Our transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international conventions. Legislation has been proposed that could make our towboats subject to inspection by the U.S. Coast Guard.

EXECUTIVE OFFICERS OF AEP as of February ~~25, 2014~~20, 2015

The following persons are executive officers of AEP. Their ages are given as of February 1, ~~2014.~~2015. The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins

Chairman of the Board, President and Chief Executive Officer

Age 5354

Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011. Was Executive Vice ~~President-Generation~~President – Generation from September 2006 to December 2010.

Lisa M. Barton

Executive Vice President – Transmission

Age 4849

Executive Vice ~~President-Transmission~~President – Transmission of AEPSC since August 2011. Was Senior Vice ~~President-Transmission~~President – Transmission Strategy and Business Development of AEPSC from November 2010 to July 2011, Vice ~~President-Transmission~~President – Transmission Strategy and Business Development of AEPSC from October 2007 to November 2010.

David M. Feinberg

Executive Vice President, General Counsel and Secretary

Age 4445

Executive Vice President since January 2013. Was Senior Vice President, General Counsel and Secretary from January 2012 to December 2012 and Senior Vice President and General Counsel of AEPSC from May 2011 to December 2011. Previously served as Vice President, General Counsel and Secretary of Allegheny Energy, Inc. from 2006 to 2011.

Lana L. Hillebrand

Senior Vice President and Chief Administrative Officer

Age 5354

Senior Vice President and Chief Administrative Officer since December 2012. Previously served as South Region ~~leader-Senior~~leader – Senior Partner at Aon Hewitt since 2010. Was U.S. Consulting Client Development ~~leader-managing~~leader – managing principal at Aon Hewitt from 2008-2010.

Mark C. McCullough

Executive Vice President – Generation

Age 5455

Executive Vice ~~President-Generation~~President – Generation of AEPSC since January 2011. Was Senior Vice ~~President-Fossil~~President – Fossil & Hydro Generation of AEPSC from February 2008 to December 2010.

Robert P. Powers

Executive Vice President and Chief Operating Officer

Age 5961

Executive Vice President and Chief Operating Officer since November 2011. Was ~~President-Utility~~President – Utility Group from April 2009 to November ~~2011, President-AEP Utilities from January 2008 to April 2009.~~2011.

Brian X. Tierney

Executive Vice President and Chief Financial Officer

Age 4647

Executive Vice President and Chief Financial Officer since October 2009. ~~Was Executive Vice President-AEP Utilities East of AEPSC from January 2008 to October 2009.~~

Dennis E. Welch

Executive Vice President and Chief External Officer

Age 6263

Executive Vice President and Chief External Officer since January 2013. Was Executive Vice President and Chief Administrative Officer from October 2011 to December 2012. Was Executive Vice ~~President-Environment,~~President – Environment, Safety & Health and Facilities from January 2008 to September 2011.

Charles E. Zebula

Executive Vice President – Energy Supply

Age 54

Executive Vice President – Energy Supply since January 2013. Was Senior Vice President – Investor Relations and Treasurer from September 2008 to December 2012.

ITEM 1A. RISK FACTORS

GENERAL RISKS OF OUR REGULATED OPERATIONS

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions. – Affecting each Registrant

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction of additional transmission facilities, modernizing existing infrastructure as well as other initiatives. Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment. This would cause our financial results to be diminished.

~~Approval~~Our regulated electric revenues, earnings and results are dependent on state regulation that may limit our ability to recover costs and other amounts. – Affecting each Registrant

The rates our customers pay to our regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Ohio, Texas, Virginia, West Virginia, Oklahoma, Indiana, Louisiana, Kentucky, Arkansas, Michigan and Tennessee. If our regulated utility earnings exceed the ~~June 2012 through May 2015 ESP order in Ohio~~returns established by the relevant commissions, retail electric rates may be ~~overturned and is~~ subject to ~~appeal. – Affecting AEP~~review and ~~OPCo~~

~~In August 2012,~~possible reduction by the ~~PUCO issued an order~~commissions, which ~~adopted and modified an ESP through May 2015 (the “2012 ESP”). The 2012 ESP allowed the continuation of the fuel adjustment clause, maintained~~may decrease our future earnings. Additionally, if regulatory bodies do not allow recovery of ~~several previous ESP riders and approved~~costs incurred in providing service on a storm damage recovery mechanism. The 2012 ESP further established (a) a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover certain distribution investment, and (b) a non-bypassable Retail Stability Rider (RSR), a portion of which provides for the collection of deferred capacity costs. The deferred capacity costs may exceed the amount we will collect under the RSR. In January 2013, the PUCO issued an order on rehearing for the 2012 ESP which generally upheld its prior order. Intervenors are challenging various parts of these orders at the PUCO and with the Supreme Court of Ohio. In parallel proceedings, the PUCO addressed certain issues around the energy auctions while other issues were deferred to a separate docket. The PUCO has agreed to issue a request for an independent auditor in the fuel adjustment clause proceeding to separately examine the recovery of the fixed fuel costs. If all or part of 2012 ESP is overturned by the PUCO or the Supreme Court of Ohio, or if deferred capacity and other costs are not recoverable,timely basis, it could reduce future net income and cash flows and impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, our future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost, including fuel and related costs, generally results in an impairment to the balance sheet and a charge to the income statement of the company involved.

~~Our request for an ESP from June 2015 through May 2018 may not be approved in its entirety. – Affecting AEP and OPCo~~

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, effective June 2015 through May 2018. The proposal includes a return on common equity of 10.65% for certain riders. Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR in which the unrecovered portion of the deferred capacity costs will continue to be collected until the balance of the capacity deferrals has been collected. If the PUCO denies all or part of the requested ESP, it could reduce future net income and cash flows and impact financial condition.

~~Ohio may require us to refund revenue that we have collected. – Affecting AEP and OPCo~~

Ohio law requires that the PUCO determine on an annual basis if rate adjustments included in prior orders resulted in significantly excessive earnings. If the PUCO determines there were significantly excessive earnings, the excess amount could be returned to customers. In November 2013, OPCo filed its 2011 and 2012 significantly excessive earnings filings with the PUCO. If the PUCO determines that OPCo’s earnings were significantly excessive, and requires OPCo to return a portion of its revenues to customers, it could reduce future net income and cash flows and impact financial condition.

~~We may not recover deferred fuel costs. – Affecting AEP and OPCo~~

In August 2012, the PUCO ordered recovery of deferred fuel costs beginning September 2012 through the Phase-In Recovery Rider. The August 2012 order was upheld by the PUCO in October 2012. OPCo and intervenors have filed appeals at the Supreme Court of Ohio. If the Supreme Court of Ohio does not permit full recovery of OPCo’s deferred fuel costs, it would reduce future net income and cash flows and impact financial condition.

~~Ohio may require us to refund additional fuel costs. – Affecting AEP and OPCo~~

In January 2012, the PUCO ordered that proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance and that an outside consultant be hired to review our fuel procurement through 2011. The audit by the outside consultant included recommendations that would limit some of our fuel recovery or require us to refund certain fuel costs already incurred. In addition, an intervenor filed an appeal with the Supreme Court of Ohio challenging the recovery of certain fuel costs. Any reduction to our fuel recovery by the PUCO and/or the Supreme Court of Ohio could reduce future net income and cash flows and impact financial condition.

~~We may not fully recover all of the investment in and expenses related to the Turk Plant – Affecting AEP and SWEPCo~~

In December 2012, SWEPCo placed the Turk Plant in Arkansas into commercial operation. SWEPCo holds a 73% ownership interest in the 600 MW coal-fired generating facility. SWEPCo had originally intended that the Arkansas jurisdictional share of the Turk Plant (approximately 20%) would become part of the rate base for its retail customers in Arkansas. Following a proceeding at the Arkansas Supreme Court, the APSC issued an order which reversed and set aside a previously granted Certificate of Environmental Compatibility and Public Need. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. In addition, in February 2013, the LPSC granted recovery for the Louisiana portion of the Turk Plant costs in a formula rate filing, subject to refund based on the staff review of the cost of service and prudence review of the Turk Plant. If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant either through retail rates or sales into the wholesale market, it could reduce future net income and cash flows and impact financial condition.

~~Request for rate recovery in Indiana may be overturned on appeal. – Affecting AEP and I&M~~

In February 2013, the IURC issued an order granting an annual increase in base rates. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case. If any part of the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

~~Approved recovery related to enabling the useful life of the Cook Plant may be overturned on appeal or further consideration. – Affecting AEP and I&M~~

In April and May 2012, I&M filed petitions 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 intended to ensure the safe and reliable operation of the 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. 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 as well as the amount of the CON related to the LCM Project. In July 2013, the IURC approved I&M’s proposed project apart from a minor exception which the IURC stated I&M could seek recovery in a base rate case. I&M was granted recovery through an LCM Project Rider to be determined in a series of proceedings beginning in the fourth quarter of 2013 and then semi-annually thereafter. 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.

~~Request for rate recovery in Texas may not be approved in its entirety and could be overturned. – Affecting AEP and SWEPCo~~

In July 2012, SWEPCo filed a request with the PUCT for an increase in Texas base rates. In October 2013, the PUCT issued an order that granted part of the requested rate recovery. Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

~~Request for rate recovery in Oklahoma may not be approved in its entirety. – Affecting AEP and PSO~~

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. If PSO cannot ultimately recover its costs that are the subject of this request, it could reduce future net income and cash flows and impact financial condition.

Our transmission investment strategy and execution bears certain risks associated with these activities. – Affecting ~~AEP~~each Registrant

We expect that a growing portion of our earnings in the future will derive from the transmission investments and activities of AEPTCo and our transmission joint ventures. FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction. If FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, our strategy of investing in transmission could be curtailed. We believe our experience with transmission facilities construction and operation gives us an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities. However, there can be no assurance that PJM, SPP or other RTOs will authorize any new transmission projects or will award any such projects to us. If the FERC were to lower the rate of return it has authorized for our transmission investments and facilities, or if one or more states were to successfully limit FERC jurisdiction on recovery of costs on transmission investment and its return, it could reduce future net income and cash flows and impact financial condition.

We may not recover costs incurred to begin construction on projects that are canceled. – Affecting each Registrant

Our business plan for the construction of new projects involves a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs. To limit the risks of these construction projects, we enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits. If any of these projects is canceled for any reason, including our failure to receive necessary regulatory approvals and/or siting or environmental permits, we could incur significant cancellation penalties under the equipment purchase orders and construction contracts. In addition, if we have recorded any construction work or investments as an asset, we may need to impair that asset in the event the project is canceled.

~~Rate regulation may delay or deny full recovery of capital improvements, additions, storm damage operations and maintenance expense repairs and other costs. – Affecting each Registrant~~

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year. Thus, commission-approved rates may or may not match a utility’s expenses at any given time. There may also be a delay between the timing of when these costs are incurred and when these costs are recovered. We often finance the operations and maintenance expense to repair facilities damaged by storms or other severe weather events until the operations and maintenance storm costs, including any deferred regulatory assets, are recovered in rates. We have also traditionally financed capital investments and improvements until the new asset was placed in service. Provided the asset was found to be a prudent investment, the asset was then added to rate base and entitled to a return through rate recovery. Similarly, long lead times in construction and scheduled repairs, the high costs of plant and equipment and volatile capital markets have heightened the risks involved in our capital investments, repairs and improvements. While we are actively pursuing strategies to accelerate rate recognition of investments and cash flow, including pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates, there can be no assurance that these will be adopted, that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will be done in a timely manner.

~~Certain of our revenues and results of operations are subject to risks that are beyond our control. – Affecting each Registrant~~

Our operations are structured to comply with all applicable federal and state laws and regulations and we take measures to minimize the risk of significant disruptions. Material disruptions at one or more of our operational facilities, however, could negatively impact our revenues, operating and capital expenditures and results of operations. Such events may also create additional risks related to the supply and/or cost of equipment and materials. We could experience unexpected but significant interruption due to several events, including, but not limited to:

·	~~Major facility or equipment failure.~~

·	~~An environmental event such as a serious spill or release.~~

·	~~Fires, floods, droughts, earthquakes, hurricanes, tornados or other natural disasters.~~

·	~~Wars, terrorist acts (including cyber-terrorism) or threats and other catastrophic events.~~

·	~~Significant health impairments or disease events.~~

·	~~Other serious operational problems.~~

We are exposed to nuclear generation risk. – Affecting AEP and I&M

Through I&M, we own the Cook Plant. It consists of two nuclear generating units for a rated capacity of 2,191 MW, or about 6% of the generating capacity in the AEP System. We are, therefore, subject to the risks of nuclear generation, which include the following:

·	The potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel.

·	Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations.

·	Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the losses of others).

·	Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if and when these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could harm our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Moreover, a major incident at any nuclear facility in the U.S. could require us to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities. Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs. Our ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.

The different regional power markets in which we compete or will compete in the future have changing market and transmission structures, which could affect our performance in these regions. – Affecting each Registrant

Our results are likely to be affected by differences in the market and transmission structures in various regional power markets. The rules governing the various regional power markets, including SPP and PJM, may also change from time to time which could affect our costs or revenues. Because the manner in which RTOs will evolve remains unclear, we are unable to assess fully the impact that changes in these power markets may have on our business.

We could be subject to higher costs and/or penalties related to mandatory reliability standards. – Affecting each Registrant

As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

Our financial performance may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions. – Affecting each Registrant

Our performance is highly dependent on the successful operation of our generation, transmission and distribution facilities. Operating these facilities involves many risks, including:

·	Operator error and breakdown or failure of equipment or processes.

·	Operating limitations that may be imposed by environmental or other regulatory requirements.

·	Labor disputes.

·	Compliance with mandatory reliability standards, including mandatory cyber security standards.

·	Information technology failure that impairs our information technology infrastructure or disrupts normal business operations.

·	Information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims.

·	Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by our suppliers and other factors.

·	Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.

Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information and damage our reputation.– Affecting each Registrant

We own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or our operations could view our computer systems, software or networks as targets for cyber attack. In addition, our business requires that we collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A successful cyber attack on the systems that control our generation, transmission, distribution or other assets could severely disrupt business operations, preventing us from serving customers or collecting revenues. The breach of certain business systems could affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. We maintain cyber insurance to cover liabilities and losses directly arising from a potential cyber event. We also maintain property and casualty insurance that may cover certain resultant physical damage or third-party injuries caused by potential cyber ~~security incidents.~~events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered ~~or may exceed the amount of any insurance available.~~at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.

In an effort to reduce the likelihood and severity of cyber intrusions, we have a comprehensive cyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, we are subject to mandatory cyber security regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that we could experience a successful cyber attack despite our current security posture and regulatory compliance efforts.

If we are unable to access capital markets on reasonable terms, it could reduce future net income and cash flows and impact financial condition. – Affecting each Registrant

We rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows. Volatility and reduced liquidity in the financial markets could affect our ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness. In addition, if capital is available only on less than reasonable terms or to borrowers whose creditworthiness is better than ours, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and impact financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses. – Affecting each Registrant

The credit ratings agencies periodically review our capital structure and the quality and stability of our earnings. Any negative ratings actions could constrain the capital available to us and could limit our access to funding for our operations. Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive. In periods of market turmoil, access to capital is difficult for all borrowers. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and could reduce future net income and cash flows and impact financial condition.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt or on the investment grade ratings of AEP. Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions. If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce ~~our profits.~~future net income and cash flows and impact financial condition.

AEP has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries. – Affecting AEP

AEP is a holding company and has no operations of its own. Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP. Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans

from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments. Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations. AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness.

Our operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. – Affecting each Registrant

Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the terms of power sale contracts that we enter into. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could ~~diminish our results of operations~~reduce future net income and ~~harm our~~cash flows and impact financial condition. Conversely, unusually extreme weather conditions could increase AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions generally result in reduced consumption by our customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues. As a result, ~~our overall operating results in the future may fluctuate on the basis of~~ prevailing economic ~~conditions.~~conditions may reduce our future net income and cash flows and impact financial condition.

Failure to attract and retain an appropriately qualified workforce could harm our results of operations. – Affecting each Registrant

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our ~~results of operations could~~future net income and cash flows may be ~~negatively affected.~~reduced.

~~Parties we have engaged to provide construction materials or services may fail to perform their obligations, which could harm our results of operations. – Affecting each Registrant~~

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades, construction of additional generation units and transmission facilities as well as other initiatives. We are exposed to the risk of substantial price increases in the costs of materials used in construction. We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and almost certainly cause delays in that and related projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This would cause our financial results to be diminished, and we might incur losses or delays in completing construction.

Changes in commodity prices and the costs of transport may increase our cost of producing power or decrease the amount we receive from selling power, harming our financial performance. – Affecting each Registrant

We are exposed to changes in the price and availability of coal and the price and availability to transport coal. We have existing contracts of varying durations for the supply of coal, but as these contracts end or otherwise are not honored, we may not be able to purchase coal on terms as favorable as the current contracts. Similarly, we are exposed to changes in the price and availability of emission allowances. We use emission allowances based on the amount of coal we use as fuel and the reductions achieved through emission controls and other measures. As long as current environmental programs remain in effect, we have sufficient emission allowances to cover the majority of our projected needs for the next two years and beyond. If the Federal EPA is able to create a replacement rule to reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions. If we need to obtain allowances under a

replacement rule, those purchases may not be on as favorable terms as those under the current environmental programs. Our risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

We also own natural gas-fired facilities which exposes us to market prices of natural gas. Historically, natural gas prices have tended to be more volatile than prices for other fuel sources. Recently however, the availability of natural gas from shale production has lessened price volatility. Our ability to make ~~off-system~~ sales at a profit is highly dependent on the price of natural gas. As the price of natural gas falls, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices relative to our ~~off-system~~ sales prices, so the margins we realize from sales will be lower and, on occasion, we may need to curtail operation of marginal plants. We expect the availability of shale natural gas and issues related to its accessibility will have a long-term material effect on the price and volatility of natural gas.

Prices for coal, natural gas and emission allowances have shown material upward and downward swings in the past. Changes in the cost of coal, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power ~~will affect our~~could reduce future net income and cash flows and impact financial ~~results.~~condition.

In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value our trading and marketing transactions, and those differences may be material. As a result, ~~our financial results may be diminished in the future~~ as those transactions are marked to ~~market.~~market, those transactions may reduce future results of operations and cash flows and impact financial condition.

Our AEP River Operations ~~business~~ segment is subject to risks that are beyond our control. – Affecting AEP

Our AEP River Operations ~~business~~ segment transports liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers. These activities can be hazardous and depend on natural conditions and forces. Our river transport operations could result in an environmental event such as a serious spill or release. In addition, if drought conditions or other factors cause the water levels of one or more of these rivers to drop below the amount necessary to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargo on the affected river. Conversely, if unusually high amounts of precipitation or other factors cause the water levels of one or more of these rivers to be too high to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargo on the affected river. Extreme water levels that do not close river basin commercial traffic can still harm our business if the levels curtail the total volume permitted to move on the affected river. The levels on portions of the Mississippi River in 2013 ~~have been reported as remaining at or approaching~~were near the lowest since the levels caused by severe drought in 1988. Water levels during 2014 were improved and generally considered favorable for barge operations. Any reduction in the commercial activities of our AEP River Operations due to ~~low~~extreme water levels could reduce future net income and cash flows.

We are subject to physical and financial risks associated with climate change. – Affecting each Registrant

~~There is a growing consensus on the evidence of global climate change.~~ Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes, hurricanes and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.

We cannot predict the outcome of the legal proceedings relating to our business activities. – Affecting each Registrant

We are involved in legal proceedings, claims and litigation arising out of our business operations, the most significant of which are summarized in Note 6 of the ~~Combined~~ Notes to Consolidated Financial Statements entitled Commitments, Guarantees and Contingencies. Adverse outcomes in these proceedings could require significant expenditures that could ~~have a material adverse effect on our results of operations.~~reduce future net income and cash flows and impact financial condition.

RISKS RELATING TO STATE RESTRUCTURING

Customers are choosing alternative electric generation service providers, as allowed by Ohio law and regulation. – Affecting AEP

Under current Ohio law, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service. CRES providers are targeting retail customers by offering alternative generation service. ~~Through a short term agreement, AGR provides capacity and a decreasing portion of power to the Ohio customers that have not switched.~~ As customer switching in Ohio continues, it could reduce AGR’s future net income and cash flows and impact financial condition.

Collection of our revenues in Texas is concentrated in a limited number of REPs. – Affecting AEP

Our revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distribute to their customers. Currently, we do business with approximately one hundred REPs. In ~~2013,~~2014, TCC’s largest REP accounted for ~~29%~~25% of its operating revenue and its second largest REP accounted for ~~16%~~23% of its operating revenue; TNC’s largest REP accounted for ~~12%~~11% of its operating revenues, and its second largest REP accounted for 7%9% of its operating revenues. Adverse economic conditions, structural problems in the Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or ~~could~~ cause them to delay such payments. We depend on these REPs for timely remittance of payments. Any delay or default in payment could reduce future cash flows and impact financial condition.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Our costs of compliance with existing environmental laws are significant. – Affecting each Registrant

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities and could cause us to retire generating capacity prior to the end of its estimated useful life. These expenditures have been significant in the past, and we expect that they will continue to be significant in order to comply with the current and proposed regulations. Costs of compliance with environmental regulations could reduce future net income and

impact financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed ~~and~~or additional substances become regulated. If we retire generation plants prior to the end of their estimated useful life, there can be no assurance that we will recover the remaining costs associated with such plants. We typically recover our expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers through regulated rates in regulated jurisdictions. Failure to recover these costs could reduce our future net income and cash flows and possibly harm our financial condition. For our sales of energy from our competitive units, there is no such cost-recovery mechanism. As a result, we may not recover our costs through the market and we may be forced to shut competitive units down. The costs of compliance for our competitive units could reduce our future net income and cash flows and possibly harm our financial condition.

Regulation of CO₂ emissions ~~either through legislation or by the Federal EPA,~~ could materially increase costs to us and our customers or cause some of our electric generating units to be uneconomical to operate or maintain. – Affecting each Registrant

The U.S. Congress has not taken any significant steps toward enacting legislation to control CO₂emissions since 2009. In December 2009, the Federal EPA issued a final endangerment finding under the CAA regarding emissions from motor vehicles. The Federal EPA ~~also~~ finalized CO₂emission standards for new motor vehicles and issued a rule that implements a permitting program for new and modified stationary sources of CO₂emissions in a phased manner. Several groups have filed challenges to the endangerment finding and the Federal EPA’s subsequent rulemakings. The Supreme Court ~~has~~ agreed to review whether the Federal EPA reasonably determined that establishing standards for new motor vehicles automatically triggered regulation of stationary sources through the prevention of significant deterioration and Title V permitting ~~programs.~~programs, and determined that the Federal EPA was neither compelled nor authorized to automatically regulate stationary sources of CO₂ emissions under these programs, but that the Federal EPA could establish requirements for best available control technology reviews of CO₂ emissions for sources otherwise required to obtain a Prevention of Significant Deterioration permit if their emissions exceed a reasonable level. The Federal EPA must undertake additional rulemaking to establish such requirements and a reasonable level.

In 2012, the Federal EPA issued a proposed CO₂emissions standard for new power generation ~~sources with a CO~~2 ~~limit equivalent to a natural gas unit.~~sources. In response to the comments submitted on this proposed rule, and in accordance with a directive from the President, the Federal EPA withdrew the April 2012 proposed rule and has issued a new proposal. This proposed rule includes separate, but equivalent, standards for natural gas and coal-fired units, based on the use of partial carbon capture and storage at coal units. ~~We do not believe that carbon capture and storage has been adequately demonstrated, and intend to submit comments on~~In June 2014, the ~~proposed rule. The President has also directed~~ Federal EPA ~~to issue~~issued standards for modified and reconstructed units, and a guideline for the development of state implementation plans that would reduce carbon emissions from existing utility ~~units by June 2014, to finalize those standards by June 2015, and to require states to submit implementation plans no later than June 2016.~~units. The guidelines for existing sources include aggressive emission rate goals that are composed of a number of measures. Management believes some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including AEP and our customers.

If CO₂ ~~and other emission standards are imposed, the~~ standards could require significant increases in capital expenditures and operating costs ~~which would~~and could impact the ~~ultimate~~dates for retirement of ~~older, less-efficient,~~our coal-fired units. We typically recover costs of complying with new requirements such as the potential CO₂ and other greenhouse gases emission standards from customers through regulated rates in regulated jurisdictions. For our sales of energy ~~based on market rate authority,~~into the markets, however, there is no such recovery mechanism. Failure to recover these costs, should they arise, could reduce our future net income and cash flows and possibly harm our financial condition.

We may be harmed if our merchant generation fleet is not profitable or loses value. – Affecting AEP

We are evaluating strategic alternatives for our merchant generation fleet, which primarily includes AGR’s generation fleet which operates in PJM and a 54.7% interest in the Oklaunion Plant which operates in ERCOT. Potential alternatives may include, but are not limited to, continued operation of the merchant generation fleet, executing a PPA with a regulated affiliate for certain merchant generation units in Ohio, a spin-off of the merchant generation fleet or a sale of the merchant generation fleet. We have not made a decision regarding the potential alternatives, nor have we set a specific timeframe for a decision. Certain of these alternatives could result in a loss which could reduce future net income and cash flow and impact financial condition.

Amounts we receive from the results of PJM capacity auctions associated with our nonregulated generation assets could fail to adequately compensate us. – Affecting AEP

~~At the end of last year, AGR acquired most of the generation formerly owned by OPCo. Recovery of~~Financial returns on AGR’s generation capacity isare subject to the results of annual PJM capacity auctions. Recent auction results indicate a great deal of volatility and the possibility of clearing prices substantially lower than the cost of such capacity. We ~~formed~~expect a ~~coalition with other utility companies to address mutual concerns related to~~significant decline in AGR capacity revenues after May 2015 when the Power Supply Agreement between AGR and OPCo ends. Additionally, we expect a decline in AGR capacity revenues from June 2016 through May 2017 based upon the decrease in the PJM base auction ~~process~~price. PJM recently proposed at FERC a set of supplemental auctions for 2016/17 and ~~PJM~~2017/18. Those auctions may mitigate the decline in capacity revenues. However, this proposal has ~~made filings with the~~not yet been accepted at FERC ~~seeking modification of that process. Additional filings are expected. We~~and we can give no assurance that the FERC will approve ~~any modifications to~~ the ~~annual PJM capacity auctions.~~proposal. If the ~~annual~~ PJM capacity auctions continue to result in clearing prices lower than the cost of our capacity, it could reduce our future net income and cash flows and impact financial condition.

Courts adjudicating nuisance and other similar claims ~~against us~~in the future may order us to pay damages or to limit or reduce our CO2emissions. – Affecting each Registrant

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which we, among others, were defendants. In general, the actions allege that CO2emissions from the defendants’ power plants constitute a public ~~nuisance due to impacts of global warming and climate change.~~nuisance. The plaintiffs in these actions generally seek recovery of damages and other relief. If ~~the pending or other~~ future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required and we might be required to limit or reduce CO2 emissions. Such remedies could require us to purchase power from third parties to fulfill our commitments to supply power to our customers. This could have a material impact on our costs. In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. While management believes such costs should be recoverable from customers as costs of doing business in our jurisdictions where generation rates are set on a cost of service basis, without such recovery, those costs could reduce our future net income and cash flows and harm our financial condition. Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Changes in technology and regulatory policies may ~~cause~~lower the value of our generating ~~facilities to be less competitive.~~ facilities. – Affecting each Registrant

We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than (a) newer technologies such as fuel cells, microturbines, ~~windmills~~wind turbines and photovoltaic solar ~~cells.~~cells and (b) distributed generation using either new or existing technology. Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. It is possible that advances in technologies, the availability of distributed generation or changes in regulatory policies will lower the demand for electricity or reduce the costs of new technology to levels that are equal to or below that of most central station electricity production, either of which could have a material adverse effect on our results of operations.

Our profitability is impacted by our continued authorization to sell power at market-based rates. – Affecting each Registrant

FERC has granted ~~AEGCo,~~ AGR, APCo, I&M, KPCo, OPCo, PSO and SWEPCo authority to sell electricity at market-based ~~rates (except in our balancing authority area of the SPP where our wholesale power transactions are cost-capped by FERC).~~rates. FERC reserves the right to revoke or revise this market-based rate authority if it subsequently determines that one or more of these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. Each company that has obtained market-based rate authority from FERC must file a market power update every three years to show that they continue to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. The loss of market-based rate authority by any of these entities, especially by AGR, could have a material adverse effect on our results of operations.

Our revenues and results of operations from selling power are subject to market risks that are beyond our control. – Affecting each Registrant

We sell power from our generation facilities into the spot market and other competitive power markets on a contractual basis. We also enter into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of our power marketing and energy trading operations. With respect to such transactions, the rate of

return on our capital investments is not determined through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets. These market prices can fluctuate substantially over relatively short periods of time. Trading margins may erode as markets mature and there may be diminished opportunities for gain should volatility decline. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as RTOs that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Power supply and other similar agreements entered into during extreme market conditions may subsequently be held to be unenforceable by a reviewing court or the FERC. Fuel and emissions prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel and/or emissions costs. These factors could reduce our margins and therefore diminish our revenues and results of operations. Volatility in market prices for fuel and power may result from:

·	Weather conditions, including storms.

·	Economic conditions.

·	Outages of major generation or transmission facilities.

·	Seasonality.

·	Power usage.

·	Illiquid markets.

·	Transmission or transportation constraints or inefficiencies.

·	Availability of competitively priced alternative energy sources.

·	Demand for energy commodities.

·	Natural gas, crude oil and refined products and coal production levels.

·	Natural disasters, wars, embargoes and other catastrophic events.

·	Federal, state and foreign energy and environmental regulation and legislation and/or incentives.

Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. – Affecting each Registrant

We attempt to manage the exposure of or power trading activities by establishing and enforcing risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate the risks associated with these activities. As a result, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position.

We routinely have open trading positions in the market, within guidelines we set, resulting from the management of our trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.

Our power trading risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.

We may not successfully manage the uncertainty involved with our power trading (including coal, natural gas and emission allowances trading and power marketing). – Affecting each Registrant

Our power trading activities also expose us to risks of commodity price movements. To the extent that our power trading does not hedge the price risk associated with the generation it owns, or controls, through long-term power purchase agreements, we would be exposed to the risk of rising and falling spot market prices.

For example, the use of new technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing further downward pressure on natural gas prices, and has reduced the need for our coal-fired generation. Further, in the event that alternative generation resources, such as wind and solar, are mandated or otherwise subsidized or encouraged through climate legislation or regulation and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which

market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output. These events could adversely affect our financial condition, results of operations and cash flows, and could also result in an impairment of certain long-lived assets.

In connection with these trading activities, we routinely enter into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts. These activities expose us to risks from price movements. If the values of the financial contracts change in a manner we do not anticipate, it could harm our financial position or reduce the financial contribution of our trading operations.

Parties with whom we have contracts may fail to perform their obligations, which could harm our results of operations. – Affecting each Registrant

We are exposed to the risk that counterparties that owe us money or power could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the estimates predict.

We rely on electric transmission facilities that we do not own or control. If these facilities do not provide us with adequate transmission capacity, we may not be able to deliver our wholesale electric power to the purchasers of our power. – Affecting each Registrant

We depend on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power we sell at wholesale. This dependence exposes us to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, we may not be able to sell and deliver our wholesale power. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

~~Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations. – Affecting each Registrant~~

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law (Dodd-Frank Act). The federal legislation was enacted to reform financial markets and significantly alter how over-the-counter (OTC) derivatives are regulated. The law increased regulatory oversight of OTC energy derivatives, including: (a) imposing pervasive regulation by the Commodity Futures Trading Commission (CFTC) on dealers and traders who hold significant positions in swaps, (b) requiring certain standardized OTC derivatives to be traded on registered exchanges as directed by CFTC, (c) imposing new and potentially higher capital and margin requirements on swap dealers and traders who hold significant positions in swaps and (d) increasing the monitoring and compliance obligations of parties who engage in swaps, including new recordkeeping and reporting requirements with governmental entities. The CFTC has issued regulations exempting certain end users of energy commodities from being required to clear OTC derivatives, provided that they (a) are using the swaps to hedge or mitigate commercial risk and (b) satisfy certain other requirements. To the extent we meet such requirements, the end user exemption could reduce the effect of the law's clearing requirements on our hedging activity. Pursuant to authority granted under the Dodd-Frank Act, the CFTC has also issued rules that, among other things, further define the OTC derivative products and entities subject to additional regulatory oversight, which recently became effective. These requirements could subject us to additional regulatory oversight related to our OTC derivative transactions, cause our OTC derivative transactions to be more costly and have an impact on financial condition due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to manage.



Commission File Number		Registrants; States of Incorporation; Address and Telephone Number		I.R.S. Employer Identification Nos.
	1-3525		AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)		13-4922640
	1-3457		APPALACHIAN POWER COMPANY (A Virginia Corporation)		54-0124790
	1-3570		INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)		35-0410455
	1-6543		OHIO POWER COMPANY (An Ohio Corporation)		31-4271000
	0-343		PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)		73-0410895
	1-3146		SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 716-1000		72-0323455



Registrant	Title of each class	Name of Each Exchange on Which Registered
American Electric Power Company, Inc.	Common Stock, $6.50 par value	New York Stock Exchange
Appalachian Power Company	None
Indiana Michigan Power Company	None
Ohio Power Company	None
Public Service Company of Oklahoma	None
Southwestern Electric Power Company	None



Indicate by check mark if the registrant American Electric Power Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 onof the Securities Act.	Yes Tx	No o

Indicate by check mark if the registrants Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 onof the Securities Act.	Yes o	No Tx

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.	Yes o	No Tx

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.	Yes Tx	No o

Indicate by check mark whether American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company have submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).	Yes Tx	No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.	Tx

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of ‘large accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act. (Check One)



Large accelerated filer	T x	Accelerated filer	o
Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	o

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	xT (Do not check if a smaller reporting company)	Smaller reporting company	o

T

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See definitions of ‘large accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act. (Check One)



Description		Part of Form 10-K into which Document is Incorporated

Portions of Annual Reports of the following companies for the fiscal year ended December 31, ~~2013:~~ 2014:		Part II
American Electric Power Company, Inc.
Appalachian Power Company
Indiana Michigan Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company

Portions of Proxy Statement of American Electric Power Company, Inc. for ~~2014~~2015 Annual Meeting of Shareholders.		Part III

TABLE OF CONTENTS
Item			Page
Number			Number

Item Number					Page Number
				Glossary of Terms	i
	Glossary of Terms		i	Forward-Looking Information	iii
	Forward-Looking Information		iii
PART I	PART I			PART I
1	Business			Business
		General	1	General	1
		Business Segments	14	Business Segments	14
		Vertically Integrated Utilities	14	Vertically Integrated Utilities	14
		Transmission and Distribution Utilities	23	Transmission and Distribution Utilities	23
		Generation & Marketing	24	Generation & Marketing	24
		AEP Transmission Holdco	27	AEP Transmission Holdco	27
		AEP River Operations	30	AEP River Operations	31
		Executive Officers of AEP	31	Executive Officers of AEP	32
1A	Risk Factors		32	Risk Factors	34
1B	Unresolved Staff Comments		45	Unresolved Staff Comments	45
2	Properties		45	Properties	45
		Generation Facilities	45	Generation Facilities	45
		Transmission and Distribution Facilities	48	Transmission and Distribution Facilities	49
		Title to Property	48	Title to Property	49
		System Transmission Lines and Facility Siting	49	System Transmission Lines and Facility Siting	50
		Construction Program	49	Construction Program	50
��		Potential Uninsured Losses	49
				Potential Uninsured Losses	50
3	Legal Proceedings		49	Legal Proceedings	50
4	Mine Safety Disclosure		49	Mine Safety Disclosure	50

PART II
5	Market for Registrants’ Common Equity, Related Stockholder Matters			Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	51
	and Issuer Purchases of Equity Securities		50
6	Selected Financial Data		50	Selected Financial Data	51
7	Management’s Discussion and Analysis of Financial Condition and			Management's Discussion and Analysis of Financial Condition and Results of Operations	51
	Results of Operations		50
7A	Quantitative and Qualitative Disclosures about Market Risk		50	Quantitative and Qualitative Disclosures about Market Risk	52
8	Financial Statements and Supplementary Data		51	Financial Statements and Supplementary Data	52
9	Changes In and Disagreements with Accountants on Accounting			Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	52
	and Financial Disclosure		51
9A	Controls and Procedures		51	Controls and Procedures	52
9B	Other Information		51	Other Information	52

PART III
				PART III
10	Directors, Executive Officers and Corporate Governance		52	Directors, Executive Officers and Corporate Governance	53
11	Executive Compensation		52	Executive Compensation	53
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		53	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	54
13	Certain Relationships and Related Transactions and Director Independence		53	Certain Relationships and Related Transactions and Director Independence	54
14	Principal Accounting Fees and Services		53	Principal Accounting Fees and Services	55

PART IV	PART IV			PART IV
15	Exhibits and Financial Statement Schedules		55	Exhibits and Financial Statement Schedules	56
	Financial Statements		55	Financial Statements	56
	Signatures		56	Signatures	57
	Index of Financial Statement Schedules		S-1	Index of Financial Statement Schedules	S-1
	Reports of Independent Registered Public Accounting Firm		S-2	Reports of Independent Registered Public Accounting Firm	S-2
	Exhibit Index		E-1	Exhibit Index	E-1



Term		Meaning

AEGCo		AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent		American Electric Power Company, Inc., an electric utility holding company.
AEP East Companies		APCo, I&M, KPCo and OPCo.
AEP River Operations		AEP’s inland river transportation subsidiary, AEP River Operations LLC, operating primarily on the Ohio, Illinois and lower Mississippi rivers.
AEP System		American Electric Power System, an ~~integrated~~ electric ~~utility~~ system, owned and operated by ~~AEP’s electric utility~~AEP subsidiaries.
AEP Utilities		AEP Utilities, Inc., a subsidiary of AEP, ~~formerly, Central~~ and ~~South West Corporation.~~a holding company for TCC, TNC and our interest in ETT.
AEP West Companies		PSO, SWEPCo, TCC and TNC.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo		AEP Transmission Company, LLC, a subsidiary of AEPTHCo, is an intermediate holding company that owns seven wholly-owned transmission companies.
AEPTHCo		AEP Transmission Holding Company, LLC, a subsidiary of AEP, is an intermediate holding company that owns our transmission operations joint ventures and AEPTCo.
AFUDC		Allowance for Funds Used During Construction.
AGR		AEP Generation Resources ~~Inc,~~Inc., a nonregulated AEP subsidiary ~~that acquired~~in the ~~generation assets and liabilities of OPCo.~~Generation & Marketing segment.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
~~Buckeye~~		~~Buckeye Power, Inc., a nonaffiliated corporation.~~
CAA		Clean Air Act.
CO₂		Carbon dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider		Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo		Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
EPACT		The Energy Policy Act of 2005.
ERCOT		Electric Reliability Council of Texas regional transmission organization.
ESP		Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP and ~~MidAmerican~~Berkshire Hathaway Energy ~~Holdings~~ Company ~~Texas Transco, LLC~~ formed to own and operate electric transmission facilities in ERCOT.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
I&M		AEP Indiana Michigan Power Company, ~~an AEP electric utility subsidiary.~~Inc.
IMTCo		Indiana Michigan Transmission Company Inc.
Interconnection Agreement		An agreement by and among APCo, I&M, KPCo and OPCo, ~~that~~which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014.
IURC		Indiana Utility Regulatory Commission.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
kV		Kilovolt.
~~LPSC~~		~~Louisiana Public Service Commission.~~

MISO		Midwest Independent Transmission System Operator.
MMBtu		Million British Thermal Units.
MPSC		Michigan Public Service Commission.



Term		Meaning

MW		Megawatt.
NO_x		Nitrogen oxide.
Nonutility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NRC		Nuclear Regulatory Commission.
OATT		Open Access Transmission ~~Tariff, filed with FERC.~~Tariff.
OCC		Corporation Commission of the State of Oklahoma.
OHTCo		AEP Ohio Transmission Company, Inc.
OKTCo		AEP Oklahoma Transmission Company, Inc.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
~~Operating Agreement~~		Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales. AEPSC acts as the agent.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
REP		Texas Retail Electric Provider.
Rockport Plant		A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC		U.S. Securities and Exchange Commission.
SO₂		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA		Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
TCA		Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
TCC		AEP Texas Central Company, an AEP electric utility subsidiary.
TNC		AEP Texas North Company, an AEP electric utility subsidiary.
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

·

Ÿ	The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·Ÿ	Inflationary or deflationary interest rate trends.
·Ÿ	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·Ÿ	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·Ÿ	Electric load, customer growth and the impact of competition, including competition for retail ~~competition, particularly in Ohio.~~customers.
·Ÿ	Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration ~~costs through applicable rate mechanisms.~~costs.
·Ÿ	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·Ÿ	Availability of necessary generation capacity and the performance of our generation plants.
·Ÿ	Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·Ÿ	Our ability to build or acquire generation capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those ~~costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.~~costs.
·Ÿ	New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
·Ÿ	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·Ÿ	A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·Ÿ	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·Ÿ	Resolution of litigation.
·Ÿ	Our ability to constrain operation and maintenance costs.
·Ÿ	Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
·Ÿ	Prices and demand for power that we generate and sell at wholesale.
·Ÿ	Changes in technology, particularly with respect to new, developing, alternative or ~~alternative~~distributed sources of generation.
·Ÿ	Our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
·Ÿ	Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural ~~gas.~~gas and capacity auction returns.

·

Ÿ	Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.
·Ÿ	The transition to market for generation in Ohio, including the implementation of ~~ESPs.~~ESPs and our ability to recover investments in our Ohio generation assets.
·Ÿ	Our ability to successfully and profitably manage our ~~Ohio~~separate competitive generation ~~assets in a startup, nonregulated merchant business.~~assets.
·Ÿ	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·Ÿ	Actions of rating agencies, including changes in the ratings of our debt.
·Ÿ	The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
·Ÿ	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·Ÿ	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.


				Years Ended December 31,						Years Ended December 31,
Description	Description			2013		2012		2011		2014			2013			2012
				(in millions)						(in millions)
Vertically Integrated Utilities Segment	Vertically Integrated Utilities Segment
	Retail Revenues
		Residential Sales		$	3,216	$	2,993	$	3,061
		Commercial Sales			2,002		1,886		1,884
		Industrial Sales			2,029		1,951		1,905
		PJM Net Charges			10		(25)		(43)
		Provision for Rate Refund			(16)		(3)		1
		Other Retail Sales			172		164		164
			Total Retail Revenues		7,413		6,966		6,972
	Wholesale Revenues
		Off-System Sales			1,671		1,583		1,788
		Transmission			133		103		43
			Total Wholesale Revenues		1,804		1,686		1,831
	Other Electric Revenues				90		98		87
	Other Operating Revenues				39		35		52
	Sales to Affiliates				646		633		760
Retail Revenues
Residential Sales										$	3,329		$	3,216		$	2,993
Commercial Sales										2,032			2,002			1,886
Industrial Sales										2,125			2,029			1,951
PJM Net Charges										(62		)	10			(25		)
Provision for Rate Refund										(2		)	(16		)	(3		)
Other Retail Sales										182			172			164
Total Retail Revenues										7,604			7,413			6,966
Wholesale Revenues
Off-System Sales										1,530			1,671			1,583
Transmission										113			133			103
Total Wholesale Revenues										1,643			1,804			1,686
Other Electric Revenues										125			90			98
Other Operating Revenues										25			39			35
Sales to Affiliates										87			646			633
Total Revenues Vertically Integrated Utilities Segment	Total Revenues Vertically Integrated Utilities Segment				9,992		9,418		9,702	9,484			9,992			9,418

Transmission and Distribution Utilities Segment	Transmission and Distribution Utilities Segment
Retail Revenues
Residential Sales										2,313			2,164			2,121



		Years Ended December 31,
Description	��	2014			2013		2012
		(in thousands)
Retail Revenues
Residential Sales		$	1,257,273		$	1,219,649	$	1,159,576
Commercial Sales		585,929			583,835		576,153
Industrial Sales		690,432			697,043		701,603
PJM Net Charges		13,447			4,998		(13,049		)
Provision for Rate Refund		(6,085		)	—		—
Other Retail Sales		82,484			77,182		72,455
Total Retail Revenues		2,623,480			2,582,707		2,496,738
Wholesale Revenues
Off-System Sales		191,194			433,575		409,527
Transmission		26,898			21,049		14,059
Total Wholesale Revenues		218,092			454,624		423,586
Other Electric Revenues		57,830			22,246		28,438
Total Electric Generation, Transmission and Distribution Revenues		2,899,402			3,059,577		2,948,762
Sales to Affiliates		144,437			347,484		318,199
Other Revenues		9,239			10,345		9,970
Total Revenues		$	3,053,078		$	3,417,406	$	3,276,931

APCo
			Years Ended December 31,
Description			2013		2012		2011
			(in thousands)
Retail Revenues
	Residential Sales		$	1,219,649	$	1,159,576	$	1,107,199
	Commercial Sales			583,835		576,153		535,040
	Industrial Sales			697,043		701,603		638,854
	PJM Net Charges			4,998		(13,049)		(23,696)
	Other Retail Sales			77,182		72,455		64,741
		Total Retail Revenues		2,582,707		2,496,738		2,322,138
Wholesale Revenues
	Off-System Sales			433,575		409,527		504,955
	Transmission			21,049		14,059		(19,723)
		Total Wholesale Revenues		454,624		423,586		485,232
Other Electric Revenues				22,246		28,438		29,649
	Total Electric Generation, Transmission and Distribution Revenues			3,059,577		2,948,762		2,837,019
Sales to Affiliates				347,484		318,199		358,264
Other Revenues				10,345		9,970		9,942
Total Revenues			$	3,417,406	$	3,276,931	$	3,205,225



	Years Ended December 31,
Description	2014			2013		2012
	(in thousands)
Retail Revenues
Residential Sales	$	588,445		$	565,822	$	505,142
Commercial Sales	390,439			400,810		377,302
Industrial Sales	462,982			455,067		430,042
PJM Net Charges	(60,912		)	3,318		(9,003		)
Provision for Rate Refund	(592		)	—		—
Other Retail Sales	6,895			6,945		6,508
Total Retail Revenues	1,387,257			1,431,962		1,309,991
Wholesale Revenues
Off-System Sales	759,531			571,802		481,000
Transmission	(9,444		)	4,145		2,092
Total Wholesale Revenues	750,087			575,947		483,092
Other Electric Revenues	11,765			14,348		16,986
Total Electric Generation, Transmission and Distribution Revenues	2,149,109			2,022,257		1,810,069
Sales to Affiliates	98,577			341,686		385,460
Other Revenues	2,048			2,916		4,582
Total Revenues	$	2,249,734		$	2,366,859	$	2,200,111


Jurisdiction	Percentage of AEP System Retail Revenues (a)		AEP Utility Subsidiaries Operating in that Jurisdiction		Authorized Return on Equity (b)		Percentage of AEP System Retail Revenues (a)		AEP Utility Subsidiaries Operating in that Jurisdiction		Authorized Return on Equity (b)

Ohio	26%		OPCo		10.2% (c)		25%		OPCo		10.20%

Texas	14%		TCC		9.96%		14%		TCC		9.96%
		TNC		9.96%				TNC		9.96%
		SWEPCo		9.65%				SWEPCo		9.65%

Virginia							13%		APCo		9.70%

West Virginia		12%		APCo		10.00%		11%		APCo		10.00%
		12%	WPCo		10.00%				WPCo		10.00%

Virginia	13%		APCo		10.90%

Oklahoma	10%		PSO		10.15%		11%		PSO		10.15%

Indiana	10%		I&M		10.20%		10%		I&M		10.20%

Louisiana	5%		SWEPCo		10.00%		5%		SWEPCo		10.00%

Kentucky	5%		KPCo		10.50%		5%		KPCo		10.50%

Arkansas	2%		SWEPCo		10.25%		3%		SWEPCo		10.25%

Michigan	2%		I&M		10.20%		2%		I&M		10.20%

Tennessee	1%		KGPCo		12.00%		1%		KGPCo		12.00%


(a)	Represents the percentage of public utility subsidiaries revenue from sales to retail customers to total public utility subsidiaries revenue for the year ended December 31, ~~2013.~~2014.


(b)	Identifies the predominant authorized return on equity and may not include other, less significant, permitted recovery. Actual return on equity varies from authorized return on equity.

SWEPCo
			Year Ended December 31,
Description			2013		2012		2011
			(in thousands)
Retail Revenues
	Residential Sales		$	586,517	$	512,578	$	554,663
	Commercial Sales			472,264		404,204		411,652
	Industrial Sales			316,282		298,604		288,474
	Provision for Rate Refund			(16,110)		(1,207)		1,604
	Other Retail Sales			8,360		8,074		8,118
		Total Retail Revenues		1,367,313		1,222,253		1,264,511
Wholesale Revenues
	Off-System Sales			294,594		247,118		259,877
	Transmission			59,097		48,404		47,782
		Total Wholesale Revenues		353,691		295,522		307,659
Other Electric Revenues				21,571		20,758		22,022
	Total Electric Generation, Transmission and Distribution Revenues			1,742,575		1,538,533		1,594,192
Sales to Affiliates				51,812		37,441		57,615
Other Revenues				1,416		1,860		2,019
Total Revenues			$	1,795,803	$	1,577,834	$	1,653,826

																									Historical and Projected Environmental Investments

		2011	2012		2013		2014		2015		2016
		Actual	Actual		Actual		Estimate		Estimate		Estimate		2012		2013		2014		2015		2016		2017
													Actual		Actual		Actual		Estimate		Estimate		Estimate
		(in thousands)											(in thousands)
Total AEP (a)	$	186,800	$	235,400	$	415,000	$	588,000	$	644,000	$	447,000	$	241,000	$	424,200	$	539,800	$	661,000	$	401,000	$	531,000
APCo		68,900		50,800		44,500		48,000		67,000		68,000	52,400		44,800		31,300		70,000		53,000		151,000
I&M		5,900		30,400		27,300		55,000		42,000		52,000	30,000		28,300		51,400		40,000		49,000		84,000
OPCo (b)		63,000		66,200		123,900		-		-		-	70,300		129,300		—		—		—		—
PSO		6,500		26,100		55,500		66,000		75,000		49,000	26,300		56,100		72,100		85,000		49,000		9,000
SWEPCo		11,000		23,800		134,000		217,000		312,000		118,000	24,200		135,700		225,300		316,000		86,000		66,000


(a)	Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies. Excludes discontinued operations.


(b)	~~Estimates for 2014, 2015 and 2016 reflect the transfer of~~OPCo transferred all of ~~OPCo~~its generation assets ~~which occurred~~ on December 31, 2013.

	Peak Demand	Member-Load Ratio
	(MWs)	(%)
APCo	6,839	31
I&M	4,540	21
KPCo	1,409	6
OPCo	9,385	42


		Years Ended December 31,						Years Ended December 31,
Company	Company	2013		2012		2011		2014		2013		2012
		(in thousands)						(in thousands)
APCo	APCo	$	40,609	$	20,264	$	4,608	$	84,667	$	40,609	$	20,264
I&M	I&M		19,947		5,689		1,538	39,707		19,947		5,689


(a)	ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed, current and future projects in ERCOT over the next ten years is expected to be ~~$3.057~~$3.1 billion. Future projects will be evaluated on a case-by-case basis.


(b)	AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in ETA. ETA is a 50/50 joint venture with Berkshire Hathaway Energy (formerly known as MidAmerican ~~Energy~~Energy) and AEP.


(d)	AEP owns 87.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in RITELine Transmission Development, LLC (RTD) and AEP Transmission Holding Company, LLC ~~(AEPTHC)~~(AEPTHCo). AEP owns 12.5% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in RTD. RTD is a 50/50 joint venture with Exelon Transmission Company, LLC and ~~AEPTHC.~~AEPTHCo.


(e)	RITELine IN is a consolidated variable interest entity. RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects. The projects and other segments that are electrically equivalent in nature are currently under consideration for inclusion in the interregional planning process between PJM and MISO.


(f)	AEP owns 86.5% of Transource Missouri through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture with ~~AEPTHC~~AEPTHCo and Great Plains Energy formed to pursue competitive transmission projects. ~~AEPTHC~~AEPTHCo and Great Plains Energy own 86.5% and 13.5% of Transource, respectively.


(g)	The ROE represents the weighted average approved return on equity based on the projected costs of two projects currently under development by Transource Missouri: the $65 million Iatan-Nashua project (10.3%) and the $333 million Sibley-Nebraska City project (11.3%).


(h)	RITELine IN and Transource Missouri are consolidated joint ventures by AEP. Therefore, the investment value listed reflects applicable income taxes that are the responsibility of AEP. All other investments in this schedule are joint ventures that are not consolidated by AEP. Therefore, these investment values listed do not reflect income taxes that are the responsibility of AEP.



AEGCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Rockport, Units 1 and 2 – 50% of each (a)	2	IN	Steam - Coal	1,310	1984
Lawrenceburg (b)	6	IN	Natural Gas	1,186	2004
Total MWs				2,496


(b)	The capacity and output of this plant is under contract to (and its financial impact is included with) AGR through 2017.

AEGCo
						Year Plant
					Net Maximum	or First Unit
Plant Name		Units	State	Fuel Type	Capacity (MWs)	Commissioned
Rockport, Units 1 and 2 – 50% of each (a)		2	IN	Steam - Coal	1,310	1984
Lawrenceburg (b)		6	IN	Natural Gas	1,186	2004
Total MWs					2,496

(a)	Rockport, Unit 2 is leased.
(b)	The capacity and output of this plant is under contract to (and its financial impact is included with) AGR through 2017.

APCo
						Year Plant
					Net Maximum	or First Unit
Plant Name		Units	State	Fuel Type	Capacity (MWs)	Commissioned
Buck		3	VA	Hydro	9	1912
Byllesby		4	VA	Hydro	22	1912
Claytor		4	VA	Hydro	76	1939
Leesville		2	VA	Hydro	50	1964
London		3	WV	Hydro	14	1935
Marmet		3	WV	Hydro	14	1935
Niagara		2	VA	Hydro	2	1906
Reusens		5	VA	Hydro	13	1904
Winfield		3	WV	Hydro	15	1938
Ceredo		6	WV	Natural Gas	516	2001
Dresden		3	OH	Natural Gas	608	2012
Smith Mountain		5	VA	Pumped Storage	586	1965
Amos		3	WV	Steam - Coal	2,900	1971
Clinch River		3	VA	Steam - Coal	705	1958
Glen Lyn		2	VA	Steam - Coal	335	1918
Kanawha River		2	WV	Steam - Coal	400	1953
Mountaineer		1	WV	Steam - Coal	1,320	1980
Sporn		2	WV	Steam - Coal	300	1950
Total MWs					7,885


	Cook Plant
	Unit 1	Unit 2	Cook Plant
			Unit 1		Unit 2
Year Placed in Operation	1975	1978	1975		1978
Year of Expiration of NRC License	2034	2037	2034		2037
Nominal Net Electrical Rating in Kilowatts	1,084,000	1,107,000	1,084,000		1,107,000
Annual Capacity Utilization
2014			87.4	%	96.3	%
2013	82.7%	86.9%	82.7	%	86.9	%
2012	96.9%	87.4%	96.9	%	87.4	%
2011	81.3%	99.4%	81.3	%	99.4	%
2010	82.2%	80.8%