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 ____

INDEX TOOF QUARTERLY REPORTS ON FORM 10-Q

FORWARD-LOOKING INFORMATION

EXECUTIVE OVERVIEW

Economic Conditions

Retail margins increased during the first nine monthsquarter of 20102011 due to successful rate proceedings in our various jurisdictions and higher overall industrial usage partially offset by decreased residential and commercial demand for electricityusage primarily as a result of less favorable weatherweather.  While lower in comparison to the first quarter of 2010, heating degree days were higher than normal throughout our service territories.  In comparison to the recessionary lows of 2009,Our industrial sales increased 6%7% primarily due to increased production levels by Ormet, a large aluminum manufacturer in the third quarter and 5% during the first nine months of 2010.Ohio.

Regulatory Activity

Turk Plant

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.  See “Turk Plant” section of Note 2.

Ohio Customer Choice

In our Ohio service territory, various certifiedcompetitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As of September 30, 2010,Through March 31, 2011, approximately 2,0007,800 Ohio retail customers (primarily CSPCo customers) have switched to alternative CRES providers while approximately 1,200 additional Ohio customers have provided notice of their intent to switch.providers.  As a result, in comparison to 2009,the first three months of 2010, we lost approximately $5$18 million of generation related gross margin through September 30, 2010 and currently forecast incremental lost margins of approximately $10 million and $53 million for the fourth quarter of 2010 and for all of 2011, respectively.March 31, 2011.  We anticipate recovery of a portion of this lost margin through off-system sales.  In addition, we havesales, including PJM capacity revenues, and our newly created our ownCRES provider.  Our CRES provider t o targettargets retail customers in Ohio, both within and outside of our retail footprint.

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, theThe replacement of the repaired turbine rotors and other equipment is sch eduledscheduled 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 reduce future net income and cash flows and impact financial condition.  See “Indiana Fuel Clause Filing”“Michigan 2009 and “Michigan 20092010 Power Supply Cost Recovery Reconciliation” sectionsReconciliations” section of Note 32 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.3.

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.Court of Texas.  Review is discretionary and the Texas Supreme Court of Texas has not yet determined if it will grant review.  See “Texas Restructuring Appeals” section of Note 3.2.

Mountaineer Carbon Capture and Storage Project

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility under consideration at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility.  Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility.  As of March 31, 2011, APCo has incurred $25 million in total costs and has received $7 million of DOE eligible funding resulting in a net $18 million balance included in Construction Work In October 2010, we announced our capital expenditure budgetsProgress on the Condensed Consolidated Balance Sheets.  Upon the completion of $2.6 billionthe FEED study and $2.9 billion for 2011the expected reimbursement of eligible cash expenditures, principally from the DOE, APCo expects a net investment of approximately $13 million.  If APCo is unable to recover the costs of the CCS project, it would reduce future net income and 2012, respectively.cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 2.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss 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”Analysis” in the 20092010 Annual Report.  Additionally, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to materially affect our net income.

ENVIRONMENTAL ISSUES

Clean Air Act Transport Rule (Transport Rule)

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants.  The CAMR was vacated and remanded to the Federal EPA by the D.C. Circuit Court of Appeals in 2008.  The Federal EPA issued an information collection request to owners and operators of existing power plants in 2010 to collect information to support the development of a maximum achievable control technology (MACT) standard for mercury and other hazardous air pollutant emissions under the CAA.  Under the terms of a consent decree,In response, the Federal EPA is required to issue final MACT standards forhas been developing a rule addressing a broad range of hazardous air pollutants from coal and oil-fired power plants by November 2011. 0;plants.  The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has substantial discretionnot yet been published in determining howthe Federal Register.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups.  A one-year extension may be available if the extension is necessary for the installation of controls.  We are developing comments to structuresubmit to the MACT standards.  agency and collecting additional information regarding the performance of our coal-fired units.  Comments will be accepted for 60 days after the rule is published in the Federal Register.

We will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  However, weWe have approximately 5,0005,500 MW of older coal units including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls.

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 our 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 init iateinitiate closure within five years of the issuance of a final rule.

Currently, approximately 40% of the coal ash and other residual products from our 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, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities.  We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as a total of $3.9 billion including AFUDC for un itsunits across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.

In March 2011, the Federal EPA Administrator signed a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment requires closed cycle cooling or a site-specific evaluation of the available measures for reducing entrainment.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We will seek recoveryare evaluating the proposal and engaged in the collection of expenditures for pollution control technologies and associated costs from customers throughadditional information regarding the feasibility of implementing this proposal at our regulated rates (in regulated jurisdictions).  We should be able to recover these expenditures through market pricesfacilities.  Comments on the proposal are due within 90 days after the rule is published in deregulated jurisdictions.  If not, these costs could adversely affect future net income, cash flows and possibly financial condition.the Federal Register.

Global Warming

RESULTS OF OPERATIONS

SEGMENTS

Our reportable segments and their related business activities are as follows:

Utility Operations

AEP River Operations

Generation and Marketing

The table below presents our consolidated Net Income (Loss) Before Extraordinary Loss by segment for the three and nine months ended September 30, 2010March 31, 2011 and 2009.2010.