This report made by AEP and its Registrant Subsidiariesthe Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertakemanagement undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP’s public utility subsidiaries are interconnected and their operations are coordinated.  Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring legislationlaws in Michigan, Ohio and the ERCOT area of Texas hashave caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.  In Ohio, AEP’s regulated utility operates its distribution and transmission assets while its former generation assets are owned and operated by affiliates.

The AEP System is an integrated electric utility system.  As a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2012,2015, the subsidiaries of AEP had a total of 18,51317,405 employees. Because it is a holding company rather than an operating company, AEP has no employees. The public utilitymaterial subsidiaries of AEP are:

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 960,000957,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,650 MW of generating capacity.  APCo uses its generation to serve its retail and other customers.  As of December 31, 2012,2015, APCo had 2,1281,836 employees. Among the principal industries served by APCo are paper, rubber, coal mining, textile mill products and stone, clay and glass products. In addition to its AEP System interconnections, APCo is interconnected with the following nonaffiliated utility companies: Carolina Power & Light Company, Duke Carolina and Virginia Electric and Power Company.  APCo has several points of interconnection with Tennessee Valley Authority (TVA) and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.  APCo is a member of PJM.  APCo is part of AEP’s Vertically Integrated Utilities segment.

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 584,000588,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants.  I&M owns or leases 3,523 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2012,2015, I&M had 2,6492,489 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and chemicals and allied products, rubber products and transportation equipment.  In addition to its AEP System interconnections, I&M is interconnected with the following nonaffiliated utility companies: Central Illinois Public Service Company, Duke Energy Ohio, Inc., Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, Duke Indiana and Richmond Power & Light Company.  I&M is a member of PJM.  I&M is part of AEP’s Vertically Integrated Utilities segment.

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 173,000170,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  KPCo owns 1,058 MW of generating capacity.  KPCo uses its generation to serve its retail and other customers.  As of December 31, 2012,2015, KPCo had 392558 employees. Among the principal industries served are petroleum refining, coal mining and chemical production.  In addition to its AEP System interconnections, KPCo is interconnected with the following nonaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc.  KPCo is also interconnected with TVA.  KPCo is a member of PJM.  KPCo is part of AEP’s Vertically Integrated Utilities segment.

Organized in Virginia in 1917, KGPCo provides electric service to approximately 47,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2012,2015, KGPCo had 5452 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the generation, transmission and distribution of electric power to approximately 1,459,0001,468,000 retail customers in Ohio,Ohio.  Following corporate separation of OPCo’s generation assets in December 2013, OPCo purchases energy and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  OPCo also provides generation capacity to support shopping customer load, and will do so through mid-2015.serve generation service customers.  As of December 31, 2012,2015, OPCo had 3,1311,552 employees.  We have already obtained PUCO authorization for corporate separation and currently we are seeking regulatory approval from the FERC to transfer OPCo's generation assets to a newly formed wholly owned competitive Ohio generation affiliate as of January 1, 2014.  Following this transaction, OPCo will continue to own transmission and distribution assets and to provide transmission and distribution services to its customers in Ohio.  Among the principal industries served by OPCo are primary metals, chemicals and allied products, health services, electronic machinery, petroleum refining, and rubber and plastic products. In addition to its AEP System interconnection, OPCo is interconnected with the following nonaffiliated utility companies: Duke Ohio, The Cleveland Electric Illuminating Company, Dayton Power and Light Company, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.  OPCo is a member of PJM.  OPCo is part of AEP’s Transmission and Distribution Utilities segment.

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 535,000545,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants.  PSO owns 4,432 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2012,2015, PSO had 1,1271,134 employees. Among the principal industries served by PSO are paper manufacturing and timber products, natural gas and oil extraction, transportation, non-metallic mineral production, oil refining and steel processing. In addition to its AEP System interconnections, PSO is interconnected with Empire District Electric Company, Oklahoma Gas and Electric Company, Southwestern Public Service Company and Westar Energy, Inc.  PSO is a member of SPP.  PSO is part of AEP’s Vertically Integrated Utilities segment.

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 524,000531,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,798 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2012,2015, SWEPCo had 1,4721,483 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing and metal refining. The territory served by SWEPCo also includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal mining operation. In addition to its AEP System interconnections, SWEPCo is interconnected with Central Louisiana Electric Company, Empire District Electric Company, Entergy Corp. and Oklahoma Gas & Electric Company.  SWEPCo is a member of SPP.

Organized in Texas in 1945, TCC is engaged in the transmission and distribution of electric power to approximately 799,000826,000 retail customers through REPs in southern Texas. TCC sold all of its generation assets.  As of December 31, 2012,2015, TCC had 9961,085 employees. Among the principal industries served by TCC are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT. TCC is part of AEP’s Transmission and Distribution Utilities segment.

Organized in Texas in 1927, TNC is engaged in the transmission and distribution of electric power to approximately 187,000189,000 retail customers through REPs in west and central Texas. TNC’s generating capacity has been transferred to an affiliate at TNC’s cost pursuant to an agreement effective through 2027. As of December 31, 2012,2015, TNC had 319346 employees. Among the principal industries served by TNC are petroleum refining, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.  TNC is part of AEP’s Transmission and Distribution Utilities segment.

Organized in West Virginia in 1883 and reincorporated in 1911, WPCo provides electric service to approximately 41,000 retail customers in northern West Virginia. On January 31, 2015, WPCo does not own anyacquired an interest in a 780 MW generating facilities.unit owned by AGR. WPCo is a member of PJM. It purchasesPrior to acquiring the 780 MW generating unit interest, WPCo purchased electric power from OPCoAGR for distribution to its customers. As of December 31, 2012,2015, WPCo had 5156 employees.  In December 2011, APCo and WPCo filed an application with the WVPSC requesting approval to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC.  A hearing at the Virginia SCC is scheduled for April 2013.part of AEP’s Vertically Integrated Utilities segment.

Organized in Ohio in 1982, AEGCo is an electric generating company. AEGCo owns 2,496 MW of generating capacity.  AEGCo sells power at wholesale to OPCo,AGR, I&M and KPCo. AEGCo has nogranted AGR the rights to the power generated at the Lawrenceburg facility, a 1,186 MW natural gas-fired generating unit, pursuant to a unit power agreement through 2017. As of December 31, 2015, AEGCo had 73 employees.  AEGCo is part of AEP’s Vertically Integrated Utilities segment.

AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP affiliated companies.subsidiaries. The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC. As of December 31, 2012,2015, AEPSC had 4,7875,622 employees.

The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the yearyears ended December 31, 20122015, 2014 and 2013 are as follows:

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt.  In recent history, short-term funding needs have been provided for by cash on hand, borrowing under AEP'sAEP’s revolving credit agreements and AEP’s commercial paper program.  Funds are made available to subsidiaries under the AEP corporate borrowing program.  Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 20122015 Annual Reports, under the heading entitled Financial Condition for additional information concerning short-term funding and our access to bank lines of credit, commercial paper and capital markets.

AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and, for AEP andtest.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its significantmajor subsidiaries, aprior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, cross-acceleration provision.would cause an event of default under these credit agreements. As of December 31, 2012,2015, AEP was in compliance with its debt covenants.  With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before

termination of the agreements.  A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 20122015 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreements.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.

UtilityAEP’s vertically integrated utility operations constitute most of AEP’s business operations.  Utility operations include (a)are engaged in the generation, transmission and distribution of electric powerelectricity for sale to retail and wholesale customers through assets owned and (b) the supplyingoperated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants.WPCo.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.activities on behalf of each of these subsidiaries.

As of December 31, 2012,2015, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 37,30023,600 MW of domestic generation.  See Item 2 – Properties for more information regarding AEP’s generation capacity.

The following2013 results include fuel used and transported by OPCo, a utility subsidiary that is not part of the Vertically Integrated Utilities segment.  OPCo’s results appear here because it retained its generation until year-end 2013 at which point all of its generation was transferred to AGR which transferred portions to APCo and KPCo.

The table shows the generation sources of fuelby type, on an actual net generation (MWhs) basis, used by the AEP System:Vertically Integrated Utilities:

A price increase/decrease in one or more fuel sources relative to other fuels may result in the decreased/increased use of other fuels.  AEP’s overall 20122015 fossil fuel costs are downfor the Vertically Integrated Utilities decreased approximately 2%12% on a dollar per MMBtu basis from 20112014. This was due primarily to the favorable impact of lowa significant decline in natural gas prices along with a marginal decrease in coal prices.

AEP’s public utility subsidiariesVertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms.  Coal consumption in 2012 was down significantly2015 decreased from the same period2014 due to a decrease in 2011power prices and corresponding decrease in demand for the reasons discussed below. The AEP System average target level for coal inventory ranges from 35 to 40 days and as of December 31, 2012, the AEP System average forcoal-fired generation. As a result, coal inventories was 44 days.ended the year at above-target levels on a system basis.

Management believes that AEP’s public utility subsidiariesthe Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units.  Through subsidiaries, AEP owns, leases or controls more than 7,6004,838 railcars, approximately 600498 barges, 1512 towboats, 8 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in ourAEP generating facilities.  See AEP River Operations for a discussion of AEP’s for-profit coal and other dry-bulk commodity transportation operations that are not part of AEP’s Utility Operations segment.

Spot market prices for certain coals utilized by AEPcoal continued to decrease throughout 2015.  The decreased significantly in the first half of 2012, but made a modest recovery by the end of the year.  The general decrease in spot coal prices duringreflect the year can be attributed to the persistently weakreduction in demand for domestic coal driven, in large part, by low natural gas pricescoal-fired generation and the displacementoversupply in the market.   As of coal generation with natural gas resources.  MostDecember 31, 2015, slightly less than half of the coal purchased by AEP iswas procured through term contracts.  As those contracts expire, they can beare replaced

with contracts at the newcurrent market prices.  The price with an impact of this process is reflected in subsequent periods.  The average cost per tonprice paid for coal delivered in 2012 increased2015 decreased from the prior year.year primarily due to a decrease in spot coal prices and heavier reliance on shorter term contracts.

The following table shows the amount of coal and lignite delivered to the AEP SystemVertically Integrated Utilities plants during the past three years and the average delivered price of coal purchased by AEP System companies:the Vertically Integrated Utilities:

The coal supplies at AEP Systemthe Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2012,2015, the AEP System’sVertically Integrated Utilities coal inventory was approximately 4447 days of full load burn.

Through its public utility subsidiaries, AEPThe Vertically Integrated Utilities consumed nearly 220over 89 billion cubic feet of natural gas during 20122015 for generating power. This represents an increasea decrease of 32%7% from 2011 and continues a trend that began in 2010.  Since 2009,2014.  While AEP’s natural gas consumptiongas-fired generating capacity has increased approximately 130%.  The increased natural gas consumption is attributable toover the past several years with the addition of the Stall and Dresden units, the implementation of the SPP Market and change in the dispatch of AEP’s natural gas combined cycle unitsfleet resulted in June 2010 and January 2012, respectively, along with increased operation of the Lawrenceburg and Waterford combined cycle units.  The efficient heat rates of these units (low 7,000 British thermal units/KWh range) coupled with sustained lowera decreased natural gas prices have supported the increased operation of AEP’s combined cycle natural gas units.  A mild 2011-12 winter and the continuation of high levels of production from shale gas developments led to higher U.S. natural gas inventories and continued to place downward pressure on natural gas prices as a result of more abundant supplies, making power generated from these units more economic.gas-fired generation.  Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allowsallow greater access to competitive supplies and improvesimprove delivery reliability. A portfolio of term, monthly, seasonal, firm and daily peaking commoditysupply and transportation agreements (thatprovide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply agreements are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate.prices.

The following table shows the amount of natural gas delivered to the AEP SystemVertically Integrated Utilities plants during the past three years and the average delivered price of natural gas purchased by AEP System companies:the Vertically Integrated Utilities. Results for 2013 include natural gas delivered to OPCo, while results for 2015 and 2014 do not.

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant.  I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets.  I&M also continues to lease a portion of its nuclear fuel.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago.  I&M entered into an agreement to provide for onsite dry cask storage of spent nuclear fuel to permit normal operations to continue.  I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis.  I&M began and completed its initial loading of spent nuclear fuel into the dry casks in 2012, which consisted of 12 casks (32 spent nuclear fuel assemblies contained within each).  The second loading of spent nuclear fuel into dry casks was completed in 2015, which consisted of 16 casks. The third dry cask loading is expected to occur in 2018.

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely.  The cost to decommission a nuclear plant is affected by NRC regulations and the spent nuclear fuel disposal program.  The most recent decommissioning cost study was completed in 2012.  In it, the2015.  The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranged from $1.3 billion to $1.7was $1.6 billion in 20122015 non-discounted dollars.  As of December 31, 2012,2015, the total decommissioning trust fund balance for the Cook Plant was approximately $1.4$1.8 billion. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  WeAEP will seek recovery from customers through our regulated rates if actual decommissioning costs exceed our projections.  See Note 56 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies, included in the 20122015 Annual Reports, for information with respect to nuclear waste and decommissioning.

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states.  Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials.  Michigan does not currently have a disposal site for such waste available.  I&M cannot predict when such a site may be available. However the states of Utah and Texas have licensed low level radioactive waste disposal sites which currently accept low level radioactive waste from Michigan waste generators.  There is currently no set date limiting I&M’s access to either of these facilities.  The Cook Plant has a facility onsite designed specifically for the storage of low level radioactive waste.  In the event that low level radioactive waste disposal facility access becomes unavailable, then low level radioactive waste can be stored onsite at this facility.

The Unit Power Agreement between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant.  Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M).  The agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant hashave expired (currently December 2022) unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCoAEGCo and AEGCo,KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the Unit Power Agreement between AEGCo and I&M for such entitlement.  The KPCo unit power agreement expires in December 2022.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  See Item 11. Business – Utility OperationsVertically Integrated Utilities – Regulation – Rates.  The FERC regulates and approves the rates for both wholesale transmission transactions.transactions and wholesale generation contracts.  The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM, SPP and ERCOT, and as approved by the FERC. See Item 11. Business – Utility OperationsVertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.service within a specific territory.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.  For a discussion of competition in the sale of power, see Item 11. Business – Utility OperationsVertically Integrated Utilities – Competition.

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA.  OPCo, a subsidiary in AEP’s Transmission and Distribution Utilities segment, is also a party to the TA.  The useTA defines how the parties to the agreement share the revenues associated with their transmission facilities and the recoverycosts of costs associated with the transmission assets of the AEP East Companies, including WPCo and KGPCo, are subject to the rules, protocols and agreements in place with PJM and asservice provided by PJM.  The TA has been approved by the FERC.

The AEP East CompaniesAEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and SWEPCoPSO and PSOSWEPCo are members of the SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  The remaining AEP West Companies (TCC and TNC) are members of ERCOT.

Except for transmission and/or retail generation sales in certain of its jurisdictions, AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions as well as certain unbundled retail transmission rates mainly in Ohio.transactions.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.  EPACT provides the FERC increased utility merger oversight.

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes.  State utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.  Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period

of time, a state utility commission can review and change rates on its own initiative.  Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers.  Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, we aremanagement is actively pursuing strategies to accelerate rate recognition of investments and cash flow.  AEP representatives continue to engage our state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process.  These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

In many jurisdictions, theThe rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  In the ERCOT area of Texas, our utilities have exited the generation business and they currently charge unbundled cost-based rates for transmission and distribution service only.  In Ohio, rates for electric service are unbundled for generation, transmission and distribution service.  Historically, the state regulatory frameworks in the service area of the AEP Systemvertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs.  Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP operates.AEP’s vertically integrated public utility subsidiaries operate.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 34 to the consolidated financial statements, entitled Rate Matters, included in the 20122015 Annual Reports, for more information regarding pending rate matters.

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis.  Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC.  PSO’s rates are set on a cost-of-service basis.  Fuel and purchased energy costs above or below the amount included in base rates are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.  The factors are generally adjusted annually and are based upon forecasted fuel and purchased energy costs.  Over or under collections of fuel and purchased energy costs for prior periods are returned to or recovered from customers in the yearperiod following when new annual factors are established.

APCo currently provides retail electric service in Virginia at unbundled rates approved by the Virginia SCC.  Virginia generally allows for timely recovery of fuel costs through a fuel adjustment clause.  Transmission services are provided at OATT rates based on rates established by the FERC.  In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses.