Brian X. Tierney Brian X. Tierney Chief Financial Officer July 30, 2010 A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

We have other railcar lease arrangements that do not utilize this type of financing structure.

ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA. Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units. The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit. The defendants and the plaintiffs appealed to the Seventh Circuit Co urt of Appeals. Beckjord is operated by Duke Energy Ohio, Inc. We are unable to determine a range of potential losses that are reasonably possible of occurring.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

In 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint alleging violations of the CAA at SWEPCo’s Welsh Plant. In 2008, a consent decree resolved all claims in the case and in the pending appeal of an altered permit for the Welsh Plant. The consent decree required SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects and pay a portion of plaintiffs’ attorneys’ fees and costs.

The Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in a previous state permit. The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper. In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations. The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit. We are unable to predict the timing of any future action by the Federal EPA. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Carbon Dioxide Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The trial court dismissed the lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York. The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints. The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law. The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims. The defendants’ petition for rehearing was denied. We believe the actions are without merit and intend to continue to defend against the claims. The Solicitor General requested an extension of time to file a petition for review by the U.S. Supreme Court and the remaining defendants received a similar extension of time. Petitions are currently due on or before August 2, 2010.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court 217;s decision in place. We were initially dismissed from this case without prejudice, but are named as a defendant in a pending fourth amended complaint. Unless the plaintiffs elect to file a petition for review by the U.S. Supreme Court, there will be no further proceedings in this case.

We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming wil l require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. The plaintiffs appealed the decision. We believe the action is without merit and intend to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. In May 2008, I&M started remediation work in accordance with a plan approved by MDEQ. I&M recorded approximately $11 million of expense prior to January 1, 2010, $3 million of which I&M recorded in March 2009. As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. I&M cannot predict the amount of additional cost, if any.

Amos Plant – Request to Show Cause

In March 2010, we received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting us to engage in settlement negotiations. The request includes a proposed civil penalty of approximately $300 thousand. We indicated our willingness to engage in good faith negotiations and met with representatives of the Federal EPA. We have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Defective Environmental Equipment

As part of our continuing environmental investment program, we chose to retrofit wet flue gas desulfurization systems on several units utilizing the jet bubbling reactor (JBR) technology. The following plants have been scheduled for the installation of the JBR technology or are currently utilizing JBR retrofits:

			JBRs
			Installed/
			Scheduled for
Plant Name		Plant Owners	Installation
Cardinal		OPCo/Buckeye Power, Inc.	3
Conesville		CSPCo/Dayton Power and Light Company/	1
		Duke Energy Ohio, Inc.
Clifty Creek		Indiana-Kentucky Electric Corporation	2
Kyger Creek		Ohio Valley Electric Corporation	2
Muskingum River (a)		OPCo	1
Big Sandy (a)		KPCo	1

(a)	Contracts for the Muskingum River and Big Sandy Projects have been temporarily
	suspended during the early development stages of the projects.

The retrofits on two of the Cardinal Plant units and the Conesville Plant unit are operational. Due to unexpected operating results, we completed an extensive review of the design and manufacture of the JBR internal components. Our review concluded that there are fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components. We initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan. We intend to pursue our contractual and other legal remedies if we are unable to resolve these issues with Black & Veatch. If we are unsuccessful in obtaining reimbursement for the work required to remedy this situation, the cost of repair or replacement could have an adverse impact on construction costs, net income, cash flows and financial condition. We are unable to determine a range of potential losses that are reasonably possible of occurring.

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small 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. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of these costs through th e turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.

I&M maintains property insurance through NEIL with a $1 million deductible. As of June 30, 2010, we recorded $53 million in Prepayments and Other Current Assets on our Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy. Through June 30, 2010, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

I&M also maintains a separate accidental outage policy with NEIL. In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies. The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

OPERATIONAL CONTINGENCIES

Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010. I&M has been negotiating with Fort Wayne to purchase the assets at the end of the lease, but no agreement has been reached. Fort Wayne issued a technical notice of default under the lease to I&M in August 2009. I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease. In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court. The parties agreed to submit this matter to mediation. In February 2010, the court issued a stay to continue mediation. I&M is making monthly payments to an escrow account in lieu of rent.& #160; I&M will seek recovery in rates for any amount it may pay related to this dispute. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Enron Bankruptcy

In 2001, we purchased Houston Pipeline Company (HPL) from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy. In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangemen t. After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. This dispute is being litigated in the Enron bankruptcy proceedings and in federal courts in Texas and New York.

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

In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led the lending syndicate involving the monetization of the cushion gas to Enron and its subsidiaries. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false. In 2005, the Judge entered an order severing and transferring the declaratory judgment claims involving the right to use and cushion gas consent agreements to the Southern District of New Yor k and retaining in the Southern District of Texas the four counts alleging breach of contract, fraud and negligent misrepresentation. Trial in federal court in Texas was continued pending a decision in the New York case.

In 2007, the judge in the New York action issued a decision on all claims, including those that were pending trial in Texas, granting BOA summary judgment and dismissing our claims. In August 2008, the court entered a final judgment of $346 million. We appealed and posted a bond covering the amount of the judgment entered against us. In May 2009, the judge awarded $20 million of attorneys’ fees to BOA. We appealed this award and posted bond covering that amount. In September 2009, the United States Court of Appeals for the Second Circuit heard oral argument on our appeal.

The liability for the BOA litigation was $445 million and $441 million including interest at June 30, 2010 and December 31, 2009, respectively. These liabilities are included in Deferred Credits and Other Noncurrent Liabilities on our Condensed Consolidated Balance Sheets.

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. These cases are at various pre-trial stages. In 2008, we settled all of the cases pending against us in Cali fornia. The settlements did not impact 2008 earnings due to provisions made in prior periods. We will continue to defend each remaining case where an AEP company is a defendant. We believe the provision we have for the remaining cases is adequate. We are unable to determine a range of potential losses that are reasonably possible of occurring.

5. ACQUISITION AND DISPOSITIONS

ACQUISITION

2010

Valley Electric Membership Corporation (Utility Operations segment)

In November 2009, SWEPCo signed a letter of intent to purchase the transmission and distribution assets of Valley Electric Membership Corporation (VEMCO). The current estimate of the purchase is approximately $100 million, plus the assumption of certain liabilities, subject to adjustments at closing. Consummation of the transaction is subject to regulatory approval by the LPSC, the APSC, the Rural Utilities Service, the National Rural Utilities Cooperative Finance Corporation and the FERC. In January 2010, the VEMCO members approved the transaction. In the second quarter of 2010, a purchase and sales agreement was signed and a joint application between SWEPCo and VEMCO was filed with the LPSC. SWEPCo will seek recovery from Louisiana customers for all costs related to this acquisit ion. VEMCO services approximately 30,000 customers in Louisiana. SWEPCo expects to complete the transaction in the third quarter of 2010 upon receipt of regulatory approvals.

2009

None

DISPOSITIONS

2010

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

TCC and TNC sold $64 million and $71 million, respectively, of transmission facilities to ETT for the six months ended June 30, 2010. There were no gains or losses recorded on these transactions.

Intercontinental Exchange, Inc. (ICE) (All Other)

In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain ($10 million, net of tax). We recorded the gain in Interest and Investment Income on our Condensed Consolidated Statements of Income for the three months ended June 30, 2010.

2009

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

TCC and TNC sold $91 million and $1 million, respectively, of transmission facilities to ETT for the six months ended June 30, 2009. There were no gains or losses recorded on these transactions.

6. BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost for the plans for the three and six months ended June 30, 2010 and 2009:

					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2010		2009		2010		2009
	(in millions)
Service Cost	$	27	$	26	$	11	$	11
Interest Cost		64		64		28		28
Expected Return on Plan Assets		(78)		(81)		(26)		(20)
Amortization of Transition Obligation		-		-		7		6
Amortization of Net Actuarial Loss		23		15		7		10
Net Periodic Benefit Cost	$	36	$	24	$	27	$	35

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in millions)
Service Cost	$	55	$	52	$	23	$	21
Interest Cost		127		127		56		55
Expected Return on Plan Assets		(156)		(161)		(52)		(40)
Amortization of Transition Obligation		-		-		14		13
Amortization of Net Actuarial Loss		45		30		14		21
Net Periodic Benefit Cost	$	71	$	48	$	55	$	70

7. BUSINESS SEGMENTS

As outlined in our 2009 Annual Report, our primary business is our electric utility operations. Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations

segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable 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 transport 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 remainder of our activities is presented as All Other. While not considered a business segment, 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 gradually settle and completely expire in 2011.

·	Revenue sharing related to the Plaquemine Cogeneration Facility.

The tables below present our reportable segment information for the three and six months ended June 30, 2010 and 2009 and balance sheet information as of June 30, 2010 and December 31, 2009. These amounts include certain estimates and allocations where necessary.

					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended June 30, 2010
Revenues from:
	External Customers	$	3,186		$	127	$	42	$	5	$	-	$	3,360
	Other Operating Segments		25			5		-		(1)		(29)		-
Total Revenues		$	3,211		$	132	$	42	$	4	$	(29)	$	3,360

Net Income (Loss)		$	132		$	(1)	$	7	$	(1)	$	-	$	137

					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended June 30, 2009
Revenues from:
	External Customers	$	3,035	(d)	$	105	$	58	$	4	$	-	$	3,202
	Other Operating Segments		21	(d)		3		1		5		(30)		-
Total Revenues		$	3,056		$	108	$	59	$	9	$	(30)	$	3,202

Income (Loss) Before Extraordinary Loss		$	327		$	1	$	4	$	(10)	$	-	$	322
Extraordinary Loss, Net of Tax			(5)			-		-		-		-		(5)
Net Income (Loss)		$	322		$	1	$	4	$	(10)	$	-	$	317

					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Six Months Ended June 30, 2010
Revenues from:
	External Customers	$	6,592		$	248	$	89	$	-	$	-	$	6,929
	Other Operating Segments		45			10		-		7		(62)		-
Total Revenues		$	6,637		$	258	$	89	$	7	$	(62)	$	6,929

Net Income (Loss)		$	476		$	2	$	17	$	(12)	$	-	$	483

					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Six Months Ended June 30, 2009
Revenues from:
	External Customers	$	6,302	(d)	$	228	$	145	$	(15)	$	-	$	6,660
	Other Operating Segments		21	(d)		9		6		27		(63)		-
Total Revenues		$	6,323		$	237	$	151	$	12	$	(63)	$	6,660

Income (Loss) Before Extraordinary Loss		$	673		$	12	$	28	$	(28)	$	-	$	685
Extraordinary Loss, Net of Tax			(5)			-		-		-		-		(5)
Net Income (Loss)		$	668		$	12	$	28	$	(28)	$	-	$	680

			Nonutility Operations
					Generation				Reconciling
	Utility		AEP River		and		All Other		Adjustments
	Operations		Operations		Marketing		(a)		(b)			Consolidated
	(in millions)
June 30, 2010
Total Property, Plant and Equipment	$	51,529	$	527	$	584	$	10	$	(250)		$	52,400
Accumulated Depreciation and Amortization		17,431		99		183		9		(40)			17,682
Total Property, Plant and Equipment - Net	$	34,098	$	428	$	401	$	1	$	(210)		$	34,718

Total Assets	$	47,994	$	565	$	851	$	15,344	$	(14,817)	(c)	$	49,937

			Nonutility Operations
					Generation				Reconciling
	Utility		AEP River		and		All Other		Adjustments
	Operations		Operations		Marketing		(a)		(b)			Consolidated
	(in millions)
December 31, 2009
Total Property, Plant and Equipment	$	50,905	$	436	$	571	$	10	$	(238)		$	51,684
Accumulated Depreciation and Amortization		17,110		88		168		8		(34)			17,340
Total Property, Plant and Equipment - Net	$	33,795	$	348	$	403	$	2	$	(204)		$	34,344

Total Assets	$	46,930	$	495	$	779	$	15,094	$	(14,950)	(c)	$	48,348

(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 gradually settle and completely expire in 2011.

·	Revenue sharing related to the Plaquemine Cogeneration Facility.

(b)	Includes eliminations due to an intercompany capital lease.

(c)	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

(d) PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP. As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as Revenues from External Customers for the Utility Operations segment. This was offset by the Utility Operations segment’s related net sales (purchases) for these contracts with AEPEP in Revenues from Other Operating Segments of $(1) million and $(6) million for the three and six months ended, 2009, respectively. The Generation and Marketin g segment also reported these purchase or sales contracts with Utility Operations as Revenues from Other Operating Segments. These affiliated contracts between PSO and SWEPCo with AEPEP ended in December 2009.

8. DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are 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, credit risk and to a lesser extent foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value based on our open trading positions by utilizing both economic and formal hedging strategies. To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into electricity, coal, natural gas, interest rate and to a lesser degree heating oil, gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of June 30, 2010 and December 31, 2009:

Notional Volume of Derivative Instruments

	Volume
		June 30,		December 31,		Unit of
		2010		2009		Measure
	(in millions)
Commodity:
Power			935		589	MWHs
Coal			71		60	Tons
Natural Gas			144		127	MMBtus
Heating Oil and Gasoline			7		6	Gallons
Interest Rate		$	191	$	216	USD

Interest Rate and Foreign Currency		$	423	$	83	USD

Fair Value Hedging Strategies

We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of electricity, coal, heating oil and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. We do not hedge all commodity price risk.

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial gasoline and heating oil derivative contracts in order to mitigate price risk of our future fuel purchases. We do not hedge all fuel price risk. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”

We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities in the balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consens us for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the June 30, 2010 and December 31, 2009 balance sheets, we netted $19 million and $12 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $96 million and $98 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following tables represent the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009:

Fair Value of Derivative Instruments
June 30, 2010

		Risk Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign		Other
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)(c)		(a) (b)		Total
		(in millions)
Current Risk Management Assets		$	1,051	$	14	$	3	$	(818)	$	250
Long-term Risk Management Assets			691		7		1		(291)		408
Total Assets			1,742		21		4		(1,109)		658

Current Risk Management Liabilities			978		15		3		(876)		120
Long-term Risk Management Liabilities			540		3		2		(368)		177
Total Liabilities			1,518		18		5		(1,244)		297

Total MTM Derivative Contract Net Assets
	(Liabilities)	$	224	$	3	$	(1)	$	135	$	361

Fair Value of Derivative Instruments
December 31, 2009

		Risk Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign		Other
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		(a) (b)		Total
		(in millions)
Current Risk Management Assets		$	1,078	$	13	$	-	$	(831)	$	260
Long-term Risk Management Assets			614		-		-		(271)		343
Total Assets			1,692		13		-		(1,102)		603

Current Risk Management Liabilities			997		17		3		(897)		120
Long-term Risk Management Liabilities			442		-		2		(316)		128
Total Liabilities			1,439		17		5		(1,213)		248

Total MTM Derivative Contract Net Assets
	(Liabilities)	$	253	$	(4)	$	(5)	$	111	$	355

(a)

Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the Condensed Consolidated Balance Sheet on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”

(b)

Amounts represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging” and dedesignated risk management contracts.

(c)

At June 30, 2010, Risk Management Assets included $4 million related to fair value hedging strategies while the remainder related to cash flow hedging strategies. At December 31, 2009, we only employed cash flow hedging strategies.

The table below presents our activity of derivative risk management contracts for the three and six months ended June 30, 2010 and 2009:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2010 and 2009

Location of Gain (Loss)	2010		2009
	(in millions)
Utility Operations Revenue	$	7	$	33
Other Revenue		8		5
Regulatory Assets (a)		(14)		(18)
Regulatory Liabilities (a)		(4)		3
Total Gain (Loss) on Risk Management Contracts	$	(3)	$	23

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2010 and 2009

Location of Gain (Loss)	2010		2009
	(in millions)
Utility Operations Revenue	$	45	$	99
Other Revenue		9		18
Regulatory Assets (a)		(3)		(11)
Regulatory Liabilities (a)		27		10
Total Gain (Loss) on Risk Management Contracts	$	78	$	116

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current

on the balance sheet.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the Condensed Consolidated Statements of Income on an accrual basis.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis on the Condensed Consolidated Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the Condensed Consolidated Statements of Income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gain s) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2010 and 2009, we recognized a gain of $4 million on our hedging instrument with an offsetting loss of $4 million on our long-term debt. During the three and six months ended June 30, 2010, no hedge ineffectiveness was recognized. During the three and six months ended June 30, 2010 and 2009, we did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of electricity, coal, heating oil and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our Condensed Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Condensed Consolidated Balance Sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2010 and 2009, we designated commodity derivatives as cash flow hedges.

We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Condensed Consolidated Statements of Income. During the three and six months ended June 30, 2010 and 2009, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2010 and 2009, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Depreciation and Amortization expense on our Condensed Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2010 and 2009, we designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2010 and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

The following tables provide details on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2010 and 2009. All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2010
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of March 31, 2010			$	2	$	(13)	$	(11)
Changes in Fair Value Recognized in AOCI				1		(3)		(2)
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		-		-		-
		Other Revenue		(2)		-		(2)
		Purchased Electricity for Resale		1		-		1
		Interest Expense		-		1		1
		Regulatory Assets (a)		-		-		-
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of June 30, 2010			$	2	$	(15)	$	(13)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2009
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of March 31, 2009			$	9	$	(28)	$	(19)
Changes in Fair Value Recognized in AOCI				-		15		15
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		(4)		-		(4)
		Other Revenue		(4)		-		(4)
		Purchased Electricity for Resale		6		-		6
		Interest Expense		-		2		2
		Regulatory Assets (a)		1		-		1
		Regulatory Liabilities (a)		(2)		-		(2)
Balance in AOCI as of June 30, 2009			$	6	$	(11)	$	(5)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2010
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2009			$	(2)	$	(13)	$	(15)
Changes in Fair Value Recognized in AOCI				4		(4)		-
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		-		-		-
		Other Revenue		(3)		-		(3)
		Purchased Electricity for Resale		2		-		2
		Interest Expense		-		2		2
		Regulatory Assets (a)		1		-		1
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of June 30, 2010			$	2	$	(15)	$	(13)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2009
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2008			$	7	$	(29)	$	(22)
Changes in Fair Value Recognized in AOCI				(3)		15		12
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		(6)		-		(6)
		Other Revenue		(6)		-		(6)
		Purchased Electricity for Resale		14		-		14
		Interest Expense		-		3		3
		Regulatory Assets (a)		3		-		3
		Regulatory Liabilities (a)		(3)		-		(3)
Balance in AOCI as of June 30, 2009			$	6	$	(11)	$	(5)

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheet.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009 were:

Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
June 30, 2010

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	11	$	-	$	11
Hedging Liabilities (a)			(8)		(5)		(13)
AOCI Gain (Loss) Net of Tax			2		(15)		(13)

Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		(1)		(4)		(5)

Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
December 31, 2009

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	8	$	-	$	8
Hedging Liabilities (a)			(12)		(5)		(17)
AOCI Gain (Loss) Net of Tax			(2)		(13)		(15)

Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		(2)		(4)		(6)

(a)

Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Condensed Consolidated Balance Sheets.

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of June 30, 2010, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 42 months.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We use Moody’s, S&P and current market-based qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.

We use standardized master agreements which may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

Collateral Triggering Events

Under a limited number of derivative and non-derivative counterparty contracts primarily related to our pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. We do not anticipate a downgrade below investment grade. The following table represents our aggregate fair value of such derivative contracts, the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and how much was attributable to RTO and ISO activities as of June 30, 2010 and December 31, 2009:

	June 30,		December 31,
	2010		2009
	(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers	$	21	$	10
Amount of Collateral AEP Subsidiaries Would Have Been		25		34
Required to Post
Amount Attributable to RTO and ISO Activities		24		29

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event under outstanding debt in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. We do not anticipate a non-performance event under these provisions. The following table represents the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, the amount this exposure has been reduced by cash collateral we have posted and if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of June 30, 2010 and December 31, 2009:

	June 30,		December 31,
	2010		2009
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
Netting Arrangements	$	557	$	567
Amount of Cash Collateral Posted		25		15
Additional Settlement Liability if Cross Default Provision is Triggered		251		199

9. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser de gree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations and if the points are highly correlated we include these locations within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Fixed income securities do not trade on an exchange and do not have an official closing price. Pricing vendors calculate bond valuations using financial models and matrices. &# 160;Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data. Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data, and economic events. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.

Items classified as Level 2 are primarily investments in individual fixed income securities. These fixed income securities are valued using models with input data as follows:

	Type of Fixed Income Security
	United States		State and Local
Type of Input	Government	Corporate Debt	Government

Benchmark Yields	X	X	X
Broker Quotes	X	X	X
Discount Margins	X	X
Treasury Market Update	X
Base Spread	X	X	X
Corporate Actions		X
Ratings Agency Updates			X
Prepayment Schedule and
History			X
Yield Adjustments	X

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of Long-term Debt as of June 30, 2010 and December 31, 2009 are summarized in the following table:

	June 30, 2010				December 31, 2009
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	17,348	$	18,821	$	17,498	$	18,479

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include marketable securities that we intend to hold for less than one year, investments by our protected cell of EIS and funds held by trustees primarily for the payment of debt.

The following is a summary of Other Temporary Investments:

			June 30, 2010
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	195	$	-	$	-	$	195
Fixed Income Securities:
	Mutual Funds			68		1		-		69
	Variable Rate Demand Notes			14		-		-		14
Equity Securities - Mutual Funds				18		2		-		20
Total Other Temporary Investments			$	295	$	3	$	-	$	298

			December 31, 2009
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	223	$	-	$	-	$	223
Fixed Income Securities:
	Mutual Funds			57		-		-		57
	Variable Rate Demand Notes			45		-		-		45
Equity Securities:
	Domestic			1		15		-		16
	Mutual Funds			18		4		-		22
Total Other Temporary Investments			$	344	$	19	$	-	$	363

(a)		Primarily represents amounts held for the payment of debt.

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in millions)
Proceeds From Investment Sales	$	16	$	-	$	257	$	-
Purchases of Investments		24		1		221		1
Gross Realized Gains on Investment Sales		16		-		16		-
Gross Realized Losses on Investment Sales		-		-		-		-

In June 2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments of Other Temporary Investments for equity investments of our protected cell captive insurance company. At June 30, 2010, the fair value of fixed income securities are primarily debt based mutual funds with short and intermediate maturities and variable rate demand notes. Mutual funds may be sold and do not contain maturity dates for an individual investment holder.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

·	Acceptable investments (rated investment grade or above when purchased).

·	Maximum percentage invested in a specific type of investment.

·	Prohibition of investment in obligations of AEP or its affiliates.

·	Withdrawals permitted only for payment of decommissioning costs and trust expenses.

·	Target asset allocation is 50% fixed income and 50% equity securities.

We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether the investor has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment, among other things, is based on whether the investor has the ability and intent to hold the investment to recover its value. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. The gains, losses or other-than-temporary impairments shown below did not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw deco mmissioning funds.

The following is a summary of nuclear trust fund investments at June 30, 2010 and December 31, 2009:

		June 30, 2010						December 31, 2009
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in millions)
Cash and Cash Equivalents		$	26	$	-	$	-	$	14	$	-	$	-
Fixed Income Securities:
	United States Government		473		31		(1)		401		13		(4)
	Corporate Debt		60		6		(6)		57		5		(2)
	State and Local Government		316		3		-		369		8		1
	Subtotal Fixed Income Securities		849		40		(7)		827		26		(5)
Equity Securities - Domestic			516		194		(122)		551		234		(119)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,391	$	234	$	(129)	$	1,392	$	260	$	(124)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in millions)
Proceeds From Investment Sales	$	360	$	253	$	592	$	411
Purchases of Investments		369		264		617		442
Gross Realized Gains on Investment Sales		1		6		6		9
Gross Realized Losses on Investment Sales		-		1		-		1

The adjusted cost of debt securities was $809 million and $801 million as of June 30, 2010 and December 31, 2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at June 30, 2010 was as follows:

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year		$	12
1 year – 5 years			262
5 years – 10 years			304
After 10 years			271
Total		$	849

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010 and December 31, 2009. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in AEP’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2010

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)

Cash and Cash Equivalents (a)			$	593	$	18	$	-	$	227	$	838

Other Temporary Investments
Restricted Cash (a)				161		-		-		34		195
Fixed Income Securities:
	Mutual Funds			69		-		-		-		69
	Variable Rate Demand Notes			-		14		-		-		14
Equity Securities - Mutual Funds (b)				20		-		-		-		20
Total Other Temporary Investments				250		14		-		34		298

Risk Management Assets
Risk Management Commodity Contracts (c) (f)				17		1,573		152		(1,157)		585
Cash Flow Hedges:
	Commodity Hedges (c)			9		13		-		(11)		11
Fair Value Hedges				-		4		-		-		4
Dedesignated Risk Management Contracts (d)				-		-		-		58		58
Total Risk Management Assets				26		1,590		152		(1,110)		658

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		14		-		12		26
Fixed Income Securities:
	United States Government			-		473		-		-		473
	Corporate Debt			-		60		-		-		60
	State and Local Government			-		316		-		-		316
		Subtotal Fixed Income Securities		-		849		-		-		849
Equity Securities - Domestic (b)				516		-		-		-		516
Total Spent Nuclear Fuel and Decommissioning Trusts				516		863		-		12		1,391

Total Assets			$	1,385	$	2,485	$	152	$	(837)	$	3,185

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)			$	22	$	1,444	$	52	$	(1,234)	$	284
Cash Flow Hedges:
	Commodity Hedges (c)			2		17		-		(11)		8
	Interest Rate/Foreign Currency Hedges			-		5		-		-		5
Total Risk Management Liabilities			$	24	$	1,466	$	52	$	(1,245)	$	297

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)

Cash and Cash Equivalents (a)			$	427	$	-	$	-	$	63	$	490

Other Temporary Investments
Restricted Cash (a)				198		-		-		25		223
Fixed Income Securities:
	Mutual Funds			57		-		-		-		57
	Variable Rate Demand Notes			-		45		-		-		45
Equity Securities (b):
	Domestic			16		-		-		-		16
	Mutual Funds			22		-		-		-		22
Total Other Temporary Investments				293		45		-		25		363

Risk Management Assets
Risk Management Commodity Contracts (c) (g)				8		1,609		72		(1,119)		570
Cash Flow Hedges:
	Commodity Hedges (c)			1		11		-		(4)		8
Dedesignated Risk Management Contracts (d)				-		-		-		25		25
Total Risk Management Assets				9		1,620		72		(1,098)		603

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		3		-		11		14
Fixed Income Securities:
	United States Government			-		401		-		-		401
	Corporate Debt			-		57		-		-		57
	State and Local Government			-		369		-		-		369
		Subtotal Fixed Income Securities		-		827		-		-		827
Equity Securities - Domestic (b)				551		-		-		-		551
Total Spent Nuclear Fuel and Decommissioning Trusts				551		830		-		11		1,392

Total Assets			$	1,280	$	2,495	$	72	$	(999)	$	2,848

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	11	$	1,415	$	10	$	(1,205)	$	231
Cash Flow Hedges:
	Commodity Hedges (c)			-		16		-		(4)		12
	Interest Rate/Foreign Currency Hedges			-		5		-		-		5
Total Risk Management Liabilities			$	11	$	1,436	$	10	$	(1,209)	$	248

(a)

Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investments in money market funds. Level 2 amounts primarily represent investments in commercial paper.

(b)

Amounts represent publicly traded equity securities and equity-based mutual funds.

(c)

Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

(d)

Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.” At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts.

(e)

Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds.

(f) The June 30, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($1) million in 2010, ($2) million in periods 2011-2013 and ($2) million in periods 2014-2018; Level 2 matures $43 million in 2010, $69 million in periods 2011-2013, $9 million in periods 2014-2015 and $8 million in periods 2016-2028; Level 3 matures $12 million in 2010, $24 million in periods 2011-2013, $22 million in periods 2014-2015 and $42 million in periods 2016-2028. Risk management commodity contracts are substantially comprised of power contracts.

(g) The December 31, 2009 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($1) million in 2010, ($1) million in periods 2011-2013 and ($1) million in periods 2014-2015; Level 2 matures $65 million in 2010, $84 million in periods 2011-2013, $22 million in periods 2014-2015 and $23 million in periods 2016-2028; Level 3 matures $17 million in 2010, $16 million in periods 2011-2013, $8 million in periods 2014-2015 and $21 million in periods 2016-2028.

There have been no transfers between Level 1 and Level 2 during the six months ended June 30, 2010.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:

	Net Risk
	Management
	Assets
Three Months Ended June 30, 2010	(Liabilities)
	(in millions)
Balance as of March 31, 2010	$	116
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		(25	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		10
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		14
Transfers into Level 3 (d) (h)		1
Transfers out of Level 3 (e) (h)		(6	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		(10	)
Balance as of June 30, 2010	$	100

	Net Risk
	Management
	Assets
Six Months Ended June 30, 2010	(Liabilities)
	(in millions)
Balance as of December 31, 2009	$	62
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		4
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		33
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		(13	)
Transfers into Level 3 (d) (h)		12
Transfers out of Level 3 (e) (h)		(5	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		7
Balance as of June 30, 2010	$	100

		Net Risk
		Management
		Assets
Three Months Ended June 30, 2009		(Liabilities)
		(in millions)
Balance as of March 31, 2009		$	86
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)			(15)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		7
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements			-
Transfers in and/or out of Level 3 (f)			(29)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			18
Balance as of June 30, 2009		$	67

		Net Risk
		Management
		Assets
Six Months Ended June 30, 2009		(Liabilities)
		(in millions)
Balance as of December 31, 2008		$	49
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)			(20)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		40
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements			-
Transfers in and/or out of Level 3 (f)			(25)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			23
Balance as of June 30, 2009		$	67

(a)

Included in revenues on our Condensed Consolidated Statements of Income.

(b)

Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c)

Represents the settlement of risk management commodity contracts for the reporting period.

(d)

Represents existing assets or liabilities that were previously categorized as Level 2.

(e)

Represents existing assets or liabilities that were previously categorized as Level 3.

(f)

Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

(g)

Relates to the net gains (losses) of those contracts that are not reflected on our Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets.

(h)

Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

10. INCOME TAXES

We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

We are no longer subject to U.S. federal examination for years before 2001. We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level. The years 2007 and 2008 are currently under examination. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions. We believe that we have filed tax returns with positions that may be challenged by these tax authorities. However, management believes that the ultimate resolution of these audits will not materially impact net income. With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.

Federal Legislation

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010. This reduction did not materially affect our cash flows or financial condition. For the six months ended June 30, 2010, deferred tax assets decreased $56 million, partially offset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a decrease in net income of $21 million.

11. FINANCING ACTIVITIES

Long-term Debt

Type of Debt	June 30, 2010		December 31, 2009
	(in millions)
Senior Unsecured Notes	$	12,176	$	12,416
Pollution Control Bonds		2,263		2,159
Notes Payable		376		326
Securitization Bonds		1,909		1,995
Junior Subordinated Debentures		315		315
Spent Nuclear Fuel Obligation (a)		265		265
Other Long-term Debt		88		88
Unamortized Discount (net)		(44)		(66)
Total Long-term Debt Outstanding		17,348		17,498
Less Portion Due Within One Year		1,043		1,741
Long-term Portion	$	16,305	$	15,757

(a)

Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation of $307 million and $306 million at June 30, 2010 and December 31, 2009, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets.

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2010 are shown in the tables below.

			Principal			Interest
Company		Type of Debt	Amount			Rate	Due Date
			(in millions)			(%)
Issuances:
APCo		Senior Unsecured Notes	$	300		3.40	2015
APCo		Pollution Control Bonds		18		4.625	2021
APCo		Pollution Control Bonds		50		5.375	2038
CSPCo		Floating Rate Notes		150		Variable	2012
I&M		Notes Payable		84		4.00	2014
OPCo		Pollution Control Bonds		86		3.125	2015
OPCo		Pollution Control Bonds		79		3.25	2014
SWEPCo		Senior Unsecured Notes		350		6.20	2040
SWEPCo		Pollution Control Bonds		54		3.25	2015
Total Issuances			$	1,171	(a)

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

(a)	Amount indicated on the statement of cash flows of $1,161 million is net of issuance costs and premium or discount.

			Principal		Interest
Company		Type of Debt	Amount Paid		Rate	Due Date
			(in millions)		(%)
Retirements and
	Principal Payments:
AEP		Senior Unsecured Notes	$	490	5.375	2010
APCo		Senior Unsecured Notes		150	4.40	2010
APCo		Pollution Control Bonds		50	7.125	2010
I&M		Notes Payable		19	5.44	2013
OPCo		Senior Unsecured Notes		400	Variable	2010
OPCo		Pollution Control Bonds		79	7.125	2010
SWEPCo		Pollution Control Bonds		54	Variable	2019

Non-Registrant:
AEP Subsidiaries		Notes Payable		4	Variable	2017
AEP Subsidiaries		Notes Payable		5	Variable	2011
AEGCo		Senior Unsecured Notes		4	6.33	2037
TCC		Securitization Bonds		32	5.56	2010
TCC		Securitization Bonds		54	4.98	2010
Total Retirements and
	Principal Payments		$	1,341

As of June 30, 2010, trustees held, on our behalf, $303 million of our reacquired auction-rate tax-exempt long-term debt.

Dividend Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income derives from our common stock equity in the earnings of our utility subsidiaries. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

We have issued $315 million of Junior Subordinated Debentures. The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068. We have the option to defer interest payments on the debentures 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 do not anticipate any deferral of those interest payments in the foreseeable future.

Pursuant to the leverage restrictions in our credit agreements, Parent and the Registrant Subsidiaries must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends generally results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and other capital is contractually defined in the credit agreements. As of June 30, 2010, none of Parent’s retained earnings were restricted for the purpose of the payment of dividends. As of June 30, 2010, approximately $204 million of the retained earnings of APCo, $149 million of the retained earnings of CSPCo, $33 million of the retained earnings of I&M, $50 million of the retained earnings of OPCo, $101 million of the retained earnings of SWEPCo and none of the retained earnings of PSO have restrictions related to the payment of dividends to Parent.

Short-term Debt

Our outstanding short-term debt was as follows:
	June 30, 2010						December 31, 2009
	Outstanding			Interest			Outstanding			Interest
Type of Debt	Amount			Rate (a)			Amount			Rate (a)
	(in millions)						(in millions)
Securitized Debt for Receivables (b)		$	677		0.42	%		$	-		-
Commercial Paper			787		0.51	%			119		0.26	%
Line of Credit – Sabine Mining Company (c)			9		2.11	%			7		2.06	%
Total Short-term Debt		$	1,473					$	126

(a)	Weighted average rate.

(b)	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2.

(c)	Sabine Mining Company is a consolidated variable interest entity. This line of credit does not reduce available liquidity under AEP’s credit facilities.

Credit Facilities

We have credit facilities totaling $3 billion to support our commercial paper program. The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit. In June 2010, we canceled a facility that was scheduled to mature in March 2011 and entered into a new $1.5 billion credit facility scheduled to mature in 2013 that allows for the issuance of up to $600 million as letters of credit. As of June 30, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $149 million.

In June 2010, we reduced the $627 million credit agreement to $478 million. Under the facility, we may issue letters of credit. As of June 30, 2010, $477 million of letters of credit were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables it acquires from affiliated utility subsidiaries. Prior to January 1, 2010, this transaction constituted a sale of receivables in accordance with the accounting guidance for “Transfers and Servicing,” allowing the receivables to be removed from our Condensed Consolidated Balance Sheet. See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010 whereby such future transactions do not constitute a sale of receivables and will be accounted for as financing. AEP Credit continues to ser vice the receivables. We entered into these securitized transactions to allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

In July 2010, AEP Credit renewed its receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to finance receivables from AEP Credit. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.

Accounts receivable information for AEP Credit is as follows:


		Three Months Ended June 30,				Six Months Ended June 30,
		2010		2009		2010		2009
		($ in millions)
Proceeds from Sale of Accounts Receivable		$	N/A	$	2,061	$	N/A	$	4,249
Loss on Sale of Accounts Receivable			N/A		1		N/A		2
Average Variable Discount Rate on Sale of
	Accounts Receivable		N/A		0.55%		N/A		0.83%
Effective Interest Rates on Securitization of
	Accounts Receivable		0.31%		N/A		0.27%		N/A
Net Uncollectible Accounts Receivable
	Written Off		4		2		12		4

		June 30,		December 31,
		2010			2009
		(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
	Less Uncollectible Accounts	$	983	$	160
Deferred Revenue from Servicing Accounts Receivable			N/A		1
Retained Interest if 10% Adverse Change in Uncollectible Accounts			N/A		158
Retained Interest if 20% Adverse Change in Uncollectible Accounts			N/A		156
Total Principal Outstanding			677		656
Derecognized Accounts Receivable			N/A		631
Delinquent Securitized Accounts Receivable			42		29
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable			27		20
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable			391		376

N/A = Not Applicable

Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

12.	COST REDUCTION INITIATIVES

In April 2010, we began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. Approximately 2,450 positions were eliminated as a result of process improvements, streamlined organizational designs and other efficiencies. Most of the affected employees terminated employment May 31, 2010. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge to expense in the second quarter of 2010 primarily related to the headcount reduction initiatives.

	Total
	(in millions)
Incurred	$	293
Settled		4
Remaining Balance at June 30, 2010	$	289

These costs relate primarily to severance benefits. They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet. Approximately 99% of the expense was within the Utility Operations segment.

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Net Income (Loss)
(in millions)

Second Quarter of 2009	$	29

Changes in Gross Margin:
Retail Margins		14
Transmission Revenues		(1	)
Other Revenues		(2	)
Total Change in Gross Margin		11

Total Expenses and Other:
Other Operation and Maintenance		(72	)
Depreciation and Amortization		(9	)
Taxes Other Than Income Taxes		(6	)
Carrying Costs Income		5
Other Income		(2	)
Total Expenses and Other		(84	)

Income Tax Expense		24

Second Quarter of 2010	$	(20	)

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

·	Retail Margins increased $14 million primarily due to the following:
	·	A $22 million increase in rate relief primarily due to an increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia. This increase in retail margins had corresponding offsets of $14 million related to cost recovery riders/trackers that were recognized in other expense line items below.
	·	A $5 million increase in residential usage primarily due to a 47% increase in cooling degree days.
	These increases were partially offset by:
	·	An $8 million decrease in non-weather related residential usage due to economic conditions.
	·	A $3 million decrease in industrial sales primarily due to suspended operations in the first half of 2009 by APCo’s largest customer, Century Aluminum.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $72 million primarily due to the following:
	·	A $55 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
	These increases were partially offset by:
	·	A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $7 million decrease in maintenance expenses related to a true-up between expense and capital for the December 2009 storm.
	·	A $4 million decrease in employee-related expenses.
·	Depreciation and Amortization expenses increased $9 million primarily due to a greater depreciation base resulting from environmental upgrades at the Amos and Mountaineer Plants and the amortization of carrying charges and depreciation expenses being collected through the Virginia E&R surcharges.
·	Taxes Other Than Income Taxes expense increased $6 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income increased $5 million primarily due to increased environmental deferrals in Virginia.
·	Income Tax Expense decreased $24 million primarily due to a decrease in pretax book income.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Net Income (Loss)
(in millions)

Six Months Ended June 30, 2009	$	104

Changes in Gross Margin:
Retail Margins		56
Off-system Sales		2
Other Revenues		(2)
Total Change in Gross Margin		56

Total Expenses and Other:
Other Operation and Maintenance		(104)
Depreciation and Amortization		(16)
Taxes Other Than Income Taxes		(8)
Carrying Costs Income		6
Other Income		(3)
Interest Expense		(2)
Total Expenses and Other		(127)

Income Tax Expense		18

Six Months Ended June 30, 2010	$	51

·	Retail Margins increased $56 million primarily due to the following:
	·	A $75 million increase in rate relief primarily due to the impact of the Virginia interim rate increase implemented in December 2009, subject to refund, and increases in the recoveries of E&R costs in Virginia, costs related to the Transmission Rate Adjustment Clause in Virginia and construction financing costs in West Virginia. This increase in retail margins had corresponding offsets of $32 million related to cost recovery riders/trackers that were recognized in other expense line items below.
	·	A $17 million increase in residential usage primarily due to a 13% increase in heating degree days and a 42% increase in cooling degree days.
	These increases were partially offset by:
	·	A $17 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
	·	A $14 million decrease in industrial sales primarily due to suspended operations in the first half of 2009 by APCo’s largest customer, Century Aluminum.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $104 million primarily due to the following:
	·	A $55 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
	·	A $10 million increase related to the reduction of a 2009 regulatory asset for the over-recovery of transmission costs.
	·	A $6 million increase in employee-related expenses.
	·	A $4 million increase related to generation plant maintenance.
	These increases were partially offset by:
	·	A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $7 million decrease in maintenance expenses related to a true-up between expense and capital related to the December 2009 storm.
·	Depreciation and Amortization expenses increased $16 million primarily due to a greater depreciation base resulting from environmental upgrades at the Amos and Mountaineer Plants and the amortization of carrying charges and depreciation expenses being collected through the Virginia E&R surcharges.
·	Taxes Other Than Income Taxes expense increased $8 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income increased $6 million primarily due to increased environmental deferrals in Virginia.
·	Income Tax Expense decreased $18 million primarily due to a decrease in pretax book income, partially offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

FINANCIAL CONDITION

LIQUIDITY

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. APCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 224 for additional discussion of liquidity.

Credit Ratings

Downgrades in credit ratings by one of the rating agencies could increase APCo’s borrowing costs.

CASH FLOW

Cash flows for the six months ended June 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	2,006		$	1,996
Net Cash Flows from (Used for) Operating Activities		252,172			(90,383	)
Net Cash Flows Used for Investing Activities		(252,171	)		(313,971	)
Net Cash Flows from (Used for) Financing Activities		(181	)		404,159
Net Decrease in Cash and Cash Equivalents		(180	)		(195	)
Cash and Cash Equivalents at End of Period	$	1,826		$	1,801

Operating Activities

Net Cash Flows from Operating Activities were $252 million in 2010. APCo produced Net Income of $51 million during the period and noncash expense items of $151 million for Depreciation and Amortization and $32 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $100 million outflow from Accounts Payable was primarily due to the placement of FGD equipment into service at the Amos Plant and decreased purchases of energy from the system pool. The $76 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies. The $69 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory and a decrease in the average cost per ton. The $39 million outflow from Accrued Taxes, Net was primarily due to increased accruals related to federal income taxes. The $32 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in West Virginia.

Net Cash Flows Used for Operating Activities were $90 million in 2009. APCo produced Net Income of $104 million during the period and had noncash expense items of $135 million for Deferred Income Taxes and $134 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $136 million cash outflow from Accounts Payable was primarily due to APCo’s provision for revenue refund of $77 million which was paid in the first quarter of 2009 to the AEP West companies as part of a FER C order on the SIA. The $93 million outflow from Fuel, Materials and Supplies was primarily due to an increase in coal inventory. The $87 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies. The $79 million outflow from Accrued Taxes, Net was primarily due to increased accruals related to federal income taxes. The $138 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in both Virginia and West Virginia.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 were $252 million and $314 million, respectively. Construction Expenditures of $255 million and $328 million in 2010 and 2009, respectively, were primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades. Environmental upgrades primarily include the installation of FGD equipment at the Amos Plant.

Financing Activities

Net Cash Flows Used for Financing Activities were $181 thousand in 2010. APCo issued $300 million of Senior Unsecured Notes and $68 million of Pollution Control Bonds. APCo had a net increase of $17 million in borrowings from the Utility Money Pool. These increases were partially offset by the retirement of $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds. In addition, APCo paid $78 million in dividends on common stock.

Net Cash Flows from Financing Activities were $404 million in 2009. APCo received capital contributions from the Parent of $250 million in the second quarter of 2009. APCo issued $350 million of Senior Unsecured Notes and retired $150 million of Senior Unsecured Notes.

Long-term debt issuances, retirements and principal payments made during the first six months of 2010 were:

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Pollution Control Bonds	$	17,500	4.625	2021
	Pollution Control Bonds		50,000	5.375	2038
	Senior Unsecured Notes		300,000	3.40	2015

Retirements and Principal Payments
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Notes Payable – Affiliated	$	100,000	4.708	2010
	Senior Unsecured Notes		150,000	4.40	2010
	Pollution Control Bonds		50,000	7.125	2010
	Land Note		9	13.718	2026

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above.

REGULATORY ACTIVITY

Virginia Regulatory Activity

In July 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity. Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when Virginia newly enacted legislation suspended the collection of interim rates. In July 2010, the Virginia SCC issued an order approving a $62 million increase based on a 10.53% return on equity. The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project, which resulted in a write-off of approximately $54 million in the second quarter of 2010. In addition, the order allowed the deferral in the second quarter of 2010 of approximately $25 million of incremental storm expense incurred in 2009. In July 2010, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project. See “2009 Virginia Base Rate Case” section of Note 3.

In June 2010, the Virginia SCC denied APCo’s request to include certain wind purchased power agreements (Beech Ridge and Grand Ridge) with a 20-year term in its Virginia renewable energy portfolio standard program. As a result, APCo recorded an expense of $4 million in June 2010 to reduce the regulatory asset related to the Virginia portion of wind power costs to reflect the difference between the actual Grand Ridge purchased power costs incurred from September 2009 through June 2010 and the cost of non-wind power. No costs to date have been deferred for Beech Ridge, which is estimated to be in service in the third quarter of 2010. Management is evaluating several options regarding the Beech Ridge and Grand Ridge contracts. APCo’s future net income and cash flows will be reduced b y the unrecoverable Virginia portion of the Beech Ridge and Grand Ridge costs until such time as the contracts are reassigned, renegotiated or terminated.

West Virginia Regulatory Activity

In May 2010, APCo filed a request with the WVPSC to increase annual base rates by $140 million based on an 11.75% return on common equity to be effective March 2011. Hearings are scheduled for December 2010. A decision from the WVPSC is expected in March 2011. See “2010 West Virginia Base Rate Case” section of Note 3.

In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division. The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources. Merger approvals from the WVPSC, Virginia SCC and the FERC are required. No merger approval filings have been made. See “WPCo Merger with APCo” section of Note 3.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In APCo’s July 2009 Virginia base rate filing and May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virgin ia share of the Mountaineer Carbon Capture and Storage Project costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010. In response to the order, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project. Through June 30, 2010, APCo has recorded a noncurrent regulatory asset of $58 million consisting of $38 million in project costs and $20 million in asset retirement costs. If APCo cannot recover its remaining investments in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition. See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condense d Financial Statements beginning on page 156. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Significant Factors” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 224 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 224 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 224 for a discussion of risk management activities.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)


	Three Months Ended						Six Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	633,140		$	572,027		$	1,479,130		$	1,299,986
Sales to AEP Affiliates		67,365			62,038			146,136			118,269
Other Revenues		2,769			2,047			4,631			3,886
TOTAL REVENUES		703,274			636,112			1,629,897			1,422,141

EXPENSES
Fuel and Other Consumables Used for Electric Generation		169,616			118,891			350,256			262,572
Purchased Electricity for Resale		56,936			59,631			120,619			135,447
Purchased Electricity from AEP Affiliates		179,607			171,064			447,109			368,188
Other Operation		170,907			63,537			260,947			129,039
Maintenance		14,060			49,478			77,170			105,388
Depreciation and Amortization		73,160			64,148			150,590			134,143
Taxes Other Than Income Taxes		29,955			23,796			56,235			47,899
TOTAL EXPENSES		694,241			550,545			1,462,926			1,182,676

OPERATING INCOME		9,033			85,567			166,971			239,465

Other Income (Expense):
Interest Income		662			395			953			777
Carrying Costs Income		10,298			5,791			16,062			9,874
Allowance for Equity Funds Used During Construction		128			1,184			1,291			3,837
Interest Expense		(51,831	)		(51,457	)		(103,558	)		(101,162	)

INCOME (LOSS) BEFORE INCOME TAX EXPENSE		(31,710	)		41,480			81,719			152,791
(CREDIT)

Income Tax Expense (Credit)		(12,091	)		12,310			31,056			49,214

NET INCOME (LOSS)		(19,619	)		29,170			50,663			103,577

Preferred Stock Dividend Requirements Including Capital
Stock Expense		225			225			450			450

EARNINGS (LOSS) ATTRIBUTABLE TO COMMON
STOCK	$	(19,844	)	$	28,945		$	50,213		$	103,127

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	260,458	$	1,225,292	$	951,066		$	(60,225	)	$	2,376,591

Capital Contribution from Parent				250,000								250,000
Common Stock Dividends						(20,000	)					(20,000	)
Preferred Stock Dividends						(399	)					(399	)
Capital Stock Expense				51		(51	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,606,192

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $217									403			403
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,034									1,920			1,920
NET INCOME						103,577						103,577
TOTAL COMPREHENSIVE INCOME												105,900

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2009	$	260,458	$	1,475,343	$	1,034,193		$	(57,902	)	$	2,712,092

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	260,458	$	1,475,393	$	1,085,980		$	(50,254	)	$	2,771,577

Common Stock Dividends						(78,000	)					(78,000	)
Preferred Stock Dividends						(399	)					(399	)
Capital Stock Expense				52		(51	)					1
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,693,179

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $1,369									(2,542	)		(2,542	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,124									2,087			2,087
NET INCOME						50,663						50,663
TOTAL COMPREHENSIVE INCOME												50,208

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2010	$	260,458	$	1,475,445	$	1,058,193		$	(50,709	)	$	2,743,387

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)

	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,826		$	2,006
Accounts Receivable:
Customers		160,841			150,285
Affiliated Companies		66,933			135,686
Accrued Unbilled Revenues		54,265			68,971
Miscellaneous		4,052			6,690
Allowance for Uncollectible Accounts		(5,770	)		(5,408	)
Total Accounts Receivable		280,321			356,224
Fuel		272,147			343,261
Materials and Supplies		90,220			88,575
Risk Management Assets		54,819			67,956
Accrued Tax Benefits		213,891			180,708
Regulatory Asset for Under-Recovered Fuel Costs		36,652			78,685
Prepayments and Other Current Assets		30,419			36,293
TOTAL CURRENT ASSETS		980,295			1,153,708

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		4,632,273			4,284,361
Transmission		1,830,336			1,813,777
Distribution		2,686,675			2,642,479
Other Property, Plant and Equipment		361,450			329,497
Construction Work in Progress		450,005			730,099
Total Property, Plant and Equipment		9,960,739			9,800,213
Accumulated Depreciation and Amortization		2,808,993			2,751,443
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,151,746			7,048,770

OTHER NONCURRENT ASSETS
Regulatory Assets		1,467,502			1,433,791
Long-term Risk Management Assets		48,088			47,141
Deferred Charges and Other Noncurrent Assets		121,172			113,003
TOTAL OTHER NONCURRENT ASSETS		1,636,762			1,593,935

TOTAL ASSETS	$	9,768,803		$	9,796,413

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2010 and December 31, 2009
(Unaudited)

	2010			2009
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	246,873		$	229,546
Accounts Payable:
General		156,418			291,240
Affiliated Companies		127,104			157,640
Long-term Debt Due Within One Year – Nonaffiliated		250,020			200,019
Long-term Debt Due Within One Year – Affiliated		-			100,000
Risk Management Liabilities		24,839			25,792
Customer Deposits		58,144			57,578
Deferred Income Taxes		56,364			68,706
Accrued Taxes		59,924			65,241
Accrued Interest		57,673			58,962
Other Current Liabilities		112,244			95,292
TOTAL CURRENT LIABILITIES		1,149,603			1,350,016

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		3,310,756			3,177,287
Long-term Risk Management Liabilities		19,744			20,364
Deferred Income Taxes		1,500,176			1,439,884
Regulatory Liabilities and Deferred Investment Tax Credits		544,263			526,546
Employee Benefits and Pension Obligations		303,680			312,873
Deferred Credits and Other Noncurrent Liabilities		179,447			180,114
TOTAL NONCURRENT LIABILITIES		5,858,066			5,657,068

TOTAL LIABILITIES		7,007,669			7,007,084

Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,747			17,752

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares		260,458			260,458
Paid-in Capital		1,475,445			1,475,393
Retained Earnings		1,058,193			1,085,980
Accumulated Other Comprehensive Income (Loss)		(50,709	)		(50,254	)
TOTAL COMMON SHAREHOLDER’S EQUITY		2,743,387			2,771,577

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	9,768,803		$	9,796,413

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	2010			2009
OPERATING ACTIVITIES
Net Income	$	50,663		$	103,577
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for)
Operating Activities:
Depreciation and Amortization		150,590			134,143
Deferred Income Taxes		32,037			135,034
Carrying Costs Income		(16,062	)		(9,874	)
Allowance for Equity Funds Used During Construction		(1,291	)		(3,837	)
Mark-to-Market of Risk Management Contracts		9,975			(23,490	)
Fuel Over/Under-Recovery, Net		(32,329	)		(137,717	)
Change in Other Noncurrent Assets		42,141			(24,202	)
Change in Other Noncurrent Liabilities		(5,225	)		13,786
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		75,903			86,840
Fuel, Materials and Supplies		69,469			(93,304	)
Accounts Payable		(100,171	)		(136,330	)
Accrued Taxes, Net		(38,806	)		(78,773	)
Other Current Assets		5,421			(29,341	)
Other Current Liabilities		9,857			(26,895	)
Net Cash Flows from (Used for) Operating Activities		252,172			(90,383	)

INVESTING ACTIVITIES
Construction Expenditures		(254,663	)		(327,982	)
Other Investing Activities		2,492			14,011
Net Cash Flows Used for Investing Activities		(252,171	)		(313,971	)

FINANCING ACTIVITIES
Capital Contribution from Parent		-			250,000
Issuance of Long-term Debt – Nonaffiliated		363,913			345,666
Change in Advances from Affiliates, Net		17,327			(19,512	)
Retirement of Long-term Debt – Nonaffiliated		(200,009	)		(150,008	)
Retirement of Long-term Debt – Affiliated		(100,000	)		-
Retirement of Cumulative Preferred Stock		(4	)		-
Principal Payments for Capital Lease Obligations		(3,600	)		(1,669	)
Dividends Paid on Common Stock		(78,000	)		(20,000	)
Dividends Paid on Cumulative Preferred Stock		(399	)		(399	)
Other Financing Activities		591			81
Net Cash Flows from (Used for) Financing Activities		(181	)		404,159

Net Decrease in Cash and Cash Equivalents		(180	)		(195	)
Cash and Cash Equivalents at Beginning of Period		2,006			1,996
Cash and Cash Equivalents at End of Period	$	1,826		$	1,801

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	103,271		$	114,983
Net Cash Paid (Received) for Income Taxes		30,259			(2,644	)
Noncash Acquisitions Under Capital Leases		22,344			526
Construction Expenditures Included in Accounts Payable at June 30,		42,890			69,300

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo. The footnotes begin on page 156.

	Footnote Reference

Significant Accounting Matters	Note 1

New Accounting Pronouncements and Extraordinary Item	Note 2

Rate Matters	Note 3

Commitments, Guarantees and Contingencies	Note 4

Benefit Plans	Note 6

Business Segments	Note 7

Derivatives and Hedging	Note 8

Fair Value Measurements	Note 9

Income Taxes	Note 10

Financing Activities	Note 11

Cost Reduction Initiatives	Note 12

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Net Income
(in millions)

Second Quarter of 2009	$	84

Changes in Gross Margin:
Retail Margins		(15	)
Off-system Sales		(3	)
Total Change in Gross Margin		(18	)

Total Expenses and Other:
Other Operation and Maintenance		(32	)
Depreciation and Amortization		(3	)
Taxes Other Than Income Taxes		(1	)
Total Expenses and Other		(36	)

Income Tax Expense		22

Second Quarter of 2010	$	52

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

·	Retail Margins decreased $15 million due to:
	·	A $14 million decrease as a result of the timing of the approval and implementation of new rates set by the Ohio ESP from April through December 2009.
	·	An $8 million decrease in fuel margins.
	·	An $8 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $4 million decrease as a result of the loss of the City of Westerville as a dedicated customer to Off-system Sales. These sales are shared by the members of the AEP Power Pool.
	These decreases were partially offset by:
	·	A $13 million increase in residential and commercial revenue, $8 million of which was due to weather-related usage and a 33% increase in cooling degree days.
·	Margins from Off-system Sales decreased $3 million primarily due to lower trading and marketing margins, partially offset by higher physical sales volumes.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $32 million primarily due to:
	·	A $31 million increase due to expenses incurred related to the cost reduction initiatives in the second quarter of 2010.
	·	A $3 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
	These increases were partially offset by:
	·	A $6 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville and Zimmer plants in 2009.
·	Depreciation and Amortization increased $3 million primarily due to projects at the Conesville Plant that were completed and placed in service in November 2009.
·	Income Tax Expense decreased $22 million primarily due to a decrease in pretax book income.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Net Income
(in millions)

Six Months Ended June 30, 2009	$	133

Changes in Gross Margin:
Retail Margins		(12)
Off-system Sales		1
Other		(1)
Total Change in Gross Margin		(12)

Total Expenses and Other:
Other Operation and Maintenance		(26)
Depreciation and Amortization		(5)
Taxes Other Than Income Taxes		(3)
Interest Expense		(1)
Total Expenses and Other		(35)

Income Tax Expense		18

Six Months Ended June 30, 2010	$	104

The major component of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power was as follows:

·	Retail Margins decreased $12 million due to:
	·	A $14 million decrease as a result of the elimination of Restructuring Transition Charge (RTC) revenues with the implementation of CSPCo’s ESP.
	·	An $11 million decrease in capacity settlements under the Interconnection Agreement.
	·	An $8 million decrease as a result of the loss of the City of Westerville as a dedicated customer to Off-system Sales. These sales are shared by the members of the AEP Power Pool.
	These decreases were partially offset by:
	·	A $9 million increase in retail sales attributable to residential and commercial classes due to weather-related usage and a 32% increase in cooling degree days.
	·	An $8 million increase related to the implementation of higher rates set by the Ohio ESP.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $26 million primarily due to:
	·	A $31 million increase due to expenses incurred related to the cost reduction initiatives in the second quarter of 2010.
	·	A $6 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
	These increases were partially offset by:
	·	A $7 million decrease related to a 2009 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 ESP.
	·	A $7 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville and Zimmer plants.
·	Depreciation and Amortization increased $5 million primarily due to projects at the Conesville Plant that were completed and placed in service in November 2009.
·	Income Tax Expense decreased $18 million primarily due to a decrease in pretax book income.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Ohio Electric Security Plan Filing

During 2009, the PUCO issued an order that modified and approved CSPCo’s ESP which established rates through 2011. The order also limits rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011. The order provides a FAC for the three-year period of the ESP. Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates. CSPCo will file its significantly excessive earnings test with the PUCO by the September 2010 deadline. CSPCo is unable to determine whether it will be required to return any of the ESP revenues to customers. See “Ohio Electric Security Plan Filings” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, CSPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condens ed Financial Statements beginning on page 156. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	503,270		$	488,193		$	1,004,289		$	949,115
Sales to AEP Affiliates		20,090			19,165			35,922			29,371
Other Revenues		744			518			1,332			1,126
TOTAL REVENUES		524,104			507,876			1,041,543			979,612

EXPENSES
Fuel and Other Consumables Used for Electric Generation		105,290			63,476			219,731			134,420
Purchased Electricity for Resale		20,138			22,422			39,783			52,260
Purchased Electricity from AEP Affiliates		91,287			96,068			190,086			189,160
Other Operation		103,229			65,555			180,555			141,643
Maintenance		25,114			31,618			49,397			62,632
Depreciation and Amortization		37,602			34,626			75,089			69,571
Taxes Other Than Income Taxes		44,294			43,145			91,351			88,427
TOTAL EXPENSES		426,954			356,910			845,992			738,113

OPERATING INCOME		97,150			150,966			195,551			241,499

Other Income (Expense):
Interest Income		167			234			309			474
Carrying Costs Income		1,963			1,721			4,184			3,410
Allowance for Equity Funds Used During Construction		314			585			1,235			1,885
Interest Expense		(21,091	)		(21,076	)		(42,875	)		(41,869	)

INCOME BEFORE INCOME TAX EXPENSE		78,503			132,430			158,404			205,399

Income Tax Expense		26,387			48,252			54,638			72,363

NET INCOME		52,116			84,178			103,766			133,036

Capital Stock Expense		40			40			79			79

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	52,076		$	84,138		$	103,687		$	132,957

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	41,026	$	580,506	$	674,758		$	(51,025	)	$	1,245,265

Common Stock Dividends						(100,000	)					(100,000	)
Capital Stock Expense				79		(79	)					-
Noncash Dividend of Property to Parent						(8,123	)					(8,123	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,137,142

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $184									(342	)		(342	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $514									954			954
NET INCOME						133,036						133,036
TOTAL COMPREHENSIVE INCOME												133,648

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2009	$	41,026	$	580,585	$	699,592		$	(50,413	)	$	1,270,790

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	41,026	$	580,663	$	788,139		$	(49,993	)	$	1,359,835

Common Stock Dividends						(52,500	)					(52,500	)
Capital Stock Expense				79		(79	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,307,335

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $232									(431	)		(431	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $667									1,238			1,238
NET INCOME						103,766						103,766
TOTAL COMPREHENSIVE INCOME												104,573

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2010	$	41,026	$	580,742	$	839,326		$	(49,186	)	$	1,411,908

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

100

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)

	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,193		$	1,096
Other Cash Deposits		5,861			16,150
Advance to Affiliates		57,069			-
Accounts Receivable:
Customers		50,518			37,158
Affiliated Companies		21,444			28,555
Accrued Unbilled Revenues		23,152			11,845
Miscellaneous		2,558			4,164
Allowance for Uncollectible Accounts		(1,973	)		(3,481	)
Total Accounts Receivable		95,699			78,241
Fuel		77,268			74,158
Materials and Supplies		40,054			39,652
Emission Allowances		23,190			26,587
Risk Management Assets		30,962			34,343
Accrued Tax Benefits		47,966			29,273
Margin Deposits		13,281			14,874
Prepayments and Other Current Assets		13,851			6,349
TOTAL CURRENT ASSETS		406,394			320,723

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		2,648,583			2,641,860
Transmission		639,205			623,680
Distribution		1,762,600			1,745,559
Other Property, Plant and Equipment		202,368			189,315
Construction Work in Progress		157,297			155,081
Total Property, Plant and Equipment		5,410,053			5,355,495
Accumulated Depreciation and Amortization		1,892,328			1,838,840
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		3,517,725			3,516,655

OTHER NONCURRENT ASSETS
Regulatory Assets		317,426			341,029
Long-term Risk Management Assets		27,204			23,882
Deferred Charges and Other Noncurrent Assets		98,544			147,217
TOTAL OTHER NONCURRENT ASSETS		443,174			512,128

TOTAL ASSETS	$	4,367,293		$	4,349,506

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

101

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
June 30, 2010 and December 31, 2009
(Unaudited)

	2010			2009
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	-		$	24,202
Accounts Payable:
General		83,021			95,872
Affiliated Companies		64,933			81,338
Long-term Debt Due Within One Year – Nonaffiliated		150,000			150,000
Long-term Debt Due Within One Year – Affiliated		-			100,000
Risk Management Liabilities		14,021			13,052
Customer Deposits		28,964			27,911
Accrued Taxes		127,589			199,001
Accrued Interest		23,046			24,669
Other Current Liabilities		89,625			67,053
TOTAL CURRENT LIABILITIES		581,199			783,098

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,438,673			1,286,393
Long-term Risk Management Liabilities		11,165			10,313
Deferred Income Taxes		549,059			535,265
Regulatory Liabilities and Deferred Investment Tax Credits		174,600			174,671
Employee Benefits and Pension Obligations		129,368			133,968
Deferred Credits and Other Noncurrent Liabilities		71,321			65,963
TOTAL NONCURRENT LIABILITIES		2,374,186			2,206,573

TOTAL LIABILITIES		2,955,385			2,989,671

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 24,000,000 Shares
Outstanding – 16,410,426 Shares		41,026			41,026
Paid-in Capital		580,742			580,663
Retained Earnings		839,326			788,139
Accumulated Other Comprehensive Income (Loss)		(49,186	)		(49,993	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,411,908			1,359,835

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	4,367,293		$	4,349,506

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

102

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

			2010		2009
OPERATING ACTIVITIES
Net Income			$	103,766	$	133,036
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			75,089		69,571
	Deferred Income Taxes			19,833		60,104
	Carrying Costs Income			(4,184)		(3,410)
	Allowance for Equity Funds Used During Construction			(1,235)		(1,885)
	Mark-to-Market of Risk Management Contracts			1,466		(10,671)
	Property Taxes			48,526		44,075
	Fuel Over/Under-Recovery, Net			32,120		(33,963)
	Change in Other Noncurrent Assets			(12,867)		(10,738)
	Change in Other Noncurrent Liabilities			(2,458)		20,003
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(17,458)		46,738
		Fuel, Materials and Supplies		(3,512)		(29,021)
		Accounts Payable		(12,744)		(84,284)
		Customer Deposits		1,053		1,390
		Accrued Taxes, Net		(89,647)		(60,756)
		Other Current Assets		8,582		3,600
		Other Current Liabilities		11,209		5,772
Net Cash Flows from Operating Activities				157,539		149,561

INVESTING ACTIVITIES
Construction Expenditures				(84,208)		(147,128)
Change in Other Cash Deposits				10,289		11,075
Change in Advances to Affiliates, Net				(57,069)		-
Acquisitions of Assets				(463)		(184)
Proceeds from Sales of Assets				3,410		465
Net Cash Flows Used for Investing Activities				(128,041)		(135,772)

FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated				149,443		-
Change in Advances from Affiliates, Net				(24,202)		87,794
Retirement of Long-term Debt - Affiliated				(100,000)		-
Principal Payments for Capital Lease Obligations				(2,237)		(1,333)
Dividends Paid on Common Stock				(52,500)		(100,000)
Other Financing Activities				95		-
Net Cash Flows Used for Financing Activities				(29,401)		(13,539)

Net Increase in Cash and Cash Equivalents				97		250
Cash and Cash Equivalents at Beginning of Period				1,096		1,063
Cash and Cash Equivalents at End of Period			$	1,193	$	1,313

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	43,615	$	53,045
Net Cash Paid for Income Taxes				54,032		1,239
Noncash Acquisitions Under Capital Leases				9,196		565
Construction Expenditures Included in Accounts Payable at June 30,				14,594		42,894
Noncash Dividend of Property to Parent				-		8,123

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

103

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to CSPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to CSPCo. The footnotes begin on page 156.

	Footnote Reference

Significant Accounting Matters	Note 1

New Accounting Pronouncements	Note 2

Rate Matters	Note 3

Commitments, Guarantees and Contingencies	Note 4

Benefit Plans	Note 6

Business Segments	Note 7

Derivatives and Hedging	Note 8

Fair Value Measurements	Note 9

Income Taxes	Note 10

Financing Activities	Note 11

Cost Reduction Initiatives	Note 12

104

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

105

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Net Income
(in millions)

Second Quarter of 2009	$	49

Changes in Gross Margin:
Retail Margins		47
FERC Municipals and Cooperatives		(8	)
Other Revenues		(42	)
Total Change in Gross Margin		(3	)

Total Expenses and Other:
Other Operation and Maintenance		(46	)
Taxes Other Than Income Taxes		(1	)
Other Income		2
Total Expenses and Other		(45	)

Income Tax Expense		14

Second Quarter of 2010	$	15

·	Retail Margins increased $47 million primarily due to the following:
	·	A $20 million increase in fuel margins primarily due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
	·	A $15 million increase in usage for residential and commercial customers primarily due to an increase in cooling degree days and demand.
	·	An $11 million increase in industrial sales margins due to higher usage reflecting an improvement in demand.
·	FERC Municipals and Cooperatives margins decreased $8 million primarily due to a unit power sales agreement ending in December 2009.
·	Other Revenues decreased $42 million primarily due to the Cook Plant accidental outage insurance proceeds of $46 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $20 million in the second quarter of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.

Total Expenses and Other and Income Tax Expense changed between years as follows:

106

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Net Income
(in millions)

Six Months Ended June 30, 2009	$	129

Changes in Gross Margin:
Retail Margins		82
FERC Municipals And Cooperatives		(16)
Off-system Sales		3
Transmission Revenues		1
Other Revenues		(97)
Total Change in Gross Margin		(27)

Total Expenses and Other:
Other Operation and Maintenance		(69)
Depreciation and Amortization		(1)
Taxes Other Than Income Taxes		(1)
Other Income		3
Interest Expense		(3)
Total Expenses and Other		(71)

Income Tax Expense		29

Six Months Ended June 30, 2010	$	60

·	Retail Margins increased $82 million primarily due to the following:
	·	A $42 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Unit 1 shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
	·	A $19 million increase in industrial sale margins due to higher usage reflecting an improvement in demand.
	·	A $17 million increase in usage and price for residential and commercial customers primarily due to an increase in cooling degree days and demand.
	·	A $5 million increase in capacity settlements under the Interconnection Agreement.
·	FERC Municipals and Cooperatives margins decreased $16 million primarily due to a unit power sales agreement ending in December 2009.
·	Other Revenues decreased $97 million primarily due to the Cook Plant accidental outage insurance proceeds of $99 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $42 million in the first six months of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.

107

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $69 million primarily due to the following:
	·	A $40 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $10 million increase in administrative and general expenses primarily due to a $7 million increase in benefit and insurance costs and a $2 million increase in property insurance.
	·	A $6 million increase in transmission expense primarily due to lower credits under the Transmission Agreement.
	·	A $4 million increase in distribution expenses associated with storm restoration expenses from June 2010 storms.
·	Income Tax Expense decreased $29 million primarily due to a decrease in pretax book income.

REGULATORY ACTIVITY

Michigan Regulatory Activity

In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity. In the August 2010 billing cycle, I&M, with the MPSC authorization, will implement a $44 million interim rate increase, subject to refund with interest. In July 2010, the MPSC staff filed testimony which recommended a $34 million annual increase in base rates based on a 10.35% return on common equity plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period. The MPSC must issue a final order within one year of the original filing. See “Michigan Base Rate Filing” section of Note 3.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equipme nt is scheduled for the Unit 1 planned outage in the fall of 2011. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Conde nsed Financial Statements beginning on page 156. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

108

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

109

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	408,702		$	400,347		$	846,726		$	822,274
Sales to AEP Affiliates		67,473			57,385			151,690			117,371
Other Revenues - Affiliated		30,685			25,192			58,651			55,932
Other Revenues - Nonaffiliated		3,055			47,492			5,904			101,883
TOTAL REVENUES		509,915			530,416			1,062,971			1,097,460

EXPENSES
Fuel and Other Consumables Used for Electric Generation		102,258			108,202			221,439			211,162
Purchased Electricity for Resale		31,444			30,853			61,211			69,214
Purchased Electricity from AEP Affiliates		68,496			80,893			150,746			160,871
Other Operation		162,978			115,224			293,659			224,684
Maintenance		49,633			51,488			98,077			97,762
Depreciation and Amortization		33,971			33,629			67,802			66,374
Taxes Other Than Income Taxes		18,995			18,253			40,027			38,949
TOTAL EXPENSES		467,775			438,542			932,961			869,016

OPERATING INCOME		42,140			91,874			130,010			228,444

Other Income (Expense):
Interest Income		1,034			974			1,519			3,517
Allowance for Equity Funds Used During Construction		4,567			2,783			9,002			4,338
Interest Expense		(26,410	)		(26,173	)		(52,511	)		(49,704	)

INCOME BEFORE INCOME TAX EXPENSE		21,331			69,458			88,020			186,595

Income Tax Expense		6,729			20,949			28,360			57,134

NET INCOME		14,602			48,509			59,660			129,461

Preferred Stock Dividend Requirements		85			85			170			170

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	14,517		$	48,424		$	59,490		$	129,291

The common stock of I&M is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

110

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	56,584	$	861,291	$	538,637		$	(21,694	)	$	1,434,818

Capital Contribution from Parent				120,000								120,000
Common Stock Dividends						(49,000	)					(49,000	)
Preferred Stock Dividends						(170	)					(170	)
Gain on Reacquired Preferred Stock				1								1
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,505,649

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $103									192			192
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $184									341			341
NET INCOME						129,461						129,461
TOTAL COMPREHENSIVE INCOME												129,994

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2009	$	56,584	$	981,292	$	618,928		$	(21,161	)	$	1,635,643

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	56,584	$	981,292	$	656,608		$	(21,701	)	$	1,672,783

Common Stock Dividends						(51,500	)					(51,500	)
Preferred Stock Dividends						(170	)					(170	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,621,113

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $39									72			72
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $235									436			436
NET INCOME						59,660						59,660
TOTAL COMPREHENSIVE INCOME												60,168

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2010	$	56,584	$	981,292	$	664,598		$	(21,193	)	$	1,681,281

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

111

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)

	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	732		$	779
Advances to Affiliates		126,515			114,012
Accounts Receivable:
Customers		86,002			71,120
Affiliated Companies		68,632			83,248
Accrued Unbilled Revenues		4,243			8,762
Miscellaneous		15,702			8,638
Allowance for Uncollectible Accounts		(2,111	)		(2,265	)
Total Accounts Receivable		172,468			169,503
Fuel		107,293			79,554
Materials and Supplies		163,532			164,439
Risk Management Assets		32,803			34,438
Accrued Tax Benefits		147,959			144,473
Deferred Cook Plant Fire Costs		53,218			134,322
Prepayments and Other Current Assets		25,833			29,395
TOTAL CURRENT ASSETS		830,353			870,915

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		3,652,725			3,634,215
Transmission		1,168,195			1,154,026
Distribution		1,382,429			1,360,553
Other Property, Plant and Equipment (including nuclear fuel and coal mining)		748,725			755,132
Construction Work in Progress		329,245			278,278
Total Property, Plant and Equipment		7,281,319			7,182,204
Accumulated Depreciation, Depletion and Amortization		3,105,441			3,073,695
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,175,878			4,108,509

OTHER NONCURRENT ASSETS
Regulatory Assets		517,700			496,464
Spent Nuclear Fuel and Decommissioning Trusts		1,391,428			1,391,919
Long-term Risk Management Assets		36,177			29,134
Deferred Charges and Other Noncurrent Assets		76,365			82,047
TOTAL OTHER NONCURRENT ASSETS		2,021,670			1,999,564

TOTAL ASSETS	$	7,027,901		$	6,978,988

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

112

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2010 and December 31, 2009
(Unaudited)

	2010			2009
CURRENT LIABILITIES	(in thousands)
Accounts Payable:
General	$	91,297		$	171,192
Affiliated Companies		55,208			61,315
Long-term Debt Due Within One Year – Nonaffiliated DCC Fuel Bonds		61,435			37,544
Long-term Debt Due Within One Year – Affiliated		-			25,000
Risk Management Liabilities		14,108			13,436
Customer Deposits		28,748			27,711
Accrued Taxes		63,131			56,814
Accrued Interest		27,588			27,633
Obligations Under Capital Leases		20,981			25,065
Other Current Liabilities		156,678			126,800
TOTAL CURRENT LIABILITIES		519,174			572,510

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		2,057,239			2,015,362
Long-term Risk Management Liabilities		11,249			10,386
Deferred Income Taxes		728,741			696,163
Regulatory Liabilities and Deferred Investment Tax Credits		753,515			756,845
Asset Retirement Obligations		923,666			894,746
Deferred Credits and Other Noncurrent Liabilities		344,959			352,116
TOTAL NONCURRENT LIABILITIES		4,819,369			4,725,618

TOTAL LIABILITIES		5,338,543			5,298,128

Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,077			8,077

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares		56,584			56,584
Paid-in Capital		981,292			981,292
Retained Earnings		664,598			656,608
Accumulated Other Comprehensive Income (Loss)		(21,193	)		(21,701	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,681,281			1,672,783

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	7,027,901		$	6,978,988

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

113

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

			2010		2009
OPERATING ACTIVITIES
Net Income			$	59,660	$	129,461
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			67,802		66,374
	Deferred Income Taxes			23,213		92,892
	Deferral of Incremental Nuclear Refueling Outage Expenses, Net			(16,103)		(13,928)
	Allowance for Equity Funds Used During Construction			(9,002)		(4,338)
	Mark-to-Market of Risk Management Contracts			(4,314)		(10,602)
	Amortization of Nuclear Fuel			69,478		24,718
	Fuel Over/Under Recovery, Net			11,389		2,410
	Change in Other Noncurrent Assets			7,224		(8,727)
	Change in Other Noncurrent Liabilities			33,814		26,606
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(2,965)		9,383
		Fuel, Materials and Supplies		(26,832)		(8,668)
		Accounts Payable		(31,079)		(62,884)
		Accrued Taxes, Net		4,470		(21,736)
		Received (Deferred) Cook Plant Fire Costs		61,906		(24,209)
		Other Current Assets		(284)		(13,840)
		Other Current Liabilities		20,087		(26,990)
Net Cash Flows from Operating Activities				268,464		155,922

INVESTING ACTIVITIES
Construction Expenditures				(160,797)		(162,153)
Change in Advances to Affiliates, Net				(12,503)		-
Purchases of Investment Securities				(617,059)		(441,928)
Sales of Investment Securities				592,263		411,027
Acquisitions of Nuclear Fuel				(41,357)		(152,150)
Other Investing Activities				(345)		15,473
Net Cash Flows Used for Investing Activities				(239,798)		(329,731)

FINANCING ACTIVITIES
Capital Contribution from Parent				-		120,000
Issuance of Long-term Debt - Nonaffiliated				84,564		567,797
Issuance of Long-term Debt - Affiliated				-		25,000
Change in Advances from Affiliates, Net				-		(473,686)
Retirement of Long-term Debt - Nonaffiliated				(19,208)		-
Retirement of Long-term Debt - Affiliated				(25,000)		-
Retirement of Cumulative Preferred Stock				-		(2)
Principal Payments for Capital Lease Obligations				(17,669)		(16,235)
Dividends Paid on Common Stock				(51,500)		(49,000)
Dividends Paid on Cumulative Preferred Stock				(170)		(170)
Other Financing Activities				270		189
Net Cash Flows from (Used for) Financing Activities				(28,713)		173,893

Net Increase (Decrease) in Cash and Cash Equivalents				(47)		84
Cash and Cash Equivalents at Beginning of Period				779		728
Cash and Cash Equivalents at End of Period			$	732	$	812

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	50,759	$	51,199
Net Cash Paid (Received) for Income Taxes				8,092		(23)
Noncash Acquisitions Under Capital Leases				8,844		1,380
Construction Expenditures Included in Accounts Payable at June 30,				19,220		26,763
Acquisition of Nuclear Fuel Included in Accounts Payable at June 30,				123		9

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

114

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M. The footnotes begin on page 156.

	Footnote Reference

Significant Accounting Matters	Note 1

New Accounting Pronouncements and Extraordinary Item	Note 2

Rate Matters	Note 3

Commitments, Guarantees and Contingencies	Note 4

Benefit Plans	Note 6

Business Segments	Note 7

Derivatives and Hedging	Note 8

Fair Value Measurements	Note 9

Income Taxes	Note 10

Financing Activities	Note 11

Cost Reduction Initiatives	Note 12

115

OHIO POWER COMPANY CONSOLIDATED

116

OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Net Income
(in millions)

Second Quarter of 2009	$	64

Changes in Gross Margin:
Retail Margins		26
Off-system Sales		(7	)
Other Revenues		(2	)
Total Change in Gross Margin		17

Total Expenses and Other:
Other Operation and Maintenance		(55	)
Taxes Other Than Income Taxes		(6	)
Carrying Costs Income		3
Other Income		1
Interest Expense		(4	)
Total Expenses and Other		(61	)

Income Tax Expense		18

Second Quarter of 2010	$	38

·	Retail Margins increased $26 million primarily due to the following:
	·	A $13 million increase in retail sales as a result of an increase in weather-related usage of residential and commercial customers and an increase in usage of industrial customers resulting from an improvement in demand.
	·	A $13 million increase in capacity settlements under the Interconnection Agreement.
	·	An $8 million increase in fuel margins.
	·	A $6 million increase associated with increased demand charges from WPCo effective January 2010.
	These increases were partially offset by:
	·	An $8 million decrease as a result of the timing of the approval and implementation of rates set by the Ohio ESP from April through December 2009.
	·	A $3 million decrease related to increased consumable and allowance expenses.
·	Margins from Off-system Sales decreased $7 million primarily due to lower trading and marketing margins, partially offset by higher physical sales volumes.

117

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $55 million primarily due to a $49 million increase in expenses related to the cost reduction initiatives in the second quarter of 2010.
·	Taxes Other Than Income Taxes increased $6 million primarily due to a $2 million increase in real and property tax and a $2 million increase due to the employer portion of payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income increased $3 million primarily due to higher Ohio ESP FAC carrying charges in 2010 related to an increase in the deferred fuel regulatory asset balance.
·	Interest Expense increased $4 million primarily due to:
	·	A $7 million increase due to a prior year gain on an interest rate hedge of a forecasted debt issuance.
	·	A $5 million increase primarily due to an issuance of long-term debt in September 2009 partly offset by a retirement of long-term debt in April 2010.
	These increases were partially offset by:
	·	An $8 million decrease related to the reacquisition of JMG Funding LP’s (JMG) bonds during the third quarter of 2009.
·	Income Tax Expense decreased $18 million primarily due to a decrease in pretax book income.

118

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Net Income
(in millions)

Six Months Ended June 30, 2009	$	137

Changes in Gross Margin:
Retail Margins		68
Off-system Sales		(1)
Transmission Revenues		(2)
Other Revenues		(19)
Total Change in Gross Margin		46

Total Expenses and Other:
Other Operation and Maintenance		(41)
Depreciation and Amortization		(6)
Taxes Other Than Income Taxes		(7)
Carrying Costs Income		6
Other Income		1
Interest Expense		(5)
Total Expenses and Other		(52)

Income Tax Expense		(2)

Six Months Ended June 30, 2010	$	129

·	Retail Margins increased $68 million primarily due to the following:
	·	A $37 million increase in capacity settlements under the Interconnection Agreement.
	·	A $26 million increase in rate relief due to a $14 million increase related to the implementation of higher rates set by the Ohio ESP and $12 million of increased demand charges from WPCo effective January 2010.
	·	A $20 million increase in fuel margins.
	These increases were partially offset by:
	·	A $10 million net decrease as a result of revenue collected from the Economic Development Rider more than offset by a reduction in revenue from the 2010 Special Arrangement Discount for Ormet.
	·	A $6 million decrease related to increased consumable and allowance expenses.
·	Other Revenues decreased $19 million primarily due to reduced gains on sales of emission allowances.

119

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $41 million primarily due to:
	·	A $49 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $5 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
	These increases were partially offset by:
	·	A $7 million decrease related to a 2009 obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of OPCo’s ESP.
	·	A $7 million decrease in rent expense as a result of the purchase of JMG in July 2009.
·	Depreciation and Amortization increased $6 million primarily due to:
	·	A $9 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions.
	This increase was partially offset by:
	·	A $3 million decrease due to the completion of the amortization of software and leasehold improvements in the fourth quarter of 2009.
·	Taxes Other Than Income Taxes increased $7 million primarily due to a $4 million increase in real and property tax and a $2 million increase due to the employer portion of payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income increased $6 million primarily due to higher Ohio ESP FAC carrying charges in 2010 related to an increase in the deferred fuel regulatory asset balance.
·	Interest Expense increased $5 million primarily due to:
	·	An $11 million increase primarily due to an issuance of long-term debt in September 2009 partly offset by a retirement of long-term debt in April 2010.
	·	A $7 million increase due to a prior year gain on an interest rate hedge of a forecasted debt issuance.
	·	A $6 million decrease in the debt component of AFUDC primarily due to the Amos Plant Unit 3 FGD and precipitator upgrade going into service in March 2009.
	These increases were partially offset by:
	·	A $16 million decrease related to the reacquisition of JMG’s bonds during the third quarter of 2009.
·	Income Tax Expense increased $2 million primarily due to the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits offset in part by a decrease in pretax book income.

FINANCIAL CONDITION

LIQUIDITY

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. OPCo has $200 million of Senior Unsecured Notes that will mature in the remainder of 2010. OPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund its maturities, current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 224 for additional discussion of liquidity.

Credit Ratings

Downgrades in credit ratings by one of the rating agencies could increase OPCo’s borrowing costs.

120

CASH FLOW

Cash flows for the six months ended June 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,984		$	12,679
Net Cash Flows from (Used for) Operating Activities		352,278			(19,453	)
Net Cash Flows from (Used for) Investing Activities		119,588			(296,508	)
Net Cash Flows from (Used for) Financing Activities		(472,912	)		320,054
Net Increase (Decrease) in Cash and Cash Equivalents		(1,046	)		4,093
Cash and Cash Equivalents at End of Period	$	938		$	16,772

Operating Activities

Net Cash Flows from Operating Activities were $352 million in 2010. OPCo produced Net Income of $129 million during the period and noncash expense items of $179 million for Depreciation and Amortization and $73 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. Accrued Taxes, Net had a $71 million outflow due to temporary timing differences of payments for property taxes and an increase of federal income tax related accruals. Accounts Receivable, Net had a $4 4 million inflow primarily due to decreased sales to affiliates and settlement of allowance sales to affiliated companies. Fuel, Materials and Supplies had a $26 million inflow primarily due to price decreases. The $76 million increase in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Net Cash Flows Used for Operating Activities were $19 million in 2009. OPCo produced Net Income of $137 million during the period and noncash expense items of $173 million for Depreciation and Amortization, $117 million for Deferred Income Taxes and $44 million for Property Taxes offset by a $142 million increase in Fuel Over/Under-Recovery, Net due to an under-recovery of fuel costs in Ohio. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital primarily relates to a number of items. Fuel, Materials and Supplies had a $166 million outflow primarily d ue to an increase in coal inventory. Accounts Payable had a $101 million outflow primarily due to OPCo’s provision for revenue refund of $62 million which was paid in the first quarter of 2009 to the AEP West companies as part of the FERC’s order on the SIA. Accrued Taxes, Net had a $93 million outflow due to a decrease of federal income tax related accruals and temporary timing differences of payments for property taxes.

Investing Activities

Net Cash Flows from Investing Activities were $120 million in 2010. Net Cash Flows Used for Investing Activities were $297 million in 2009. OPCo had a net decrease of $266 million and a net increase of $40 million in loans to the Utility Money Pool during 2010 and 2009, respectively. Construction Expenditures of $148 million and $276 million in 2010 and 2009, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include the installation of selective catalytic reduction equipment and FGD projects at the Amos Plant.

Financing Activities

Net Cash Flows Used for Financing Activities were $473 million in 2010. OPCo issued Pollution Control Bonds of $86 million in March 2010 and $79 million in May 2010. OPCo retired $400 million of Senior Unsecured Notes in April 2010 and $79 million of Pollution Control Bonds in June 2010. In addition, OPCo paid $151 million of dividends on common stock.

121

Net Cash Flows from Financing Activities were $320 million in 2009 primarily due to a $550 million Capital Contribution from Parent partially offset by a net decrease of $134 million in borrowings from the Utility Money Pool and a $78 million retirement of Notes Payable.

Long-term debt issuances and retirements during the first six months of 2010 were:

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Pollution Control Bonds	$	86,000	3.125	2015
	Pollution Control Bonds		79,450	3.25	2014

Retirements
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Senior Unsecured Notes	$	400,000	Variable	2010
	Pollution Control Bonds		79,450	7.125	2010

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in “Cash Flow” above.

SIGNIFICANT FACTORS

REGULATORY ISSUES

Ohio Electric Security Plan Filing

During 2009, the PUCO issued an order that modified and approved OPCo’s ESP which established rates through 2011. The order also limits rate increases for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. The order provides a FAC for the three-year period of the ESP. Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates. OPCo will file its significantly excessive earnings test with the PUCO by the September 2010 deadline. OPCo is unable to determine whether it will be required to return any of the ESP revenues to customers. See “Ohio Electric Security Plan Filings” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condense d Financial Statements beginning on page 156. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

122

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

123

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	490,422		$	457,465		$	1,034,122		$	982,151
Sales to AEP Affiliates		222,561			210,998			529,329			437,692
Other Revenues - Affiliated		5,155			6,281			11,729			13,769
Other Revenues - Nonaffiliated		3,826			3,269			8,057			7,116
TOTAL REVENUES		721,964			678,013			1,583,237			1,440,728

EXPENSES
Fuel and Other Consumables Used for Electric Generation		220,174			189,475			551,191			442,949
Purchased Electricity for Resale		38,746			43,969			77,636			96,238
Purchased Electricity from AEP Affiliates		21,583			20,465			43,774			37,207
Other Operation		146,417			96,249			235,573			195,847
Maintenance		63,472			58,150			119,703			118,190
Depreciation and Amortization		89,861			89,384			179,222			173,407
Taxes Other Than Income Taxes		52,088			46,482			105,172			97,974
TOTAL EXPENSES		632,341			544,174			1,312,271			1,161,812

OPERATING INCOME		89,623			133,839			270,966			278,916

Other Income (Expense):
Carrying Costs Income		5,681			2,425			10,555			4,009
Other Income		1,320			417			2,756			1,528
Interest Expense		(39,077	)		(35,241	)		(79,052	)		(73,922	)

INCOME BEFORE INCOME TAX EXPENSE		57,547			101,440			205,225			210,531

Income Tax Expense		19,999			37,528			75,774			74,010

NET INCOME		37,548			63,912			129,451			136,521

Less: Net Income Attributable to Noncontrolling Interest		-			553			-			1,016

NET INCOME ATTRIBUTABLE TO OPCo
SHAREHOLDERS		37,548			63,359			129,451			135,505

Less: Preferred Stock Dividend Requirements		183			183			366			366

EARNINGS ATTRIBUTABLE TO OPCo COMMON
SHAREHOLDER	$	37,365		$	63,176		$	129,085		$	135,139

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

124

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	OPCo Common Shareholder
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive			Noncontrolling
	Stock		Capital		Earnings			Income (Loss)			Interest			Total

TOTAL EQUITY – DECEMBER 31, 2008	$	321,201	$	536,640	$	1,697,962		$	(133,858	)	$	16,799		$	2,438,744

Capital Contribution from Parent				550,000											550,000
Common Stock Dividends - Affiliated						(25,000	)								(25,000	)
Common Stock Dividends - Nonaffiliated												(1,016	)		(1,016	)
Preferred Stock Dividends						(366	)								(366	)
Other Changes in Equity												1,111			1,111
SUBTOTAL – EQUITY															2,963,473

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $7,828									14,538						14,538
Amortization of Pension and OPEB
Deferred Costs, Net of Tax of $1,459									2,709						2,709
NET INCOME						135,505						1,016			136,521
TOTAL COMPREHENSIVE INCOME															153,768

TOTAL EQUITY – JUNE 30, 2009	$	321,201	$	1,086,640	$	1,808,101		$	(116,611	)	$	17,910		$	3,117,241

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	321,201	$	1,123,149	$	1,908,803		$	(118,458	)	$	-		$	3,234,695

Common Stock Dividends						(150,575	)								(150,575	)
Preferred Stock Dividends						(366	)								(366	)
SUBTOTAL – COMMON SHAREHOLDER'S
EQUITY															3,083,754

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $676									(1,255	)					(1,255	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,897									3,523						3,523
NET INCOME						129,451									129,451
TOTAL COMPREHENSIVE INCOME															131,719

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2010	$	321,201	$	1,123,149	$	1,887,313		$	(116,190	)	$	-		$	3,215,473

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

125

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)

	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	938		$	1,984
Advances to Affiliates		172,751			438,352
Accounts Receivable:
Customers		71,608			60,711
Affiliated Companies		139,427			200,579
Accrued Unbilled Revenues		21,630			15,021
Miscellaneous		2,320			2,701
Allowance for Uncollectible Accounts		(2,665	)		(2,665	)
Total Accounts Receivable		232,320			276,347
Fuel		304,977			336,866
Materials and Supplies		121,867			115,486
Risk Management Assets		40,071			50,048
Accrued Tax Benefits		166,875			143,473
Prepayments and Other Current Assets		24,769			26,301
TOTAL CURRENT ASSETS		1,064,568			1,388,857

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		6,788,912			6,731,469
Transmission		1,202,373			1,166,557
Distribution		1,595,110			1,567,871
Other Property, Plant and Equipment		373,811			348,718
Construction Work in Progress		187,230			198,843
Total Property, Plant and Equipment		10,147,436			10,013,458
Accumulated Depreciation and Amortization		3,470,968			3,318,896
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		6,676,468			6,694,562

OTHER NONCURRENT ASSETS
Regulatory Assets		845,503			742,905
Long-term Risk Management Assets		31,506			28,003
Deferred Charges and Other Noncurrent Assets		139,122			184,812
TOTAL OTHER NONCURRENT ASSETS		1,016,131			955,720

TOTAL ASSETS	$	8,757,167		$	9,039,139

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

126


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2010 and December 31, 2009
(Unaudited)

	2010			2009
	(in thousands)
CURRENT LIABILITIES
Accounts Payable:
General	$	140,269		$	182,848
Affiliated Companies		91,992			92,766
Long-term Debt Due Within One Year – Nonaffiliated		200,000			679,450
Risk Management Liabilities		19,972			24,391
Customer Deposits		26,723			22,409
Accrued Taxes		155,946			203,335
Accrued Interest		45,623			46,431
Other Current Liabilities		149,314			104,889
TOTAL CURRENT LIABILITIES		829,839			1,356,519

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		2,529,248			2,363,055
Long-term Debt – Affiliated		200,000			200,000
Long-term Risk Management Liabilities		13,401			12,510
Deferred Income Taxes		1,379,968			1,302,939
Regulatory Liabilities and Deferred Investment Tax Credits		137,944			128,187
Employee Benefits and Pension Obligations		252,832			269,485
Deferred Credits and Other Noncurrent Liabilities		181,835			155,122
TOTAL NONCURRENT LIABILITIES		4,695,228			4,431,298

TOTAL LIABILITIES		5,525,067			5,787,817

Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,627			16,627

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares		321,201			321,201
Paid-in Capital		1,123,149			1,123,149
Retained Earnings		1,887,313			1,908,803
Accumulated Other Comprehensive Income (Loss)		(116,190	)		(118,458	)
TOTAL COMMON SHAREHOLDER’S EQUITY		3,215,473			3,234,695

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	8,757,167		$	9,039,139

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

127

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

				2010		2009
OPERATING ACTIVITIES
Net Income				$	129,451	$	136,521
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for)
	Operating Activities:
		Depreciation and Amortization			179,222		173,407
		Deferred Income Taxes			72,638		117,372
		Carrying Costs Income			(10,555)		(4,009)
		Allowance for Equity Funds Used During Construction			(2,017)		(768)
		Mark-to-Market of Risk Management Contracts			2,359		(16,123)
		Property Taxes			48,578		44,125
		Fuel Over/Under-Recovery, Net			(75,987)		(141,874)
		Change in Other Noncurrent Assets			(7,571)		6,483
		Change in Other Noncurrent Liabilities			(2,326)		15,173
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		44,027		20,986
			Fuel, Materials and Supplies		25,508		(165,648)
			Accounts Payable		(23,991)		(100,613)
			Accrued Taxes, Net		(71,199)		(93,152)
			Other Current Assets		2,680		(14,965)
			Other Current Liabilities		41,461		3,632
Net Cash Flows from (Used for) Operating Activities					352,278		(19,453)

INVESTING ACTIVITIES
Construction Expenditures					(147,831)		(276,255)
Change in Advances to Affiliates, Net					265,601		(40,319)
Acquisitions of Assets					(2,113)		(1,075)
Proceeds from Sales of Assets					4,245		17,261
Other Investing Activities					(314)		3,880
Net Cash Flows from (Used for) Investing Activities					119,588		(296,508)

FINANCING ACTIVITIES
Capital Contribution from Parent					-		550,000
Issuance of Long-term Debt – Nonaffiliated					163,944		(445)
Change in Short-term Debt, Net – Nonaffiliated					-		11,500
Change in Advances from Affiliates, Net					-		(133,887)
Retirement of Long-term Debt – Nonaffiliated					(479,450)		(77,500)
Retirement of Cumulative Preferred Stock					-		(1)
Principal Payments for Capital Lease Obligations					(3,903)		(2,224)
Dividends Paid on Common Stock – Nonaffiliated					-		(463)
Dividends Paid on Common Stock – Affiliated					(150,575)		(25,000)
Dividends Paid on Cumulative Preferred Stock					(366)		(366)
Other Financing Activities					(2,562)		(1,560)
Net Cash Flows from (Used for) Financing Activities					(472,912)		320,054

Net Increase (Decrease) in Cash and Cash Equivalents					(1,046)		4,093
Cash and Cash Equivalents at Beginning of Period					1,984		12,679
Cash and Cash Equivalents at End of Period				$	938	$	16,772

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	78,747	$	100,522
Net Cash Paid for Income Taxes					27,206		2,566
Noncash Acquisitions Under Capital Leases					23,489		468
Construction Expenditures Included in Accounts Payable at June 30,					10,567		16,391

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

128

OHIO POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo. The footnotes begin on page 156.

	Footnote Reference

Significant Accounting Matters	Note 1

New Accounting Pronouncements and Extraordinary Item	Note 2

Rate Matters	Note 3

Commitments, Guarantees and Contingencies	Note 4

Benefit Plans	Note 6

Business Segments	Note 7

Derivatives and Hedging	Note 8

Fair Value Measurements	Note 9

Income Taxes	Note 10

Financing Activities	Note 11

Cost Reduction Initiatives	Note 12

129

PUBLIC SERVICE COMPANY OF OKLAHOMA

130

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Net Income
(in millions)

Second Quarter of 2009		$	24

Changes in Gross Margin:
Retail Margins (a)			12
Other Revenues			(2	)
Total Change in Gross Margin			10

Total Expenses and Other:
Other Operation and Maintenance			(23	)
Depreciation and Amortization			2
Other Income			(2	)
Interest Expense			(1	)
Total Expenses and Other			(24	)

Income Tax Expense			5

Second Quarter of 2010		$	15

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $12 million primarily due to the following:
	·	An $8 million increase primarily resulting from rate increases during the year, including revenue increases from rate riders of $5 million. This increase in retail margins had corresponding offsets of $2 million related to cost recovery riders/trackers that were recognized in other expense line items below.
	·	A $4 million increase in weather-related usage primarily due to a 17% increase in cooling degree days.

Total Expenses and Other and Income Tax Expense changed between years as follows:

	·	Other Operation and Maintenance expenses increased $23 million primarily due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income.

131

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Net Income
(in millions)

Six Months Ended June 30, 2009		$	30

Changes in Gross Margin:
Retail Margins (a)			23
Transmission Revenues			3
Other Revenues			(1)
Total Change in Gross Margin			25

Total Expenses and Other:
Other Operation and Maintenance			(39)
Depreciation and Amortization			2
Taxes Other Than Income Taxes			1
Other Income			(2)
Interest Expense			(3)
Total Expenses and Other			(41)

Income Tax Expense			6

Six Months Ended June 30, 2010		$	20

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $23 million primarily due to the following:
	·	A $19 million increase primarily resulting from rate increases during the year, including revenue increases from rate riders of $12 million. This increase in retail margins had corresponding offsets of $4 million related to cost recovery riders/trackers that were recognized in other expense line items below.
	·	A $10 million increase in weather-related usage primarily due to a 27% increase in heating degree days and a 14% increase in cooling degree days.
·	Transmission Revenues increased $3 million primarily due to higher rates in the SPP region.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $39 million primarily due to the following:
	·	A $23 million increase primarily due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $6 million increase in employee-related expenses.
	·	A $5 million increase in plant maintenance expense resulting from the 2009 deferral of generation maintenance expenses as a result of PSO’s base rate case.
·	Interest Expense increased $3 million primarily due to an increase in long-term borrowings in the last half of 2009.
·	Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income.

132

FINANCIAL CONDITION

LIQUIDITY

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity. PSO relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 224 for additional discussion of liquidity.

Credit Ratings

Downgrades in credit ratings by one of the rating agencies could increase PSO’s borrowing costs.

CASH FLOW

Cash flows for the six months ended June 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	796		$	1,345
Net Cash Flows from Operating Activities		8,473			199,675
Net Cash Flows Used for Investing Activities		(46,697	)		(118,301	)
Net Cash Flows from (Used For) Financing Activities		38,517			(81,659	)
Net Increase (Decrease) in Cash and Cash Equivalents		293			(285	)
Cash and Cash Equivalents at End of Period	$	1,089		$	1,060

Operating Activities

Net Cash Flows from Operating Activities were $8 million in 2010. PSO produced Net Income of $20 million during the period and had noncash expense items of $54 million for Depreciation and Amortization and $33 million for Deferred Income Taxes, partially offset by a $19 million increase in the deferral of Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a $38 million inflow from Accounts Payable primarily due to timing differences for payments to affiliates and purchased power. The $100 million outflow from Fuel Over/Un der-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates.

Net Cash Flows from Operating Activities were $200 million in 2009. PSO produced Net Income of $30 million during the period and had a noncash expense item of $56 million for Depreciation and Amortization, partially offset by a $19 million increase in the deferral of Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $88 million inflow from Accounts Receivable, Net was primarily due to receiving the SIA refund from the AEP East companies and lower customer receivables. The $40 million inf low from Accrued Taxes, Net was the result of increased accruals related to property and income taxes. The $15 million inflow from Fuel Over/Under-Recovery, Net was primarily due to lower fuel costs, partially offset by SIA refunds to customers.

133

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 were $47 million and $118 million, respectively. Construction Expenditures of $107 million and $99 million in 2010 and 2009, respectively, were primarily related to project improvements made during the restoration of damage from a 2010 ice storm and for improved generation, transmission and distribution service reliability. During 2010, PSO had a net decrease of $63 million in loans to the Utility Money Pool. During 2009, PSO had a net increase of $19 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows from Financing Activities were $39 million during 2010. PSO had a net increase of $66 million in borrowings from the Utility Money Pool. This inflow was partially offset by $25 million paid in dividends on common stock.

Net Cash Flows Used for Financing Activities were $82 million during 2009. PSO had a net decrease of $70 million in borrowings from the Utility Money Pool. PSO retired $50 million of Senior Unsecured Notes in June 2009 and issued $34 million of Pollution Control Bonds in February 2009. PSO received capital contributions from the Parent of $20 million. In addition, PSO paid $15 million in dividends on common stock.

PSO did not have any long-term debt issuances or retirements during the first six months of 2010.

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end.

REGULATORY ACTIVITY

Oklahoma Regulatory Activity

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider. The requested increase is based on an 11.5% return on common equity. PSO requested that new rates become effective no later than July 2011. A procedural schedule has not been established. See “2010 Oklahoma Base Rate Case” section of Note 3.

SIGNIFICANT FACTORS

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 156. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

134

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

135

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	322,394		$	263,763		$	550,945		$	542,534
Sales to AEP Affiliates		4,481			11,690			13,151			27,513
Other Revenues		811			1,688			1,345			2,381
TOTAL REVENUES		327,686			277,141			565,441			572,428

EXPENSES
Fuel and Other Consumables Used for Electric Generation		88,615			62,753			129,587			182,152
Purchased Electricity for Resale		53,555			46,108			98,535			90,533
Purchased Electricity from AEP Affiliates		10,471			3,416			21,463			9,331
Other Operation		70,837			46,521			120,499			86,066
Maintenance		27,038			27,965			57,977			53,395
Depreciation and Amortization		26,920			28,529			54,208			56,479
Taxes Other Than Income Taxes		10,985			10,958			21,285			21,709
TOTAL EXPENSES		288,421			226,250			503,554			499,665

OPERATING INCOME		39,265			50,891			61,887			72,763

Other Income (Expense):
Interest Income		93			580			275			1,228
Carrying Costs Income		819			1,019			1,686			2,730
Allowance for Equity Funds Used During Construction		119			571			366			741
Interest Expense		(15,765	)		(15,163	)		(33,128	)		(29,968	)

INCOME BEFORE INCOME TAX EXPENSE		24,531			37,898			31,086			47,494

Income Tax Expense		9,042			13,776			11,458			17,334

NET INCOME		15,489			24,122			19,628			30,160

Preferred Stock Dividend Requirements		49			53			103			106

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	15,440		$	24,069		$	19,525		$	30,054

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

136

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	157,230	$	340,016	$	251,704		$	(704	)	$	748,246

Capital Contribution from Parent				20,000								20,000
Common Stock Dividends						(14,500	)					(14,500	)
Preferred Stock Dividends						(106	)					(106	)
Gain on Reacquired Preferred Stock				1								1
Other Change in Common Shareholder's Equity				4,214		(4,214	)					-
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY												753,641

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $117									218			218
NET INCOME						30,160						30,160
TOTAL COMPREHENSIVE INCOME												30,378

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2009	$	157,230	$	364,231	$	263,044		$	(486	)	$	784,019

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	157,230	$	364,231	$	290,880		$	(599	)	$	811,742

Common Stock Dividends						(25,375	)					(25,375	)
Preferred Stock Dividends						(103	)					(103	)
Gain on Reacquired Preferred Stock				76								76
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY												786,340

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $39									72			72
NET INCOME						19,628						19,628
TOTAL COMPREHENSIVE INCOME												19,700

TOTAL COMMON SHAREHOLDER'S
EQUITY – JUNE 30, 2010	$	157,230	$	364,307	$	285,030		$	(527	)	$	806,040

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

137

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)

	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,089		$	796
Advances to Affiliates		-			62,695
Accounts Receivable:
Customers		40,145			38,239
Affiliated Companies		58,673			59,096
Miscellaneous		7,388			7,242
Allowance for Uncollectible Accounts		(144	)		(304	)
Total Accounts Receivable		106,062			104,273
Fuel		22,270			20,892
Materials and Supplies		46,816			44,914
Risk Management Assets		2,608			2,376
Deferred Income Tax Benefits		8,771			26,335
Accrued Tax Benefits		29,754			15,291
Regulatory Asset for Under-Recovered Fuel Costs		48,689			-
Prepayments and Other Current Assets		6,329			9,139
TOTAL CURRENT ASSETS		272,388			286,711

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		1,319,083			1,300,069
Transmission		658,014			617,291
Distribution		1,652,722			1,596,355
Other Property, Plant and Equipment		244,748			228,705
Construction Work in Progress		36,359			67,138
Total Property, Plant and Equipment		3,910,926			3,809,558
Accumulated Depreciation and Amortization		1,237,130			1,220,177
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		2,673,796			2,589,381

OTHER NONCURRENT ASSETS
Regulatory Assets		272,732			279,185
Long-term Risk Management Assets		33			50
Deferred Charges and Other Noncurrent Assets		31,268			13,880
TOTAL OTHER NONCURRENT ASSETS		304,033			293,115

TOTAL ASSETS	$	3,250,217		$	3,169,207

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

138

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2010 and December 31, 2009
(Unaudited)

	2010			2009
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	66,229		$	-
Accounts Payable:
General		89,124			76,895
Affiliated Companies		98,320			71,099
Long-term Debt Due Within One Year – Nonaffiliated		75,000			-
Risk Management Liabilities		387			2,579
Customer Deposits		41,015			42,002
Accrued Taxes		38,171			19,471
Regulatory Liability for Over-Recovered Fuel Costs		-			51,087
Other Current Liabilities		59,620			60,905
TOTAL CURRENT LIABILITIES		467,866			324,038

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		893,851			968,121
Long-term Risk Management Liabilities		112			144
Deferred Income Taxes		610,292			588,768
Regulatory Liabilities and Deferred Investment Tax Credits		317,960			326,931
Employee Benefits and Pension Obligations		105,939			107,748
Deferred Credits and Other Noncurrent Liabilities		43,275			36,457
TOTAL NONCURRENT LIABILITIES		1,971,429			2,028,169

TOTAL LIABILITIES		2,439,295			2,352,207

Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,882			5,258

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares		157,230			157,230
Paid-in Capital		364,307			364,231
Retained Earnings		285,030			290,880
Accumulated Other Comprehensive Income (Loss)		(527	)		(599	)
TOTAL COMMON SHAREHOLDER’S EQUITY		806,040			811,742

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,250,217		$	3,169,207

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

139

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

			2010		2009
OPERATING ACTIVITIES
Net Income			$	19,628	$	30,160
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			54,208		56,479
	Deferred Income Taxes			33,402		(6,130)
	Carrying Costs Income			(1,686)		(2,730)
	Allowance for Equity Funds Used During Construction			(366)		(741)
	Mark-to-Market of Risk Management Contracts			(2,448)		1,053
	Property Taxes			(18,532)		(18,700)
	Fuel Over/Under-Recovery, Net			(99,776)		15,268
	Change in Other Noncurrent Assets			(13,891)		1,885
	Change in Other Noncurrent Liabilities			2,900		(3,290)
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(1,789)		87,923
		Fuel, Materials and Supplies		(3,280)		4,322
		Accounts Payable		37,817		7,980
		Accrued Taxes, Net		4,838		39,800
		Other Current Assets		2,760		115
		Other Current Liabilities		(5,312)		(13,719)
Net Cash Flows from Operating Activities				8,473		199,675

INVESTING ACTIVITIES
Construction Expenditures				(107,213)		(98,559)
Change in Advances to Affiliates, Net				62,695		(19,438)
Other Investing Activities				(2,179)		(304)
Net Cash Flows Used for Investing Activities				(46,697)		(118,301)

FINANCING ACTIVITIES
Capital Contribution from Parent				-		20,000
Issuance of Long-term Debt – Nonaffiliated				-		33,283
Change in Advances from Affiliates, Net				66,229		(70,308)
Retirement of Long-term Debt – Nonaffiliated				-		(50,000)
Retirement of Cumulative Preferred Stock				(301)		(2)
Principal Payments for Capital Lease Obligations				(2,040)		(772)
Dividends Paid on Common Stock				(25,375)		(14,500)
Dividends Paid on Cumulative Preferred Stock				(103)		(106)
Other Financing Activities				107		746
Net Cash Flows from (Used For) Financing Activities				38,517		(81,659)

Net Increase (Decrease) in Cash and Cash Equivalents				293		(285)
Cash and Cash Equivalents at Beginning of Period				796		1,345
Cash and Cash Equivalents at End of Period			$	1,089	$	1,060

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	30,152	$	44,038
Net Cash Paid (Received) for Income Taxes				(8,073)		3,584
Noncash Acquisitions Under Capital Leases				13,434		522
Construction Expenditures Included in Accounts Payable at June 30,				13,534		5,932

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

140

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO. The footnotes begin on page 156.

	Footnote Reference

Significant Accounting Matters	Note 1

New Accounting Pronouncements and Extraordinary Item	Note 2

Rate Matters	Note 3

Commitments, Guarantees and Contingencies	Note 4

Benefit Plans	Note 6

Business Segments	Note 7

Derivatives and Hedging	Note 8

Fair Value Measurements	Note 9

Income Taxes	Note 10

Financing Activities	Note 11

Cost Reduction Initiatives	Note 12

141

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

142

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

RESULTS OF OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Income Before Extraordinary Loss
(in millions)

Second Quarter of 2009		$	36

Changes in Gross Margin:
Retail Margins (a)			25
Transmission Revenues			(1	)
Other Revenues			(7	)
Total Change in Gross Margin			17

Total Expenses and Other:
Other Operation and Maintenance			(28	)
Depreciation and Amortization			6
Interest Expense			(3	)
Equity Earnings of Unconsolidated Subsidiaries			1
Total Expenses and Other			(24	)

Income Tax Expense			(2	)

Second Quarter of 2010		$	27

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $25 million primarily due to:
	·	A $9 million increase in base rates in Arkansas and Texas.
	·	A $6 million increase in weather-related usage primarily due to a 30% increase in cooling degree days.
	·	A $4 million increase in industrial sales due to higher usage reflecting an improvement in demand.
	·	A $4 million increase in fuel recovery primary due to lower capacity costs.
·	Other Revenues decreased $7 million resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC. Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO. SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting. The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

143

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $28 million primarily due to:
	·	A $29 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $5 million increase in other generation operation expenses primarily related to Stall Unit testing for commercial operation. The Stall Unit was placed in service in June 2010.
	These increases were partially offset by:
	·	A $5 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC. The decreased expenses for coal deliveries were partially offset by a corresponding decrease in revenues from mining operations as discussed above.
·	Depreciation and Amortization expenses decreased $6 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders.
·	Interest Expense increased $3 million primarily due to increased long-term debt outstanding and capital leases, partially offset by an increase in the debt component of AFUDC due to the Turk Plant and Stall Unit generation projects.
·	Income Tax Expense increased $2 million primarily due to changes in certain book/tax differences accounted for on a flow-through basis, partially offset by a decrease in pretax book income.

144

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Income Before Extraordinary Loss
(in millions)

Six Months Ended June 30, 2009		$	47

Changes in Gross Margin:
Retail Margins (a)			43
Off-system Sales			1
Transmission Revenues			1
Other Revenues			(18)
Total Change in Gross Margin			27

Total Expenses and Other:
Other Operation and Maintenance			(22)
Depreciation and Amortization			9
Taxes Other Than Income Taxes			(1)
Other Income			10
Interest Expense			(5)
Equity Earnings of Unconsolidated Subsidiaries			1
Total Expenses and Other			(8)

Income Tax Expense			(8)

Six Months Ended June 30, 2010		$	58

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $43 million primarily due to:
	·	A $13 million increase in base rates in Arkansas and Texas.
	·	A $13 million increase in weather-related usage primarily due to a 42% increase in heating degree days.
	·	A $6 million increase in industrial sales due to higher usage reflecting an improvement in demand.
	·	A $5 million increase in fuel recovery primarily due to lower capacity costs.
·	Other Revenues decreased $18 million resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC. Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO. SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting. The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

145

Total Expenses and Other and Income Tax Expense changed between years as follows:

·	Other Operation and Maintenance expenses increased $22 million primarily due to:
	·	A $29 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $3 million increase in employee-related expenses.
	·	A $2 million gain on sale of property during the first quarter of 2009 related to the sale of percentage ownership of Turk Plant to nonaffiliated companies who exercised their participation options.
	These increases were partially offset by:
	·	A $13 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC. The decreased expenses for coal deliveries were partially offset by a corresponding decrease in revenues from mining operations as discussed above.
·	Depreciation and Amortization expenses decreased $9 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders and the deconsolidation of DHLC.
·	Other Income increased $10 million primarily due to an increase in the equity component of AFUDC as a result of construction at the Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of Texas’ retail jurisdiction effective the second quarter of 2009.
·	Interest Expense increased $5 million primarily due to increased long-term debt outstanding and capital leases, partially offset by an increase in the debt component of AFUDC due to the Turk Plant and Stall Unit generation projects.
·	Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

FINANCIAL CONDITION

LIQUIDITY

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 224 for additional discussion of liquidity.

Credit Ratings

In June 2010, Fitch downgraded SWEPCo's senior unsecured rating to BBB. Further downgrades in SWEPCo's ratings by one of the rating agencies could increase SWEPCo's borrowing costs and affect SWEPCo's ability to finance construction costs.

CASH FLOW

Cash flows for the six months ended June 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,661		$	1,910
Net Cash Flows from Operating Activities		80,809			222,403
Net Cash Flows Used for Investing Activities		(371,560	)		(236,343	)
Net Cash Flows from Financing Activities		290,652			13,541
Net Decrease in Cash and Cash Equivalents		(99	)		(399	)
Cash and Cash Equivalents at End of Period	$	1,562		$	1,511

146

Operating Activities

Net Cash Flows from Operating Activities were $81 million in 2010. SWEPCo produced Net Income of $58 million during the period and had a noncash item of $63 million for Depreciation and Amortization, partially offset by $28 million for Allowance for Equity Funds Used During Construction and an $18 million increase in the deferral of Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $32 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to property taxes. & #160;The $25 million outflow from Accounts Receivable, Net was primarily due to increased affiliated and jointly owned receivables partially offset by lower construction related receivables. The $20 million inflow from Fuel, Materials and Supplies was primarily due to a decrease in coal and lignite inventories. The $16 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates in Texas.

Net Cash Flows from Operating Activities were $222 million in 2009. SWEPCo produced Net Income of $42 million during the period and had a noncash item of $72 million for Depreciation and Amortization, partially offset by $30 million for Deferred Income Taxes, a $20 million increase in the deferral of Property Taxes and $19 million for Allowance for Equity Funds Used During Construction. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $88 million inflow from Accounts Receivable, Net was primarily due to the recei pt of payment for SIA from the AEP East companies. The $64 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federal and property taxes. The $54 million outflow from Other Current Liabilities was due to a decrease in checks outstanding, a refund to wholesale customers for the SIA and payments of employee-related expenses. The $23 million inflow from Accounts Payable was primarily due to increases related to customer accounts factored, net. The $44 million inflow from Fuel Over/Under-Recovery, Net was the result of a decrease in fuel costs in relation to the recovery of these costs from customers.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 were $372 million and $236 million, respectively. Construction Expenditures of $176 million and $306 million in 2010 and 2009, respectively, were primarily related to new generation projects at the Turk Plant and Stall Unit. Proceeds from Sales of Assets in 2009 primarily included $104 million relating to the sale of a portion of Turk Plant to joint owners. SWEPCo’s net increase in loans to the Utility Money Pool during 2010 and 2009 were $193 million and $32 million, respectively.

Financing Activities

Net Cash Flows from Financing Activities were $291 million during 2010 related to a $350 million issuance of Senior Unsecured Notes and a $54 million issuance of Pollution Control Bonds. These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated.

Net Cash Flows from Financing Activities were $14 million during 2009. SWEPCo received capital contributions from the Parent of $18 million and paid $5 million in principal payments for capital lease obligations.

147

Long-term debt issuances and retirements during the first six months of 2010 were:

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Senior Unsecured Notes	$	350,000	6.20	2040
	Pollution Control Bonds		53,500	3.25	2015

Retirements
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Notes Payable – Affiliated	$	50,000	4.45	2010
	Pollution Control Bonds		53,500	Variable	2019

SUMMARY OBLIGATION INFORMATION

REGULATORY ACTIVITY

Texas Regulatory Activity

In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%. In addition, the settlement agreement allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years. See “2009 Texas Base Rate Filing” section of Note 3.

SIGNIFICANT FACTORS

REGULATORY ISSUES

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in 2012. SWEPCo owns 73% of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC. Notices of appeal are outstanding at the Arkansas Court of Appeals and the Circuit Court of Hempstead County, Arkansas. Matters are also outstanding at the LPSC, the Texas Court of Appeals and the Federal District Court for the Western Distri ct of Arkansas. See “Turk Plant” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condens ed Financial Statements beginning on page 156. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

148

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

149

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	347,657		$	326,992		$	680,735		$	629,375
Sales to AEP Affiliates		13,231			5,706			22,564			14,050
Lignite Revenues – Nonaffiliated		-			7,518			-			18,238
Other Revenues		579			566			972			921
TOTAL REVENUES		361,467			340,782			704,271			662,584

EXPENSES
Fuel and Other Consumables Used for Electric Generation		135,051			117,135			257,939			243,450
Purchased Electricity for Resale		22,841			30,339			64,727			54,736
Purchased Electricity from AEP Affiliates		4,211			10,520			13,963			23,530
Other Operation		82,265			59,566			140,518			113,770
Maintenance		28,133			23,314			45,552			50,016
Depreciation and Amortization		29,868			35,559			63,111			72,351
Taxes Other Than Income Taxes		15,580			15,479			31,475			30,868
TOTAL EXPENSES		317,949			291,912			617,285			588,721

OPERATING INCOME		43,518			48,870			86,986			73,863

Other Income (Expense):
Interest Income		169			363			248			817
Allowance for Equity Funds Used During Construction		12,462			12,369			27,979			18,774
Interest Expense		(21,475	)		(18,990	)		(40,019	)		(35,289	)

INCOME BEFORE INCOME TAX EXPENSE AND
EQUITY EARNINGS		34,674			42,612			75,194			58,165

Income Tax Expense		8,707			6,834			18,863			10,687
Equity Earnings of Unconsolidated Subsidiaries		738			-			1,457			-

INCOME BEFORE EXTRAORDINARY LOSS		26,705			35,778			57,788			47,478

EXTRAORDINARY LOSS, NET OF TAX		-			(5,325	)		-			(5,325	)

NET INCOME		26,705			30,453			57,788			42,153

Less: Net Income Attributable to Noncontrolling Interest		1,273			812			2,424			1,949

NET INCOME ATTRIBUTABLE TO SWEPCo
SHAREHOLDERS		25,432			29,641			55,364			40,204

Less: Preferred Stock Dividend Requirements		57			57			114			114

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
SHAREHOLDER	$	25,375		$	29,584		$	55,250		$	40,090

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

150

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

	SWEPCo Common Shareholder
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive			Noncontrolling
	Stock		Capital		Earnings			Income (Loss)			Interest			Total

TOTAL EQUITY – DECEMBER 31, 2008	$	135,660	$	530,003	$	615,110		$	(32,120	)	$	276		$	1,248,929

Capital Contribution from Parent				17,500											17,500
Common Stock Dividends – Nonaffiliated												(1,920	)		(1,920	)
Preferred Stock Dividends						(114	)								(114	)
Other Changes in Equity				2,476		(2,476	)								-
SUBTOTAL – EQUITY															1,264,395

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $306									568						568
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $8,583									15,939						15,939
NET INCOME						40,204						1,949			42,153
TOTAL COMPREHENSIVE INCOME															58,660

TOTAL EQUITY – JUNE 30, 2009	$	135,660	$	549,979	$	652,724		$	(15,613	)	$	305		$	1,323,055

TOTAL EQUITY – DECEMBER 31, 2009	$	135,660	$	674,979	$	726,478		$	(12,991	)	$	31		$	1,524,157

Common Stock Dividends – Nonaffiliated												(1,892	)		(1,892	)
Preferred Stock Dividends						(114	)								(114	)
SUBTOTAL – EQUITY															1,522,151

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $48									90						90
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $253									469						469
NET INCOME						55,364						2,424			57,788
TOTAL COMPREHENSIVE INCOME															58,347

TOTAL EQUITY – JUNE 30, 2010	$	135,660	$	674,979	$	781,728		$	(12,432	)	$	563		$	1,580,498

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

151

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)

	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,562		$	1,661
Advances to Affiliates		245,253			34,883
Accounts Receivable:
Customers		26,322			46,657
Affiliated Companies		38,491			19,542
Miscellaneous		26,261			9,952
Allowance for Uncollectible Accounts		(378	)		(64	)
Total Accounts Receivable		90,696			76,087
Fuel
(June 30, 2010 amount includes $32,452 related to Sabine)		96,434			121,453
Materials and Supplies		46,205			54,484
Risk Management Assets		2,197			3,049
Deferred Income Tax Benefits		12,707			13,820
Accrued Tax Benefits		15,141			16,164
Regulatory Asset for Under-Recovered Fuel Costs		13,380			1,639
Prepayments and Other Current Assets		21,904			20,503
TOTAL CURRENT ASSETS		545,479			343,743

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		2,263,438			1,837,318
Transmission		904,424			870,069
Distribution		1,465,137			1,447,559
Other Property, Plant and Equipment
(June 30, 2010 amount includes $226,011 related to Sabine)		637,520			733,310
Construction Work in Progress		895,663			1,176,639
Total Property, Plant and Equipment		6,166,182			6,064,895
Accumulated Depreciation and Amortization
(June 30, 2010 amount includes $88,113 related to Sabine)		2,054,693			2,086,333
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,111,489			3,978,562

OTHER NONCURRENT ASSETS
Regulatory Assets		288,004			268,165
Long-term Risk Management Assets		49			84
Deferred Charges and Other Noncurrent Assets		93,881			49,479
TOTAL OTHER NONCURRENT ASSETS		381,934			317,728

TOTAL ASSETS	$	5,038,902		$	4,640,033

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

152

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2010 and December 31, 2009
(Unaudited)

	2010			2009
	(in thousands)
CURRENT LIABILITIES
Accounts Payable:
General	$	149,872		$	160,870
Affiliated Companies		74,433			59,818
Short-term Debt – Nonaffiliated		8,717			6,890
Long-term Debt Due Within One Year – Nonaffiliated		-			4,406
Long-term Debt Due Within One Year – Affiliated		-			50,000
Risk Management Liabilities		1,011			844
Customer Deposits		43,238			41,269
Accrued Taxes		53,692			24,720
Accrued Interest		39,958			33,179
Obligations Under Capital Leases		12,557			14,617
Regulatory Liability for Over-Recovered Fuel Costs		9,887			13,762
Provision for SIA Refund		22,358			19,307
Other Current Liabilities		56,476			71,781
TOTAL CURRENT LIABILITIES		472,199			501,463

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,769,394			1,419,747
Long-term Risk Management Liabilities		296			221
Deferred Income Taxes		499,528			485,936
Regulatory Liabilities and Deferred Investment Tax Credits		371,511			333,935
Asset Retirement Obligations		49,161			60,562
Employee Benefits and Pension Obligations		121,001			125,956
Obligations Under Capital Leases		116,887			134,044
Deferred Credits and Other Noncurrent Liabilities		53,730			49,315
TOTAL NONCURRENT LIABILITIES		2,981,508			2,609,716

TOTAL LIABILITIES		3,453,707			3,111,179

Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,697			4,697

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 7,600,000 Shares
Outstanding – 7,536,640 Shares		135,660			135,660
Paid-in Capital		674,979			674,979
Retained Earnings		781,728			726,478
Accumulated Other Comprehensive Income (Loss)		(12,432	)		(12,991	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,579,935			1,524,126

Noncontrolling Interest		563			31

TOTAL EQUITY		1,580,498			1,524,157

TOTAL LIABILITIES AND EQUITY	$	5,038,902		$	4,640,033

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

153

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010 and 2009
(in thousands)
(Unaudited)

			2010		2009
OPERATING ACTIVITIES
Net Income			$	57,788	$	42,153
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			63,111		72,351
	Deferred Income Taxes			(5,742)		(29,774)
	Extraordinary Loss, Net of Tax			-		5,325
	Allowance for Equity Funds Used During Construction			(27,979)		(18,774)
	Mark-to-Market of Risk Management Contracts			715		279
	Property Taxes			(18,105)		(19,862)
	Fuel Over/Under-Recovery, Net			(15,619)		44,125
	Change in Other Noncurrent Assets			(11,364)		5,731
	Change in Other Noncurrent Liabilities			17,928		2,222
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(24,733)		88,457
		Fuel, Materials and Supplies		20,096		(4,293)
		Accounts Payable		(10,505)		22,698
		Accrued Taxes, Net		32,339		64,066
		Other Current Assets		(825)		1,902
		Other Current Liabilities		3,704		(54,203)
Net Cash Flows from Operating Activities				80,809		222,403

INVESTING ACTIVITIES
Construction Expenditures				(176,107)		(305,886)
Change in Advances to Affiliates, Net				(193,437)		(31,999)
Proceeds from Sales of Assets				962		105,453
Other Investing Activities				(2,978)		(3,911)
Net Cash Flows Used for Investing Activities				(371,560)		(236,343)

FINANCING ACTIVITIES
Capital Contribution from Parent				-		17,500
Issuance of Long-term Debt – Nonaffiliated				399,411		(15)
Borrowings from Revolving Credit Facilities				50,339		58,440
Change in Advances from Affiliates, Net				-		(2,526)
Retirement of Long-term Debt – Nonaffiliated				(53,500)		(2,203)
Retirement of Long-term Debt – Affiliated				(50,000)		-
Repayments to Revolving Credit Facilities				(48,512)		(50,740)
Principal Payments for Capital Lease Obligations				(5,944)		(5,266)
Dividends Paid on Common Stock – Nonaffiliated				(1,892)		(1,645)
Dividends Paid on Cumulative Preferred Stock				(114)		(114)
Other Financing Activities				864		110
Net Cash Flows from Financing Activities				290,652		13,541

Net Decrease in Cash and Cash Equivalents				(99)		(399)
Cash and Cash Equivalents at Beginning of Period				1,661		1,910
Cash and Cash Equivalents at End of Period			$	1,562	$	1,511

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	29,649	$	50,711
Net Cash Paid for Income Taxes				19,663		3,816
Noncash Acquisitions Under Capital Leases				380		1,751
Construction Expenditures Included in Accounts Payable at June 30,				85,870		86,920

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 156.

154

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo. The footnotes begin on page 156.

	Footnote Reference

Significant Accounting Matters	Note 1

New Accounting Pronouncements and Extraordinary Item	Note 2

Rate Matters	Note 3

Commitments, Guarantees and Contingencies	Note 4

Acquisition	Note 5

Benefit Plans	Note 6

Business Segments	Note 7

Derivatives and Hedging	Note 8

Fair Value Measurements	Note 9

Income Taxes	Note 10

Financing Activities	Note 11

Cost Reduction Initiatives	Note 12

155

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:

1.	Significant Accounting Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

2.	New Accounting Pronouncements and Extraordinary Item	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

3.	Rate Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

4.	Commitments, Guarantees and Contingencies	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

5.	Acquisition	SWEPCo

6.	Benefit Plans	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

7.	Business Segments	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

8.	Derivatives and Hedging	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

9.	Fair Value Measurements	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

10.	Income Taxes	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

11.	Financing Activities	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

12.

Cost Reduction Initiatives

APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

156

1.	SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and six months ended June 30, 2010 is not necessarily indicative of results that may be expected for the year ending December 31, 2010. The condensed financial statements are unaudited and should be read in conjunction with the audited 2009 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2009 as filed with the SEC on February 26, 2010.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE as defined by the accounting guidance for “Variable Interest Entities.” In determining whether t hey are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, power to direct the VIE and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

SWEPCo is the primary beneficiary of Sabine. As of January 1, 2010, SWEPCo is no longer the primary beneficiary of DHLC as defined by new accounting guidance for “Variable Interest Entities.” I&M is the primary beneficiary of DCC Fuel LLC (DCC Fuel) and DCC Fuel II LLC (DCC Fuel II). APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC. I&M and CSPCo each hold a significant variable interest in AEGCo. SWEPCo holds a significant variable interest in DHLC.

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined for each year. Based on these facts, management concluded that SWEPCo is the primary beneficia ry and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended June 30, 2010 and 2009 were $30 million and $25 million, respectively, and for the six months ended June 30, 2010 and 2009 were $73 million and $61 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.

DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and its voting rights equally. Each entity guarantees a 50% share of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. Based on the shared control of DHLC’s operations, management concluded as of January 1 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.

157

SWEPCo’s total billings from DHLC for the three months ended June 30, 2010 and 2009 were $13 million and $8 million, respectively, and for the six months ended June 30, 2010 and 2009 were $26 million and $18 million, respectively. See the tables below for the classification of DHLC’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheet at December 31, 2009 as well as SWEPCo’s investment and maximum exposure as of June 30, 2010. As of June 30, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Condensed Consolidated Balance Sheet. Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2010
(in millions)
	Sabine
ASSETS
Current Assets	$	48
Net Property, Plant and Equipment		144
Other Noncurrent Assets		34
Total Assets	$	226

LIABILITIES AND EQUITY
Current Liabilities	$	31
Noncurrent Liabilities		194
Equity		1
Total Liabilities and Equity	$	226

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
	Sabine		DHLC
ASSETS
Current Assets	$	51	$	8
Net Property, Plant and Equipment		149		44
Other Noncurrent Assets		35		11
Total Assets	$	235	$	63

LIABILITIES AND EQUITY
Current Liabilities	$	36	$	17
Noncurrent Liabilities		199		38
Equity		-		8
Total Liabilities and Equity	$	235	$	63

SWEPCo’s investment in DHLC was:

	June 30, 2010
	As Reported on
	the Consolidated			Maximum
	Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	7		$	7
Retained Earnings			1			1
SWEPCo's Guarantee of Debt			-			48

Total Investment in DHLC		$	8		$	56

158

In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel LLC. In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel II LLC. DCC Fuel LLC and DCC Fuel II LLC (collectively DCC) were formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Payments on the leases are made semi-annually and began in April 2010. Payment on the leases for the three months ended June 30, 2010 and for the six months ended June 30, 2010 was $22 million. No pay ments were made to DCC in 2009. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48 and 54 month lease term, respectively. Based on I&M’s control of DCC, management concluded that I&M is the primary beneficiary and is required to consolidate DCC. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC’s assets and liabilities on I&M’s Condensed Consolidated Balance Sheets.

The balances below represent the assets and liabilities of the VIE that are consolidated. These balances include intercompany transactions that would be eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2010
(in millions)
	DCC
ASSETS
Current Assets	$	76
Net Property, Plant and Equipment		141
Other Noncurrent Assets		93
Total Assets	$	310

LIABILITIES AND EQUITY
Current Liabilities	$	63
Noncurrent Liabilities		247
Equity		-
Total Liabilities and Equity	$	310

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
	DCC
ASSETS
Current Assets	$	47
Net Property, Plant and Equipment		89
Other Noncurrent Assets		57
Total Assets	$	193

LIABILITIES AND EQUITY
Current Liabilities	$	39
Noncurrent Liabilities		154
Equity		-
Total Liabilities and Equity	$	193

AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. No AEP subsidiary has provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billi ngs are subject to regulation by the FERC. AEP’s subsidiaries are exposed to losses to the extent they cannot recover the costs of

159

AEPSC through their normal business operations. All Registrant Subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, no Registrant Subsidiary has control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
Company	2010			2009			2010			2009
	(in millions)
APCo		$	67		$	46		$	126		$	97
CSPCo			39			31			74			60
I&M			41			32			75			61
OPCo			63			46			112			87
PSO			31			21			55			43
SWEPCo			44			31			79			60

The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

	June 30, 2010						December 31, 2009
	As Reported in the			Maximum			As Reported in the			Maximum
Company	Balance Sheet			Exposure			Balance Sheet			Exposure
	(in millions)
APCo		$	36		$	36		$	23		$	23
CSPCo			21			21			13			13
I&M			21			21			13			13
OPCo			32			32			18			18
PSO			17			17			9			9
SWEPCo			23			23			14			14

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo leases the Lawrenceburg Generating Station to CSPCo. AEP guarantees all the debt obligations of AEGCo. I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financ ing would be provided by AEP. For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 13 in the 2009 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
Company	2010			2009			2010			2009
	(in millions)
CSPCo		$	22		$	15		$	37		$	32
I&M			49			60			105			123

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:

	June 30, 2010						December 31, 2009
	As Reported in						As Reported in
	the Consolidated			Maximum			the Consolidated			Maximum
Company	Balance Sheet			Exposure			Balance Sheet			Exposure
	(in millions)
CSPCo		$	10		$	10		$	6		$	6
I&M			21			21			23			23

160

Related Party Transactions

SWEPCo Lignite Purchases from DHLC

Effective January 1, 2010, SWEPCo deconsolidated DHLC due to the adoption of new accounting guidance. See “ASU 2009-17 ‘Consolidations’ ” section of Note 2. DHLC sells 50% of its lignite mining output to SWEPCo and the other 50% to CLECO. SWEPCo purchased $26 million of lignite from DHLC and recorded these costs in Fuel on its Condensed Consolidated Balance Sheet at June 30, 2010.

AEP Power Pool Purchases from OVEC

In January 2010, the AEP Power Pool began purchasing power from OVEC to serve off-system sales and retail sales through June 2010. Purchases serving off-system sales are reported net as a reduction in Electric Generation, Transmission and Distribution revenues and purchases serving retail sales are reported in Purchased Electricity for Resale expenses on the respective income statements. The following table shows the amounts recorded for the three and six months ended June 30, 2010:

	Three Months Ended June 30, 2010						Six Months Ended June 30, 2010
	Reported in			Reported in			Reported in			Reported in
Company	Revenues			Expenses			Revenues			Expenses
	(in thousands)
APCo		$	3,736		$	1,441		$	6,631		$	3,635
CSPCo			2,113			815			3,689			1,963
I&M			2,131			822			3,721			1,980
OPCo			2,432			938			4,248			2,268

SWEPCo Revised Depreciation Rates

Effective December 2009 and May 2010, SWEPCo revised book depreciation rates for its Arkansas and Texas jurisdictions, respectively, as a result of base rate orders. In comparing 2010 and 2009, the change in depreciation rates resulted in a net decrease in depreciation expense of:

Total Depreciation Expense Variance
Three Months Ended		Six Months Ended
June 30, 2010/2009		June 30, 2010/2009
(in thousands)
$	7,132	$	10,433

Adjustments to Reported Cash Flows

In the Financing Activities section of SWEPCo’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009, SWEPCo corrected the presentation of borrowings on lines of credit of $58 million from Change in Short-term Debt, Net – Nonaffiliated to Borrowings from Revolving Credit Facilities. SWEPCo also corrected the presentation of repayments on lines of credit of $51 million for the six months ended June 30, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net – Nonaffiliated. The correction to present borrowings and repayments on lines of credit on a gross basis was not material to SWEPCo’s financial statements and had no impact on SWEPCo’s previously reported net income, change s in shareholder’s equity, financial position or net cash flows from financing activities.

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Adjustments to Sale of Receivables Disclosure

In the “Sale of Receivables – AEP Credit” section of Note 11, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the sale of receivables that were not previously disclosed. These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.

Adjustments to Benefit Plans Footnote

In Note 6 – Benefit Plans, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the Net Periodic Benefit Cost and the Estimated Future Benefit Payments and Contributions that were not previously disclosed. These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.

2.	NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following represents a summary of final pronouncements that impact the financial statements.

Pronouncements Adopted During 2010

The following standard was effective during the first six months of 2010. Consequently, its impact is reflected in the financial statements. The following paragraphs discuss its impact.

ASU 2009-17 “Consolidations” (ASU 2009-17)

In 2009, the FASB issued ASU 2009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a VIE. In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:

·	The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance.

·	The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

The Registrant Subsidiaries adopted the prospective provisions of ASU 2009-17 effective January 1, 2010. This standard required separate presentation of material consolidated VIEs’ assets and liabilities on the balance sheets. Upon adoption, SWEPCo deconsolidated DHLC. DHLC was deconsolidated due to the shared control between SWEPCo and CLECO. After January 1, 2010, SWEPCo reports DHLC using the equity method of accounting.

EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011. In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes. Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009. Management believes that a switch to competition in the SPP area of Texas will not occur. The reapplication of “Regulated Op erations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.

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3.	RATE MATTERS

As discussed in the 2009 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2009 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2010 and updates the 2009 Annual Report.

Regulatory Assets Not Yet Being Recovered
			APCo					I&M
			June 30,			December 31,		June 30,			December 31,
			2010			2009		2010			2009
	Noncurrent Regulatory Assets (excluding fuel)		(in thousands)					(in thousands)
	Regulatory assets not yet being recovered pending
		future proceedings to determine the recovery
		method and timing:
	Regulatory Assets Currently Not Earning a Return
		Mountaineer Carbon Capture and Storage Project	$	58,085		$	110,665	$	-		$	-
		Virginia Environmental Rate Adjustment Clause		43,273			25,311		-			-
		Virginia Transmission Rate Adjustment Clause		21,088			26,184		-			-
		Special Rate Mechanism for Century Aluminum		12,524			12,422		-			-
		Deferred Wind Power Costs		11,523			5,372		-			-
		Storm Related Costs		25,437			-		-			-
		Deferred PJM Fees		-			-		6,880			6,254
	Total Regulatory Assets Not Yet Being Recovered		$	171,930		$	179,954	$	6,880		$	6,254

			CSPCo					OPCo
			June 30,			December 31,		June 30,			December 31,
			2010			2009		2010			2009
	Noncurrent Regulatory Assets (excluding fuel)		(in thousands)					(in thousands)
	Regulatory assets not yet being recovered pending
		future proceedings to determine the recovery
		method and timing:
	Regulatory Assets Currently Earning a Return
		Customer Choice Deferrals	$	29,197		$	28,781	$	28,666		$	28,330
		Line Extension Carrying Costs		30,121			26,590		18,741			16,278
		Storm Related Costs		18,634			17,014		10,742			9,794
		Acquisition of Monongahela Power		11,108			10,282		-			-
	Regulatory Assets Currently Not Earning a Return
		Peak Demand Reduction/Energy Efficiency		-	(a)		4,071		-	(a)		4,007
	Total Regulatory Assets Not Yet Being Recovered		$	89,060		$	86,738	$	58,149		$	58,409

			PSO					SWEPCo
			June 30,			December 31,		June 30,			December 31,
			2010			2009		2010			2009
	Noncurrent Regulatory Assets (excluding fuel)		(in thousands)					(in thousands)
	Regulatory assets not yet being recovered pending
		future proceedings to determine the recovery
		method and timing:
	Regulatory Assets Currently Not Earning a Return
		Storm Related Costs	$	15,755		$	-	$	-		$	-
		Asset Retirement Obligation		-			-		558			471
	Total Regulatory Assets Not Yet Being Recovered		$	15,755		$	-	$	558		$	471

	(a) Recovery of regulatory asset was granted during 2010.

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CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle. The ESPs are in effect through 2011. The order also limits annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected 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 avoid having the resultant rate increases exceed the ordered annual caps described above. The FAC increase is subject to quarterly true-ups, annual accounting audits and prudency reviews. See the “2009 Fuel Adjustment Clause Audit” section below. The order allows CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital. Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. Management expects to recover the CSPCo FAC deferral during 2010. That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges. See the “Ormet Interim Arrangement” section below. The FAC deferrals as of June 30, 2010 were $5 million and $388 million for CSPCo and OPCo, respectively, excluding $1 million and $18 million, respectively, of unrecognized equity carrying costs.

Discussed below are the outstanding uncertainties related to the ESP order:

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins. A decision from the Supreme Court of Ohio is pending.

In November 2009, the Industrial Energy Users-Ohio group filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline. A decision from the Supreme Court of Ohio is pending.

In April 2010, the Industrial Energy Users-Ohio group filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. A decision from the Supreme Court of Ohio is pending.

In 2009, the PUCO convened a workshop to determine the methodology for the Significantly Excessive Earnings Test (SEET). Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings. If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers. The PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals. Management believes that CSPCo and OPCo should not be required to refund unrecovered FAC regulatory assets until they are collected, even assuming there are significantly excessive earnings in that year. In June 2010, the PUCO issued an order resolving some of the SEET issues. The PUCO determined that the earnings of CSPCo and OPCo sh all be calculated on an individual company basis and not on a combined CSPCo/OPCo basis. The PUCO ruled that many issues including the treatment of deferrals and off-system sales should be determined on a case-by-case basis. The PUCO’s decision on the SEET methodology is not expected to be finalized until after the SEET filings are made by CSPCo and OPCo related to 2009 earnings and the PUCO issues an order thereon. CSPCo and OPCo will file their significantly excessive earnings tests with the PUCO by their September 2010 deadlines. CSPCo and OPCo are unable to determine whether they will be required to return any of their ESP revenues to customers.

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Management is unable to predict the outcome of the various ongoing ESP proceedings and litigation discussed above. If these proceedings result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for the period of January 2009 through December 2009. In May 2010, the outside consultant provided their confidential audit report of the FAC audit to the PUCO. The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million will reduce fuel expense in 2009 and 2010. If the PUCO orders any portion of the $58 million previously recognized gains be used to reduce the current year FAC deferral, it would reduce futur e net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filings. The approval of the FAC, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges but excluding $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the ESP proceeding. The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement. If CSPCo and OPCo are not ultimately permi tted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The Industrial Energy Users-Ohio raised several issues including claims that (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.

In June 2010, Industrial Energy Users-Ohio filed a notice of appeal of the 2010 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The Industrial Energy Users-Ohio raised the same issues as noted in the 2009 EDR appeal plus a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP Orders.

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As of June 30, 2010, CSPCo and OPCo have incurred $32 million and $23 million, respectively, in EDR costs including carrying costs. Of these costs, CSPCo and OPCo have collected $16 million and $12 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010. The remaining $16 million and $11 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets. If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs for 2009 through 2011 related to environmental investments made in 2009. CSPCo’s and OPCo’s proposed initial rider would recover 2009 carrying costs of $29 million and $37 million, respectively, through December 2011. In July 2010, CSPCo and OPCo filed an updated position to its application which reduced its original rider application amount to recover $27 million and $35 million, respectively, through December 2011. If approved, the implementation of the rider will likely not impact cash flows, but will increase the ESP phase-in plan deferrals associated with the FAC since this rider is subject to the rate increase caps authorized by the PUCO in the ESP proceedings.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through June 30, 2010, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each incurred $11 million in pre-construction costs. As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million. The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, all pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. Intervenors have filed motions with the PUCO requesting all pre-construction costs be r efunded to Ohio ratepayers with interest.

CSPCo and OPCo will not start construction of an IGCC plant until existing statutory barriers are addressed and sufficient assurance of regulatory cost recovery exists. Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo were required to refund all or some of the pre-construction costs collected and the costs incurred were not recoverable in another jurisdiction, it would reduce future net income and cash flows and impact financial condition.

Ohio Energy Efficiency & Demand Response Program Rider

In November 2009, CSPCo and OPCo filed an application with the PUCO to implement energy efficiency and demand response programs as part of Senate Bill 221, which requires investor-owned utilities to create programs to help customers conserve and reduce demand for electricity. Simultaneous with the filing, a stipulation agreement was filed with the PUCO agreeing to terms consistent with the filed application. In May 2010, the PUCO issued an order adopting the stipulation, with minor modification, and authorized CSPCo and OPCo to implement a new rider rate effective with the first billing cycle in June 2010. The rider rates are estimated to increase CSPCo's and OPCo's revenues by $81 million and $86 million, respectively, over the period from June 2010 through December 2011. CSPCo's and OPCo's revenue increases include $79 million and $83 million, respectively, for program costs and $2 million and $3 million, respectively, for net lost distribution revenues and shared savings.

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SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC. As of June 30, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $855 million of expenditures (including AFUDC and capitalized interest of $106 million and related transmission costs of $46 million).&# 160; As of June 30, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $425 million (including related transmission costs of $7 million). SWEPCo’s share of the contractual construction commitments is $312 million. If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of June 30, 2010, of approximately $121 million (including related transmission cancellation fees of $1 million). SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

Discussed below are the outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas share of the Turk Plant. Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN. However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding. In June 2010, the Arkansas Supreme Court denied motions for rehearing filed b y the APSC and SWEPCo. Therefore, SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88MW portion of Turk Plant costs in Arkansas retail rates. In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.

In July 2010, the Hempstead County Hunting Club filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking an injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.

The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers fi led an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant was unnecessary to serve retail customers. In February 2010, the Texas District Court affirmed the PUCT’s order in all respects. In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.

The LPSC approved SWEPCo’s application to construct the Turk Plant. The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC in November 2009. In December 2009, the Sierra Club refiled its petition as a stand alone complaint proceeding. In February 2010, SWEPCo filed a motion to dismiss and denied the allegations in the complaint.

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In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit. In February 2010, the parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas.

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. In May 2010, parties filed with the Federal District Court for the Western District of Arkansas for a preliminary injunction to halt construction and for a temporary restraining order.

In January 2009, SWEPCO was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant. Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals. In July 2010, the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines. In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC. As a result, a stay was not ordered and construction continues on the affected transmission lines.

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 SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

Stall Unit

SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana. The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs. The Stall Unit was placed in service in June 2010. As of June 30, 2010, the Stall Unit cost $422 million, including $49 million of AFUDC. Management does not expect the final costs of the Stall Unit to exceed the ordered cap.

Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC. The audit report included a significant recommendation that might result in a financial impact that could be material for SWEPCo. The audit report recommended that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to off-system sales margins on a prospective basis. In addition, the audit report contained a recommendation that SWEPCo should reflect the SIA refunds as reductions in the Louisiana FAC rates as soon as possible, including interest through the date the refunds are reflected in the FAC. See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.” Management is unable to predict how the LPSC will rule on the recommendatio ns in the audit report and its financial statement impact on net income, cash flows and financial condition.

2009 Texas Base Rate Filing

In August 2009, SWEPCo filed a rate case with the PUCT to increase its base rates by approximately $75 million annually including a return on equity of 11.5%. The filing included requests for financing cost riders of $32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $27 million. In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%, which consists of $5 million related to construction of the Stall Unit and $10 million in other increases. In addition, the settlement agreement will decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million on e-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.

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Texas Fuel Reconciliation

In May 2010, various intervenors, including the PUCT staff, filed testimony recommending disallowances ranging from $3 million to $30 million in SWEPCo’s $755 million fuel and purchase power costs reconciliation for the period January 2006 through March 2009. In July 2010, Cities Advocating Reasonable Deregulation filed testimony regarding the 2007 transfer of ERCOT trading contracts to AEP Energy Partners. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions. Management is unable to predict the outcome of this reconciliation. If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.

Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year formula rate plan (FRP). SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%. In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund. During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors. A settlement stipulation was reached by the parties and is pending LPSC approval.

Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009. SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund. In October 2009, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation. The consultants also recommended reflecting the SIA refunds through SWEPCo’s FRP. See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.” SWEPCo is currently in settlement discussions. If a refund is required, it could reduce future net income and cash flows and impact financial condition.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund. SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC. If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows and impact financial condition.

APCo Rate Matters

2009 Virginia Base Rate Case

In July 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity. Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when newly enacted Virginia legislation suspended the collection of interim rates. In July 2010, the Virginia SCC issued an order approving a $62 million increase based on a 10.53% return on equity. The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project, which resulted in a pretax write-off of $54 million in the second quarter of 2010. See “Mountaineer Carbon Capture and Storage Project” section below. In addition, the order allowed the deferral in the secon d quarter of 2010 of approximately $25 million of incremental storm expense incurred in 2009. In July 2010, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project.

2010 West Virginia Base Rate Case

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Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In October 2009, APCo started injecting CO2 into the underground storage facilities. The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset. Through June 30, 2010, APCo has recorded a noncurrent regulatory asset of $ 58 million consisting of $38 million in project costs and $20 million in asset retirement costs.

In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project costs, which resulted in a write-off of approximately $54 million in the second quarter of 2010. In response to the order, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project. See “2009 Virginia Base Rate Case” section above.

In APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its estimated increased West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion. If APCo cannot recover its remaining investment in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition.

APCo’s Filings for an IGCC Plant

APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia. APCo also requested the Virginia SCC and the WVPSC to approve a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. The WVPSC granted APCo the CPCN and approved the requested cost recovery. Various intervenors filed petitions with the WVPSC to reconsider the order.

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon its finding that the estimated cost of the plant was uncertain and may escalate. The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities. During 2009, based on an unfavorable order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.

Through June 30, 2010, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and in West Virginia. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs which, if not recoverable, would reduce future net income and cash flows and impact financial condition.

APCo’s 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request. The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009. The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million. As of June 30, 2010, APCo’s ENEC under-recovery balance was $358 million, including carrying costs, which is included in noncurrent regulatory assets.

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In June 2010, a settlement agreement for $86 million, including $9 million of construction surcharges, was filed with the WVPSC related to APCo’s second year ENEC increase. The settlement agreement provided for recovery of the amounts related to the renegotiated coal contracts and allows APCo to accrue weighted average cost of capital carrying costs on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. In June 2010, the WVPSC approved the settlement agreement which made rates effective in July 2010.

WPCo Merger with APCo

PSO Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

The OCC filed a complaint with the FERC related to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement. The FERC issued an adverse ruling in 2008. As a result, PSO recorded a regulatory liability in 2008 to return reallocated OSS to customers. Starting in March 2009, PSO refunded the additional reallocated OSS to its customers through February 2010.

A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $42 million of PSO fuel costs. PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008. The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval. As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause. The OCC has heard the OIEC appeal and a decision is pending. In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins proceeding and PSO has refunded the additional margins to its retail customers. If the OCC were to order PSO to refund all or a part of the $42 million, it would reduce future net income and cash flows and impact financial condition.

2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs. In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%. The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEP Energy Partners was filed. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions. If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on equity. The new rates reflecting the final order were implemented with the first billing cycle of February 2009. PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues. The Oklahoma Supreme Court assigned the case to the Court of Civil Appeals. In June 2010, the Court of Civil Appeals affirmed the OCC's decision. No parties sought rehearing or appeal. As a result, this case has concluded.

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2010 Oklahoma Base Rate Case

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider. The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity. PSO requested that new rates become effective no later than July 2011. A procedural schedule has not been established.

I&M Rate Matters

Indiana Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown)

I&M filed applications with the IURC to increase its fuel adjustment charge by approximately $53 million for the period of April 2009 through September 2009. The filings sought increases for previously under-recovered fuel clause expenses.

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator. Unit 1 was placed back into service in December 2009 at slightly reduced power. The unit outage resulted in increased replacement power fuel costs. The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds. I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.

I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed. Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds. Hearings are scheduled to be held in December 2010.

Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs. If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.

Michigan 2009 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds. Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs. If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition. See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Michigan Base Rate Filing

In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity. In the August 2010 billing cycle, I&M, with the MPSC authorization, will implement a $44 million interim rate increase, subject to refund with interest. The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses. In July 2010, the MPSC staff filed testimony which recommended a $34 million annual increase in base rates based on a 10.35% return on common equity plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period. The MPSC must issue a final order within one year of the original filing.

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FERC Rate Matters

Regional Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and OPCo

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006. Intervenors objected to the temporary SECA rates. The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million from 2004 through 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the shortfall in revenues. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recogniz ed gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
CSPCo		38.8
I&M		41.3
OPCo		53.3

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates should not have been recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made. The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supports AEP’s position and requires a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC regarding certain matters including a request to clarify the method for determining the amount of such revenues. The rehearing also requested the FERC to clarify that interest may be added to SECA charges originally billed to but never paid by Green Mountain Energy (reassigned to British Petroleum Energy). Eight other groups also filed requests for rehearing with the FERC.

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
CSPCo		7.8
I&M		8.3
OPCo		10.7

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue. The balance in the reserve for future settlements as of June 30, 2010 was $34 million. APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances at June 30, 2010 were:

Company	June 30, 2010
	(in millions)
APCo	$	10.7
CSPCo		5.9
I&M		6.3
OPCo		8.2

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Based on the AEP East companies’ analysis of the May 2010 order, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order be made final as issued by the FERC. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Allocation of Off-system Sales Margins – Affecting SWEPCo

The OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies.

In 2009, AEP made a compliance filing with the FERC and the AEP East companies refunded approximately $250 million to the AEP West companies. Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006. In 2008, the AEP West companies recorded a provision for refund reflecting the sharing. Refunds have been or are currently being returned to PSO’s and SWEPCo’s Texas, Arkansas and FERC customers. SWEPCo is working with the LPSC to determine how the FERC ordered refund will be made to its Louisiana retail customers. Consultants for the LPSC issued an audit report of SWEPCo’s Louisiana retail fuel adjustment clause, in which they recommended that SWEPCo refund the amo unts, including interest, through the fuel adjustment clause. See “Louisiana Fuel Adjustment Clause Audit” section within “SWEPCo Rate Matters.” Other consultants for the LPSC recommended refunding the amounts through SWEPCo’s formula rate plan. Management believes the AEP West companies’ provision for refund is adequate.

Modification of the Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations containing extra-high voltage facilities. In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA. Under the proposed amendments, KGPCo and WPCo will be added as parties to the TA. In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the MLR method used in the present TA. AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order. The delayed effective date was approved by the FERC when the FERC accepted the new TA for filing. Settlement discussions are in progress. Management is unable to predict whether the parties to the TA will experience regulatory lag and its effect on future net income and cash flows due to timing of the implementation of the modified TA by various state regulators.

PJM Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and OPCo

AEP filed an application with the FERC in July 2008 to increase its open access transmission tariff (OATT) rates for wholesale transmission service within PJM. The filing sought to implement a formula rate allowing annual adjustments reflecting future changes in the AEP East companies' cost of service. The FERC issued an order conditionally accepting AEP’s proposed formula rate and delayed the requested October 2008 effective date for five months. AEP began settlement discussions with the intervenors and the FERC staff which resulted in a settlement that was filed with the FERC in April 2010.

The pending settlement results in a $51 million annual increase beginning in April 2009 for service as of March 2009, of which approximately $7 million is being collected from nonaffiliated customers within PJM. The remaining $44 million is being billed to the AEP East companies and is generally offset by compensation from PJM for use of the AEP East companies’ transmission facilities so that net income is not directly affected.

The pending settlement also results in an additional $30 million increase for the first annual update of the formula rate, beginning in August 2009 for service as of July 2009. Approximately $4 million of the increase will be collected from nonaffiliated customers within PJM with the remaining $26 million being billed to the AEP East companies.

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Under the formula, an annual update will be filed to be effective July 2010 and each year thereafter. Also, beginning with the July 2010 update, the rates each year will include an adjustment to true-up the prior year's collections to the actual costs for the prior year. In May 2010, the second annual update was filed with the FERC to decrease the revenue requirement by $58 million for service as of July 2010. Approximately $8 million of the decrease will be refunded to nonaffiliated customers within PJM. Management expects the settlement will be approved by the FERC.

Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

Certain transmission facilities placed in service in 1998 were inadvertently excluded from the AEP East companies’ TA calculation prior to January 2009. The excluded equipment was KPCo’s Inez Station which had been determined as eligible equipment for inclusion in the TA in 1995 by the AEP TA transmission committee. The amount involved was $7 million annually. In June 2010, the KPSC approved a settlement agreement in KPCo’s base rate filing which set new base rates effective July 2010 and excluded consideration of this issue.

PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates. These flows affected the settlement data for congestion revenues and expenses and date back to the start of the MISO market in 2005. PJM has provided MISO an initial analysis of amounts they believe they owe MISO. MISO disputes PJM’s methodology.

Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM at the FERC related to the above claim. MISO seeks to recover a total of approximately $145 million from PJM. If PJM is held liable for these damages, PJM members, including the AEP East companies, may be billed for a share of the refunds or payments PJM is directed to make to MISO. AEP has intervened and filed a protest to one complaint. Management believes that MISO's claims are without merit and that PJM's right to recover any MISO damages from AEP and other members is limited. If the FERC orders a settlement above the AEP East companies’ reserve related to their estimated portion of PJM additional costs, it could reduce future n et income and cash flows and impact financial condition.

4.	COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2009 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit cover items such as insurance programs, security deposits and debt service reserves. These letters of credit were issued in the ordinary course of business under the two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit. In June 2010, AEP canceled a facility that was scheduled to mature in March 2011 and entered into a new $1.5 billion credit facility scheduled to mature in 2013 that allows for the issuance of up to $600 million as letters of credit.

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In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced the $627 million credit agreement to $478 million. As of June 30, 2010, $477 million of letters of credit were issued by Registrant Subsidiaries under the agreement to support variable rate Pollution Control Bonds.

At June 30, 2010, the maximum future payments of the letters of credit were as follows:

				Borrower
Company	Amount		Maturity	Sublimit
	(in thousands)			(in thousands)
$1.5 billion letters of credit:
I&M	$	300	March 2011		N/A
SWEPCo		4,448	December 2010		N/A

$478 million letter of credit:
APCo	$	232,292	November 2010 to April 2011	$	300,000
I&M		77,886	April 2011		230,000
OPCo		166,899	April 2011		400,000

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. As of June 30, 2010, SWEPCo has collected approximately $46 million through a rider for final mine closure and reclamation cost s, of which $2 million is recorded in Other Current Liabilities, $22 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $22 million is recorded in Asset Retirement Obligations on SWEPCo’s Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.

Indemnifications and Other Guarantees – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Prior to June 30, 2010, the Registrant Subsidiaries entered into sale agreements including indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary. There are no material liabilities recorded for any indemnifications.

The AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

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Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements. GE Capital Commercial Inc. (GE) notified management in November 2008 that they elected to terminate the Master Leasing Agreements in accordance with the termination rights specified within the contract. In 2011, the Registrant Subsidiaries will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased. In December 2008 and 2009, management signed new master lease agreements that include lease terms of up to 10 years.

For equipment under the GE master lease agreements that expire in 2011, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. Under the new master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subs idiaries are committed to pay the difference between the actual fair value and the residual value guarantee. At June 30, 2010, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:

	Maximum
	Potential
Company	Loss
	(in thousands)
APCo		$	236
CSPCo			57
I&M			153
OPCo			306
PSO			329
SWEPCo			272

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $18 million for I&M and $20 million for SWEPCo for the remaining railcars as of June 30, 2010.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20 year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

The Registrant Subsidiaries have other railcar lease arrangements that do not utilize this type of financing structure.

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ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation – Affecting CSPCo

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA. Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units. The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit. The defendants and the plaintiffs appealed to the Seventh Circuit Co urt of Appeals. Beckjord is operated by Duke Energy Ohio, Inc. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo

The Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in a previous state permit. The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper. In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations. The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit. Management is unable to predict the timing of any future action by the Federal EPA. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Carbon Dioxide Public Nuisance Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York. The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints. The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law. The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims. The defendants’ petition for rehearing was denied. Management believes the actions are without merit and intends to continue to defend against the claims. The Solicitor General requested an extension of time to file a petition for review by the U.S. Supreme Court and the remaining defendants received a similar extension of time. Petitions are currently due on or before August 2, 2010.

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In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court 217;s decision in place. The Registrant Subsidiaries were initially dismissed from this case without prejudice, but are named as defendants in a pending fourth amended complaint. Unless the plaintiffs elect to file a petition for review by the U.S. Supreme Court, there will be no further proceedings in this case.

Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects o f global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. The plaintiffs appealed the decision. Management believes the action is without merit and intends to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. In May 2008, I&M started remediation work in accordance with a plan approved by MDEQ. I&M recorded approximately $11 million of expense prior to January 1, 2010, $3 million of which I&M recorded in March 2009. As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. Management cannot predict the amount of additional cost, if any.

Amos Plant – Request to Show Cause – Affecting APCo and OPCo

In March 2010, APCo and OPCo received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting APCo and OPCo to engage in settlement negotiations. The request includes a proposed civil penalty of approximately $300 thousand. Management indicated a willingness to engage in good faith negotiations and met with representatives of the Federal EPA. APCo and OPCo have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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Defective Environmental Equipment – Affecting CSPCo and OPCo

As part of the AEP System’s continuing environmental investment program, management chose to retrofit wet flue gas desulfurization systems on units utilizing the jet bubbling reactor (JBR) technology. The following plants have been scheduled for the installation of the JBR technology or are currently utilizing JBR retrofits:

		JBRs
		Scheduled for
Plant Name	Plant Owners	Installation
Cardinal	OPCo/Buckeye Power, Inc.		3
Conesville	CSPCo/Dayton Power and Light Company/ Duke Energy Ohio, Inc.		1
Muskingum River (a)	OPCo		1

(a)	Contracts for the Muskingum River project have been temporarily suspended during the early development stage of the project.

The retrofits on two of the Cardinal Plant units and the Conesville Plant unit are operational. Due to unexpected operating results, management completed an extensive review of the design and manufacture of the JBR internal components. The review concluded that there are fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components. Management initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan. Management intends to pursue contractual and other legal remedies if these issues with Black & Veatch are not resolved. If the AEP System is unsuccessful in obtaining reimbursement for the work required to remedy this situation , the cost of repair or replacement could have an adverse impact on construction costs, net income, cash flows and financial condition. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

I&M maintains property insurance through NEIL with a $1 million deductible. As of June 30, 2010, I&M recorded $53 million on its Condensed Consolidated Balance Sheet representing recoverable amounts under the property insurance policy. Through June 30, 2010, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

180

OPERATIONAL CONTINGENCIES

Fort Wayne Lease – Affecting I&M

Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expires on February 28, 2010. I&M has been negotiating with Fort Wayne to purchase the assets at the end of the lease, but no agreement has been reached. Fort Wayne issued a technical notice of default under the lease to I&M in August 2009. I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease. In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court. The parties agreed to submit this matter to mediation. In February 2010, the court issued a stay to continue mediation. I&M is making monthly payments to an escrow account in lieu of rent.&# 160; I&M will seek recovery in rates for any amount it may pay related to this dispute. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Coal Transportation Rate Dispute - Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate) and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoi ced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board. In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim. PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court. In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider. In August 2009, the U.S. District Court upheld the arbitration board’s decision. BNSF appealed the U.S. District Court’s decision.

181

5.	ACQUISITION

2010

Valley Electric Membership Corporation – Affecting SWEPCo

2009

None

6.	BENEFIT PLANS

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of the Registrant Subsidiaries’ net periodic benefit cost for the plans for the three and six months ended June 30, 2010 and 2009:

APCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	3,227			$	3,172			$	1,430			$	1,286
Interest Cost			8,489				8,513				5,075				4,927
Expected Return on Plan Assets			(10,951	)			(11,221	)			(4,407	)			(3,383	)
Amortization of Transition Obligation			-				-				1,311				1,311
Amortization of Prior Service Cost			229				229				-				-
Amortization of Net Actuarial Loss			2,961				1,922				1,353				1,916
Net Periodic Benefit Cost		$	3,955			$	2,615			$	4,762			$	6,057

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	6,454			$	6,345			$	2,860			$	2,572
Interest Cost			16,978				17,025				10,150				9,855
Expected Return on Plan Assets			(21,902	)			(22,442	)			(8,813	)			(6,766	)
Amortization of Transition Obligation			-				-				2,622				2,622
Amortization of Prior Service Cost			458				458				-				-
Amortization of Net Actuarial Loss			5,921				3,844				2,705				3,832
Net Periodic Benefit Cost		$	7,909			$	5,230			$	9,524			$	12,115

182

CSPCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	1,468			$	1,376			$	690			$	618
Interest Cost			4,789				4,882				2,179				2,123
Expected Return on Plan Assets			(6,589	)			(6,819	)			(1,979	)			(1,531	)
Amortization of Transition Obligation			-				-				608				608
Amortization of Prior Service Cost			141				141				-				-
Amortization of Net Actuarial Loss			1,677				1,108				565				821
Net Periodic Benefit Cost		$	1,486			$	688			$	2,063			$	2,639

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	2,936			$	2,752			$	1,380			$	1,235
Interest Cost			9,578				9,765				4,357				4,246
Expected Return on Plan Assets			(13,178	)			(13,638	)			(3,958	)			(3,063	)
Amortization of Transition Obligation			-				-				1,216				1,216
Amortization of Prior Service Cost			282				282				-				-
Amortization of Net Actuarial Loss			3,354				2,215				1,130				1,643
Net Periodic Benefit Cost		$	2,972			$	1,376			$	4,125			$	5,277

I&M									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	3,821			$	3,501			$	1,688			$	1,497
Interest Cost			7,271				7,130				3,541				3,419
Expected Return on Plan Assets			(8,760	)			(8,933	)			(3,349	)			(2,565	)
Amortization of Transition Obligation			-				-				704				704
Amortization of Prior Service Cost			186				186				-				-
Amortization of Net Actuarial Loss			2,516				1,601				881				1,303
Net Periodic Benefit Cost		$	5,034			$	3,485			$	3,465			$	4,358

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	7,642			$	7,001			$	3,375			$	2,995
Interest Cost			14,543				14,260				7,082				6,837
Expected Return on Plan Assets			(17,520	)			(17,866	)			(6,698	)			(5,129	)
Amortization of Transition Obligation			-				-				1,407				1,407
Amortization of Prior Service Cost			372				372				-				-
Amortization of Net Actuarial Loss			5,032				3,203				1,763				2,606
Net Periodic Benefit Cost		$	10,069			$	6,970			$	6,929			$	8,716

183

OPCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	2,845			$	2,759			$	1,357			$	1,219
Interest Cost			8,186				8,275				4,446				4,331
Expected Return on Plan Assets			(10,680	)			(11,069	)			(4,044	)			(3,139	)
Amortization of Transition Obligation			-				-				1,053				1,053
Amortization of Prior Service Cost			227				227				-				-
Amortization of Net Actuarial Loss			2,861				1,875				1,154				1,676
Net Periodic Benefit Cost		$	3,439			$	2,067			$	3,966			$	5,140

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	5,691			$	5,517			$	2,713			$	2,439
Interest Cost			16,372				16,550				8,893				8,663
Expected Return on Plan Assets			(21,360	)			(22,138	)			(8,089	)			(6,280	)
Amortization of Transition Obligation			-				-				2,106				2,105
Amortization of Prior Service Cost			454				455				-				-
Amortization of Net Actuarial Loss			5,721				3,750				2,308				3,352
Net Periodic Benefit Cost		$	6,878			$	4,134			$	7,931			$	10,279

PSO									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	1,513			$	1,436			$	704			$	631
Interest Cost			3,722				3,842				1,590				1,539
Expected Return on Plan Assets			(4,935	)			(5,110	)			(1,528	)			(1,174	)
Amortization of Transition Obligation			-				-				701				701
Amortization of Prior Service Credit			(238	)			(270	)			-				-
Amortization of Net Actuarial Loss			1,297				872				393				587
Net Periodic Benefit Cost		$	1,359			$	770			$	1,860			$	2,284

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	3,026			$	2,872			$	1,407			$	1,261
Interest Cost			7,444				7,684				3,180				3,077
Expected Return on Plan Assets			(9,870	)			(10,219	)			(3,055	)			(2,348	)
Amortization of Transition Obligation			-				-				1,403				1,403
Amortization of Prior Service Credit			(475	)			(541	)			-				-
Amortization of Net Actuarial Loss			2,594				1,744				786				1,174
Net Periodic Benefit Cost		$	2,719			$	1,540			$	3,721			$	4,567

184

SWEPCo									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	1,761			$	1,689			$	777			$	705
Interest Cost			3,773				3,889				1,735				1,684
Expected Return on Plan Assets			(4,872	)			(5,021	)			(1,661	)			(1,280	)
Amortization of Transition Obligation			-				-				615				615
Amortization of Prior Service Credit			(199	)			(229	)			-				-
Amortization of Net Actuarial Loss			1,311				879				428				640
Net Periodic Benefit Cost		$	1,774			$	1,207			$	1,894			$	2,364

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	(in thousands)
Service Cost		$	3,523			$	3,378			$	1,554			$	1,409
Interest Cost			7,547				7,779				3,470				3,368
Expected Return on Plan Assets			(9,745	)			(10,042	)			(3,323	)			(2,560	)
Amortization of Transition Obligation			-				-				1,230				1,230
Amortization of Prior Service Credit			(398	)			(458	)			-				-
Amortization of Net Actuarial Loss			2,621				1,758				856				1,280
Net Periodic Benefit Cost		$	3,548			$	2,415			$	3,787			$	4,727

The following table provides the Registrant Subsidiaries’ actual contributions and payments for the pension and OPEB plans during the first half of 2010 and the expected contributions and payments for the remainder of 2010:


	Paid as of June 30, 2010						Remainder Expected to be Paid in 2010
				Other Postretirement						Other Postretirement
Company	Pension Plans			Benefit Plans			Pension Plans			Benefit Plans
	(in thousands)
APCo		$	9,682		$	10,888		$	9,254		$	6,133
CSPCo			3,274			4,690			3,129			3,574
I&M			9,947			8,100			9,507			7,098
OPCo			8,966			9,560			8,571			6,136
PSO			3,478			4,272			3,325			4,026
SWEPCo			4,799			4,374			4,587			4,097

7.	BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

8.	DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and to a lesser extent foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. These risks are managed using derivative instruments.

185

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value based on open trading positions by utilizing both economic and formal hedging strategies. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

AEPSC, on behalf of the Registrant Subsidiaries, enters into electricity, coal, natural gas, interest rate and to a lesser degree heating oil, gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with long-term commodity derivative positions. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. From time to time, AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchas e obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of June 30, 2010 and December 31, 2009:

Notional Volume of Derivative Instruments
June 30, 2010
(in thousands)

Primary Risk	Unit of
Exposure	Measure	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
Commodity:
Power	MWHs			293,757			166,188			168,869			191,251			39			72
Coal	Tons			12,408			6,854			6,443			29,978			4,581			7,357
Natural Gas	MMBtus			9,595			5,428			5,474			6,247			153			181
Heating Oil and
Gasoline	Gallons			1,289			563			634			952			757			696
Interest Rate	USD		$	12,710		$	7,185		$	7,230		$	9,038		$	745		$	957

Interest Rate and
Foreign Currency	USD		$	-		$	-		$	-		$	-		$	-		$	2,386

Notional Volume of Derivative Instruments
December 31, 2009
(in thousands)

Primary Risk	Unit of
Exposure	Measure	APCo			CSPCo			I&M			OPCo			PSO			SWEPCo
Commodity:
Power	MWHs			191,121			96,828			99,265			112,745			10			12
Coal	Tons			11,347			5,615			5,150			23,631			5,936			6,790
Natural Gas	MMBtus			17,867			9,051			9,129			10,539			-			-
Heating Oil and
Gasoline	Gallons			1,164			474			552			838			668			628
Interest Rate	USD		$	21,054		$	10,658		$	10,716		$	13,487		$	1,137		$	1,457

Interest Rate and
Foreign Currency	USD		$	-		$	-		$	-		$	-		$	-		$	3,798

186

Fair Value Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of electricity, coal, heating oil and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management closely monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial gasoline and heating oil derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. The anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily because some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

187

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the June 30, 2010 and December 31, 2009 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	June 30, 2010						December 31, 2009

	Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
	Received			Paid			Received			Paid
	Netted Against			Netted Against			Netted Against			Netted Against
	Risk Management			Risk Management			Risk Management			Risk Management
Company	Assets			Liabilities			Assets			Liabilities
	(in thousands)
APCo		$	6,359		$	28,476		$	3,789		$	31,806
CSPCo			3,598			16,097			1,920			16,108
I&M			3,628			16,230			1,936			16,222
OPCo			4,140			18,903			2,235			19,512
PSO			1			120			-			194
SWEPCo			1			159			-			305

188

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of June 30, 2010 and December 31, 2009:

Fair Value of Derivative Instruments
June 30, 2010

APCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	303,711		$	2,573			$	-		$	(251,465	)		$	54,819
Long-term Risk Management Assets			141,135			218				-			(93,265	)			48,088
Total Assets			444,846			2,791				-			(344,730	)			102,907

Current Risk Management Liabilities			285,003			4,547				-			(264,711	)			24,839
Long-term Risk Management Liabilities			126,190			429				-			(106,875	)			19,744
Total Liabilities			411,193			4,976				-			(371,586	)			44,583

Total MTM Derivative Contract Net
Assets (Liabilities)		$	33,653		$	(2,185	)		$	-		$	26,856			$	58,324

Fair Value of Derivative Instruments
December 31, 2009

APCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	332,764		$	3,621			$	-		$	(268,429	)		$	67,956
Long-term Risk Management Assets			132,044			-				-			(84,903	)			47,141
Total Assets			464,808			3,621				-			(353,332	)			115,097

Current Risk Management Liabilities			309,639			5,084				-			(288,931	)			25,792
Long-term Risk Management Liabilities			118,702			80				-			(98,418	)			20,364
Total Liabilities			428,341			5,164				-			(387,349	)			46,156

Total MTM Derivative Contract Net
Assets (Liabilities)		$	36,467		$	(1,543	)		$	-		$	34,017			$	68,941

189

Fair Value of Derivative Instruments
June 30, 2010

CSPCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	171,457		$	1,444			$	-		$	(141,939	)		$	30,962
Long-term Risk Management Assets			79,750			123				-			(52,669	)			27,204
Total Assets			251,207			1,567				-			(194,608	)			58,166

Current Risk Management Liabilities			160,892			2,558				-			(149,429	)			14,021
Long-term Risk Management Liabilities			71,291			234				-			(60,360	)			11,165
Total Liabilities			232,183			2,792				-			(209,789	)			25,186

Total MTM Derivative Contract Net
Assets (Liabilities)		$	19,024		$	(1,225	)		$	-		$	15,181			$	32,980

Fair Value of Derivative Instruments
December 31, 2009

CSPCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	168,137		$	1,805			$	-		$	(135,599	)		$	34,343
Long-term Risk Management Assets			66,816			-				-			(42,934	)			23,882
Total Assets			234,953			1,805				-			(178,533	)			58,225

Current Risk Management Liabilities			156,463			2,574				-			(145,985	)			13,052
Long-term Risk Management Liabilities			60,048			41				-			(49,776	)			10,313
Total Liabilities			216,511			2,615				-			(195,761	)			23,365

Total MTM Derivative Contract Net
Assets (Liabilities)		$	18,442		$	(810	)		$	-		$	17,228			$	34,860

190

Fair Value of Derivative Instruments
June 30, 2010

I&M
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	173,559		$	1,461			$	-		$	(142,217	)		$	32,803
Long-term Risk Management Assets			88,905			124				-			(52,852	)			36,177
Total Assets			262,464			1,585				-			(195,069	)			68,980

Current Risk Management Liabilities			161,289			2,586				-			(149,767	)			14,108
Long-term Risk Management Liabilities			71,618			239				-			(60,608	)			11,249
Total Liabilities			232,907			2,825				-			(210,375	)			25,357

Total MTM Derivative Contract Net
Assets (Liabilities)		$	29,557		$	(1,240	)		$	-		$	15,306			$	43,623

Fair Value of Derivative Instruments
December 31, 2009

I&M
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	167,847		$	1,839			$	-		$	(135,248	)		$	34,438
Long-term Risk Management Assets			72,127			-				-			(42,993	)			29,134
Total Assets			239,974			1,839				-			(178,241	)			63,572

Current Risk Management Liabilities			156,561			2,596				-			(145,721	)			13,436
Long-term Risk Management Liabilities			60,217			41				-			(49,872	)			10,386
Total Liabilities			216,778			2,637				-			(195,593	)			23,822

Total MTM Derivative Contract Net
Assets (Liabilities)		$	23,196		$	(798	)		$	-		$	17,352			$	39,750

191

Fair Value of Derivative Instruments
June 30, 2010

OPCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	245,522		$	1,683			$	-		$	(207,134	)		$	40,071
Long-term Risk Management Assets			104,381			142				-			(73,017	)			31,506
Total Assets			349,903			1,825				-			(280,151	)			71,577

Current Risk Management Liabilities			232,950			2,973				-			(215,951	)			19,972
Long-term Risk Management Liabilities			95,164			285				-			(82,048	)			13,401
Total Liabilities			328,114			3,258				-			(297,999	)			33,373

Total MTM Derivative Contract Net
Assets (Liabilities)		$	21,789		$	(1,433	)		$	-		$	17,848			$	38,204

Fair Value of Derivative Instruments
December 31, 2009

OPCo
	Risk
	Management
	Contracts			Hedging Contracts
								Interest Rate
	Commodity			Commodity				and Foreign
Balance Sheet Location	(a)			(a)				Currency (a)			Other (a) (b)				Total
	(in thousands)
Current Risk Management Assets		$	255,179		$	2,199			$	-		$	(207,330	)		$	50,048
Long-term Risk Management Assets			88,064			-				-			(60,061	)			28,003
Total Assets			343,243			2,199				-			(267,391	)			78,051

Current Risk Management Liabilities			240,877			2,998				-			(219,484	)			24,391
Long-term Risk Management Liabilities			81,186			47				-			(68,723	)			12,510
Total Liabilities			322,063			3,045				-			(288,207	)			36,901

Total MTM Derivative Contract Net
Assets (Liabilities)		$	21,180		$	(846	)		$	-		$	20,816			$	41,150

192

Fair Value of Derivative Instruments
June 30, 2010

PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	10,056	$	59	$	-	$	(7,507)	$	2,608
Long-term Risk Management Assets			2,105		-		-		(2,072)		33
Total Assets			12,161		59		-		(9,579)		2,641

Current Risk Management Liabilities			7,769		151		-		(7,533)		387
Long-term Risk Management Liabilities			2,210		40		-		(2,138)		112
Total Liabilities			9,979		191		-		(9,671)		499

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	2,182	$	(132)	$	-	$	92	$	2,142

Fair Value of Derivative Instruments
December 31, 2009

PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	14,885	$	179	$	-	$	(12,688)	$	2,376
Long-term Risk Management Assets			2,640		-		-		(2,590)		50
Total Assets			17,525		179		-		(15,278)		2,426

Current Risk Management Liabilities			14,981		301		-		(12,703)		2,579
Long-term Risk Management Liabilities			2,913		-		-		(2,769)		144
Total Liabilities			17,894		301		-		(15,472)		2,723

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(369)	$	(122)	$	-	$	194	$	(297)

193

Fair Value of Derivative Instruments
June 30, 2010

SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	14,989	$	47	$	2	$	(12,841)	$	2,197
Long-term Risk Management Assets			3,655		-		-		(3,606)		49
Total Assets			18,644		47		2		(16,447)		2,246

Current Risk Management Liabilities			13,596		66		232		(12,883)		1,011
Long-term Risk Management Liabilities			3,948		37		1		(3,690)		296
Total Liabilities			17,544		103		233		(16,573)		1,307

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,100	$	(56)	$	(231)	$	126	$	939

Fair Value of Derivative Instruments
December 31, 2009

SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	22,847	$	169	$	42	$	(20,009)	$	3,049
Long-term Risk Management Assets			4,145		-		5		(4,066)		84
Total Assets			26,992		169		47		(24,075)		3,133

Current Risk Management Liabilities			20,788		-		89		(20,033)		844
Long-term Risk Management Liabilities			4,568		-		-		(4,347)		221
Total Liabilities			25,356		-		89		(24,380)		1,065

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,636	$	169	$	(42)	$	305	$	2,068

(a)	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the Condensed Balance Sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)	Amounts represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging” and dedesignated risk management contracts.

194

The tables below presents the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended June 30, 2010 and 2009:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2010

Location of Gain (Loss)	APCo				CSPCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Electric Generation, Transmission and
Distribution Revenues		$	(1,693	)		$	3,469			$	2,503			$	2,010			$	347			$	613
Sales to AEP Affiliates			786				113				102				2,156				(121	)			(229	)
Regulatory Assets (a)			(1,046	)			(5,225	)			(2,238	)			(5,754	)			(25	)			120
Regulatory Liabilities (a)			(834	)			-				(4,393	)			-				126				1,524
Total Gain (Loss) on Risk Management
Contracts		$	(2,787	)		$	(1,643	)		$	(4,026	)		$	(1,588	)		$	327			$	2,028

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2009

Location of Gain (Loss)	APCo				CSPCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Electric Generation, Transmission and
Distribution Revenues		$	1,184			$	9,261			$	6,028			$	10,804			$	(407	)		$	(305	)
Sales to AEP Affiliates			(306	)			(393	)			(447	)			1,721				837				806
Regulatory Assets (a)			(3,267	)			(5,100	)			(3,327	)			(6,060	)			-				(62	)
Regulatory Liabilities (a)			5,010				(1,162	)			1,617				(1,439	)			(1,339	)			(324	)
Total Gain (Loss) on Risk Management
Contracts		$	2,621			$	2,606			$	3,871			$	5,026			$	(909	)		$	115

Amount of Gain (Loss) Recognized
on Risk Management Contracts
For the Six Months Ended June 30, 2010

Location of Gain (Loss)	APCo				CSPCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Electric Generation, Transmission and
Distribution Revenues		$	2,480			$	13,076			$	9,388			$	12,231			$	1,030			$	1,402
Sales to AEP Affiliates			(1,575	)			(1,449	)			(1,341	)			2,409				(297	)			(538	)
Regulatory Assets (a)			-				(1,544	)			-				(1,690	)			306				73
Regulatory Liabilities (a)			15,147				-				8,461				29				2,764				513
Total Gain (Loss) on Risk Management
Contracts		$	16,052			$	10,083			$	16,508			$	12,979			$	3,803			$	1,450

Amount of Gain (Loss) Recognized
on Risk Management Contracts
For the Six Months Ended June 30, 2009

Location of Gain (Loss)	APCo				CSPCo				I&M				OPCo				PSO				SWEPCo
	(in thousands)
Electric Generation, Transmission and
Distribution Revenues		$	10,971			$	20,006			$	24,206			$	24,298			$	848			$	1,218
Sales to AEP Affiliates			(7,326	)			(4,469	)			(4,418	)			(1,493	)			(625	)			(975	)
Regulatory Assets (a)			-				(3,627	)			(2,449	)			(4,309	)			-				(103	)
Regulatory Liabilities (a)			14,280				(2,490	)			978				(3,084	)			(882	)			249
Total Gain (Loss) on Risk Management
Contracts		$	17,925			$	9,420			$	18,317			$	15,412			$	(659	)		$	389

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheet.

195

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the Condensed Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the Condensed Statements of Income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO, the non-Texas portion of SWEPCo generation and beginning in the second quarter of 2009 the Texas portion of SWEPCo generation) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” SWEPCo re-applied the accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the Registrant Subsidiaries recognize the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk in Net Income during the period of change.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the Condensed Statements of Income. During the three and six months ended June 30, 2010 and 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of electricity, coal, heating oil and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the Condensed Statements of Income, or in Regulatory Assets or Regulatory Liabilities on the Condensed Balance Sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2010 and 2009, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income. During the three and six months ended June 30, 2010, the Registrant Subsidiaries designated cash flow hedging strategies of forecasted fuel purchases.

196

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financing from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2010, APCo designated interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2009, OPCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Depreciation and Amortization expense on the Condensed Statements of Income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2010 and 2009, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2010 and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

The following tables provides details on designated, effective cash flow hedges included in AOCI on the Condensed Balance Sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2010 and 2009. All amounts in the following tables are presented net of related income taxes.

197

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2010

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2010				$	(2,451)	$	(1,407)	$	(1,418)	$	(1,543)	$	(8)	$	100
Changes in Fair Value Recognized in AOCI					642		380		388		370		(191)		(99)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		31		79		66		91		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(4)		150		-
		Purchased Electricity for Resale			65		168		139		193		-		-
		Other Operation Expense			(18)		(11)		(11)		(15)		(13)		(16)
		Maintenance Expense			(22)		(6)		(9)		(11)		(8)		(8)
		Property, Plant and Equipment			(24)		(10)		(12)		(17)		(14)		(10)
		Regulatory Assets (a)			340		-		44		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(1,437)	$	(807)	$	(813)	$	(941)	$	(84)	$	(33)

Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2010				$	(6,488)	$	-	$	(9,262)	$	11,832	$	(475)	$	(4,947)
Changes in Fair Value Recognized in AOCI					(2,229)		-		-		-		-		(96)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-		24
		Interest Expense			419		-		251		(341)		32		207
Balance in AOCI as of June 30, 2010				$	(8,298)	$	-	$	(9,011)	$	11,492	$	(443)	$	(4,812)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2010				$	(8,939)	$	(1,407)	$	(10,680)	$	10,289	$	(483)	$	(4,847)
Changes in Fair Value Recognized in AOCI					(1,587)		380		388		370		(191)		(195)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		31		79		66		91		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(4)		150		-
		Purchased Electricity for Resale			65		168		139		193		-		-
		Other Operation Expense			401		(11)		240		(356)		19		191
		Maintenance Expense			(22)		(6)		(9)		(11)		(8)		(8)
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			-		-		-		-		-		24
		Property, Plant and Equipment			(24)		(10)		(12)		(17)		(14)		(10)
		Regulatory Assets (a)			340		-		44		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(9,735)	$	(807)	$	(9,824)	$	10,551	$	(527)	$	(4,845)

198

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2009

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2009				$	4,066	$	2,162	$	2,091	$	2,669	$	(24)	$	(21)
Changes in Fair Value Recognized in AOCI					(207)		(143)		(119)		(115)		155		166
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(458)		(1,158)		(885)		(1,434)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(6)		(4)		(4)		(5)		(3)		(3)
		Purchased Electricity for Resale			132		334		255		413		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Property, Plant and Equipment			(3)		(2)		(1)		(2)		(1)		(1)
		Regulatory Assets (a)			497		-		68		-		-		-
		Regulatory Liabilities (a)			(1,725)		-		(235)		-		-		-
Balance in AOCI as of June 30, 2009				$	2,296	$	1,189	$	1,170	$	1,526	$	127	$	141

Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2009				$	(7,702)	$	-	$	(10,271)	$	2,039	$	(658)	$	(5,808)
Changes in Fair Value Recognized in AOCI					-		-		-		14,690		-		104
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			417		-		254		(68)		45		207
Balance in AOCI as of June 30, 2009				$	(7,285)	$	-	$	(10,017)	$	16,662	$	(613)	$	(5,497)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2009				$	(3,636)	$	2,162	$	(8,180)	$	4,708	$	(682)	$	(5,829)
Changes in Fair Value Recognized in AOCI					(207)		(143)		(119)		14,575		155		270
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(458)		(1,158)		(885)		(1,434)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(6)		(4)		(4)		(5)		(3)		(3)
		Purchased Electricity for Resale			132		334		255		413		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			417		-		254		(68)		45		207
		Property, Plant and Equipment			(3)		(2)		(1)		(2)		(1)		(1)
		Regulatory Assets (a)			497		-		68		-		-		-
		Regulatory Liabilities (a)			(1,725)		-		(235)		-		-		-
Balance in AOCI as of June 30, 2009				$	(4,989)	$	1,189	$	(8,847)	$	18,188	$	(486)	$	(5,356)

199

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2010

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(743)	$	(376)	$	(382)	$	(366)	$	(78)	$	112
Changes in Fair Value Recognized in AOCI					(1,857)		(1,077)		(1,083)		(1,300)		(105)		(96)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		57		144		120		167		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		150		-
		Purchased Electricity for Resale			211		550		455		633		-		-
		Other Operation Expense			(24)		(19)		(17)		(20)		(19)		(23)
		Maintenance Expense			(36)		(12)		(14)		(15)		(12)		(12)
		Property, Plant and Equipment			(33)		(17)		(17)		(22)		(20)		(14)
		Regulatory Assets (a)			988		-		125		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(1,437)	$	(807)	$	(813)	$	(941)	$	(84)	$	(33)

Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(6,450)	$	-	$	(9,514)	$	12,172	$	(521)	$	(5,047)
Changes in Fair Value Recognized in AOCI					(2,685)		-		-		-		-		(203)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		2		-		-
		Other Operation Expense			-		-		-		-		-		24
		Interest Expense			837		-		503		(682)		78		414
Balance in AOCI as of June 30, 2010				$	(8,298)	$	-	$	(9,011)	$	11,492	$	(443)	$	(4,812)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(7,193)	$	(376)	$	(9,896)	$	11,806	$	(599)	$	(4,935)
Changes in Fair Value Recognized in AOCI					(4,542)		(1,077)		(1,083)		(1,300)		(105)		(299)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		57		144		120		167		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		150		-
		Purchased Electricity for Resale			211		550		455		633		-		-
		Other Operation Expense			(24)		(19)		(17)		(20)		(19)		1
		Maintenance Expense			(36)		(12)		(14)		(15)		(12)		(12)
		Depreciation and Amortization
			Expense		-		-		-		2		-		-
		Interest Expense			837		-		503		(682)		78		414
		Property, Plant and Equipment			(33)		(17)		(17)		(22)		(20)		(14)
		Regulatory Assets (a)			988		-		125		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(9,735)	$	(807)	$	(9,824)	$	10,551	$	(527)	$	(4,845)

200

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2009

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2008				$	2,726	$	1,531	$	1,482	$	1,898	$	-	$	-
Changes in Fair Value Recognized in AOCI					173		(25)		(6)		21		131		145
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(709)		(1,771)		(1,389)		(2,193)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(6)		(4)		(4)		(5)		(3)		(3)
		Purchased Electricity for Resale			594		1,460		1,181		1,807		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Property, Plant and Equipment			(3)		(2)		(1)		(2)		(1)		(1)
		Regulatory Assets (a)			2,136		-		231		-		-		-
		Regulatory Liabilities (a)			(2,615)		-		(324)		-		-		-
Balance in AOCI as of June 30, 2009				$	2,296	$	1,189	$	1,170	$	1,526	$	127	$	141

Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2008				$	(8,118)	$	-	$	(10,521)	$	1,752	$	(704)	$	(5,924)
Changes in Fair Value Recognized in AOCI					-		-		-		14,953		-		13
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		(2)		2		-		-
		Interest Expense			833		-		506		(45)		91		414
Balance in AOCI as of June 30, 2009				$	(7,285)	$	-	$	(10,017)	$	16,662	$	(613)	$	(5,497)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2008				$	(5,392)	$	1,531	$	(9,039)	$	3,650	$	(704)	$	(5,924)
Changes in Fair Value Recognized in AOCI					173		(25)		(6)		14,974		131		158
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statements/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(709)		(1,771)		(1,389)		(2,193)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(6)		(4)		(4)		(5)		(3)		(3)
		Purchased Electricity for Resale			594		1,460		1,181		1,807		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Depreciation and Amortization
			Expense		-		-		(2)		2		-		-
		Interest Expense			833		-		506		(45)		91		414
		Property, Plant and Equipment			(3)		(2)		(1)		(2)		(1)		(1)
		Regulatory Assets (a)			2,136		-		231		-		-		-
		Regulatory Liabilities (a)			(2,615)		-		(324)		-		-		-
Balance in AOCI as of June 30, 2009				$	(4,989)	$	1,189	$	(8,847)	$	18,188	$	(486)	$	(5,356)

(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheets.

201

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at June 30, 2010 and December 31, 2009 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2010

	Hedging Assets (a)						Hedging Liabilities (a)								AOCI Gain (Loss) Net of Tax
				Interest Rate							Interest Rate								Interest Rate
				and Foreign							and Foreign								and Foreign
Company	Commodity			Currency			Commodity				Currency				Commodity				Currency
	(in thousands)
APCo		$	332		$	-		$	(2,517	)		$	-			$	(1,437	)		$	(8,298	)
CSPCo			188			-			(1,413	)			-				(807	)			-
I&M			189			-			(1,429	)			-				(813	)			(9,011	)
OPCo			216			-			(1,649	)			-				(941	)			11,492
PSO			8			-			(140	)			-				(84	)			(443	)
SWEPCo			-			-			(56	)			(231	)			(33	)			(4,812	)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
									Maximum Term for
					Interest Rate				Exposure to
					and Foreign				Variability of Future
Company	Commodity				Currency				Cash Flows
	(in thousands)								(in months)
APCo		$	(1,300	)		$	(1,634	)		18
CSPCo			(733	)			-			18
I&M			(740	)			(1,007	)		18
OPCo			(849	)			1,359			18
PSO			(58	)			(73	)		18
SWEPCo			(10	)			(829	)		29

202

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2009

	Hedging Assets (a)						Hedging Liabilities (a)								AOCI Gain (Loss) Net of Tax
				Interest Rate							Interest Rate								Interest Rate
				and Foreign							and Foreign								and Foreign
Company	Commodity			Currency			Commodity				Currency				Commodity				Currency
	(in thousands)
APCo		$	1,999		$	-		$	(3,542	)		$	-			$	(743	)		$	(6,450	)
CSPCo			984			-			(1,794	)			-				(376	)			-
I&M			1,011			-			(1,809	)			-				(382	)			(9,514	)
OPCo			1,242			-			(2,088	)			-				(366	)			12,172
PSO			178			-			(300	)			-				(78	)			(521	)
SWEPCo			168			5			-				(46	)			112				(5,047	)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months

					Interest Rate
					and Foreign
Company	Commodity				Currency
	(in thousands)
APCo		$	(691	)		$	(1,301	)
CSPCo			(349	)			-
I&M			(358	)			(1,007	)
OPCo			(335	)			1,359
PSO			(79	)			(114	)
SWEPCo			111				(829	)

(a)	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the Condensed Balance Sheets.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, S&P and current market-based qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.

AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements which may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failu re or inability to post collateral.

203

Collateral Triggering Events

Under a limited number of derivative and non-derivative counterparty contracts primarily related to pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), the Registrant Subsidiaries are obligated to post an amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. Management does not anticipate a downgrade below investment grade. The following tables represent the Registrant Subsidiaries’ aggregate fair value of such derivative contracts, the amount of collateral the Registrant Subsid iaries would have been required to post for all derivative and non-derivative contracts if the credit ratings had declined below investment grade and how much was attributable to RTO and ISO activities as of June 30, 2010 and December 31, 2009:

	June 30, 2010

	Liabilities for			Amount of Collateral the			Amount
	Derivative Contracts			Registrant Subsidiaries			Attributable to
	with Credit			Would Have Been			RTO and ISO
Company	Downgrade Triggers			Required to Post			Activities
	(in thousands)
APCo		$	6,654		$	4,279		$	4,279
CSPCo			3,764			2,421			2,421
I&M			3,797			2,442			2,442
OPCo			4,332			2,786			2,786
PSO			291			2,837			2,546
SWEPCo			346			3,374			3,028

As of June 30, 2010, the Registrant Subsidiaries were not required to post any cash collateral.

	December 31, 2009

	Liabilities for			Amount of Collateral the			Amount
	Derivative Contracts			Registrant Subsidiaries			Attributable to
	with Credit			Would Have Been			RTO and ISO
Company	Downgrade Triggers			Required to Post			Activities
	(in thousands)
APCo		$	2,229		$	8,433		$	7,947
CSPCo			1,129			4,272			4,026
I&M			1,139			4,309			4,060
OPCo			1,315			4,975			4,688
PSO			689			2,772			2,083
SWEPCo			819			3,297			2,477

As of December 31, 2009, the Registrant Subsidiaries were not required to post any collateral.

204

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event under outstanding debt in excess of $50 million. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Management believes that a non-performance event under these provisions is unlikely. The following tables represent the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, the amou nt this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of June 30, 2010 and December 31, 2009:

	June 30, 2010

	Liabilities for						Additional
	Contracts with Cross						Settlement
	Default Provisions						Liability if Cross
	Prior to Contractual			Amount of Cash			Default Provision
Company	Netting Arrangements			Collateral Posted			is Triggered
	(in thousands)
APCo		$	126,334		$	4,808		$	31,707
CSPCo			71,471			2,720			17,937
I&M			72,079			2,744			18,089
OPCo			82,290			3,131			20,682
PSO			109			-			66
SWEPCo			366			-			313

	December 31, 2009

	Liabilities for						Additional
	Contracts with Cross						Settlement
	Default Provisions						Liability if Cross
	Prior to Contractual			Amount of Cash			Default Provision
Company	Netting Arrangements			Collateral Posted			is Triggered
	(in thousands)
APCo		$	154,924		$	3,115		$	33,186
CSPCo			78,489			1,578			16,813
I&M			79,158			1,592			16,955
OPCo			91,430			1,838			19,615
PSO			40			-			40
SWEPCo			139			-			93

9. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

205

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are non-binding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. &# 160;In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations and if the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s investment managers perform their own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Fixed income securities do not trade on an exchange and do not have an official closing price. Pricing vendors calculate bond valuations u sing financial models and matrices. Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data. Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 2 are primarily investments in individual fixed income securities. These fixed income securities are valued using models with input data as follows:

	Type of Fixed Income Security
	United States		State and Local
Type of Input	Government	Corporate Debt	Government

Benchmark Yields	X	X	X
Broker Quotes	X	X	X
Discount Margins	X	X
Treasury Market Update	X
Base Spread	X	X	X
Corporate Actions		X
Ratings Agency Updates		X	X
Prepayment Schedule and History			X
Yield Adjustments	X

206

Fair Value Measurements of Long-term Debt

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of June 30, 2010 and December 31, 2009 are summarized in the following table:

	June 30, 2010						December 31, 2009
Company	Book Value			Fair Value			Book Value			Fair Value
	(in thousands)
APCo		$	3,560,776		$	3,853,884		$	3,477,306		$	3,699,373
CSPCo			1,588,673			1,726,413			1,536,393			1,616,857
I&M			2,118,674			2,291,479			2,077,906			2,192,854
OPCo			2,929,248			3,145,855			3,242,505			3,380,084
PSO			968,851			1,051,083			968,121			1,007,183
SWEPCo			1,769,394			1,879,630			1,474,153			1,554,165

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

·	Acceptable investments (rated investment grade or above when purchased).
·	Maximum percentage invested in a specific type of investment.
·	Prohibition of investment in obligations of AEP or its affiliates.
·	Withdrawals permitted only for payment of decommissioning costs and trust expenses.
·	Target asset allocation is 50% fixed income and 50% equity securities.

I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

207

The following is a summary of nuclear trust fund investments at June 30, 2010 and December 31, 2009:

	June 30, 2010										December 31, 2009
	Estimated			Gross			Other-Than-				Estimated			Gross			Other-Than-
	Fair			Unrealized			Temporary				Fair			Unrealized			Temporary
	Value			Gains			Impairments				Value			Gains			Impairments
	(in thousands)
Cash and Cash Equivalents		$	26,512		$	-		$	-			$	14,412		$	-		$	-
Fixed Income Securities:
United States Government			472,709			31,298			(1,043	)			400,565			12,708			(3,472	)
Corporate Debt			60,607			6,113			(6,113	)			57,291			4,636			(2,177	)
State and Local Government			316,046			2,976			(258	)			368,930			7,924			991
Subtotal Fixed Income Securities			849,362			40,387			(7,414	)			826,786			25,268			(4,658	)
Equity Securities - Domestic			515,554			193,710			(121,599	)			550,721			234,437			(119,379	)
Spent Nuclear Fuel and
Decommissioning Trusts		$	1,391,428		$	234,097		$	(129,013	)		$	1,391,919		$	259,705		$	(124,037	)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(in thousands)
Proceeds From Investment Sales		$	360,185		$	252,941		$	592,263		$	411,027
Purchases of Investments			369,427			263,521			617,059			441,928
Gross Realized Gains on Investment Sales			1,022			6,471			6,350			9,353
Gross Realized Losses on Investment Sales			236			460			417			808

The adjusted cost of debt securities was $809 million and $801 million as of June 30, 2010 and December 31, 2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at June 30, 2010 was as follows:

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year		$	11,956
1 year – 5 years			262,167
5 years – 10 years			303,759
After 10 years			271,480
Total		$	849,362

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010 and December 31, 2009. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuatio n techniques.

208

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2010
APCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	2,432	$	418,877	$	21,425	$	(346,131)	$	96,603
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,775		-		(2,443)		332
Dedesignated Risk Management Contracts (b)			-		-		-		5,972		5,972
Total Risk Management Assets		$	2,432	$	421,652	$	21,425	$	(342,602)	$	102,907

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	2,565	$	395,965	$	10,551	$	(368,248)	$	40,833
Cash Flow Hedges:
	Commodity Hedges (a)		-		4,960		-		(2,443)		2,517
DETM Assignment (c)			-		-		-		1,233		1,233
Total Risk Management Liabilities		$	2,565	$	400,925	$	10,551	$	(369,458)	$	44,583

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
APCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Other Cash Deposits (d)		$	421	$	-	$	-	$	51	$	472

Risk Management Assets
Risk Management Commodity Contracts (a)			2,344		449,406		12,866		(360,248)		104,368
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,620		-		(1,621)		1,999
Dedesignated Risk Management Contracts (b)			-		-		-		8,730		8,730
Total Risk Management Assets			2,344		453,026		12,866		(353,139)		115,097

Total Assets		$	2,765	$	453,026	$	12,866	$	(353,088)	$	115,569

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	2,648	$	422,063	$	3,438	$	(388,265)	$	39,884
Cash Flow Hedges:
	Commodity Hedges (a)		-		5,163		-		(1,621)		3,542
DETM Assignment (c)			-		-		-		2,730		2,730
Total Risk Management Liabilities		$	2,648	$	427,226	$	3,438	$	(387,156)	$	46,156

209

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2010
CSPCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	1,376	$	236,523	$	12,120	$	(195,420)	$	54,599
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,559		-		(1,371)		188
Dedesignated Risk Management Contracts (b)			-		-		-		3,379		3,379
Total Risk Management Assets		$	1,376	$	238,082	$	12,120	$	(193,412)	$	58,166

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	1,451	$	223,577	$	5,968	$	(207,920)	$	23,076
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,784		-		(1,371)		1,413
DETM Assignment (c)			-		-		-		697		697
Total Risk Management Liabilities		$	1,451	$	226,361	$	5,968	$	(208,594)	$	25,186

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
CSPCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Other Cash Deposits (d)		$	16,129	$	-	$	-	$	21	$	16,150

Risk Management Assets
Risk Management Commodity Contracts (a)			1,188		227,150		6,518		(182,038)		52,818
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,805		-		(821)		984
Dedesignated Risk Management Contracts (b)			-		-		-		4,423		4,423
Total Risk Management Assets			1,188		228,955		6,518		(178,436)		58,225

Total Assets		$	17,317	$	228,955	$	6,518	$	(178,415)	$	74,375

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	1,342	$	213,330	$	1,742	$	(196,226)	$	20,188
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,615		-		(821)		1,794
DETM Assignment (c)			-		-		-		1,383		1,383
Total Risk Management Liabilities		$	1,342	$	215,945	$	1,742	$	(195,664)	$	23,365

210

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2010
I&M
			Level 1		Level 2		Level 3		Other		Total

Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (g)			$	1,388	$	247,678	$	12,225	$	(195,907)	$	65,384
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,576		-		(1,387)		189
Dedesignated Risk Management Contracts (b)				-		-		-		3,407		3,407
Total Risk Management Assets				1,388		249,254		12,225		(193,887)		68,980

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		14,009		-		12,503		26,512
Fixed Income Securities:
	United States Government			-		472,709		-		-		472,709
	Corporate Debt			-		60,607		-		-		60,607
	State and Local Government			-		316,046		-		-		316,046
		Subtotal Fixed Income Securities		-		849,362		-		-		849,362
Equity Securities - Domestic (f)				515,554		-		-		-		515,554
Total Spent Nuclear Fuel and Decommissioning Trusts				515,554		863,371		-		12,503		1,391,428

Total Assets			$	516,942	$	1,112,625	$	12,225	$	(181,384)	$	1,460,408

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)			$	1,464	$	224,254	$	6,016	$	(208,509)	$	23,225
Cash Flow Hedges:
	Commodity Hedges (a)			-		2,816		-		(1,387)		1,429
DETM Assignment (c)				-		-		-		703		703
Total Risk Management Liabilities			$	1,464	$	227,070	$	6,016	$	(209,193)	$	25,357

211

		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2009
I&M
			Level 1		Level 2		Level 3		Other		Total

Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a)			$	1,198	$	231,777	$	6,571	$	(181,446)	$	58,100
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,839		-		(828)		1,011
Dedesignated Risk Management Contracts (b)				-		-		-		4,461		4,461
Total Risk Management Assets				1,198		233,616		6,571		(177,813)		63,572

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		3,562		-		10,850		14,412
Fixed Income Securities:
	United States Government			-		400,565		-		-		400,565
	Corporate Debt			-		57,291		-		-		57,291
	State and Local Government			-		368,930		-		-		368,930
		Subtotal Fixed Income Securities		-		826,786		-		-		826,786
Equity Securities - Domestic (f)				550,721		-		-		-		550,721
Total Spent Nuclear Fuel and Decommissioning Trusts				550,721		830,348		-		10,850		1,391,919

Total Assets			$	551,919	$	1,063,964	$	6,571	$	(166,963)	$	1,455,491

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a)			$	1,353	$	213,242	$	1,755	$	(195,732)	$	20,618
Cash Flow Hedges:
	Commodity Hedges (a)			-		2,637		-		(828)		1,809
DETM Assignment (c)				-		-		-		1,395		1,395
Total Risk Management Liabilities			$	1,353	$	215,879	$	1,755	$	(195,165)	$	23,822

212

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2010
OPCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	1,583	$	332,024	$	14,006	$	(280,140)	$	67,473
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,814		-		(1,598)		216
Dedesignated Risk Management Contracts (b)			-		-		-		3,888		3,888
Total Risk Management Assets		$	1,583	$	333,838	$	14,006	$	(277,850)	$	71,577

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	1,670	$	317,217	$	6,937	$	(294,903)	$	30,921
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,247		-		(1,598)		1,649
DETM Assignment (c)			-		-		-		803		803
Total Risk Management Liabilities		$	1,670	$	320,464	$	6,937	$	(295,698)	$	33,373

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
OPCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Other Cash Deposits (d)		$	1,075	$	-	$	-	$	24	$	1,099

Risk Management Assets
Risk Management Commodity Contracts (a)			1,383		332,904		7,644		(270,272)		71,659
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,199		-		(957)		1,242
Dedesignated Risk Management Contracts (b)			-		-		-		5,150		5,150
Total Risk Management Assets			1,383		335,103		7,644		(266,079)		78,051

Total Assets		$	2,458	$	335,103	$	7,644	$	(266,055)	$	79,150

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	1,562	$	317,114	$	2,075	$	(287,549)	$	33,202
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,045		-		(957)		2,088
DETM Assignment (c)			-		-		-		1,611		1,611
Total Risk Management Liabilities		$	1,562	$	320,159	$	2,075	$	(286,895)	$	36,901

213

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2010
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	7	$	11,959	$	26	$	(9,359)	$	2,633
Cash Flow Hedges:
	Commodity Hedges (a)		-		59		-		(51)		8
Total Risk Management Assets		$	7	$	12,018	$	26	$	(9,410)	$	2,641

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	11	$	9,771	$	28	$	(9,478)	$	332
Cash Flow Hedges:
	Commodity Hedges (a)		-		191		-		(51)		140
DETM Assignment (c)			-		-		-		27		27
Total Risk Management Liabilities		$	11	$	9,962	$	28	$	(9,502)	$	499

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
PSO
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a)		$	-	$	17,494	$	14	$	(15,260)	$	2,248
Cash Flow Hedges:
	Commodity Hedges (a)		-		179		-		(1)		178
Total Risk Management Assets		$	-	$	17,673	$	14	$	(15,261)	$	2,426

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	-	$	17,865	$	12	$	(15,454)	$	2,423
Cash Flow Hedges:
	Commodity Hedges (a)		-		301		-		(1)		300
Total Risk Management Liabilities		$	-	$	18,166	$	12	$	(15,455)	$	2,723

214

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2010
SWEPCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	8	$	18,303	$	36	$	(16,101)	$	2,246
Cash Flow Hedges:
	Commodity Hedges (a)		-		47		-		(47)		-
	Interest Rate/Foreign Currency Hedges (a)		-		2		-		(2)		-
Total Risk Management Assets		$	8	$	18,352	$	36	$	(16,150)	$	2,246

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	12	$	17,197	$	38	$	(16,259)	$	988
Cash Flow Hedges:
	Commodity Hedges (a)		-		103		-		(47)		56
	Interest Rate/Foreign Currency Hedges (a)		-		233		-		(2)		231
DETM Assignment (c)			-		-		-		32		32
Total Risk Management Liabilities		$	12	$	17,533	$	38	$	(16,276)	$	1,307

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
SWEPCo
		Level 1		Level 2		Level 3		Other		Total

Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a)		$	-	$	26,945	$	22	$	(24,007)	$	2,960
Cash Flow Hedges:
	Commodity Hedges (a)		-		216		-		(43)		173
Total Risk Management Assets		$	-	$	27,161	$	22	$	(24,050)	$	3,133

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	-	$	25,312	$	19	$	(24,312)	$	1,019
Cash Flow Hedges:
	Commodity Hedges (a)		-		89		-		(43)		46
Total Risk Management Liabilities		$	-	$	25,401	$	19	$	(24,355)	$	1,065

(a)	Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(b)	Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.” At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts.
(c)	See “Natural Gas Contracts with DETM” section of Note 15 in the 2009 Annual Report.
(d)	Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 amounts primarily represent investments in money market funds.
(e)	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds.
(f)	Amounts represent publicly traded equity securities and equity-based mutual funds.
(g)	Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There have been no transfers between Level 1 and Level 2 during the six months ended June 30, 2010.

215

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Three Months Ended June 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of March 31, 2010		$	18,687	$	10,570	$	10,662	$	12,180	$	2	$	4
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(8,409)		(4,753)		(4,794)		(5,471)		(1)		(1)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		(556)		-		(667)		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			4,845		2,741		2,764		3,154		(4)		(5)
Transfers into Level 3 (d) (h)			1,332		753		760		867		-		-
Transfers out of Level 3 (e) (h)			(2,006)		(1,135)		(1,145)		(1,306)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(3,575)		(1,467)		(2,038)		(1,688)		1		-
Balance as of June 30, 2010		$	10,874	$	6,153	$	6,209	$	7,069	$	(2)	$	(2)

Six Months Ended June 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2009		$	9,428	$	4,776	$	4,816	$	5,569	$	2	$	3
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		1,232		693		698		797		7		9
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		5,157		-		5,849		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			(4,173)		(2,321)		(2,341)		(2,675)		(6)		(7)
Transfers into Level 3 (d) (h)			603		315		318		366		-		-
Transfers out of Level 3 (e) (h)			(1,738)		(999)		(1,008)		(1,148)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		5,522		(1,468)		3,726		(1,689)		(5)		(7)
Balance as of June 30, 2010		$	10,874	$	6,153	$	6,209	$	7,069	$	(2)	$	(2)

216

Three Months Ended June 30, 2009		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of March 31, 2009		$	11,847	$	6,294	$	6,092	$	7,802	$	1	$	2
Realized (Gain) Loss Included in Net Income
	(or Changes in Net Assets) (a)		(4,739)		(2,514)		(2,432)		(3,103)		3		5
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		3,878		-		5,065		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements			-		-		-		-		-		-
Transfers in and/or out of Level 3 (f)			(2,419)		(1,283)		(1,241)		(1,589)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		9,211		997		4,716		1,235		8		8
Balance as of June 30, 2009		$	13,900	$	7,372	$	7,135	$	9,410	$	12	$	15

Six Months Ended June 30, 2009		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2008		$	8,009	$	4,497	$	4,352	$	5,563	$	(2)	$	(3)
Realized (Gain) Loss Included in Net Income
	(or Changes in Net Assets) (a)		(6,200)		(3,482)		(3,369)		(4,301)		3		5
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		5,466		-		6,907		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements			-		-		-		-		-		-
Transfers in and/or out of Level 3 (f)			(176)		(106)		(97)		6		36		58
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		12,267		997		6,249		1,235		(25)		(45)
Balance as of June 30, 2009		$	13,900	$	7,372	$	7,135	$	9,410	$	12	$	15

(a)	Included in revenues on the Condensed Statements of Income.
(b)	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)	Represents the settlement of risk management commodity contracts for the reporting period.
(d)	Represents existing assets or liabilities that were previously categorized as Level 2.
(e)	Represents existing assets or liabilities that were previously categorized as Level 3.
(f)	Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.
(g)	Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.
(h)	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

10.	INCOME TAXES

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2001. The Registrant Subsidiaries have completed the exam for the years 2001 through 2006 and have issues that are being pursued at the appeals level. The years 2007 and 2008 are currently under examination. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.

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Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, management believes that the ultimate resolution of these audits will not materially impact net income. With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

Federal Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries in March 2010. This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition. For the six months ended June 30, 2010, the Reg istrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:

	Net Reduction			Tax
	to Deferred			Regulatory			Decrease in
Company	Tax Assets			Assets, Net			Net Income
	(in thousands)
APCo		$	9,397		$	8,831		$	566
CSPCo			4,386			2,970			1,416
I&M			7,212			6,528			684
OPCo			8,385			4,020			4,365
PSO			3,172			3,172			-
SWEPCo			3,412			3,412			-

11. FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2010 were:

		Principal		Interest	Due
Company	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
Issuances:
APCo	Senior Unsecured Notes	$	300,000	3.40	2015
APCo	Pollution Control Bonds		17,500	4.625	2021
APCo	Pollution Control Bonds		50,000	5.375	2038
CSPCo	Floating Rate Notes		150,000	Variable	2012
I&M	Notes Payable		84,500	4.00	2014
OPCo	Pollution Control Bonds		79,450	3.25	2014
OPCo	Pollution Control Bonds		86,000	3.125	2015
SWEPCo	Senior Unsecured Notes		350,000	6.20	2040
SWEPCo	Pollution Control Bonds		53,500	3.25	2015

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		Principal		Interest	Due
Company	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
Retirements and
Principal Payments:
APCo	Land Note	$	9	13.718	2026
APCo	Notes Payable - Affiliated		100,000	4.708	2010
APCo	Senior Unsecured Notes		150,000	4.40	2010
APCo	Pollution Control Bonds		50,000	7.125	2010
CSPCo	Notes Payable - Affiliated		100,000	4.64	2010
I&M	Notes Payable - Affiliated		25,000	5.375	2010
I&M	Notes Payable		19,200	5.44	2013
OPCo	Senior Unsecured Notes		400,000	Variable	2010
OPCo	Pollution Control Bonds		79,450	7.125	2010
SWEPCo	Notes Payable - Affiliated		50,000	4.45	2010
SWEPCo	Pollution Control Bonds		53,500	Variable	2019

On behalf of OPCo, trustees held $303 million of reacquired auction-rate tax-exempt long-term debt as of June 30, 2010.

Dividend Restrictions

The Registrant Subsidiaries pay dividends to the Parent provided funds are legally available. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to the Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares. Pursuant to the credit agreement leverage restrictions, the Registrant Subsidiaries must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends generally results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and other capital is contractually defined in the credit agreements. As of June 30, 2010, approximately $204 million of the retained earnings of APCo, $149 million of the retained earnings of CSPCo, $33 millio n of the retained earnings of I&M, $50 million of the retained earnings of OPCo, $101 million of the retained earnings of SWEPCo and none of the retained earnings of PSO have restrictions related to the payment of dividends to Parent.

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Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order. The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of June 30, 2010 and December 31, 2009 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2010 are described in the following table:

													Loans to
	Maximum			Maximum			Average			Average			(Borrowings)				Authorized
	Borrowings			Loans			Borrowings			Loans			to/from Utility				Short-term
	from Utility			to Utility			from Utility			to Utility			Money Pool as of				Borrowing
Company	Money Pool			Money Pool			Money Pool			Money Pool			June 30, 2010				Limit
	(in thousands)
APCo		$	438,039		$	-		$	290,958		$	-		$	(246,873	)		$	600,000
CSPCo			134,592			70,826			32,368			29,474			57,069				350,000
I&M			-			165,687			-			96,954			126,515				500,000
OPCo			-			618,559			-			320,872			172,751				600,000
PSO			107,320			74,751			56,695			51,041			(66,229	)			300,000
SWEPCo			78,616			274,958			39,458			208,666			245,253				350,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Six Months Ended June 30,
	2010			2009
Maximum Interest Rate		0.51	%		2.28	%
Minimum Interest Rate		0.09	%		0.65	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2010 and 2009 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate for Funds						Average Interest Rate for Funds
	Borrowed from						Loaned to
	the Utility Money Pool for the						the Utility Money Pool for the
	Six Months Ended June 30,						Six Months Ended June 30,
Company	2010			2009			2010			2009

APCo		0.23	%		1.45	%		-	%		-	%
CSPCo		0.18	%		1.27	%		0.26	%		-	%
I&M		-	%		1.47	%		0.21	%		1.71	%
OPCo		-	%		1.35	%		0.18	%		0.72	%
PSO		0.28	%		2.01	%		0.16	%		1.31	%
SWEPCo		0.19	%		1.67	%		0.25	%		1.38	%

To meet its short-term borrowing needs, DHLC is also a member of the Utility Money Pool. Effective January 1, 2010, SWEPCo no longer consolidates DHLC. DHLC’s money pool activity for the six months ended June 30, 2010 is described in the following table:

Maximum

Average

Borrowings

Loans

Borrowings

Loans

from Utility

to Utility

from Utility

to Utility

Money Pool as of

Money Pool

June 30, 2010

(in thousands)

23,145

14,791

19,962

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DHLC’s maximum, minimum and average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2010 were as follows:

Maximum

Minimum

Maximum

Minimum

Average

Interest Rates

for Funds

Six Months

Borrowed from

Loaned to

Borrowed from

Loaned to

Ended

the Utility

June 30,

Money Pool

2010

0.51

0.09

0.24

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

			June 30, 2010				December 31, 2009
			Outstanding		Interest		Outstanding		Interest
Company		Type of Debt	Amount		Rate (b)		Amount		Rate (b)
			(in thousands)				(in thousands)
SWEPCo		Line of Credit – Sabine (a)	$	8,717	2.11	%	$	6,890	2.06	%

(a)	Sabine Mining Company is a consolidated variable interest entity.
(b)	Weighted average rate.

Credit Facilities

AEP has credit facilities totaling $3 billion to support the commercial paper program. The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit. In June 2010, AEP canceled a facility that was scheduled to mature in March 2011 and entered into a new $1.5 billion credit facility scheduled to mature in 2013 that allows for the issuance of up to $600 million as letters of credit. As of June 30, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $300 thousand for I&M and $4 million for SWEPCo.

In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced the $627 million credit agreement to $478 million. Under the facility, letters of credit may be issued. As of June 30, 2010, $477 million of letters of credit were issued to support variable rate Pollution Control Bonds as follows:

Company	Amount
	(in thousands)
APCo		$	232,292
I&M			77,886
OPCo			166,899

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiaries’ receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation on the Registrant Subsidiaries’ income statements. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

In July 2010, AEP Credit renewed its receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.

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The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2010 and December 31, 2009 was as follows:

	June 30,		December 31,
Company	2010		2009
	(in thousands)
APCo	$	170,388	$	143,938
CSPCo		192,997		169,095
I&M		131,292		130,193
OPCo		169,898		160,977
PSO		138,138		73,518
SWEPCo		154,745		117,297

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:


	Three Months Ended June 30,						Six Months Ended June 30,
Company	2010			2009			2010			2009
	(in thousands)
APCo		$	1,895		$	1,074		$	3,776		$	2,525
CSPCo			2,782			2,613			5,690			5,525
I&M			1,657			1,333			3,444			2,890
OPCo			2,449			1,903			5,149			4,011
PSO			1,367			1,711			2,750			3,659
SWEPCo			1,462			1,366			3,133			2,822

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:


	Three Months Ended June 30,				Six Months Ended June 30,
Company	2010		2009		2010		2009
	(in thousands)
APCo	$	317,120	$	276,070	$	758,830	$	624,411
CSPCo		422,628		404,071		847,313		801,246
I&M		297,384		286,176		636,593		588,075
OPCo		410,331		376,810		851,840		790,409
PSO		311,883		275,221		526,530		546,642
SWEPCo		338,286		325,562		657,245		635,319

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12. COST REDUCTION INITIATIVES

In April 2010, management began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. A total of 2,461 positions were eliminated as a result of process improvements, streamlined organizational designs and other efficiencies. Most of the affected employees terminated employment May 31, 2010. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

Management recorded a charge to expense in the second quarter of 2010 primarily related to the headcount reduction initiatives.

		Expense	Incurred for					Remaining
		Allocation from	Registrant					Balance at
	AEPSC		Subsidiaries		Settled		June 30, 2010
	(in thousands)
APCo	$	20,526	$	36,399	$	753	$	56,172
CSPCo		11,048		21,244		387		31,905
I&M		12,051		32,985		885		44,151
OPCo		19,427		33,681		979		52,129
PSO		10,681		13,324		231		23,774
SWEPCo		12,588		17,074		421		29,241

These costs relate primarily to severance benefits. They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet.

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COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, (iii) footnotes and (iv) the schedules of each individual registrant. The combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2009 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Economic Conditions

The Registrant Subsidiaries’ retail margins increased primarily due to successful rate proceedings in Indiana, Ohio, Oklahoma and Virginia and higher residential and commercial demand for electricity as a result of favorable weather.

In comparison to the recessionary lows of 2009, industrial sales increased 9% in the second quarter and 4% during the first six months of 2010 for the AEP System. During 2009, the Registrant Subsidiaries’ operations were impacted by difficult economic conditions especially their industrial sales reflecting customers’ curtailments or closures of facilities. In 2009, CSPCo’s and OPCo’s largest customer, Ormet, a major industrial customer, currently operating at a reduced load of approximately 330 MW, (Ormet operated at an approximate 500 MW load in 2008), announced that it will continue operations at this reduced level. In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.

Cost Reduction Initiatives

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, the AEP System implemented cost reduction initiatives in the second quarter of 2010 to reduce its workforce by 11.5% and reduce other operation and maintenance spending. Achieving these goals involved identifying process improvements, streamlining organizational designs and developing other efficiencies that will deliver additional sustainable savings. In the second quarter of 2010, $293 million of expense were recorded related to these cost reduction initiatives.

FINANCIAL CONDITION

LIQUIDITY

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool. AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity. Under credit facilities, $1.35 billion may be issued as letters of credit (LOC). The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leasebacks, leasing arrangements and additional capital contributions from Parent.

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The Registrant Subsidiaries and certain other companies in the AEP System entered into a 3-year credit agreement which matures in April 2011. In June 2010, the credit facility was reduced from $627 million to $478 million. The Registrant Subsidiaries may issue LOCs under the credit facility. Each subsidiary has a borrowing/LOC limit under the credit facility. As of June 30, 2010, a total of $477 million of LOCs were issued under the credit agreement to support variable rate demand notes. The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under the credit facility and the outstanding amount of LOCs.

				LOC Amount
				Outstanding
		Credit Facility		Against the
		Borrowing/LOC		Agreement at
Company		Limit		June 30, 2010
		(in millions)
APCo	$	300	$		232
CSPCo		230			-
I&M		230			78
OPCo		400			167
PSO		65			-
SWEPCo		230			-

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Sales of Receivables

SIGNIFICANT FACTORS

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. Management anticipates making additional investments and operational changes. The most significant sources are the existing and anticipated CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants and new proposals governing the beneficial use and disposal of coal combustion products.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of I&M’s nuclear units. Management is also involved in development of possible future requirements to reduce CO2 emissions to address concerns about global climate change. See a complete discussion of these matters in the “Environmental Matters” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report.

Clean Air Act Transport Rule (Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia. Each state covered by the Transport Rule is assigned an allowance budget for SO2 and/or NOx. Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units. PSO’s and SWEPCo 217;s western states (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NOx program, with new limits that are proposed to take effect in 2012. The

225

remainder of the states in which the AEP System operates would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases. The first phase becomes effective in 2012 and requires approximately 1 million tons per year more SO2 emission reductions across the region than would have been required under CAIR. The second phase takes effect in 2014 and reduces emissions by an additional 800,000 tons per year. The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in the CAIR rule. The time frames for and stringency of the additional emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers, as these features could accelerate unit retirements, increase capital requirements, constrain operations and decrease reliability. Comments on the proposed rule will be due within 60 days after publication in the Federal Register.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at the coal-fired electric generating units. The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initia te closure within five years of the issuance of a final rule.

Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities. Management is currently studying the potential costs associated with this proposal, but expects that it will impose significant costs that, if not recovered through regulated rates or market prices for electricity, will have a material adverse impact on net income, cash flows and financial condition.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA. The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010. The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation u nder the CAA beginning in January 2011 at the earliest and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs. The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units.

The Registrant Subsidiaries’ fossil fuel-fired generating units are very large sources of CO2 emissions. If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units. To the extent the Registrant Subsidiaries install additional controls on their generating plants to limit CO2 emissions and receive regulatory approvals to increase rates, cost recovery could have a positive effect on future earnings. Prudently incurred capital investments made by the Registrant Subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. Management would expect these principles to apply to investments made to address new environmental requirements. However, requests for rate increases reflecting these costs can affect the Registrant Subsidiaries adversely because the regulators could limit the amount or timing of increased costs that would be recoverable through higher rates. In addition, to the extent the Registrant Subsidiaries’ costs are relatively higher than their competitors’ costs, such as operators of nuclear generation, it could reduce off-system sales or cause the Registrant Subsidiaries to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

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Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where the Registrant Subsidiaries have generating facilities. Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. The Registrant Subsidiaries are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. The Registrant Subsidiaries have been named in pending lawsuits, which management is vigorously defending. It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on net income, cash flows and financial condition.

For detailed information on global warming and the actions the AEP System is taking address potential impacts, see Part I of the 2009 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming and “Combined Management Discussion and Analysis of Registrant Subsidiaries.”

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncement Adopted During 2010

The Registrant Subsidiaries prospectively adopted ASU 2009-17 “Consolidation” effective January 1, 2010. SWEPCo no longer consolidates DHLC effective with the adoption of this standard.

See Note 2 for further discussion of accounting pronouncements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations. Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

The Registrant Subsidiaries’ risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. Also, see Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.

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The following tables summarize the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:

	MTM Risk Management Contract Net Assets (Liabilities)
	Six Months Ended June 30, 2010
	(in thousands)


APCo
Total MTM Risk Management Contract Net Assets at December 31, 2009		$	45,197
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(13,316)
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(214)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			(23)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			7,981
Total MTM Risk Management Contract Net Assets			39,625
Cash Flow Hedge Contracts			(2,185)
DETM Assignment (e)			(1,233)
Collateral Deposits			22,117
Total MTM Derivative Contract Net Assets at June 30, 2010		$	58,324

OPCo
Total MTM Risk Management Contract Net Assets at December 31, 2009		$	26,330
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(8,420)
Fair Value of New Contracts at Inception When Entered During the Period (a)			4,722
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)			(715)
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(418)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			5,843
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			(1,665)
Total MTM Risk Management Contract Net Assets			25,677
Cash Flow Hedge Contracts			(1,433)
DETM Assignment (e)			(803)
Collateral Deposits			14,763
Total MTM Derivative Contract Net Assets at June 30, 2010		$	38,204

228

PSO
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2009		$	(369)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			100
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(48)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			(1)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			2,500
Total MTM Risk Management Contract Net Assets			2,182
Cash Flow Hedge Contracts			(132)
DETM Assignment (e)			(27)
Collateral Deposits			119
Total MTM Derivative Contract Net Assets at June 30, 2010		$	2,142

SWEPCo
Total MTM Risk Management Contract Net Assets at December 31, 2009		$	1,636
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(1,115)
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(84)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			(2)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			665
Total MTM Risk Management Contract Net Assets			1,100
Cash Flow Hedge Contracts			(287)
DETM Assignment (e)			(32)
Collateral Deposits			158
Total MTM Derivative Contract Net Assets at June 30, 2010		$	939

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)	Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)	Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets.
(e)	See “Natural Gas Contracts with DETM” section of Note 15 of the 2009 Annual Report.

229

The following tables present the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
June 30, 2010
(in thousands)

		Remainder
APCo		2010		2011-2013		2014+		Total
Level 1 (a)		$	(170)	$	37	$	-	$	(133)
Level 2 (b)			10,304		11,565		1,043		22,912
Level 3 (c)			3,851		4,986		2,037		10,874
Total			13,985		16,588		3,080		33,653
Dedesignated Risk Management
	Contracts (d)		2,495		3,477		-		5,972
Total MTM Risk Management
	Contract Net Assets	$	16,480	$	20,065	$	3,080	$	39,625

		Remainder
OPCo		2010		2011-2013		2014+		Total
Level 1 (a)		$	(111)	$	24	$	-	$	(87)
Level 2 (b)			7,682		6,446		679		14,807
Level 3 (c)			2,496		3,247		1,326		7,069
Total			10,067		9,717		2,005		21,789
Dedesignated Risk Management
	Contracts (d)		1,624		2,264		-		3,888
Total MTM Risk Management
	Contract Net Assets	$	11,691	$	11,981	$	2,005	$	25,677

		Remainder
PSO		2010		2011-2013		Total
Level 1 (a)		$	(4)	$	-	$	(4)
Level 2 (b)			2,410		(222)		2,188
Level 3 (c)			(2)		-		(2)
Total MTM Risk Management
	Contract Net Assets (Liabilities)	$	2,404	$	(222)	$	2,182

		Remainder
SWEPCo		2010		2011-2013		Total
Level 1 (a)		$	(4)	$	-	$	(4)
Level 2 (b)			1,570		(464)		1,106
Level 3 (c)			(2)		-		(2)
Total MTM Risk Management
	Contract Net Assets (Liabilities)	$	1,564	$	(464)	$	1,100

(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)	Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.” At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into Revenues over the remaining life of the contracts.

230

Credit Risk

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

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR to measure 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, 2010, a near term typical change in commodity prices is not expected to have a material effect on 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:

	Six Months Ended									Twelve Months Ended
	June 30, 2010									December 31, 2009
Company		End		High		Average		Low		End		High		Average		Low
	(in thousands)									(in thousands)
APCo		$	191	$	659	$	259	$	133	$	275	$	699	$	333	$	151
OPCo			142		545		219		103		201		530		244		113
PSO			6		70		16		3		10		34		12		4
SWEPCo			8		93		24		5		16		49		18		6

Management back-tests its VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements. Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which 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 the Registrant Subsidiaries’ outstanding debt as of June 30, 2010 and December 31, 2009, the estimated EaR on the Registrant Subsidiaries’ debt portfo lio was as follows:

	June 30,		December 31,
Company	2010		2009
	(in thousands)
APCo	$	770	$	1,837
CSPCo		178		216
I&M		203		227
OPCo		1,222		1,373
PSO		77		119
SWEPCo		41		305

231

CONTROLS AND PROCEDURES

During the second quarter of 2010, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in th e reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2010, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2010 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

232

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4 incorporated herein by reference.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2009 includes a detailed discussion of our risk factors. The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in our 2009 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

We may not fully recover all of the investment in and expenses related to the Turk Plant. (Applies to AEP and SWEPCo)

In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN. SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates. The parties that successfully challenged the granting of the CECPN filed a complaint with the Federal District Court for the Western District of Arkansas seeking an injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.

In January 2009, SWEPCO was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant. Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals. In July 2010, the Hempsted County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines.

If SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would reduce future net income and cash flows and impact financial condition.

Ohio may require us to refund fuel costs that we have collected. (Applies to OPCo)

233

Ohio may require us to refund rider revenue that we have collected. (Applies to CSPCo and OPCo)

The Industrial Energy Users-Ohio filed a notice of appeal of the 2009 and 2010 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. As of June 30, 2010, CSPCo and OPCo have incurred $32 million and $23 million, respectively, in EDR costs including carrying costs. Of these costs, CSPCo and OPCo have collected $16 million and $12 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010. The remaining $16 million and $11 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets. If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Texas may require us to refund fuel costs that we have collected. (Applies to SWEPCo)

Our request for rate recovery in West Virginia may not be approved in its entirety. (Applies to AEP and APCo)

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011. If the WVPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Oklahoma may require us to refund fuel costs that we have collected. (Applies to PSO)

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs. In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins sharing decrease from 25% to 10%. The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEP Energy Partners was filed. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions. If the OCC were t o issue an unfavorable decision, it would reduce future net income and cash flows and impact financial condition.

Our request for rate recovery in Oklahoma may not be approved in its entirety. (Applies to AEP and PSO)

In July 2010, PSO filed a request with the OCC to increase annual rates by $82 million, including $30 million that is currently being recovered through a rider. The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity. If the OCC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Risks Related to Owning and Operating Generation Assets and Selling Power

We may not fully recover the costs of repairing or replacing damaged equipment in Cook Plant Unit 1 and may be required to pay additional

accidental outage insurance proceeds to ratepayers. (Applies to AEP and I&M)

Cook Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator. Unit 1 resumed operations in December 2009 at slightly reduced power, but repair of the property damage and replacement of the turbine rotors and other equipment are estimated to cost approximately $395 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.

234

In March 2009, the IURC approved a settlement agreement with intervenors to collect a prior under-recovered fuel balance. Under the settlement agreement, a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds. Separately, in March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment related to the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage. If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.

Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations. (Applies to each registrant.)

In July 2010, federal legislation was enacted to reform financial markets that significantly alter how over-the-counter (OTC) derivatives are regulated. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended June 30, 2010 of equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
04/01/10 – 04/30/10		3,759	(a)	$	80.00		-	$	-
05/01/10 – 05/31/10		2	(b)		66.75		-		-
06/01/10 – 06/30/10		-			-		-		-

(a)	PSO purchased 3,759 shares of its 4.24% cumulative preferred stock in a privately-negotiated transaction outside of an announced program.
(b)	I&M purchased 1 share of its 4.125% cumulative preferred stock and OPCo purchased 1 share of its 4.50% cumulative preferred stock in privately-negotiated transactions outside of an announced program.

235

Item 5. Other Information

NONE

Item 6. Exhibits

AEP, APCo, OPCo, PSO and SWEPCo

10 – Amended and Restated AEP System Long-term Incentive Plan.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

236

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

APPALACHIAN POWER COMPANY

COLUMBUS SOUTHERN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

By: /s/Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

Date: July 30, 2010

237

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Other Operation and Maintenance expenses increased $46 million primarily due to the following:

A $40 million increase in expenses related to the cost reduction initiatives in the second quarter of 2010.

A $4 million increase in distribution expenses associated with storm restoration expenses from June 2010 storms.

A $3 million increase in transmission expense due to lower credits under the Transmission Agreement.

Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.

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 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

			Number of shares of common stock outstanding of the registrants at July 29, 2010

American Electric Power Company, Inc.			479,437,027
			($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)

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 or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies		PSO, SWEPCo, TCC and TNC.
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.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
ASU		Accounting Standard Update.
CAA		Clean Air Act.
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.
CO2		Carbon Dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CSPCo		Columbus Southern Power Company, an AEP electric utility subsidiary.
CTC		Competition Transition Charge.
CWIP		Construction Work in Progress.
DETM		Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R		Environmental compliance and transmission and distribution system reliability.
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT		Electric Reliability Council of Texas.
ESP		Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC 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.
FGD		Flue Gas Desulfurization or Scrubbers.
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.

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

			Page
Glossary of Terms			i

Forward-Looking Information			iv

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		1
	Quantitative and Qualitative Disclosures About Risk Management Activities		19
	Condensed Consolidated Financial Statements		23
	Index to Condensed Notes to Condensed Consolidated Financial Statements		28

Appalachian Power Company and Subsidiaries:
	Management’s Financial Discussion and Analysis		81
	Quantitative and Qualitative Disclosures About Risk Management Activities		88
	Condensed Consolidated Financial Statements		89
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		94

Columbus Southern Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis		96
	Quantitative and Qualitative Disclosures About Risk Management Activities		98
	Condensed Consolidated Financial Statements		99
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		104

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis		106
	Quantitative and Qualitative Disclosures About Risk Management Activities		109
	Condensed Consolidated Financial Statements		110
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		115

Ohio Power Company Consolidated:
	Management’s Financial Discussion and Analysis		117
	Quantitative and Qualitative Disclosures About Risk Management Activities		123
	Condensed Consolidated Financial Statements		124
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		129

Public Service Company of Oklahoma:
	Management’s Financial Discussion and Analysis		131
	Quantitative and Qualitative Disclosures About Risk Management Activities		135
	Condensed Financial Statements		136
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		141

Southwestern Electric Power Company Consolidated:
	Management’s Financial Discussion and Analysis		143
	Quantitative and Qualitative Disclosures About Risk Management Activities		149
	Condensed Consolidated Financial Statements		150
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		155


Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries				156

Combined Management’s Discussion and Analysis of Registrant Subsidiaries				224

Controls and Procedures				232

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		233
	Item 1A.	Risk Factors		233
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		235
	Item 5.	Other Information		236
	Item 6.	Exhibits:		236
			Exhibit 10
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)

SIGNATURE				237

Term		Meaning

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.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
KPSC		Kentucky Public Service Commission.
kV		Kilovolt.
KWH		Kilowatthour.
LPSC		Louisiana Public Service Commission.
MISO		Midwest Independent Transmission System Operator.
MLR		Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MMBtu		Million British Thermal Units.
MPSC		Michigan Public Service Commission.
MTM		Mark-to-Market.
MW		Megawatt.
MWH		Megawatthour.
NEIL		Nuclear Electric Insurance Limited.
NOx		Nitrogen oxide.
Nonutility Money Pool		AEP’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.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
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.
RTO		Regional Transmission Organization.
S&P		Standard and Poor’s.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.

Term		Meaning

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.
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.
VIE		Variable Interest Entity.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

·	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, customer growth and the impact of retail competition.
·	Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·	Availability of necessary generating capacity and the performance of our generating plants.
·	Our ability to recover I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process.
·	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 oversight of energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.
·	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 our dispute with Bank of America).
·	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 ESPs and related regulation 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 and demand 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.
·	Our ability to recover through rates the remaining unrecovered investment, if any, in generating units that may be retired before the end of their previously projected useful lives.

(a)	While not considered a business segment, 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 gradually settle and completely expire in 2011.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility.

Summary of KWH Energy Sales for Utility Operations
For the Three and Six Months Ended June 30, 2010 and 2009

	Three Months Ended			Six Months Ended
	June 30,			June 30,
Energy/Delivery Summary	2010	2009		2010	2009
	(in millions of KWH)
Retail:
Residential	12,659		12,391	30,433	28,762
Commercial	13,002		12,595	24,476	24,205
Industrial	14,662		13,400	28,044	26,922
Miscellaneous	783		771	1,495	1,490
Total Retail (a)	41,106		39,157	84,448	81,379

Wholesale	7,019		7,166	15,156	13,943

Total KWHs	48,125		46,323	99,604	95,322

(a) Includes energy delivered to customers served by AEP's Texas Wires Companies.

Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and Six Months Ended June 30, 2010 and 2009

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2010		2009		2010		2009
		(in degree days)
Eastern Region
Actual - Heating (a)			75		156		1,975		1,977
Normal - Heating (b)			170		171		1,911		1,962

Actual - Cooling (c)			434		300		434		305
Normal - Cooling (b)			289		286		293		290

Western Region
Actual - Heating (a)			5		27		764		540
Normal - Heating (b)			21		21		595		600

Actual - Cooling (d)			866		861		886		960
Normal - Cooling (b)			757		756		815		812

(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 cooling degree days are calculated on a 65 degree temperature base.
(d)	Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC.

Second Quarter of 2010 Compared to Second Quarter of 2009

Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
Income from Utility Operations Before Extraordinary Loss
(in millions)

Second Quarter of 2009	$	327

Changes in Gross Margin:
Retail Margins		115
Off-system Sales		(12	)
Transmission Revenues		(2	)
Other Revenues		(60	)
Total Change in Gross Margin		41

Total Expenses and Other:
Other Operation and Maintenance		(307	)
Depreciation and Amortization		(6	)
Taxes Other Than Income Taxes		(14	)
Interest and Investment Income		11
Carrying Costs Income		7
Allowance for Equity Funds Used During Construction		(1	)
Interest Expense		(10	)
Total Expenses and Other		(320	)

Income Tax Expense		84

Second Quarter of 2010	$	132

·	Retail Margins increased $115 million primarily due to the following:
	·	A $22 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia, a $13 million increase in the recovery of advanced metering costs in Texas and a $13 million net increase in rates in our other jurisdictions. These increases in retail margins had corresponding offsets of $26 million related to cost recovery riders/trackers that were recognized in the other gross margin/other expense line items below.
	·	A $34 million increase in weather-related usage primarily due to a 45% increase in cooling degree days in our eastern region.
	·	A $20 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
	These increases were partially offset by:
	·	A $9 million decrease due to the termination of an I&M unit power agreement.
·	Margins from Off-system Sales decreased $12 million primarily due to lower trading and marketing margins, partially offset by higher physical sales volumes.
·	Other Revenues decreased $60 million primarily due to the Cook Plant accidental outage insurance proceeds of $46 million, which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $20 million in the second quarter of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.

·	Other Operation and Maintenance expenses increased $307 million primarily due to the following:
	·	A $278 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
	·	A $27 million increase in demand side management, energy efficiency, vegetation management programs and other costs which have associated cost recovery riders/trackers that were recognized in retail revenues.
	These increases were partially offset by:
	·	A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $14 million decrease in plant outage and other plant operating and maintenance expenses.
·	Depreciation and Amortization increased $6 million primarily due to new environmental improvements placed in service and other increases in depreciable property balances.
·	Taxes Other Than Income Taxes increased $14 million primarily due to the employer portion of payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Interest and Investment Income increased $11 million primarily due to the second quarter 2009 write-off of other-than-temporary losses related to equity investments made by EIS.
·	Carrying Costs Income increased $7 million primarily due to increased environmental deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
·	Interest Expense increased $10 million primarily due to an increase in long-term debt.
·	Income Tax Expense decreased $84 million primarily due to a decrease in pretax book income.

·	Retail Margins increased $283 million primarily due to the following:
	·	A $75 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia, a $25 million increase in the recovery of advanced metering costs in Texas, a $19 million rate increase in Oklahoma, a $17 million net rate increase for I&M, a $13 million net increase in rates for SWEPCo and a $27 million net increase in rates in our other jurisdictions. These increases in retail margins had corresponding offsets of $64 million related to cost recovery riders/trackers that were recognized in the other gross margin/other expense line items below.
	·	A $71 million increase in weather-related usage primarily due to a 43% increase in cooling degree days in our eastern region and a 41% increase in heating degree days in our western region.
	·	A $42 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Unit 1 shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
	These increases were partially offset by:
	·	A $17 million decrease due to the termination of an I&M unit power agreement.
·	Transmission Revenues increased $8 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.
·	Other Revenues decreased $143 million primarily due to the Cook Plant accidental outage insurance proceeds of $99 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $42 million in the first six months of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above. Other Revenues also decreased due to lower gains on sales of emission allowances of $23 million.

·	Other Operation and Maintenance expenses increased $344 million primarily due to the following:
	·	A $278 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
	·	A $72 million increase in demand side management, energy efficiency, vegetation management programs and other costs which have associated cost recovery riders/trackers that were recognized in retail revenues.
	·	A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
	These increases were partially offset by:
	·	A $59 million decrease in storm expenses including the deferral of $25 million of 2009 storm costs as allowed by the Virginia SCC.
·	Depreciation and Amortization increased $31 million primarily due to new environmental improvements placed in service and other increases in depreciable property balances.
·	Taxes Other Than Income Taxes increased $23 million primarily due to the employer portion of payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010 and higher franchise and property taxes.
·	Interest and Investment Income increased $8 million primarily due to the second quarter 2009 write-off of other-than-temporary losses related to equity investments made by EIS.
·	Carrying Costs Income increased $12 million primarily due to increased environmental deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
·	Allowance for Equity Funds Used During Construction increased $7 million related to construction projects at SWEPCo’s Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.
·	Interest Expense increased $25 million primarily due to an increase in long-term debt and a decrease in the debt component of AFUDC due to lower CWIP balances at APCo, CSPCo and OPCo.
·	Income Tax Expense decreased $47 million primarily due to a decrease in pretax book income, partially offset by the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

(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)	Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)	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.

		Exposure						Number of		Net Exposure
		Before						Counterparties		of
		Credit		Credit		Net		>10% of		Counterparties
Counterparty Credit Quality		Collateral		Collateral		Exposure		Net Exposure		>10%
		(in millions, except number of counterparties)
Investment Grade		$	717	$	46	$	671		1	$	152
Split Rating			4		-		4		1		4
Noninvestment Grade			3		1		2		4		2
No External Ratings:
	Internal Investment Grade		145		-		145		3		100
	Internal Noninvestment Grade		82		11		71		3		63
Total as of June 30, 2010		$	951	$	58	$	893		12	$	321

Total as of December 31, 2009		$	846	$	58	$	788		12	$	317

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2010 and 2009
(in millions)
(Unaudited)

	AEP Common Shareholders
	Common Stock										Accumulated
											Other
					Paid-in			Retained			Comprehensive			Noncontrolling
	Shares		Amount		Capital			Earnings			Income (Loss)			Interests			Total
TOTAL EQUITY – DECEMBER 31, 2008		426	$	2,771	$	4,527		$	3,847		$	(452	)	$	17		$	10,710

Issuance of Common Stock		71		460		1,278												1,738
Common Stock Dividends									(363	)					(3	)		(366	)
Preferred Stock Dividend Requirements of
Subsidiaries									(1	)								(1	)
Other Changes in Equity						(50	)								1			(49	)
SUBTOTAL – EQUITY																		12,032

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $9												17						17
Securities Available for Sale, Net of Tax of $5												9						9
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $14												25						25
NET INCOME									677						3			680
TOTAL COMPREHENSIVE INCOME																		731

TOTAL EQUITY – JUNE 30, 2009		497	$	3,231	$	5,755		$	4,160		$	(401	)	$	18		$	12,763

TOTAL EQUITY – DECEMBER 31, 2009		498	$	3,239	$	5,824		$	4,451		$	(374	)	$	-		$	13,140

Issuance of Common Stock		2		9		34												43
Common Stock Dividends									(398	)					(1	)		(399	)
Preferred Stock Dividend Requirements of
Subsidiaries									(1	)								(1	)
Other Changes in Equity						2												2
SUBTOTAL – EQUITY																		12,785

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $1												2						2
Securities Available for Sale, Net of Tax of $6												(11	)					(11	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $6												11						11
NET INCOME									481						2			483
TOTAL COMPREHENSIVE INCOME																		485

TOTAL EQUITY – JUNE 30, 2010		500	$	3,248	$	5,860		$	4,533		$	(372	)	$	1		$	13,270

See Condensed Notes to Condensed Consolidated Financial Statements.

	Three Months Ended June 30,				Six Months Ended June 30,
Amounts Attributable to AEP Common Shareholders	2010		2009		2010		2009
	(in millions)
Income Before Extraordinary Loss	$	136	$	321	$	480	$	681
Extraordinary Loss, Net of Tax		-		(5)		-		(5)
Net Income	$	136	$	316	$	480	$	676


Section
1.Purpose of the Plan
2.Definitions
3.Shares of Common Stock Subject to the Plan
4.Administration of the Plan
5.Eligibility and Awards
6.Stock Options
7.Stock Appreciation Rights
8.Restricted Stock
9.Performance Awards
10.Phantom Stock
11.Dividend Equivalents
12.Change in Control
13.Award Agreements
14.General Provisions
15.Effective Date, Termination and Amendment

											Twelve		Six
											Months		Months
	Year Ended December 31,										Ended		Ended
	2005		2006		2007			2008	2009		6/30/2010		6/30/2010
EARNINGS
Income Before Income Taxes	$	202,021	$	282,865	$	195,613	$	166,801	$	201,263	$	130,191	$	81,719
Fixed Charges (as below)		118,365		151,874		178,067		225,573		215,640		215,460		108,148
Total Earnings	$	320,386	$	434,739	$	373,680	$	392,374	$	416,903	$	345,651	$	189,867

FIXED CHARGES
Interest Expense	$	106,301	$	129,106	$	165,405	$	209,733	$	202,426	$	204,822	$	103,558
Credit for Allowance for Borrowed Funds Used During Construction		8,764		17,668		6,962		9,040		6,014		3,438		990
Estimated Interest Element in Lease Rentals		3,300		5,100		5,700		6,800		7,200		7,200		3,600
Total Fixed Charges	$	118,365	$	151,874	$	178,067	$	225,573	$	215,640	$	215,460	$	108,148

Ratio of Earnings to Fixed Charges		2.70		2.86		2.09		1.73		1.93		1.60		1.75