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AEP > SEC Filings for AEP > Form 10-Q on 26-Oct-2012All Recent SEC Filings




Quarterly Report



June 2012 - May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP through May 2015. The ESP allowed the continuation of the fuel adjustment clause and established a non-bypassable Distribution Investment Rider (DIR) effective September 2012 through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The DIR is capped at $86 million in 2012, $104 million in 2013, $124 million in 2014 and $52 million for the period January through May 2015, for a total of $366 million. The ESP also maintained recovery of several previous ESP riders and required OPCo to contribute $2 million per year during the ESP to the Ohio Growth Fund. In addition, the ESP approved a storm damage recovery mechanism which allowed OPCo to defer the majority of the incremental distribution operation and maintenance costs from 2012 storms.

Finally, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the standard service offer (SSO) load with delivery beginning six months after the receipt of ESP and corporate separation orders and extending through December 2014. The PUCO also ordered OPCo to conduct an energy-only auction for a total of 60% of the SSO load with delivery beginning June 2014 through May 2015. In addition, the PUCO ordered OPCo to conduct an energy-only auction for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. Starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load. In September 2012, OPCo and intervenors filed applications with the PUCO for rehearing. Rehearing of this order is pending at the PUCO.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of 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. Several parties, including OPCo, requested rehearing of the July 2012 PUCO order, which was upheld by the PUCO in October 2012. In the August 2012 PUCO order which adopted and modified the new ESP, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is intended to provide $508 million over the ESP period and will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the deferred capacity costs. In August 2012, the Industrial Energy Users-Ohio (IEU) filed a claim before the Supreme Court of Ohio stating, among other things, that OPCo's collection of its capacity costs is illegal. OPCo and the PUCO filed motions to dismiss IEU's claim. If OPCo is ultimately not permitted to fully collect its deferred capacity costs and ESP rates, including the RSR, it would reduce future net income and cash flows and impact financial condition. 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 third quarter of 2011 and the first nine months of 2011, we lost approximately $67 million and $165 million, respectively, of gross margin. This reduction in gross margin is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) Retail Stability Rider collections from Ohio retail distribution customers and (e) revenues from AEP Energy, our CRES provider and member of our Generation and Marketing segment. As of September 30, 2012, based upon an average annual load, approximately 42% of our Ohio load had switched to CRES providers and approximately 6% of our Ohio load had formally initiated the switching process to a CRES provider for a total of 48%. To enhance our competitive position in Ohio, AEP Energy targets retail customers, both within and outside of our retail service territory.

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. In October 2012, the PUCO issued an order which approved the transfer of OPCo's generation assets at net book value to AEP Generation Resources, Inc. (AEPGenCo), a nonregulated affiliate in the Generation and Marketing segment. AEPGenCo will also assume the associated generation liabilities. Management intends to file an application with the FERC in the fourth quarter of 2012 related to corporate separation. Our results of operations related to generation in Ohio will be largely 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.

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. Management intends to file an application with the FERC in the fourth quarter of 2012 to terminate the Interconnection Agreement. It is unknown 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. 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.

Based on the interdependent nature of generation activities subject to the Interconnection Agreement, the AEP East companies' generation assets are evaluated for their accounting recoverability collectively as an asset group. 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 accounting evaluation of the recoverability of the net book values of OPCo's generation assets. The net book value of the OPCo units that we plan to retire included in the table below in the "Environmental Controls Impact on the Generating Fleet" section and our share of W. C. Beckjord Generating Station was $284 million as of September 30, 2012. These generating assets are being depreciated through May 2015.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011. In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group 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 a portion 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 one month after the PUCO issues an order on the 2010 SEET. 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 an increase of approximately $25 million in annual depreciation expense. Included in the depreciation rates increase was a decrease in the average remaining life of Tanners Creek Plant to account for the change in the retirement date of Tanners Creek Plant, Units 1-3 from 2020 to 2014. In May 2012, I&M filed rebuttal testimony which changed the retirement date for Tanners Creek Plant, Units 1-3 to 2015.

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 included a return on and of the Texas jurisdictional share of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operations and maintenance costs. In September 2012, an Administrative Law Judge issued an order that granted the establishment of SWEPCo's existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates. A decision from the PUCT is expected in the second quarter of 2013. See "2012 Texas Base Rate Case" section of Note 2.

Special Rate Mechanism for Ormet

In October 2012, the PUCO issued an order approving a delayed payment plan for Ormet of its October and November 2012 power billings in equal monthly installment payments over the period January 2014 to May 2015 without interest. In the event Ormet, a large industrial customer in Ohio, does not pay the deferred billings, the PUCO permitted OPCo to recover the unpaid balance up to $20 million in future rates. To the extent unpaid deferred billings exceed $20 million, it will reduce future net income and cash flows.

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. As a result, the NRC issued orders and guidance that increase procedures and testing requirements, require physical modifications to the plant and will increase future operating costs at the Cook Plant. We anticipate that future cumulative compliance costs will range from $40 million to $50 million. Approximately half of this estimate is expected to be capital. The remainder will be operating expenses that generally is expected to be incurred over the plant's life.

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 increasing oversight of nuclear generating facilities. We are unable to predict the impact of potential future regulation of nuclear facilities.

Cook Plant 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. A hearing at the IURC is scheduled for January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Need and authorize I&M to defer, on an interim basis, incremental depreciation and related property tax costs, including interest, along with study, analysis and development costs until the applicable LCM costs are included in I&M's base rates. As of September 30, 2012, I&M has incurred $109 million related to the LCM Project, including AFUDC. Several intervenors filed testimony with various recommendations. If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows. See "Cook Plant Life Cycle Management Project" section of Note 2.


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.


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 September 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. If natural gas conversion is not completed, the units could be closed sooner than planned.

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:

              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.

In September 2012, based upon an agreement in principle with the Federal EPA, the State of Oklahoma and other parties, PSO filed an environmental compliance plan with the OCC to retire Units 3 and 4 of the Northeastern Station, a total of 930 MWs, in 2026 and 2016, respectively. See "Oklahoma Environmental Compliance Plan" and "Regional Haze" sections below.

Natural gas prices and pending environmental rules could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of certain coal-fired units. We are still evaluating our 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 based on 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 under our accounting evaluations, it could materially reduce future net income and cash flows.

Environmental Compliance Applications

Rockport Plant Environmental Controls

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 September 30, 2012, we have incurred $48 million, including AFUDC. If we are not ultimately permitted to recover our incurred costs, it would reduce future net income and cash flows.

In July 2012, certain intervenors filed testimony which recommended cost 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 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. A hearing is scheduled for December 2012.

Big Sandy Unit 2 FGD System

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

Flint Creek Plant Environmental Controls

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 September 30, 2012, SWEPCo has incurred $10 million related to this project, including AFUDC. The APSC staff and the Sierra Club filed testimony that recommended the APSC deny the requested declaratory order. A hearing at the APSC was held in October 2012 and a decision is pending from the APSC. If SWEPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC which requested approval for (a) full cost recovery through base rates by 2026 of an estimated $256 million of new environmental investment that will be incurred prior to 2016 at Northeastern Station Unit 3, (b) full cost recovery through 2026 of Northeastern Station Units 3 and 4 net book value (combined net book value of the two units is $235 million as of September 30, 2012), (c) full cost recovery through base rates of an estimated $83 million of new investment incurred through 2016 at various gas units and (d) a new 15-year purchase power agreement with Calpine Oneta Power, effective in 2016, with cost recovery through a rider, including an earnings component of $3 million. Although the environmental compliance plan does not seek to put any new costs into rates at this time, PSO anticipates seeking cost recovery when filing its next base rate case, which is expected to occur no later than 2014.

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 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. The Arkansas SIP was disapproved and the state is developing a revised submittal. 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. This rule is being challenged in the United States Court of Appeals for the District of Columbia Circuit and its fate is uncertain given recent developments in the CSAPR litigation.

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 . . .

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