common stock in April 2009. These actions will help to support our investment grade ratings and maintain financial flexibility.

Approximately $1.7 billion of our $17 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 believe that our projected cash flows from operating activities are sufficient to support our ongoing operations.

Pension, Nuclear Decommissioning and Other Trust Funds

We have 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 currently estimate that we will need to make minimum contributions to our pension trust of $453 million in 2010 and $292 million in 2011. However, estimates may vary significantly based on market returns, changes in actuarial assumptions and other factors.

Risk Management Contracts

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 June 30, 2009, our credit exposure net of collateral was approximately $997 million of which approximately 90% is to investment grade counterparties. At June 30, 2009, our exposure to financial institutions was $48 million, which represents 5% of our total credit exposure net of collateral (all investment grade).

Capital Expenditures

In March 2009, due to recent capital market volatility and the economic slowdown, we reduced our budgeted capital expenditures for 2010 from $3.4 billion to $1.8 billion:

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

Total		$	1,846

(a)	Does not include AFUDC.
(b)	Includes $212 million and $35 million in budgeted capital expenditures related to the Turk Plant and Stall Unit, respectively.

Cook Plant Unit 1 Fire and Shutdown

Fuel Inventory

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

Generation and Marketing

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss by segment for the three and six months ended June 30, 2009 and 2008.

	Three Months Ended June 30,								Six Months Ended June 30,
	2009				2008				2009				2008
	(in millions)
Utility Operations		$	327			$	264			$	673			$	677
AEP River Operations			1				3				12				10
Generation and Marketing			4				26				28				27
All Other (a)			(10	)			(12	)			(28	)			143
Income Before Discontinued Operations and Extraordinary Loss		$	322			$	281			$	685			$	857

(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

Second Quarter of 2009 Compared to Second Quarter of 2008

Income Before Discontinued Operations and Extraordinary Loss in 2009 increased $41 million compared to 2008 primarily due to an increase in Utility Operations segment earnings of $63 million. The increase in Utility Operations segment net income primarily relates to rate increases in our Indiana, Ohio, Oklahoma and Virginia service territories partially offset by 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 472 million in 2009 from 402 million in 2008 primarily due to the April 2009 issuance of 69 million shares of AEP common stock. Actual shares outstanding were 477 million as of June 30, 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Income Before Discontinued Operations and Extraordinary Loss in 2009 decreased $172 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. For our Utility Operations segment, Income Before Discontinued Operations and Extraordinary Loss decreased $4 million primarily due to lower off-system sales margins due to lower sales volumes and lower market prices which reflect weak market demand partially offset by rate increases in our Indiana, Ohio, Oklahoma and Virginia service territories.

Average basic shares outstanding increased to 440 million in 2009 from 401 million in 2008 primarily due to the April 2009 issuance of 69 million shares of AEP common stock. Actual shares outstanding were 477 million as of June 30, 2009.

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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(in millions)
Revenues	$	3,056	$	3,313	$	6,323	$	6,607
Fuel and Purchased Power		996		1,374		2,192		2,587
Gross Margin		2,060		1,939		4,131		4,020
Depreciation and Amortization		388		365		761		720
Other Operating Expenses		993		1,026		1,987		1,967
Operating Income		679		548		1,383		1,333
Other Income, Net		25		48		55		91
Interest Expense		227		218		447		426
Income Tax Expense		150		114		318		321
Income Before Discontinued Operations and Extraordinary Loss	$	327	$	264	$	673	$	677

Summary of KWH Energy Sales

For Utility Operations

For the Three and Six Months Ended June 30, 2009 and 2008

	Three Months Ended June 30,			Six Months Ended June 30,
Energy/Delivery Summary	2009	2008		2009	2008
	(in millions of KWH)
Energy
Retail:
Residential	9,798		9,829	24,166		24,329
Commercial	9,918		9,909	19,312		19,456
Industrial	11,926		15,060	24,052		29,410
Miscellaneous	614		639	1,191		1,248
Total Retail	32,256		35,437	68,721		74,443

Wholesale	7,167		10,996	13,944		22,738

Delivery
Texas Wires – Energy delivered to customers served by AEP’s Texas Wires Companies	6,888		7,132	12,626		12,955
Total KWHs	46,311		53,565	95,291		110,136

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 and six months ended June 30, 2009 and 2008 were as follows:

Summary of Heating and Cooling Degree Days for Utility Operations

For the Three and Six Months Ended June 30, 2009 and 2008

	Three Months Ended June 30,			Six Months Ended June 30,
	2009	2008		2009	2008
	(in degree days)
Weather Summary
Eastern Region
Actual – Heating (a)	156		136	2,056		1,966
Normal – Heating (b)	171		175	1,962		1,943

Actual – Cooling (c)	300		277	305		277
Normal – Cooling (b)	286		278	290		281

Western Region (d)
Actual – Heating (a)	48		40	902		981
Normal – Heating (b)	34		35	939		966

Actual – Cooling (c)	670		677	708		703
Normal – Cooling (b)	658		652	678		672

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

Second Quarter of 2009 Compared to Second Quarter of 2008

Reconciliation of Second Quarter of 2008 to Second Quarter of 2009

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss

(in millions)

Second Quarter of 2008			$	264

Changes in Gross Margin:
Retail Margins	226
Off-system Sales	(155	)
Transmission Revenues	8
Other Revenues	42
Total Change in Gross Margin				121

Total Expenses and Other:
Other Operation and Maintenance	35
Gain on Sales of Assets, Net	(2	)
Depreciation and Amortization	(23	)
Interest and Investment Income	(19	)
Carrying Costs Income	(14	)
Allowance for Equity Funds Used During Construction	9
Interest Expense	(9	)
Equity Earnings of Unconsolidated Subsidiaries	1
Total Expenses and Other				(22	)

Income Tax Expense				(36	)

Second Quarter of 2009			$	327

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

·	Retail Margins increased $226 million primarily due to the following:
	·	An $83 million increase related to the PUCO’s approval of our Ohio ESPs, a $44 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $24 million increase in base rates in Oklahoma and a $20 million net rate increase for I&M.
	·	A $40 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.
	·	A $62 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 $29 million increase related to a coal contract amendment in 2008.
	These increases were partially offset by:
	·	A $56 million decrease in margins from industrial sales due to reduced operating levels and suspended operations by certain 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 $155 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.
·	Transmission Revenues increased $8 million primarily due to increased rates in the ERCOT and SPP regions.
·	Other Revenues increased $42 million primarily due to Cook Plant accidental outage insurance policy proceeds of $45 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.

Total Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses decreased $35 million primarily due to a $27 million decrease in plant outage and other maintenance expenses and an $8 million decrease related to the 2008 true-up of the 2007 Oklahoma ice storm costs.
·	Depreciation and Amortization increased $23 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 and Investment Income decreased $19 million primarily due to the 2008 favorable effect of claims for refund filed with the IRS and the second quarter 2009 write-off of other-than-temporary losses related to equity investments made by EIS.
·	Carrying Costs Income decreased $14 million primarily due to the completion of reliability deferrals in Virginia in December 2008 and the decrease of environmental deferrals in Virginia in 2009.
·	Allowance for Equity Funds Used During Construction increased $9 million as a result of construction at SWEPCo’s Turk Plant and Stall Unit and the reapplication of SFAS 71 regulatory accounting for the generation portion of SWEPCo’s Texas retail jurisdiction effective April 2009. See “Texas Rate Matters – Texas Restructuring – SPP” section of Note 3.
·	Interest Expense increased $9 million primarily due to increased long-term debt and higher interest rates on variable rate, long-term debt.
·	Income Tax Expense increased $36 million due to an increase in pretax income.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Reconciliation of Six Months Ended June 30, 2008 to Six Months Ended June 30, 2009

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss

(in millions)

Six Months Ended June 30, 2008			$	677

Changes in Gross Margin:
Retail Margins	286
Off-system Sales	(291	)
Transmission Revenues	12
Other Revenues	104
Total Change in Gross Margin				111

Total Expenses and Other:
Other Operation and Maintenance	(21	)
Gain on Sales of Assets, Net	1
Depreciation and Amortization	(41	)
Interest and Investment Income	(29	)
Carrying Costs Income	(22	)
Allowance for Equity Funds Used During Construction	15
Interest Expense	(21	)
Total Expenses and Other				(118	)

Income Tax Expense				3

Six Months Ended June 30, 2009			$	673

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

·	Retail Margins increased $286 million primarily due to the following:
	·	A $104 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $96 million increase related to the PUCO’s approval of our Ohio ESPs, a $41 million increase in base rates in Oklahoma and a $25 million net rate increase for I&M.
	·	A $116 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 $47 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:
	·	An $89 million decrease in margins from industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in our service territories.
	·	A $40 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.
	·	A $29 million decrease related to coal contract amendments in 2008.
·	Margins from Off-system Sales decreased $291 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.
·	Transmission Revenues increased $12 million primarily due to increased rates in the ERCOT and SPP regions.
·	Other Revenues increased $104 million primarily due to Cook Plant accidental outage insurance policy proceeds of $99 million. Of these insurance proceeds, $40 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.

Total Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $21 million primarily due to the following:
	·	The deferral of $72 million 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 $13 million net 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 $54 million decrease in plant outage and other plant operating and maintenance expenses.
	·	A $32 million decrease in tree trimming, reliability and other transmission and distribution expenses.
	·	The write-off in the first quarter of 2008 of $10 million of unrecoverable pre-construction costs for PSO’s cancelled Red Rock Generating Facility.
·	Depreciation and Amortization increased $41 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 and Investment Income decreased $29 million primarily due to the 2008 favorable effect of claims for refund filed with the IRS and the second quarter 2009 write-off of other-than-temporary losses related to equity investments made by EIS.
·	Carrying Costs Income decreased $22 million primarily due to the completion of reliability deferrals in Virginia in December 2008 and the decrease of environmental deferrals in Virginia in 2009.
·	Allowance for Equity Funds Used During Construction increased $15 million as a result of construction at SWEPCo’s Turk Plant and Stall Unit and the reapplication of SFAS 71 regulatory accounting for the generation portion of SWEPCo’s Texas retail jurisdiction effective April 2009. See “Texas Rate Matters – Texas Restructuring – SPP” section of Note 3.
·	Interest Expense increased $21 million primarily due to increased long-term debt and higher interest rates on variable rate, long term debt.

AEP River Operations

Second Quarter of 2009 Compared to Second Quarter of 2008

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased from $3 million in 2008 to $1 million in 2009 primarily due to reduced import volumes and lower freight rates.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment increased from $10 million in 2008 to $12 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

Second Quarter of 2009 Compared to Second Quarter of 2008

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment decreased from $26 million in 2008 to $4 million in 2009 primarily due to lower gross margins from marketing activities and decreased margins from the Oklaunion Plant.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased from $27 million in 2008 to $28 million in 2009 primarily due to higher gross margins from marketing activities offset by decreased margins from the Oklaunion Plant.

All Other

Second Quarter of 2009 Compared to Second Quarter of 2008

Income Before Discontinued Operations and Extraordinary Loss from All Other decreased from a loss of $12 million in 2008 to a loss of $10 million in 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Income Before Discontinued Operations and Extraordinary Loss from All Other decreased from income of $143 million in 2008 to a loss of $28 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 increased $25 million in the second quarter of 2009 compared to the second quarter of 2008 primarily due to an increase in pretax book income.

Income Tax Expense decreased $89 million in the six-month period ended June 30, 2009 compared to the six-month period ended June 30, 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
	June 30, 2009			December 31, 2008
	($ in millions)
Long-term Debt, including amounts due within one year	$	16,696	55.5%	$	15,983	55.6%
Short-term Debt		562	1.8		1,976	6.9
Total Debt		17,258	57.3		17,959	62.5
Preferred Stock of Subsidiaries		61	0.2		61	0.2
AEP Common Equity		12,745	42.4		10,693	37.2
Noncontrolling Interests		18	0.1		17	0.1

Total Debt and Equity Capitalization	$	30,082	100.0%	$	28,730	100.0%

Our ratio of debt-to-total capital decreased from 62.5% in 2008 to 57.3% in 2009 primarily due to the issuance of 69 million new common shares and the application of the proceeds to reduce debt.

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 under our existing credit facilities. Although we are currently able to access the commercial paper market, the credit markets could constrain our ability to issue commercial paper. At June 30, 2009, we had $3.6 billion in aggregate credit facility commitments to support our operations. These commitments include 28 different banks with only one bank having more than 10% (10.3%) of our total bank commitments.

Through June 30, 2009, we issued $955 million of senior notes with interest rates ranging from 7% to 8.l3% and maturities ranging from 2019 to 2039, $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 June 30, 2009, $272 million of our auction-rate tax-exempt long-term debt, with rates ranging between 1.122% 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. As of June 30, 2009, $218 million of the $272 million of outstanding auction-rate debt relates to JMG. Interest rates on this debt are at the contractual maximum rate of 13%. We were unable to refinance this debt without JMG’s consent. We sought approval from the PUCO to terminate the JMG relationship and received the approval in June 2009. In July 2009, we purchased the outstanding equity ownership of JMG for $28 million. We plan to refinance the related outstanding debt as market conditions permit.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At June 30, 2009, our available liquidity was approximately $2.9 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
Total		3,581
Cash and Cash Equivalents		358
Total Liquidity Sources		3,939
Less: Cash Drawn on Credit Facilities		219	(b)
AEP Commercial Paper Outstanding		316
Letters of Credit Issued		485

Net Available Liquidity	$	2,919

(a)	Contractually terminated Lehman Brothers Bank’s commitment amount of $69 million in June 2009.
(b)	Repaid in July 2009.

As of June 30, 2009, we had credit facilities totaling $3.6 billion, of which two $1.5 billion credit facilities support our commercial paper program. The two $1.5 billion credit facilities allow for the issuance of up to $750 million as letters of credit under each credit facility. We also have $650 million credit facility which can be utilized for letters of credit or drawings. The $3.6 billion in combined credit facilities were reduced by Lehman Brothers Bank’s commitment amount of $69 million following its parent company’s bankruptcy.

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. In 2008, we borrowed $2 billion under these credit facilities at a LIBOR rate. In second quarter of 2009, we repaid $1.75 billion of the $2 billion borrowed under the credit facilities with proceeds from our equity offering in April 2009. The maximum amount of commercial paper outstanding during 2009 was $614 million. The weighted-average interest rate for our commercial paper during 2009 was 0.76%.

Sales of Receivables

In July 2009, we renewed and increased our sale of receivables agreement. The sale of receivables agreement provides a commitment of $750 million from bank conduits to purchase receivables. This agreement will expire in July 2010.

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 June 30, 2009, this contractually-defined percentage was 53.3%. Nonperformance of these covenants could result in an event of default under these credit agreements. At June 30, 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 June 30, 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 397 consecutive quarters. The Board of Directors declared a quarterly dividend of $0.41 per share in July 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 or financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

Our credit ratings as of June 30, 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.
·	Affirmed the Baa2 rating for TCC and downgraded TNC to Baa2. Both companies were also placed on stable outlook.
·	Placed OPCo 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.
·	Downgraded SWEPCo to Baa3 and placed it on stable outlook, reflecting higher business risk associated with the construction of the Turk Plant.

In 2009, Fitch:

·	Affirmed its stable rating outlook for I&M, PSO and TNC.
·	Changed its rating outlook for TCC from stable to negative due to weak cash flow ratios, challenging regulatory environment and upcoming capital expenditures.
·	Changed its rating outlook for SWEPCo from stable to negative due to elevated debt levels to fund Stall Unit and Turk Plant.

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.

	Six Months Ended
	June 30,
	2009				2008
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	411			$	178
Net Cash Flows from Operating Activities			857				1,201
Net Cash Flows Used for Investing Activities			(1,478	)			(1,645	)
Net Cash Flows from Financing Activities			568				484
Net Increase (Decrease) in Cash and Cash Equivalents			(53	)			40
Cash and Cash Equivalents at End of Period		$	358			$	218

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

Operating Activities

	Six Months Ended
	June 30,
	2009				2008
	(in millions)
Net Income		$	680			$	858
Less Discontinued Operations, Net of Tax			-				(1	)
Income Before Discontinued Operations			680				857
Depreciation and Amortization			779				736
Other			(602	)			(392	)
Net Cash Flows from Operating Activities		$	857			$	1,201

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 $857 million in 2009 consisting primarily of Net Income of $680 million and $779 million of noncash depreciation and amortization. Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and an increase in under-recovered fuel primarily due to the deferral of fuel costs in Ohio as a fuel clause was reactivated in 2009.

Net Cash Flows from Operating Activities were $1.2 billion in 2008 consisting primarily of Income Before Discontinued Operations of $857 million and $736 million of noncash depreciation and amortization. Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Significant changes in other items include an increase in under-recovered fuel reflecting higher natural gas prices.

Investing Activities

	Six Months Ended
	June 30,
	2009				2008
	(in millions)
Construction Expenditures		$	(1,547	)		$	(1,608	)
Proceeds from Sales of Assets			240				69
Other			(171	)			(106	)
Net Cash Flows Used for Investing Activities		$	(1,478	)		$	(1,645	)

Net Cash Flows Used for Investing Activities were $1.5 billion in 2009 and $1.6 billion in 2008 primarily due to Construction Expenditures for our new generation, environmental and distribution investment plan. Proceeds from Sales of Assets in 2009 includes $104 million relating to the sale of a portion of Turk Plant to joint owners and $92 million for sales of transmission assets in Texas to ETT.

In our normal course of business, we purchase and sell investment securities including variable rate demand notes with cash available for short-term investments and purchase and sell securities within our nuclear trusts and protected cell insurance company. 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

	Six Months Ended
	June 30,
	2009				2008
	(in millions)
Issuance of Common Stock, Net		$	1,688			$	72
Issuance/Retirement of Debt, Net			(711	)			777
Dividends Paid on Common Stock			(364	)			(333	)
Other			(45	)			(32	)
Net Cash Flows from Financing Activities		$	568			$	484

Net Cash Flows from Financing Activities in 2009 were $568 million. Issuance of Common Stock, Net of $1.7 billion included our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs. Our net debt retirements were $711 million. These retirements included a repayment of $1.75 billion outstanding under our credit facilities primarily from the proceeds of our common stock issuance and issuances of $955 million of senior unsecured notes and $135 million of pollution control bonds. See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2008 were $484 million. Our net debt issuances were $777 million. These issuances included a net increase of $1 billion in outstanding senior unsecured notes and the issuance of $315 million of junior subordinated debentures. These net increases in outstanding debt were partially offset by the reacquisition of a net $440 million of pollution control bonds and retirements of $53 million of mortgage notes and $75 million of securitization bonds.

In July 2009, TCC issued $101 million of pollution control bonds due 2029 at 6.3%.

Off-balance Sheet Arrangements

Under a limited set of circumstances, we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business. Our significant off-balance sheet arrangements are as follows:

	June 30,			December 31,
	2009			2008
	(in millions)
AEP Credit Accounts Receivable Purchase Commitments		$	596		$	650
Rockport Plant Unit 2 Future Minimum Lease Payments			1,996			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 July 2008, as required by the 2008 amendments to the Ohio restructuring legislation, CSPCo and OPCo filed ESPs with the PUCO to establish standard service offer rates. In March 2009, the PUCO issued an order, which was amended by a rehearing entry in July 2009, that modified and approved CSPCo’s and OPCo’s ESPs. The ESPs 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 FAC. The capped 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. CSPCo and OPCo implemented rates for the April 2009 billing cycle. In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis. CSPCo and OPCo are collecting the 2009 annualized revenue increase over the last nine months 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 June 30, 2009, the recognized revenues and the FAC deferrals were adjusted to reflect the PUCO’s July 2009 rehearing entry, which among other things, reversed the prior authorization to recover the cost of CSPCo's recently acquired Waterford and Darby Plants. In July 2009, CSPCo filed an application for rehearing with the PUCO seeking authorization to sell or transfer the Waterford and Darby Plants. The FAC deferrals after adjustment at June 30, 2009 were $34 million and $140 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.

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 Significantly Excessive Earnings Test (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. This is determined by measuring 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, which have comparable business and financial risk. In the March 2009 order, the PUCO determined that off-system sales margins and FAC deferral credits and associated costs should be excluded from the SEET methodology. The July 2009 PUCO rehearing entry deferred those issues to the SEET workshop. If the rate adjustments, in the aggregate, result in significantly excessive earnings, the PUCO must require that the excess amount 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 a SEET filing is made in 2010 and the PUCO issues an order thereon.

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 and not to the effective date of tariffs and clarified the tariffs were not retroactive. In the rehearing entry, the PUCO reaffirmed its holding that it had not authorized retroactive rates.

In April 2009, certain intervenors 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. In May 2009, CSPCo, OPCo and the PUCO filed a motion to dismiss the writ of prohibition. In June 2009, the Ohio Supreme Court dismissed the writ of prohibition.

In June 2009, intervenors filed a motion in the ESP proceeding with the PUCO requesting CSPCo and OPCo to refund deferrals allegedly collected by CSPCo and OPCo which were created by the PUCO’s approval of a temporary special arrangement between CSPCo, OPCo and Ormet, a large industrial customer. In addition, the intervenors requested that the PUCO prevent CSPCo and OPCo from collecting these revenues in the future. In June 2009, CSPCo and OPCo filed its response regarding the motion to refund amounts allegedly collected and to prevent future collections. The CSPCo and OPCo response noted that the difference in the amount deferred between the PUCO-determined market price for 2008 and the rate paid by Ormet was not collected, but instead was deferred, with PUCO authorization, as a regulatory asset for future recovery. In the rehearing entry, the PUCO did not order an adjustment to rates based on this issue.

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 June 30, 2009, we recorded $54 million in Prepayments and Other Current Assets 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 2009, I&M recorded $99 million in revenues, including $9 million in revenues that were deferred at December 31, 2008, related to the accidental outage policy. In 2009, I&M applied $40 million of the accidental outage insurance proceeds to reduce customer bills. 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 or if any future regulatory proceedings are adverse, 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. Municipal customers and other intervenors appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. TCC also 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.

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. The favorable commercial unreasonableness judgment entered by the District Court was not reversed. In June 2008, the Texas Court of Appeals denied intervenors’ motions for rehearing. In August 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 which concluded in June 2009.

TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed. TNC appealed its final true-up order, which 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 possibly 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

321

198

Gas

Combined-cycle

580

2013

SWEPCo

Stall

Louisiana

384

322

Gas

Combined-cycle

500

2010

SWEPCo

Turk

(d)

Arkansas

1,628

(d)

560

(e)

Coal

Ultra-supercritical

600

(d)

2012

APCo

Mountaineer

(f)

West Virginia

(f)

Coal

IGCC

629

(f)

CSPCo/OPCo

Great Bend

(f)

Ohio

(f)

Coal

IGCC

629

(f)

(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 owns approximately 73%, or 440 MW, totaling $1.2 billion in capital investment. See “Turk Plant” section below.
(e)	Amount represents SWEPCo’s CWIP balance only.
(f)	Construction of IGCC plants is subject to regulatory approvals. See “IGCC Plants” section below.

Turk Plant

In November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in Arkansas at the existing site by issuing a Certificate of Environmental Compatibility and Public Need (CECPN). Certain intervenors appealed the APSC’s decision to grant the CECPN to build the Turk Plant to the Arkansas Court of Appeals. In January 2009, the APSC granted additional CECPNs allowing SWEPCo to construct Turk-related transmission facilities. Intervenors also appealed these CECPN orders to the Arkansas Court of Appeals.

In June 2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN permitting construction of the Turk Plant to serve Arkansas retail customers. The decision was based upon the Arkansas Court of Appeals’ interpretation of the statute that governs the certification process and its conclusion that the APSC did not fully comply with that process. The Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity, the construction and financing of the generating plant and the proposed transmission facilities’ construction and location should all have been considered by the APSC in a single docket instead of separate dockets. Both SWEPCo and the APSC petitioned the Arkansas Supreme Court to review the Arkansas Court of Appeals decision. SWEPCo’s petition for review had the effect of staying the Arkansas Court of Appeals decision and, while the appeals are pending, SWEPCo is continuing construction of the Turk Plant. Management believes that the APSC properly interpreted and applied the Arkansas statutes governing the Turk Plant certification process and that SWEPCo’s grounds for seeking review are strong.

If the decision of the Court of Appeals is not reversed by the Supreme Court of Arkansas, SWEPCo and the other joint owners of the Turk Plant will evaluate their options. Depending on the time taken by the Arkansas Supreme Court to consider the case and the reasoning of the Arkansas Supreme Court when it acts on SWEPCo’s and the APSC’s petitions, the construction schedule and/or the cost could be adversely affected. Should the appeal be unsuccessful, additional proceedings or alternative contractual ownership and operational responsibilities could be required.

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 and related transmission costs, (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 as being unlawful. If the cost cap restrictions are upheld and construction or CO2 emission costs exceed the restrictions, it could have an adverse effect on net income, cash flows and possibly financial condition. 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 District Court by certain 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, which was granted in March 2009.

In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. In December 2008, certain parties 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 the appeal of the Turk Plant’s permit is heard. In June 2009, hearings on the air permit appeal were held at the APCEC. A decision is still pending and not expected until 2010. These same parties have filed a petition with the Federal EPA to review the air permit. If the air permit were to be remanded or ultimately revoked, construction of the Turk Plant could be suspended or cancelled. The Turk Plant cannot be placed into service without an air permit.

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 an inadvertent impact on approximately 2.5 acres of wetlands at the Turk Plant construction site prior to the receipt of the permit. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas outside of the proposed Army Corps of Engineers permitted areas of the Turk Plant pending the Army Corps of Engineers review. SWEPCo has entered into a Consent Agreement and Final Order with the Federal EPA to resolve liability for the inadvertent impact and agreed to pay a civil penalty of approximately $29 thousand.

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. To date, the report’s effect is only advisory, but if legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s ability to complete construction on schedule in 2012 and on budget.

If the Turk Plant cannot be completed and placed in service, SWEPCo would seek approval to recover its prudently incurred capitalized construction costs including any cancellation fees and a return on unrecovered balances through rates in all of its jurisdictions. As of June 30, 2009, and excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $570 million of expenditures (including AFUDC and related transmission costs of $10 million) and has contractual construction commitments for an additional $582 million (including related transmission costs of $7 million). As of June 30, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $136 million (including related transmission cancellation fees of $1 million).

Management believes that SWEPCo’s planning, certification and construction of the Turk Plant to date have been in material compliance with all applicable laws and regulations, except for the inadvertent wetlands intrusion discussed above. Further, management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if for any reason SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service, it would adversely impact net income, cash flows and possibly financial condition unless the resultant losses can be fully recovered, with a return on unrecovered balances, through rates in all of its jurisdictions.

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 June 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, 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 was filed with the OCC in May 2009. 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 base load generation by 2012. In July 2009, OCC staff, the Independent Evaluator and the Oklahoma Industrial Energy Consumers filed responsive testimony in support of PSO’s proposed PPA with Exelon. An order from the OCC is expected before year-end 2009.

The American Recovery and Reinvestment Act of 2009

The American Recovery and Reinvestment Act of 2009 was signed into law by the President in February 2009. It provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008. The enacted provisions are not expected to have a material impact on net income or financial condition. However, we forecast the bonus depreciation provision could provide a significant favorable cash flow benefit of approximately $300 million in 2009.

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 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

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACES). ACES is a comprehensive energy and climate change bill that includes a number of provisions that would directly affect our business. ACES contains a combined energy efficiency and renewable electricity standard beginning at 6% in 2012 and increasing to 20% by 2020 of our retail sales. The proposed legislation would also create a carbon capture and sequestration program funded through rates to accelerate the development of this technology and establishes GHG emission standards for new fossil fuel-fired electric generating plants. ACES creates an economy-wide cap and trade program for large sources of GHG emissions that would reduce emissions by 17% in 2020 and just over 80% by 2050 from 2005 levels. A portion of the allowances under the cap and trade program would be allocated to retail electric and gas utilities, certain energy-intensive industries, small refiners and state governments. Some allowances would be auctioned. Bonus allowances would be available to encourage energy efficiency, renewable energy and carbon sequestration projects. Consideration of climate legislation has now moved to the Senate. Until legislation is final, we are unable to predict its impact on net income, cash flows and financial condition.

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 “Business Combinations” improving financial reporting about business combinations and their effects and FSP SFAS 141(R)-1. 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, including the FSP, effective January 1, 2009. We will apply it to any future business combinations.

The FASB issued SFAS 160 “Noncontrolling Interests 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.

In May 2009, the FASB issued SFAS 165 “Subsequent Events” (SFAS 165), incorporating guidance on subsequent events into authoritative accounting literature and clarifying the time following the balance sheet date which management reviewed for events and transactions that may require disclosure in the financial statements. We adopted this standard effective second quarter of 2009. The standard increased our disclosure by requiring disclosure of the date through which subsequent events have been reviewed. The standard did not change our procedures for reviewing subsequent events.

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. With the adoption of FSP SFAS 107-1 and APB 28-1, it is applied to the fair value of long-term debt. The application of this standard had an immaterial effect on the fair value of debt outstanding.

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 107-1 and APB 28-1 requiring disclosure about the fair value of financial instruments in all interim reporting periods. The standard requires disclosure of the method and significant assumptions used to determine the fair value of financial instruments. We adopted the standard effective second quarter of 2009. This standard increased the disclosure requirements related to financial instruments.

The FASB issued FSP SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments”, amending the other-than-temporary impairment (OTTI) recognition and measurement guidance for debt securities. For both debt and equity securities, the standard requires disclosure for each interim reporting period of information by security class similar to previous annual disclosure requirements. We adopted the standard effective second quarter of 2009 with no impact on our financial statements and increased disclosure requirements related to financial instruments.

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 “Effective Date of FASB Statement No. 157” (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 2009.

The FASB issued FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4), providing additional guidance on estimating fair value when the volume and level of activity for an asset or liability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly. Fair value measurements shall be based on the price that would be received to sell an asset or paid to transfer a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the measurement date under current market conditions. The standard also requires disclosures of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, for both interim and annual periods. We adopted the standard effective second quarter of 2009. This standard had no impact on our financial statements but increased our disclosure requirements.

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 Executive Vice President - Generation, 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 June 30, 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

June 30, 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	$	257	$	33	$	7		$	297	$	56	$	(18	)	$	335
Noncurrent Assets		182		205		6			393		4		(17	)		380
Total Assets		439		238		13			690		60		(35	)		715

Current Liabilities		154		25		12			191		23		(56	)		158
Noncurrent Liabilities		104		73		6			183		5		(50	)		138
Total Liabilities		258		98		18			374		28		(106	)		296

Total MTMDerivative Contract Net Assets (Liabilities)	$	181	$	140	$	(5	)	$	316	$	32	$	71		$	419

MTM Risk Management Contract Net Assets (Liabilities)

Six Months Ended June 30, 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		(60	)		(6	)		2			(64	)
Fair Value of New Contracts at Inception When Entered During the Period (a)		13			54			-			67
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)		11			(12	)		-			(1	)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		42			-			-			42
Total MTM Risk Management Contract Net Assets (Liabilities) at June 30, 2009	$	181		$	140		$	(5	)		316
Cash Flow Hedge Contracts											32
Collateral Deposits											71
Ending Net Risk Management Assets at June 30, 2009										$	419

(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)

June 30, 2009

(in millions)

	Remainder 2009			2010			2011		2012		2013		After 2013 (f)		Total
Utility Operations
Level 1 (a)	$	(3	)	$	-		$	-	$	-	$	-	$	-	$	(3	)
Level 2 (b)		46			45			17		-		3		1		112
Level 3 (c)		13			18			6		3		-		-		40
Total		56			63			23		3		3		1		149

Generation and Marketing
Level 1 (a)		(5	)		1			-		-		-		-		(4	)
Level 2 (b)		4			15			18		16		20		44		117
Level 3 (c)		-			1			1		2		2		21		27
Total		(1	)		17			19		18		22		65		140

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

Total
Level 1 (a)		(8	)		-			-		-		-		-		(8	)
Level 2 (b)		48			56			37		16		23		45		225
Level 3 (c) (d)		13			19			7		5		2		21		67
Total		53			75			44		21		25		66		284
Dedesignated Risk Management Contracts (e)		7			14			6		5		-		-		32
Total MTM Risk Management Contract Net Assets	$	60		$	89		$	50	$	26	$	25	$	66	$	316

(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 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 $66 million in individual periods beyond 2013. $46 million of this mark-to-market value is in periods 2014-2018, $15 million is in periods 2019-2023 and $5 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 June 30, 2009, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.2%, 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 June 30, 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	$	656	$	56	$	600		1	$	121
Split Rating		14		-		14		3		13
Noninvestment Grade		14		2		12		1		11
No External Ratings:
Internal Investment Grade		304		3		301		3		245
Internal Noninvestment Grade		81		11		70		2		54
Total as of June 30, 2009	$	1,069	$	72	$	997		10	$	444

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

See Note 8 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 June 30, 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

Six Months Ended

Twelve Months Ended

June 30, 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 back-testing 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 four 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. As calculated on debt outstanding as of June 30, 2009, the estimated EaR on our debt portfolio for the following twelve months was $28 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2009 and 2008

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

(Unaudited)

	Three Months Ended						Six Months Ended
REVENUES	2009			2008			2009			2008
Utility Operations	$	3,035		$	3,200		$	6,302		$	6,210
Other Revenues		167			346			358			803
TOTAL REVENUES		3,202			3,546			6,660			7,013
EXPENSES
Fuel and Other Consumables Used for Electric Generation		764			1,053			1,693			2,033
Purchased Electricity for Resale		258			366			553			629
Other Operation and Maintenance		911			982			1,825			1,860
Gain on Sales of Assets, Net		(2	)		(5	)		(11	)		(8	)
Asset Impairments and Other Related Charges		-			-			-			(255	)
Depreciation and Amortization		397			373			779			736
Taxes Other Than Income Taxes		192			191			389			389
TOTAL EXPENSES		2,520			2,960			5,228			5,384

OPERATING INCOME		682			586			1,432			1,629

Other Income (Expense):
Interest and Investment Income (Loss)		(5	)		15			-			31
Carrying Costs Income		12			26			21			43
Allowance for Equity Funds Used During Construction		20			11			36			21
Interest Expense		(240	)		(234	)		(478	)		(453	)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		469			404			1,011			1,271

Income Tax Expense		148			123			327			416
Equity Earnings of Unconsolidated Subsidiaries		1			-			1			2

INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS		322			281			685			857

DISCONTINUED OPERATIONS, NET OF TAX		-			1			-			1

INCOME BEFORE EXTRAORDINARY LOSS		322			282			685			858