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AEP > SEC Filings for AEP > Form 10-Q on 26-Jul-2013All Recent SEC Filings

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Form 10-Q for AMERICAN ELECTRIC POWER CO INC


26-Jul-2013

Quarterly Report


MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets at net book value (NBV) to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.

Also in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at NBV approximately 9,200 MW of OPCo-owned generation assets to AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo's current two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo's Mitchell Plant to APCo and KPCo in equal one-half interests. In December 2012, APCo and KPCo filed requests with their respective commissions for the approval of the plant transfers discussed above. We are currently pursuing cost recovery of these plants in Kentucky and West Virginia and plan to pursue cost recovery in Virginia. In April 2013, the FERC issued orders approving the merger of APCo and WPCo and approving the transfer of OPCo's generation assets to AEPGenCo and the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo, to be effective using our requested date of December 31, 2013. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo strongly contested the petition for rehearing, which remains pending before the FERC. In June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the plant transfer discussed above. The Attorney General was not party to the settlement agreement. If approved, KPCo will withdraw the current base rate case request and current rates will remain in effect until at least May 2015. Hearings in the plant transfer cases were held at the Virginia SCC in June 2013 and at the KPSC and WVPSC in July 2013. See the "Plant Transfers" sections of APCo and WPCo Rate Matters and KPCo Rate Matters in Note 3 and the "2013 Kentucky Base Rate Case" section below.

The AEP East Companies also requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. In March 2013, a revised PCA was filed at the FERC that included certain clarifying wording changes agreed upon by intervenors. A decision is pending at the FERC. See the "Corporate Separation and Termination of Interconnection Agreement" section of Note 3.

Additionally, FERC approval was sought for a power supply agreement between AEPGenCo and OPCo. This agreement provides for AEPGenCo to supply capacity for OPCo's switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.

If approved as filed, for any AEPGenCo generation not serving OPCo's retail load, AEPGenCo's results of operations will be largely determined by prevailing market conditions effective January 1, 2014. If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.


Ohio Electric Security Plan Filing

2009 - 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo's deferred fuel costs in rates beginning September 2012. As of June 30, 2013, OPCo's net deferred fuel balance was $484 million, excluding unrecognized equity carrying costs. Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance.

June 2012 - May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

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 up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As of June 30, 2013, OPCo's incurred deferred capacity costs balance was $171 million, including debt carrying costs.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is expected to provide approximately $500 million of revenue 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 recovery of deferred capacity costs.

In June 2013, intervenors in the competitive bid process (CBP) docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo's non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo's non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). Depending upon actual customer switching levels and the timing of the auctions, OPCo estimates that these capacity issues could reduce OPCo's projected future revenues by up to approximately $160 million through May 2015. An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. See "Ohio Electric Security Plan Filing" section of Note 3.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. The reduction in gross margin as a result of customer switching in Ohio 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 and (e) revenues from AEP Energy. AEP Energy is our CRES provider and part of our Generation and Marketing segment which targets retail customers, both within and outside of our retail service territory.


Customer Demand

In comparison to 2012, our weather-normalized retail sales were down 2.7% and 2.1% for the three and six months ended June 30, 2013, respectively. Our industrial sales declined 5.3% and 5.7%, respectively, partially due to Ormet, a large aluminum company that lowered their production in the third quarter of 2012 by one-third and is currently in bankruptcy proceedings.

PJM Capacity Market

If corporate separation and asset transfers are approved as filed, AEPGenCo will be subject to the PJM capacity auction prices after May 2015 for the majority of the current OPCo-owned generation assets. Under the previously approved June 2012 - May 2015 ESP, OPCo is allowed to receive revenues through May 2015 for the generation assets from base generation rates and allowed to defer incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The PJM base capacity price for the planning year June 2015 through May 2016 was previously announced as $136.00/MW day. In May 2013, PJM announced the base capacity auction price for the June 2016 through May 2017 planning period would be $59.37/MW day.

Significantly Excessive Earnings Test

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 a refund of up to $62 million of 2010 earnings. OPCo provided a reserve based upon management's estimate of the probable amount for a PUCO-ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. See the "Ohio Electric Security Plan Filing" section of Note 3.

U.K. Windfall Tax Decision

In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash during the second quarter of 2013.

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of June 30, 2013, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital cost cap, SWEPCo has capitalized approximately $1.8 billion of expenditures, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the SPP market. If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the "Turk Plant" section of Note 3.


2012 Texas Base Rate Case

In 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 operation and maintenance costs. In September 2012, an Administrative Law Judge (ALJ) 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.

In December 2012, several intervenors filed opposing testimony and in May 2013, the ALJ issued a proposal for decision (PFD) and added clarifications to the PFD in July 2013. The PFD, as clarified, made various recommendations including (a) an annual base rate increase of approximately $41 million based upon a return on common equity of 9.65%, (b) the disallowance of the Turk Plant capital costs in excess of the investment and committed costs as of June 2010 plus the cost to retrofit Welsh Plant, Unit 2 which, as of June 30, 2013, SWEPCo estimates could result in a write-off of approximately $74 million (in excess of the $62 million reserve previously recorded related to the Texas capital cost cap) and (c) the exclusion, until SWEPCo's next Texas base rate case, of the Turk Plant transmission line investment that was not in service at the end of the test year. A decision from the PUCT is expected in the third quarter of 2013. If the PUCT does not approve full cost recovery of SWEPCo's Texas jurisdictional share of assets, it could reduce future net income and cash flows and impact financial condition. See the "2012 Texas Base Rate Case" section of Note 3.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant. In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013. The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover all non-fuel Turk Plant costs and a full weighted-average cost of capital return on the Turk Plant portion of rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See the "2012 Louisiana Formula Rate Filing" section of Note 3.

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor filed an appeal of the order with the Indiana Court of Appeals. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. See the "2011 Indiana Base Rate Case" section of Note 3.

2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase includes the cost recovery of the pending transfer of the one-half interest in the Mitchell Plant, cost recovery of Big Sandy Plant, Units 1 and 2 and includes requests for recovery of deferrals related to the Big Sandy Plant FGD project and 2012 storm costs. Also in June 2013, a settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club was filed with the KPSC which supported the Mitchell plant transfer discussed above. If the settlement agreement is approved, KPCo will withdraw this base rate case request and current rates will remain in effect until at least May 2015. If KPCo is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition. See the "2013 Kentucky Base Rate Case" section of Note 3.


Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of June 30, 2013, I&M has incurred $240 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items which the IURC stated could be sought for recovery in a base rate case. I&M was granted recovery through an LCM rider which will be determined by a mid-September 2013 proceeding and semi-annual proceedings thereafter. The IURC authorized deferral accounting for I&M's incurred project costs effective January 2012 to the extent such costs are not reflected in its rates.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. See "Cook Plant Life Cycle Management Project (LCM Project)" section of Note 3.

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 Discussion and Analysis of Financial Condition and Results of Operations" in the 2012 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 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 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 (HAPs) from fossil fuel-fired power plants, 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, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. 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 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 Discussion and Analysis of Financial Condition and Results of Operations" in the 2012 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Recovery in Ohio will be dependent upon prevailing market conditions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If we are unable to recover the costs of environmental compliance, it would 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, 2013, the AEP System had a total generating capacity of 37,600 MWs, of which 23,700 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, investments to meet these proposed requirements range from approximately $4 billion to $5 billion through 2020. These amounts include investments to convert some of our coal generation units to natural gas. If natural gas conversion is not completed, the units could be retired 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 intend 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 2                    800
             OPCo        Kammer Plant                               630
             OPCo        Muskingum River Plant, Units 1-5         1,440
             OPCo        Picway Plant                               100
             PSO         Northeastern Station, Unit 4               470
             SWEPCo      Welsh Plant, Unit 2                        528
             Total                                                6,033

As of June 30, 2013, the net book value of all of OPCo's units above is zero and the net book value including related inventory and CWIP balances of the other plants in the table above was $873 million.

In the second quarter of 2013, we re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit's useful life is remote. As a result, in the second quarter of 2013, we completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for OPCo's net book value of Muskingum River Plant, Unit 5. We expect to retire the plant no later than 2015. See "Muskingum River Plant, Unit 5" section of Note 5.


In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units. The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

                                                              Generating
               Company            Plant Name and Unit          Capacity
                                                               (in MWs)
            APCo             Clinch River Plant, Units 1-2           470
            I&M/AEGCo/KPCo   Rockport Plant, Units 1-2             2,620
            I&M              Tanners Creek Plant, Unit 4             500
            KPCo             Big Sandy Plant, Unit 1                 278
            PSO              Northeastern Station, Unit 3            460
            Total                                                  4,328

As of June 30, 2013, the net book value including related inventory and CWIP balances of the plants in the table above was $1.3 billion.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units. For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values. 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.

Modification of the New Source Review (NSR) Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree's terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.

The consent decree requires certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019. In January 2013, an agreement to modify the consent decree was reached and filed with the court. The terms of the . . .

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