UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO QUARTERLY REPORTS ON FORM 10-Q

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

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

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

Operating Activities

Net Cash Flows from Operating Activities increaseddecreased in 20082009 primarily due to the TEM settlement.a decline in net income and an increase in fuel inventory.

Net Cash Flows from Operating Activities were $2.1 billion$317 million in 20082009 consisting primarily of Net Income Before Discontinued Operations of $1.2 billion$363 million and $1.1 billion$382 million of noncash Depreciationdepreciation and Amortization.amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel reflecting higher coal and natural gas prices.

Net Cash Flows from Operating Activities were $631 million in 2008 consisting primarily of Net Income of $576 million and $363 million of noncash depreciation and amortization.  Other represents items that had a numbercurrent period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items resulted in lower cash from operations due to payment of items the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.accrued at December 31, 2007.

Investing Activities

Net Cash Flows Used for Investing Activities were $3.1 billion$727 million in 2009 and $894 million in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation, environmental and distribution investment plan.

In our normal course of business, we purchase and sell investment securities including variable rate demand notes with cash available for short-term investments including the cash drawn against our credit facilities in 2008.  We alsoand purchase and sell investment securities within our nuclear trusts.  The net amount of these activities is included in Other.

We forecast approximately $1.2$2.6 billion of construction expenditures for the remainderall of 2008.2009, excluding AFUDC.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through cash flows from operationsnet income and financing activities.

Financing Activities

Net Cash Flows from Financing Activities in 20082009 were $1.2 billion$709 million primarily due to the issuance of additional debt including $315$825 million of Junior Subordinated Debenturessenior unsecured notes and a net increase of $1.3 billion in outstanding Senior Unsecured Notes partially offset, by the reacquisition of a net $370$134 million of Pollution Control Bonds and $125 million of Securitization Bonds.  In September 2008, we borrowed $600 million under our credit agreements.pollution control bonds.  See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 20072008 were $1.2 billion$240 million primarily due to issuing $1.9 billionthe issuance of debt securities including $1 billion$315 million of new debt for plant acquisitionsjunior subordinated debentures and construction$500 million of senior unsecured notes, partially offset by the retirement of $95 million of pollution control bonds, $52 million of senior unsecured notes and increasing$34 million of mortgage notes and the reduction of our short-term commercial paper borrowings.outstanding by $251 million.

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

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20072008 Annual Report.

A summary of our contractual obligations is included in our 20072008 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above and the drawdowns and standby letters of credit discussed in “Liquidity” above.

SIGNIFICANT FACTORS

We continue to be involved in various matters described in the “Significant Factors” section of “Management’s Financial Discussion and Analysis of Results of Operations” in our 20072008 Annual Report.  The 20072008 Annual Report should be read in conjunction with this report in order to understand significant factors which have not materially changed in status since the issuance of our 20072008 Annual Report, but may have a material impact on our future net income, cash flows and financial condition.

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

In March 2009, intervenors filed a motion to stay a portion of the ESP rates or alternately make that portion subject to refund because the intervenors believed that the ordered ESP rates for 2009 were retroactive and therefore unlawful.  In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs effective with the April 2009 billing cycle and rejected the intervenors’ motion.  The PUCO also clarified that the reference in its earlier order to the January 1, 2009 date related to the term of the ESP, not to the effective date of tariffs and clarified the tariffs were not retroactive.  In March 2009, CSPCo and OPCo implemented the new ESP tariffs effective with the start of the April 2009 billing cycle.  In April 2009, CSPCo and OPCo filed a motion requesting rehearing of several issues.  In April 2009, several intervenors filed motions requesting rehearing of issues underlying the PUCO’s authorized rate increases and one intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease collecting rates under the order.  Certain intervenors also filed a complaint for writ of prohibition with the Ohio legislature passed Senate Bill 221, which amendsSupreme Court to halt any further collection from customers of what the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  Electric utilitiesintervenors claim is unlawful retroactive rate increases.

Management will evaluate whether it will withdraw the ESP applications after a final order, thereby terminating the ESP proceedings.  If CSPCo and/or OPCo withdraw the ESP applications, CSPCo and/or OPCo may file an ESP with a fuel cost recovery mechanism.  Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing.  An MRO, fromor another ESP as permitted by the date of its commencement, could transition CSPColaw.  The revenues collected and OPCo to full market rates no sooner than six years and no later than ten years after therecorded in 2009 under this PUCO approves an MRO.  The PUCO has the authority to approve or modify the utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than the MRO.  Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pending the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operationsorder are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented withinpossible refund through the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.SEET process.  Management is unable, to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds over a period ending inthrough the end of 2020.  TCC has refunded its net other true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider.  Cash paidAlthough earnings were not affected by this CTC refund, cash flow was adversely impacted for these CTC refunds for the nine months ended September 30, 2008, 2007 and 2007 was2006 by $75 million, $238 million and $207$69 million, respectively.  TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  Municipal customers and other intervenors also appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries.

In March 2007, the Texas District Court judge hearing the appeals of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration.  This remand could potentially have an adverse effect on TCC’s future net income and cash flows if upheld on appeal.  The district courtDistrict Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.unreasonableness which could have a favorable effect on TCC’s future net income and cash flows.

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

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

In 2008,2009, AEP completed or is in various stages of construction of the following generation facilities:

Turk Plant

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

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

The Arkansas Governor’s Commission on Global Warming is scheduled to issueissued its final report to the Governor by November 1,governor in October 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating.  If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build and operate the Turk Plant.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paidcosts incurred plus related shutdown costs.  If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements.  As of September 30, 2008,March 31, 2009, SWEPCo has capitalized approximately $448$480 million of expenditures (including AFUDC) and has significant contractual construction commitments for an additional $771$655 million.  As of September 30, 2008,March 31, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $61 million would have been required in order to terminate these construction commitments.$100 million.  If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future net income, cash flows and possibly financial condition.

IGCC Plants

The construction of the West Virginia and Ohio IGCC plants are pending necessary permits and regulatory approvals.  In MayApril 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC’s previous denial ofissued an order denying APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia.  In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant.  Comments were filed by various parties, including APCo, but the WVPSC has not taken any action.  In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant contingent upon the commencement of construction, qualifying expenses being incurred and certification of the IGCC plant prior to July 2010.  Through September 30, 2008,March 2009, APCo deferred for future recovery preconstruction IGCC costs of $19$20 million.  If the West Virginia IGCC plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is cancelled and if the deferred costs are not recoverable, it would have an adverse effect on future net income and cash flows.

In Ohio, neither CSPCo nor OPCo are engaged in a continuous course of construction on the IGCC plant.  However, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant.  In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1pre-construction cost recoveries be refunded to Ohio ratepayers with interest.  CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  If CSPCo and OPCo were required to refund some or all of the $24 million collected for IGCC pre-construction costs and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future net income and cash flows.

In the ordinary course of business, we along with our subsidiaries, are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assessassesses the probability of loss for such contingencieseach contingency and accrues a liability for cases that have a probable likelihood of loss and if the loss amount can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20072008 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to materially affect our net income.income and cash flows.

Environmental Litigation

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

Clean Water Act Regulations

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

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

In April 2008,2009, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appealsissued a decision that limitallows the Federal EPA’s abilityEPA the discretion to weighrely on cost-benefit analysis in setting national performance standards and in providing for cost-benefit variances from those standards as part of the retrofittingregulations.  We cannot predict if or how the Federal EPA will apply this decision to any revision of the regulations or what effect it may have on similar requirements adopted by the states.

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

In September 2006, theThe FASB issued SFAS 157 “Fair Value Measurements”141R (revised “Business Combinations” 2007) improving financial reporting about business combinations and their effects.  SFAS 141R can affect tax positions on previous acquisitions.  We do not have any such tax positions that result in adjustments.  We adopted SFAS 141R effective January 1, 2009.  We will apply it to any future business combinations.

The FASB issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 157)160), modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements.  The statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest.  We adopted SFAS 160 effective January 1, 2009 and retrospectively applied the standard to prior periods.  See Note 2.

The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing existing guidancedisclosure requirements for fair value measurement of assetsderivative instruments and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.hedging activities.  The standard requires fair value measurementsthat objectives for using derivative instruments be disclosed by hierarchy level, an entity includes its own credit standing in the measurementterms of its liabilitiesunderlying risk and modifies the transaction price presumption.  accounting designation.  This standard increased our disclosure requirements related to derivative instruments and hedging activities.  We adopted SFAS 161 effective January 1, 2009.

The standard also nullifies the consensus reached inFASB ratified EITF Issue No. 02-3 “Issues Involved in08-5 “Issuer’s Accounting for Derivative Contracts Held for Trading PurposesLiabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on liabilities with third-party credit enhancements when the liability is measured and Contracts Involveddisclosed at fair value.  The consensus treats the liability and the credit enhancement as two units of accounting.  We adopted EITF 08-5 effective January 1, 2009.  It will be applied prospectively with the effect of initial application included as a change in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.  In February 2008, the liability.

The FASB issued FSP SFAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  In October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” which clarifies application ofAs defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets that are notfor identical assets or liabilities and the lowest priority to unobservable inputs.  In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and provides an illustrative example.  The provisions ofexternal valuation methods including cash flow analysis and appraisals.  We adopted SFAS 157 are applied prospectively, except for a) changes in157-2 effective January 1, 2009.  We will apply these requirements to applicable fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction pricewhich include new asset retirement obligations and c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157impairment analysis related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings.  The impact of considering our own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact onlong-lived assets, equity investments, goodwill and intangibles.  We did not record any fair value measurements upon adoption.  We partially adopted SFAS 157 effective January 1, 2008.  FSP SFAS 157-3 is effective upon issuance.  We will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP SFAS 157-2.  We expect that the adoption of FSP SFAS 157-2 will have an immaterial impact on our financial statements.  See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.