EXECUTIVE OVERVIEW

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing. The SSO rates would be effective through May 2015. The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015. The ESP also proposed to collect the Phase-In Recovery Rider from June 2013 through December 2018. Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period. The proposed RSR would be effective through May 2015. Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo's ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. In addition, the PUCO staff's testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis. A decision from the PUCO is expected in August 2012. See "Ohio Electric Security Plan Filing" section of Note 2.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the second quarter of 2011 and the first six months of 2011, we lost approximately $56 million and $99 million, respectively, of gross margin. We are recovering a portion of lost margins through collection of capacity revenues from CRES providers, off-system sales and new revenues from AEP Retail Energy Partners LLC, our CRES provider and member of our Generating and Marketing segment. We have lost 34% of our Ohio load to CRES providers. To enhance our competitive position in Ohio, AEP Retail Energy Partners LLC targets retail customers, both within and outside of our retail service territory.

Ohio Capacity Rate

In March 2012, in response to OPCo's motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo's current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day. In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 - May 2015 ESP proceeding. The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo's pending June 2012 - May 2015 ESP proceeding, whichever is sooner. In July 2012, OPCo requested rehearing of the PUCO order. See "Ohio Electric Security Plan Filing" section of Note 2.

Proposed Corporate Separation and Termination of the Interconnection Agreement

In March 2012, OPCo filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value. Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future. If all regulatory approvals are received, our results of operations related to generation in Ohio will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market. If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition. A decision is pending from the PUCO.

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Sustainable Cost Reductions

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings. We recorded a charge to expense of $13 million in the second quarter of 2012 related to the elimination of approximately 170 positions in the first phase of this process. In May 2012, we selected one consulting firm to conduct an organizational and process optimization evaluation and a second consulting firm to evaluate our current employee benefit programs. The second phase of this process is expected to be completed by the end of 2012 with additional cost reductions.

Storm Damage

In late June 2012 and early July 2012, our eastern service territory was significantly impacted by several severe storms. In the second quarter of 2012, AEP recorded minimal incremental operation and maintenance expenses related to the June 2012 storms. AEP expects to incur an estimated $230 million in total storm restoration costs in the third quarter of 2012, including an estimated $70 million in capital spending related to these storms and an estimated $160 million in incremental operation and maintenance costs. We intend to defer the majority of the incremental operation and maintenance costs and seek future recovery. If we are not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011. In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO's SEET decision. In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO's 2009 order. Subsequent testimony and legal briefs from intervenors recommended refunds of 2010 earnings. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. The PUCO approved OPCo's request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo. See "Ohio Electric Security Plan Filing" section of Note 2.

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%. The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%. I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders. Final hearings were held in June 2012. A decision from the IURC is expected in the fourth quarter of 2012. See "2011 Indiana Base Rate Case" section of Note 2.

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 scheduled to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. See "Turk Plant" section of Note 2.

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs. It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

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 cost approximately $400 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. 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 would reduce future net income and cash flows and impact financial condition. See "Cook Plant Unit 1 Fire and Shutdown" section of Note 3.

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) initiated a review of safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant. The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant. Their concern relates to fuel temperatures if abnormal conditions are experienced. We continue to monitor this issue and respond to the NRC's inquiry, as necessary. In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities. We are unable to predict the impact of potential future regulation of nuclear facilities.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2. The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M's base rates. As of June 30, 2012, I&M has incurred $92 million related to the LCM Project. If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

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 predict the eventual resolution, timing or amount of any loss, fine or penalty. 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 3 - Rate Matters, Note 5 - Commitments, Guarantees and Contingencies and the "Litigation" section of "Management's Financial Discussion and Analysis" in the 2011 Annual Report. Additionally, see Note 2 - Rate Matters and Note 3 - Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

We 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 SNF and future decommissioning of our nuclear units. We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules and facilitate a comprehensive analysis of their impacts. The Senate is considering similar legislation. We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the "Environmental Issues" section of "Management's Financial Discussion and Analysis" in the 2011 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. We should be able to recover certain of these expenditures through market prices in deregulated jurisdictions. If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2012, the AEP System had a total generating capacity of 37,035 MWs, of which 23,900 MWs are coal-fired. We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities. Based upon our estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $7 billion between 2012 and 2020. These amounts include investments to convert 1,055 MWs of coal generation to natural gas capacity.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates will also change based on: (a) the states' implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

Subject to the factors listed above and based upon our continuing evaluation, we have given notice to the applicable RTOs of our intent to retire the following plants or units of plants before or during 2016:

                                                           Generating
              Company        Plant Name and Unit            Capacity
                                                            (in MWs)
             APCo      Clinch River Plant, Unit 3                  235
             APCo      Glen Lyn Plant                              335
             APCo      Kanawha River Plant                         400
             APCo/OPCo Philip Sporn Plant, Units 1-4               600
             I&M       Tanners Creek Plant, Units 1-3              495
             KPCo      Big Sandy Plant, Unit 1                     278
             OPCo      Conesville Plant, Unit 3                    165
             OPCo      Kammer Plant                                630
             OPCo      Muskingum River Plant, Units 1-4            840
             OPCo      Picway Plant                                100
             SWEPCo    Welsh Plant, Unit 2                         528
             Total                                               4,606

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015. OPCo owns 12.5% (54 MWs) of one unit at that station.

We are monitoring the potential impact that the proposed corporate separation of OPCo's generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo's generation assets.

In April 2012, we reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO's Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit in 2016 and retire the second unit no later than 2026. These two coal-fired units have a combined generating capacity of 930 MWs. The parties are working toward a final settlement agreement.

Plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Environmental Control Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its Rockport Plant with environmental controls estimated to cost $1.4 billion to comply with new requirements. AEGCo and I&M jointly own Unit 1 and jointly lease Unit 2 of the Rockport Plant. I&M is also evaluating options related to the maturity of the lease for Rockport Plant Unit 2 in 2022 and continues to investigate alternative compliance technologies for these Units as part of its overall compliance strategy. As of June 30, 2012, AEGCo and I&M have incurred $10 million and $10 million, respectively, related to this project.

In July 2012, certain intervenors filed testimony which recommended costs caps ranging from $1.1 billion to $1.4 billion if the IURC approved the CPCN. In addition, the Indiana Office of Utility Consumer Counselor recommended the CPCN be denied until a more detailed and precise project plan and cost estimates are filed with the IURC. If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism. An IURC decision is expected in the fourth quarter of 2012.

In May 2012, KPCo filed a motion with the KPSC to withdraw its application seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system. The motion was accepted by the KPSC in May 2012. KPCo is currently re-evaluating its needs to meet the short and long-term energy needs of its customers at the most reasonable costs. KPCo has not determined its future plan. As of June 30, 2012, KPCo has incurred $29 million related to the project. Management intends to pursue recovery of all costs related to this project. If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Flint Creek Plant

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo's portion of those costs is estimated at $204 million. Through June 30, 2012, SWEPCo has incurred $9 million related to this project. In June 2012, the APSC staff and the Arkansas Attorney General's office filed testimony that recommended additional analysis be performed in order to reach a final conclusion. The Sierra Club filed testimony that recommended the APSC deny the declaratory order. SWEPCo is currently reviewing the testimony and will file rebuttal testimony on July 30, 2012. A decision is pending from the APSC.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation's air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA's requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs). The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma. The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO2 emissions from affected units in that state. No action has been finalized in Arkansas. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. As a result, depending on how the states decide to implement the CAVR, compliance with the CSAPR requirements may be sufficient to satisfy CAVR's BART requirements without the need for additional unit-specific controls.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NOx and lead, and is currently reviewing the NAAQS for ozone and PM. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations. We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in March 2012. CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012. Arkansas and Louisiana are subject only to the seasonal NOx program in the rule. Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the rule. Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In December 2011, the court granted the motions for stay. Oral argument was heard in April 2012. A supplemental rule includes Oklahoma in the seasonal NOx program. The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year. A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal. The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR. Challenges to these rules have also been filed, but are being held in abeyance pending a decision in the main appeal.

The time frames and stringency of the required 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 our electric utility customers. We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury . . .