2015 Fact Book 50Th EEI Financial Conference Hollywood, FL November 8 – 11, 2015 1 “Safe Harbor” Statement Under the Private Securities Litigation Reform Act of 1995

Home , American Electric Power, Eric Skrmetta

2015 Fact Book 50th EEI Financial Conference Hollywood, FL November 8 – 11, 2015 1 “Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995

This presentation contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: the economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory, inflationary or deflationary interest rate trends, 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, 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, electric load, customer growth and the impact of competition includingcompetition for retail customers; weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs, available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters, availability of necessary generation capacity and the performance of our generation plants, our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates, our ability to build 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, 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, evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel, a reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers, 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, resolution of litigation, our ability to constrain operation and maintenance costs, our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities, prices and demand for power that we generate and sell at wholesale, changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation, 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, volatility and changes in markets for capacity and electricity, coal, and other energy-related commodities, particularly changes in the price of natural gas, changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP, the transition to market for generation in Ohio, including the implementation of ESPs, our ability to successfully and profitably manage our separate competitive generation assets, changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market, actions of rating agencies, including changes in the ratings of our debt, 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, accounting pronouncements periodically issued by accounting standard-setting bodies and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

Bette Jo Rozsa Bradley Funk Investor Managing Director Director Relations Investor Relations Regulated Accounting 614-716-2840 614-716-3162 2 [email protected] [email protected] Table of Contents

AEP Overview Operating Company Detail for: AEP Overview Appalachian Power Company (including Wheeling & Kingsport) AEP Corporate Leadership Indiana Michigan Power Company AEP Operational Structure Kentucky Power Company AEP Service Territory Ohio Power Company 2014 Retail Revenue Public Service Company of Oklahoma Generation Fleet Southwestern Power Company Transmission Line Circuit Miles Detail AEP Texas Distribution Line Detail Rate Base & ROEs Detail Provided: Summary of Rate Case Filing Requirements Overview Recovery Mechanisms Across Juridictions Financial & Operational Data Storm Recovery Mechanisms by Jurisdictions Customer Statistics Jurisdictional Off-System Sales Sharing Summary Commissions Overview Federal Energy Regulatory Commission Regulated Generation Transforming Our Generation Fleet Regulated Generation - Generation Capacity Transforming Our Generation Fleet Regulated Generation - AEG & APCo Investments Driving Emission Reductions Generation by Company Dramatic Reductions in Emissions Regulated Fuel Procurement - 2016 Projected Large-scale Renewable Opportunities Regulated 2016 Projected Coal Delivery Delivering Clean Energy Resources Jurisdictional Fuel Clause Summary Long-term Renewable Energy Purchase Agreement Renewable Portfolio/Energy Efficiency Standards Competitive Operations Competitive Business Organizational Structure Environmental AEP Generation Resources Footprint Regulated Environmental Retrofit Status Competitive Fleet Characteristics Competitive Environmental Retrofit Status Competitive 2014 Fleet Statistics Regulated Environmental Investment & Retirements Competitive Coal Procurement Competitive Environmental Investment & Retirements AEP Energy Clean Power Plan Additional Environmental Regulations Transmission Initiatives AEP Transmission Ownership Structure Financial Update AEPTHC Growth Plan Project Summary Capitalization & Liquidity AEP Transco Has a Large, Diverse Footprint AEP Banking Group Transco Regulatory Compacts AEP Credit Ratings State Transco Rates are Regulated by FERC Long-term Debt Maturity Profile Project Selection Guidelines Debt Schedules Active Joint Venture Projects 3 Competitive Transmission AEP: America’s Energy Partner

AEP IS THE NATION’S LEADING REGULATED ELECTRIC UTILITY

Provides generation, transmission and / or distribution services to approximately 5.4 million customers in eleven states with headquarters in Columbus, Ohio (NYSE: AEP)

Our regulated electric assets include: Approximately 32,000 megawatts of generating capacity in 3 RTOs (one of the largest US generation portfolios with a significant cost advantage in many of our market areas)

Approximately 40,000 circuit miles of transmission lines, including 447 miles of Transco lines, and 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.

AEP Transco has $1.8B of transmission assets in-service with plans to construct approximately $3B additional through 2017

Over 223,000 miles of overhead and underground distribution lines

AEP consistently produces strong financial results:

Operating earnings growth of 4% to 6%

Strong balance sheet including $61 billion of assets

Cash dividend paid every quarter since 1910 with targeted payout of 60% to 70% of operating earnings

4 AEP: THE NEXT PREMIUM REGULATED UTILITY AEP Corporate Leadership

Nicholas K. Akins – Chairman, President, and Chief Executive Officer

Brian X. Tierney – Robert P. Powers – Executive Vice President and Executive Vice President and Chief Financial Officer Chief Operating Officer

Lisa M. Barton - Mark C. McCullough - Charles E. Zebula- Executive Vice President Executive Vice President Executive Vice President- - Transmission - Generation Energy Supply

David M. Feinberg – Lana L. Hillebrand- Executive Vice Senior Vice President President, General and Chief Administrative Counsel and Secretary Officer 5 AEP Operational Structure*

AEP, Inc.

Regulated Utilities AEP Transmission Holding Competitive Operations Company

Appalachian Power Indiana Michigan Power AEP Transmission Joint Ventures AEP Energy Supply Company Company Company

Kentucky Power Public Service Company AEP Appalachian AEP Energy Company of Oklahoma Transco

Southwestern Electric Ohio Power Company CSW Energy Power Company AEP Kentucky Transco

Wheeling Power Kingsport Power AEP Southwestern AEP Generation Company Company Transco Resources

AEP Texas Central AEP Texas North Company Company AEP Ohio Transco

AEP Generating Company AEP Oklahoma Transco

AEP Indiana Michigan Transco

AEP West Virginia Transco

6 * Does not represent legal structure AEP Service Territory

VERTICALLY INTEGRATED UTILITIES

Public Service Company of Oklahoma (PSO) Appalachian Power Company (APCo) Southwestern Electric Power Company (SWEPCO) Indiana Michigan Power Company (I&M) Kingsport Power Company (KGPCo) Kentucky Power Company (KPCo) Wheeling Power Company (WPCo)

7 AEP Service Territory

TRANSMISSION AND DISTRIBUTION UTILITIES

) T Texas North Company (TNC) Ohio Power Company (OPCo) Te Texas Central Company (TCC)

8 2014 Retail Revenue

CUSTOMER PROFILE AEP’S SERVICE TERRITORY ENCOMPASSES APPROXIMATELY 5.4 MILLION CUSTOMERS IN 11 STATES

Percentage of AEP System Retail Revenues Revenue Composition by Customer Class*

Ohio 25% Residential Texas 14% Commercial Virginia 13% Industrial West Virginia 11% Wholesale Oklahoma 11% Indiana 10% Louisiana 5% Kentucky 5% Arkansas 3% Michigan 2% Tennessee 1%

9 Source: 2014 10-K. *Note: Figures do not include Other Revenues Generation Fleet Regulated - 2015 Generation Capacity Competitive - 2015 Generation Capacity by Fuel Type (Including Renewable PPA’s) by Fuel Type (Including Wind PPA’s)* Based on 30,078 MW** Based on 7,225 MW Note: Includes 1,785MW Demand Response/Energy Efficiency

*Excludes PPA’s with Regulated for purchases of 355 MW related to Oklaunion **Includes: • and 1,186 MW related to Lawrenceburg. Total Fleet - 2015 Generation Capacity 953 MW from OVEC Includes 177 MW wind PPA. • 355 MW for Oklaunion and 1,186 MW by Fuel Type (Including PPA’s) for Lawrenceburg which Regulated Based on 37,303 MW*** sells to Competitive through a PPA • 2,273 MW of Regulated renewable Note: Includes 1,785MW Demand Response/Energy Efficiency PPA’s (excluding 599 MW of wind PPA’s scheduled to begin 1/1/2016) Reflects Big Sandy 1 and Clinch River as refueled with Natural Gas, expected to complete in 2016.

***Includes: • 953 MW from OVEC • 2,273 MW of Regulated and 177 MW of Competitive wind PPA’s Reflects Big Sandy 1 and Clinch River as refueled with Natural Gas, expected to complete in 2016. 10 Transmission Line Circuit Miles Detail

Operating Company Level (Circuit Miles)

Operating Company 765kV 500kV 345kV 230kV 161kV 138kV 115kV 88kV 69kV 46kV 40kV 34.5kV 23kV Total APCo 734 97 378 106 0 2,849 0 37 981 744 0 155 0 6,081 OPCo 507 0 1,415 0 0 3,271 0 0 2,352 0 58 417 77 8,097 I&M 616 0 1,617 0 0 1,661 0 0 687 0 0 677 0 5,258 KGPCo 0 0 0 0 0 44 0 0 0 0 0 29 0 73 KPCo 258 0 8 0 48 339 0 0 429 166 0 3 0 1,251 PSO 0 0 608 34 8 2,076 10 0 647 0 0 0 0 3,384 SWEPCO 0 0 735 0 305 1,442 41 0 1,573 0 0 0 0 4,096 TCC 0 0 632 0 0 2,446 0 0 1,216 0 0 0 0 4,294 TNC 0 0 224 0 0 1,423 0 0 2,445 0 0 0 0 4,092 WPCo 0 16 15 0 0 191 0 0 84 0 0 0 0 306 Transco - IM 0 0 0 0 0 3 0 0 26 0 0 1 0 30 Transco - Ohio 1 0 0 0 0 55 0 0 88 0 3 6 8 161 Transco - OK 0 0 0 0 0 125 0 0 131 0 0 0 0 256 Transco - WV 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total 2,116 113 5,632 140 361 15,925 52 37 10,659 910 61 1,288 85 37,379

State Level (Circuit Miles) State 765kV 500kV 345kV 230kV 161kV 138kV 115kV 88kV 69kV 46kV 40kV 34.5kV 23kV Total Arkansas 0 0 78 0 305 235 26 0 444 0 0 0 0 1,088 Indiana 600 0 1,383 0 0 1,432 0 0 417 0 0 542 0 4,374 Kentucky 258 0 8 0 48 339 0 0 429 166 0 3 0 1,251 Louisiana 0 0 105 0 0 282 1 0 328 0 0 0 0 716 Michigan 16 0 234 0 0 232 0 0 296 0 0 136 0 914 Ohio 508 0 1,416 0 0 3,284 0 0 2,440 0 61 423 85 8,217 Oklahoma 0 0 650 34 8 2,227 10 0 778 0 0 0 0 3,708 Tennessee 0 0 0 91 0 154 0 0 2 0 0 29 0 276 Texas 0 0 1,364 0 0 4,768 15 0 4,462 0 0 0 0 10,609 W. Virginia 385 16 325 0 0 1,412 0 37 433 696 0 57 0 3,361 Virginia 349 97 69 15 0 1,560 0 0 630 48 0 98 0 2,866 Total 2,116 113 5,632 140 361 15,925 52 37 10,659 910 61 1,288 85 37,379

Note: 11 Transmission line circuit miles are current as of 12/31/14; excludes ETT, OVEC and Joint Ventures Distribution Line Detail

By Operating By State Line Miles* Company Line Miles*

Total 223,124 Total 223,124

* Includes approximately 33,000 miles of underground circuit miles

Note: Year End 2014 data per Small World Graphics.

12 Rate Bases & ROEs

Proforma2 Earned Rate Base1 Approved Approved Effective Date of Last Jurisdiction ROE as of ($ millions) ROE Debt/Equity Approved Rate Case 09/30/2015 APCo-Virginia 10.40% 57/43 2/2/2015 APCo-West Virginia 9.75% 53/47 5/27/2015 APCo - FERC 10.34% 55/45 6/1/2015 APCo Total $ 7,127 8.9%

KPCo-Kentucky $ 1,614 -0.1% 10.25% 56/44 7/1/2015

I&M-Indiana 10.20% 48/52 2/28/2013 I&M-Michigan 10.20% 49/51 3/29/2012 I&M - FERC 10.09% 45/55 6/1/2015 I&M Total $ 4,154 9.8% PSO-Oklahoma $ 2,424 9.2% 9.85% 51/49 5/1/2015

SWEPCO-Louisiana 10.00%3 48/52 8/1/2015 SWEPCO-Arkansas 10.25% 54/46 11/25/2009 SWEPCO-Texas 9.65% 51/49 1/29/2013 SWEPCO - FERC 11.10% 50/50 1/1/2015 1 SWEPCO Total $ 4,464 9.3% Rate base represents Net Utility Plant Transmission and Distribution Companies plus Regulatory Assets less Net Proforma2 Earned Accumulated Deferred Income Taxes and Rate Base1 Approved Approved Effective Date of Last Jurisdiction ROE as of less Regulatory Liabilities from 2014 ($ millions) ROE Debt/Equity Approved Rate Case FERC Form 1 09/30/2015

2 AEP Ohio - Distribution 10.20% 52/48 2/25/2015 Proforma adjusts GAAP results by AEP Ohio - Transmission 11.49% 51/49 7/1/2015 eliminating any material nonrecurring AEP Ohio total $ 4,152 11.8% items and is not weather normalized

4 3 AEP Texas Central $ 2,175 10.6% 9.96% 60/40 2/18/2015 Represents the midpoint of the ROE AEP Texas North $ 922 8.3% 9.96% 60/40 2/18/20154 range approved in the formula rate case AEP Texas Total $ 3,097 settled in February 2013

Transcos 4 Represents the most recent approved Proforma2 Earned Effective Date of Last Rate Base1 Approved Approved TCOS update Company ROE as of Approved Formula ($ millions) ROE Debt/Equity 09/30/2015 Rate Filing AEP Ohio Transco $ 1,299 10.8% 11.49% 51/49 7/1/2015 AEP Kentucky Transco $ 26 13.4% 11.49% 51/49 7/1/2015 AEP Indiana Michigan Transco $ 311 11.3% 11.49% 51/49 7/1/2015 AEP13 West Virginia Transco $ 281 7.8% 11.49% 51/49 7/1/2015 AEP Oklahoma Transco $ 339 10.2% 11.20% 51/49 7/1/2015 Summary of Rate Case Filing Requirements

FERC AR IN KY LA MI OH OK TN TX VA WVA FERC Transmission

GENERAL

Time Limitations Between Cases No Yes No No No No No No No Yes No N/A N/A Rates Effective Subject to Refund Yes Yes Yes Yes Yes Yes Yes No Yes No No Yes Yes Semi- N/A Monthly Tri- Fuel Clause Renewal Frequency Annually Annually Monthly Monthly Annually Note 9 Annually Note 10 Annually Annually Annually N/A N/A

Approx # of months after filing to 10 @ 50% if 10 implement rates 10 no order 6 4 Varies 9 6 4 6 Note 8 10 2 or 7 Varies Approx # of months after filing order expected 10 10 6 4 6 9 6 4 6 8 10 2 or 7 N/A

Notice of Intent

Prior PSC Notice Required? Yes Yes Yes No Optional Yes Yes No Yes Yes Yes No No Notice Period (days) 60 Varies 28 N/A 45 30 45 N/A 30 60 30 No No

CASE COMPONENTS

Hist., Partially Hist.(Forecst Forecast (formula Forecast Partially/Fully Historical / Base Case Test Year Projected Opt/ Hybrid) Optional rate) Optional Projected Hist. Hist. Hist. Hist. Hist. Forecast Forecast Filed Post Test/Year Adjustment Period Min 6, (Months) 12 12 12 ------no max 24 -- 25 12 -- Varies Limited Optional Partial Limited No Limited Limited Cash Return on CWIP Partial- Note 2 Note 3 Note 1 Yes Note 4 Note 1 Yes Note 5 Yes Note 7 Note 6 Varies

Note 1: CWIP that is projected to be placed into service within six months post test year is included in rate base (for LA, under separate docket only). No CWIP in LA annual formula rates. Note 2: CWIP is not included in rate base for a general rate case. However, for Clean Coal Technology using Indiana Coal or Qualified Pollution Control Property, Cook Life Cycle Management Projects and Federally Mandated Projects the Commission may add CWIP to utility property for ratemaking purposes between rate cases via a surcharge. In addition, new legislation (SB 251) was passed that allows CWIP recovery through a tracker for Cook Life Cycle Management projects. Note 3: KPCo uses capitalization instead of rate base which includes CWIP; however, there is also a partial AFUDC offset which partially negates the cash return effect of CWIP. Note 4: Ohio (ESP) cases are cost-based; distribution cases are cost-of-service based. Note 5: Can request inclusion in rate base but requires a showing that it is needed to maintain financial integrity. The financial integrity standard in Texas is not clearly defined and has been, essentially, impossible to meet. Note 6: The general FERC rule has been to allow CWIP in rate base. Note 7: Allows environmental CWIP in rate base. Note 8: The SCC is required to issue order within 8 months of filing. Rate are to be implemented 60 days after order and are NOT subject to refund. Depending on the nature of the RAC, the SCC has a statutory limit to issue decisions within 3 months for a transmission cost recovery RAC, 8 months for a environmental compliance or DSM/EE RAC, and 9 months for cost recovery related to a new generating facility. Note 9: Historic quarterly FAC ended May 31, 2015 with final reconciliation filed with the PUCO on September 1, 2015.. Note 10: TN passed HB 191 in 2013 providing the TRA with authority to implement alternative ratemaking to allow for public utility rate reviews and cost recovery in lieu of a general rate case proceeding. 14 Recovery Mechanisms Across Jurisdictions

SO /No /CO Distribution Other Purchased 2 x 2 Environmental Renewables Company State Allowances & GHG Vegetation Energy Efficiency REPA Power OATT Investment Investment Offsets Management (Energy/Capacity)

DSM/EE Program Indiana ECCR BR CCTR/FMR/BR GPR/BR FAC FAC/BR BR/PJM Tracker Cost Rider I&M Michigan PSCR BR BR EO Rider BR PSCR PSCR/PSCR PSCR KPCo Kentucky Surcharge BR Surcharge DSM Adj. Clause BR N/A FAC/Tariff PPA BR

EE/PDR Ohio N/A ESRR N/A N/A AER N/A BTCR AEP Ohio Rider

KGPCo Tennessee FERC Tariff BR FERC Tariff N/A N/A N/A FERC Tariff PPAR

Virginia APCo BR BR ERAC/BR EERAC GRAC/BR RPSRAC/FF FAC/BR & FF TRAC

VMP EE/DR Recovery West Virginia ENEC ENEC/BR BR ENEC ENEC/ENEC ENEC Surcharge Rider

Arkansas ECR BR Surcharge/BR EECR BR ECR ECR/BR BR SWEPCO Louisiana EAC Formula BR/FAC Formula BR EECR/ Formula BR Formula BR FAC FAC/Formula BR Formula BR Texas (SWP) BR BR BR EECRF BR FAC FAC/BR TCRF AEP TX Texas (ERCOT) N/A BR N/A EECRF N/A N/A N/A TCOS

DSM Cost Oklahoma BR SRR BR BR FAC FAC/PPC BR/SPP Tracker PSO Recovery Rider

AER – Alternative Energy Rider ENEC – Expanded Net Energy Cost PPA – Purchased Power Agreement BR – Base Rates EO – Energy Optimization PPAR – Purchased Power Adjustment Rider BTCR – Basic Transmission Cost Rider ERAC – Environmental Rate Adjustment Clause PPC – Purchased Power Capacity Rider CCTR – Clean Coal Technology Rider ESRR – Enhanced Service Reliability Rider PSCR – Power Supply Cost Recovery Rider CO2 – Carbon Dioxide FAC – Fuel Adjustment Clause RAC – Rate Adjustment Clause DSM – Demand Side Management FERC – Federal Energy Regulatory Commission REPA – Renewable Energy Purchase Agreement EAC – Environmental Adjustment Clause FF – Fuel Factor RPSRAC – Renewable Portfolio Standard RAC ECR – Energy Cost Recovery Rider FMR – Federal Mandate Rider SO2 – Sulfur Dioxide ECCR – Environmental Compliance Cost Rider GHG – Green House Gas SPP – Southwest Power Pool Regional Transmission Org. EE – Energy Efficiency GPR – Green Power Rider (Solar-only) SRR – System Reliability Rider EE/DR – Energy Efficiency/Demand Response GRAC – Generation Rate Adjustment Clause TCOS – Transmission Cost of Service EE/PDR – EE Peak Demand Response Rider N/A – not applicable in this jurisdiction TCRF – Transmission Cost Recovery Factor EECR – EE Cost Rate Rider NOx – Nitrogen Oxide TRAC – Transmission Rate Adjustment Clause EECRF – Energy Efficiency Cost Recovery Factor Rider OATT – Open Access Transmission Tariff VMP – Vegetation Management Plan EERAC – EE Rate Adjustment Clause PJM – PA-NJ-MD Regional Transmission Org. 15 Storm Recovery Mechanisms by Jurisdiction

STATE Deferral Recovery Detail Arkansas Y BR Storm expense is normally recorded as incurred, without deferral, if ruled to be a significant storm expense the commission has granted authority to defer and recover. Indiana Y BR Recovery of storm costs is requested in base rate cases. 2011 base case established a Major Storm Reserve based on a 5-year historical average of major storm expenses with an over/under mechanism. Kentucky Y BR Recovery of storm costs is requested in base rate cases. Subsequent to a base rate case, regulatory assets have been established to recover the cost typically over a 5-year period. Louisiana N Formula BR Storm costs are expensed and included in developing future formula rates; amounts are not deferred. Michigan N BR Recovery of storm costs is requested in base rate cases. Ohio Y 2011 Distribution Base Case and 2014 Electric Security Plan orders established a $5M major storm reserve and annual true-up mechanism. Significant storms are addressed in separate proceedings. Oklahoma Y BR Recovery of storm costs is requested in base rate cases. Significant storms are addressed in separate proceedings. Tennessee Y BR Costs may be recovered through base rate case or a separate mechanism/proceeding. Texas Y BR/DCRF Storm expense is normally recorded as incurred, without deferral. However, if a test period includes a significant (SWEPCo) storm expense and authority is granted to defer costs, it may be deferred for recovery. Texas (TNC) N BR/DCRF Storm expense is normally recorded as incurred, without deferral, and is included in base rates during the test year. Texas (TCC) Y BR/DCRF Approved catastrophe reserve in base rates that allows deferral of all major storm O&M above $500K. Virginia N BR Under new legislation enacted in 2015, APCo will absorb incremental generation and distribution costs associated with severe weather events and/or natural disasters. West Virginia Y BR Recovery of storm costs is requested in base rate cases.

BR - Base Rates DCRF - Distribution Cost Recovery Factor

16 Jurisdictional Off-System Sales Sharing Summary

STATE OSS Sharing? Detail Arkansas Yes, above base Up to $1,200,000 annual margin, ratepayers receive 100%. Above $1,200,000, levels ratepayers receive 90%.

Indiana Yes, above and Sharing occurs above and below levels included in base rates of $26.9M, ratepayers below base levels receive 50%.

Kentucky* Yes, above and Sharing occurs above and below levels included in base rates of $15.1M, ratepayers below base levels receive 75%.

Louisiana Yes, above base Up to $874,000 annual margin, ratepayers receive 100%. From $874,001 to $1,314,000, levels ratepayers receive 85%. Above $1,314,000, ratepayers receive 50%.

Michigan Yes 80% of profits are shared with ratepayers. Ohio No n/a Oklahoma Yes 75% of profits are shared with ratepayers.

Tennessee No n/a Texas (SWEPCo) Yes 90% of profits are shared with ratepayers.

Virginia Yes 75% of profits are shared with ratepayers.

West Virginia Yes With the exception of WPCo's Mitchell Plant, 100% of profits passed back to ratepayers through the Expanded Net Energy Cost (ENEC) clause. Generally, 82.5% of Mitchell Plant profits are shared with ratepayers.

* Effective July 2015

17 Commission Overview

Federal Energy Regulatory Commission Commissioners

Number: 4 Appointed/Elected: Appointed Term: 5 Years Political Makeup: R: 1 D: 2 I: 1

Qualifications for Commissioners

The Federal Energy Regulatory Commission (FERC) is composed of up to five commissioners who are appointed by the President of the United States with the advice and consent of the Senate. Commissioners serve five-year terms, and have an equal vote on regulatory matters. To avoid any undue political influence or pressure, no more than three commissioners may belong to the same political party. Commissioners

Norman C. Bay, Chairman (Dem.) since 2014: term expires June 2018. Commissioner Bay assumed chairmanship in April 2015. From July 2009 to July 2014, Chairman Bay was the Director of the Office of Enforcement (OE). Under his leadership, OE enhanced its ability to conduct market oversight and surveillance and to investigate wrongdoing. OE successfully investigated allegations of manipulation of the gas and electric markets, and the Commission approved settlements that returned almost $1 billion to ratepayers and taxpayers. OE also led several inquiries into major reliability events, including the Arizona-Southern California outages of September 8, 2011, and issued reports that contained dozens of findings and recommendations. Before coming to FERC, Chairman Bay was a Professor of Law at the University of New Mexico School of Law. Chairman Bay served in the Department of Justice from 1989 to 2001. From 1989 to 2000, he was an Assistant U.S. Attorney in the District of Columbia and New Mexico; and from 2000 to 2001, he was the U.S. Attorney in the District of New Mexico.

Tony Clark, Commissioner (Rep.) since 2012: term expires June 2016. Most recently served as Chairman of the North Dakota Public Service Commission (PSC), a statewide elective office, where Commissioner Clark was first elected to the PSC in 2000. While at the North Dakota Commission, Commissioner Clark held the PSC portfolio on electric generation and transmission and was active in state and regional efforts to develop North Dakota’s vast energy exporting potential and to provide affordable, reliable energy to consumers. In his 12 years at the Commission, he oversaw regulatory proceedings that permitted more than $5.5 billion in new investment in North Dakota through expanded wind, coal and oil and gas infrastructure. Prior to his election to the PSC, Commissioner Clark was North Dakota’s Labor Commissioner.

Collette D. Honorable, Commissioner (Nonpartisan) since 2014: term expires June 2017. Commissioner Honorable came to FERC from the Arkansas Public Service Commission, where she served since October 2007, and led the Commission as Chairman since January 2011. Commissioner Honorable began her career at Legal Services, and worked as a consumer protection attorney, civil litigation, and as a Medicaid fraud special prosecutor before serving as chief of staff to then-Arkansas Attorney General Mike Beebe. As Chairman of the Arkansas PSC, Commissioner Honorable oversaw an agency charged with ensuring safe, reliable and affordable retail electric service.

Cheryl A. LaFleur, Commissioner (Dem.) since 2010: term expires June 2019. She served as Acting Chairman from November 2013 to July 2014 and as Chairman from July 2014 until April 2015. Prior to joining the Commission in 2010, Chairman LaFleur had more than 20 years’ experience as a leader in the electric and natural gas industry. She served as executive vice president and acting CEO of National Grid USA, responsible for the delivery of electricity to 3.4 million customers in the Northeast. Her previous positions at National Grid USA and its predecessor New England Electric System included chief operating officer, president of the New England distribution companies and general counsel.

Transforming Our Generation Fleet

• Transforming Our Generation Fleet • Investments Driving Emission Reductions • Dramatic Reductions in Emissions • Large-scale Renewable Opportunities • Delivering Clean Energy Resources • Long-Term Renewable Energy Purchase Agreements • Renewable Portfolio/Energy Efficiency Standards

19 Transforming Our Generation Fleet

23%

11%

20 Investments Driving Emission Reductions

(est)

21 Dramatic Reductions in Emissions

22 Large-scale Renewable Opportunities

Planned Generation Resource Additions Total

Solar: 2,809 MW’s

Wind: 5,650 MW’s

Natural Gas: 2,966 MW’s

Total Estimated Regulated Coal and Gas Retirements 2015 – 2033 • Coal: 5,738 MWs • Gas: 1,063 MWs Source: Current Internal Integrated Resource Plans, subject to periodic update.

$10+ Billion investment opportunity in renewables over the timeframe before considering CPP impacts 23 Delivering Clean Energy Resources

AEP's 2016 Wind and Solar Portfolio (nameplate capacity) MW AEP Ohio 209 Appalachian Power Company* 374 Indiana Michigan Power Company 466 Public Service Company of Oklahoma* 1,138 Southwestern Electric Power Company 470 Competitive Wind & Wind PPA's 488 Total 3,145

* Some RECs are monetized and not retired on behalf of AEP customers

24 Long-Term Renewable Energy Purchase Agreements

Net Operating Maximum Contract(s) Project Name State Fuel Type Company Capacity Initiated (MW) Camp Grove APCo IL Wind 75 2008 Beech Ridge APCo WV Wind 100 2009 Fowler Ridge III APCo IN Wind 99 2009 Grand Ridge II and III APCo IL Wind 100 2009 Gauley River (Summersville) APCo WV Hydro 80 1996 ecoPower # KPCo KY Biomass 59 2013 Fowler Ridge II OPCo IN Wind 100 2009 Wyandot Solar OPCo OH Solar 10 2010 Timber Road OPCo OH Wind 99 2013 Fowler Ridge I I&M IN Wind 100 2009 Fowler Ridge II I&M IN Wind 50 2009 Wildcat I&M IN Wind 100 2012 Headwaters I&M IN Wind 200 2013 Weatherford PSO OK Wind 147 2005 Blue Canyon II ## PSO OK Wind 151 2005 Sleeping Bear PSO OK Wind 95 2008 Blue Canyon V PSO OK Wind 99 2009 Minco PSO OK Wind 99 2010 Elk City PSO OK Wind 99 2010 Balko ### PSO OK Wind 200 2013 Seiling ### PSO OK Wind 200 2013 Goodwell ### PSO OK Wind 199 2013 Majestic SWEPCO TX Wind 80 2009 Majestic II SWEPCO TX Wind 80 2012 Flat Ridge II SWEPCO KS Wind 109 2009 / 2013 Canadian Hills SWEPCO OK Wind 201 2011 / 2012 2,931 # Pending regulatory approval; project not yet constructed 25 ## Contract expires end of 2015 ### Delivery scheduled to start 1/1/2016 Renewable Portfolio/Energy Efficiency Standards

Energy Efficiency Standards:

Ohio: 22% reduction of retail electricity sales by 2026 phased in beginning in 2009; but in 2014 SB 310 put a two year hold on mandates

Indiana: 2% electricity sales reduction by 2019 Michigan – M: phase in phased in starting in 2010 starting at 2% in 2012

increasing to 10% by 2015 Michigan: 1% annual reduction of previous year retail sales by 2012 Ohio – M: phase in starting at 0.5% in 2009 increasing Texas: 25% reduction in annual growth in to 12.5% by 2026; however, demand 2012; 30% reduction in annual growth in 2014, SB 310 put a two in demand 2013 year hold on the energy Indiana – V: phase in efficiency and renewable Virginia: 10% electricity savings by 2022 relative starting at 4% in 2013 mandates to 2006 base sales (voluntary) increasing to 15% by 2025

Oklahoma – V: goal of 15% by 2015

Virginia – V: phase in starting at 4% in 2010 increasing to 15% by 2025

Louisiana – pilot program to determine whether a standard is suitable

M: Mandatory Texas – M: starting at V: Voluntary 2,280MW in 2007 increasing to 10,000MW statewide by 2025 There are currently no renewable portfolio standards in Arkansas, Kentucky, Tennessee or 26 West Virginia

Environmental

• Regulated Environmental Investment & Retirements • Competitive Environmental Investment & Retirements • Regulated Environmental Retrofit Status • Competitive Environmental Retrofit Status • Clean Power Plan – Overview • Clean Power Plan – 2030 Mass Emission Goals • Clean Power Plan – Implementation Schedule • Additional Environmental Regulations

27 Regulated Environmental Investment & Retirements

Operating Potential Type of Operating Company Plant MW retrofit Company Plant MW Retirement Date APCO Clinch River 1 242 Refuel with Natural Gas APCO Glen Lyn 5 95 2015 Clinch River 2 242 Refuel with Natural Gas Glen Lyn 6 240 2015 Clinch River 3 235 2015 I&M Rockport 2,620 DSI, SCR Sporn 1 150 2015 KPCO Big Sandy 1 268 Refuel with Natural Gas Sporn 3 150 2015 Kanawha River 1 200 2015 PSO Oklaunion 102 ACI, CaBr Injection Kanawha River 2 200 2015 Northeastern 3 460 ACI, DSI, Baghouse Total MW 1270

SWEPCO Welsh 1 528 ACI, Baghouse Welsh 3 528 ACI, Baghouse I&M Tanners Creek 1-4 995 2015 Pirkey 580 ACI, CaBr Injection Total MW 995 Dolet Hills 256 ACI, Baghouse Flint Creek 264 FGD, ACI KPCO Big Sandy 2 800 2015 Total MW 800 Total Regulated retrofits = 6,090 SWEPCO Welsh 2 528 2016 Total MW 528

PSO Northeastern 4 470 2016 Total MW 470

Total Regulated retirements 4,063

ACI – Activated Carbon Injection DSI – Dry Sorbent Injection FGD – Flue Gas Desulfurization 28 SCR – Selective Catalytic Reduction Competitive Environmental Investment & Retirements

Operating Company Plant MW Type of retrofit

AEP Generation Resources Conesville 5 & 6 810 Gore TNC Oklaunion* 355 ACI, CaBr Injection Total Competitive retrofits = 1,155

*PPA

Operating Company Plant MW Retired AEP Generation Resources Beckjord 53 Oct 2014 Conesville 3 165 Dec 2012 Muskingum River 1-5 1,440 Jun 2015 Picway 5 100 Jun 2015 Sporn 2,4 300 Jun 2015 Sporn 5 450 Dec 2011 Kammer 1-3 630 Jun 2015 Total Competitive retirements = 3,138

29 Regulated Environmental Retrofit Status

MW Projected Projected Projected Projected Projected Gas Projected Plant Name Capacity SCR In-Service FGD In-Service ACI In-Service DSI In-Service Baghouse In-Service Conversion In-Service

APCo

Amos 1 800  

Amos 2 800  

Amos 3 1300  

Clinch River 1 242 x 2016

Clinch River 2 242 x 2016

Mountaineer 1,320  

WPCo

Mitchell 1&2* 780  

KPCo

Big Sandy 1 268 x 2016

Mitchell 1&2* 780  

I&M

Rockport 1 1,310 x 2017 x 2025 

Rockport 2 1,310 x 2019 x 2028 

* Operated by Kentucky Power In Service Projected

ACI – Activated Carbon Injection DSI – Dry Sorbent Injection FGD – Flue Gas Desulfurization SCR – Selective Catalytic Reduction

30 Regulated Environmental Retrofit Status

MW Projected Projected Projected Projected Projected Gas Projected Plant Name Capacity SCR In-Service FGD In-Service ACI In-Service DSI In-Service Baghouse In-Service Conversion In-Service

PSO

Oklaunion 102  

Northeastern 3 460 x 2016 x 2016 x 2016

SWEPCO

Dolet Hills 256    

Flint Creek 1 264 x 2016 x 2016

Pirkey 580   Welsh 1 528 x 2016 x 2024 x 2016

Welsh 3 528 x 2015 x 2024 x 2015

In Service Projected

ACI – Activated Carbon Injection DSI – Dry Sorbent Injection FGD – Flue Gas Desulfurization SCR – Selective Catalytic Reduction

31 Competitive Environmental Retrofit Status

MW Mercury Projected Plant Name Capacity SCR FGD ACI Solution In-Service AEP Generation Resources

Cardinal 1 595  

Conesville 4 339  

Conesville 5 405  x 2016

Conesville 6 405  

Gavin 1&2 2640  

Stuart 1-4 600  

Zimmer 330  

TNC

Oklaunion* 355  

* PPA In Service Projected

ACI – Activated Carbon Injection FGD – Flue Gas Desulfurization SCR – Selective Catalytic Reduction

32 Clean Power Plan - Overview

 EPA announced 111(d) Guidelines (“Clean Power Plan”) to reduce CO2 emissions from existing fossil fuel-fired electric generating units on August 3, 2015

. Establishes Uniform National CO2 Emission Performance Standards

. Defines State-Specific CO2 Emission Rate and Mass Emission Goals as optional requirements

 Clean Power Plan emission reductions driven by assumed actions across the utility industry

. 32% reduction in CO2 emissions from electric generating units compared to 2005 (EPA estimate) . Improved efficiency of coal-based generating units . Increased use of natural gas combined cycle units . Increased development of renewable energy

33 Clean Power Plan - Overview

 Multi-year process to develop and implement compliance strategies . Emission reduction requirements are phased-in from 2022 through 2030 . States develop and submit State Plans to EPA for approval . Initial draft State Plans due Sept 2016; Final draft State Plans due Sept 2018 . EPA proposed a draft Federal Plan for states that fail to develop an approvable State Plan . Final rule provides more clarity on opportunities for emissions trading as a compliance strategy

 Separately, EPA announced CO2 emission standards for new fossil fuel-fired units on August 3, 2015 . New coal units would effectively require carbon capture and storage (“CCS”) technology . New natural gas units expected to meet standards without CCS

34 Clean Power Plan – 2030 Mass Emission Goals

2030 State CO2 Reduction Goals (Final State Mass Goals vs. EPA-adjusted 2012 Emissions)

MI 32%

OH IN 28% 31% WV 29% VA KY 23% 32%

OK 23% AR 30%

LA 20% TX 25%

35 Data from EPA “Technical Support Document: Emissions Performance Rate and Goal Computation.” August 2015. www2.epa.gov/cleanpowerplan/clean-power-plan-final-rule-technical-documents Clean Power Plan – Implementation Schedule

Rule Proposed Enforceable Compliance Program Begins

Final Clean Power Plan & Proposed Federal Plan

Initial State Plan Final SIP Due w/ or Extension 2 Year Extension CO2 Emission Request Due Reduction Final Federal Requirements Plan Issued Gradually Become More Stringent State Plan FIP Promulgated for Approval / States w/o SIP Disapproval

Clean Energy Incentive Program Period - Early Action RE & EE Credits

2014 2015 2016 2017 2018 2019 2020 2021 2022 ------2030

36 Additional Environmental Regulations

 Revised Effluent Limitation Guidelines (“ELG”) – EPA announced on September 30, 2015 . Establishes more stringent standards for wastewater discharge from steam electric generating units . Will drive new and upgraded treatment systems for wastewater from FGD control systems, and ash handling and storage processes . Implementation Nov 1, 2018 to Dec 31, 2023 based on the renewal schedule of existing permits

 Coal Combustion Residuals Rule (“CCR”) – Finalized in the Federal Register on April 17, 2015 . Applies to the handling and storage coal combustion and emission control system by-products . Will drive upgraded systems for the transport and storage of coal combustion by-products

 ELG and CCR Implementation Strategy . AEP has long recognized that the ELG and CCR rules address many of the same plant systems . Optimal compliance solutions to address both rules have been included in capital cost estimates . With both rules finalized, plans are being refined and are expected to be generally consistent with prior estimates

 Revised Clean Water Act 316(b) Standards - Finalized in the Federal Register on August 15, 2014 . Applies to the cooling water intake systems . Does not mandate cooling towers, but does require studies of site-specific constraints . Optimal compliance solutions to address both rules have been included in capital cost estimates . With the rule finalized, plans are being refined and are expected to be generally consistent with prior estimates 37

Financial Update • Capitalization and Liquidity Position • AEP Banking Group • Credit Ratings • Long-Term Debt Maturity Profile • Debt Schedules

38 Capitalization & Liquidity

Total Debt / Total Capitalization

Credit Statistics Actual Target

FFO Interest Coverage 5.7x >3.6x

FFO to Total Debt 21.6% 15%-20%

Note: Credit statistics represent the trailing 12 months as of 09/30/2015

Liquidity Summary

(unaudited) 09/30/2015 Actual Qualified Pension Funding ($ in millions) Amount Maturity Revolving Credit Facility $1,750 Jul-18 Revolving Credit Facility $1,750 Jun-17 Total Credit Facilities $3,500 Plus Cash & Cash Equivalents $178 Less Commercial Paper Outstanding (32) Letters of Credit Issued (33) Net Available Liquidity $3,613

39 Pension & OPEB Estimates

• Despite negative equity returns of over -6% YTD, the pension plan Assumptions 2015E 2016E has lost only -0.6%, due to its 60% allocation to liability Pension Discount Rate 4.00% 4.25% matching bonds, which posted OPEB Discount Rate 4.00% 4.25% small gains. OPEB returns are Assumed Long Term Rate of 6.00% 6.00% down -6.3% YTD, due to the Return on Pension Assets negative market for equities. Assumed Long Term Rate of 6.75% 6.75% • We expect combined pension Return on OPEB Assets and OPEB costs (pre-tax and Pension/OPEB Funding $106M $103M including capitalized portion) to decrease by about $28M from Pension/OPEB Cost* $41M $49M 2015 to 2016 subject to potential changes in investment results, interest rates and *Cost component is pretax and pre-capitalization; on average, 35% actuarial assumptions. of pension and OPEB costs are capitalized and 65% are expensed • Pension funding and expense for regulated subsidiaries are recovered through rates.

40 AEP Banking Group

$3.5B Core Credit Facilities Moodys S&P Rating Rating %Share Lender Composition LT (ST) LT (ST) Mizuho Japanese Bank A1 (P-1) A+ (A-1) 8.9% Bank of Tokyo-Mitsubishi Japanese Bank A1 (P-1) A+ (A-1) 5.0% Barclays Bank British Bank A2 (P-1) A- (A-2) 5.0% Citibank Major US Bank A1 (P-1) A (A-1) 5.0% Credit Suisse Investment Bank A1 (P-1) A (A-1) 5.0% JP Morgan Major US Bank Aa3 (P-1) A+ (A-1) 5.0% Key Bank US Regional Bank A3 (P-1) A- (A-2) 5.0% Wells Fargo Major US Bank Aa2 (P-1) AA- (A-1+) 5.0% Bank of America Major US Bank A1 (P-1) A (A-1) 3.9% Bank of New York US Regional Bank Aa2 (P-1) AA- (A-1+) 3.9% BNP Paribas European Bank A1 (P-1) A+ (A-1) 3.9% Credit Agricole European Bank A2 (P-1) A (A-1) 3.9% Lender mix gives AEP Goldman Sachs Investment Bank A1 (P-1) A (A-1) 3.9% geopolitical Morgan Stanley Investment Bank A1 (P-2) A (A-1) 3.9% diversification Royal Bank of Canada Canadian Bank Aa3 (P-1) AA- (A-1+) 3.9% Scotia Capital Canadian Bank Aa2 (P-1) A+ (A-1) 3.9% SunTrust Bank US Regional Bank Baa1 (P-1) A- (A-2) 3.9% UBS Investment Bank A2 (P-1) A (A-1) 3.9% US Bank US Regional Bank A1 (P-1) AA- (A-1+) 3.9% BBVA European Bank Baa3 (P-2) BBB (A-2) 2.6% Fifth-Third Bank US Regional Bank Baa1 (NR) A- (A-2) 2.6% PNC Financial US Regional Bank A2 (P-1) A (A-1) 2.6% Sumitomo Bank Japanese Bank A1 (P-1) A+ (A-1) 2.6% Huntington National Bank US Regional Bank A3 (P-1) BBB+ (NR) 1.4% The Northern Trust Co. US Regional Bank A2 (P-1) AA- (A-1+) 1.4% Total 100.0% 41 AEP Credit Ratings

Current Ratings for AEP, Inc. & Subsidiaries Moody's S&P Senior Senior Company Unsecured Outlook Unsecured Outlook

American Electric Power Company Inc. Baa1 S BBB- P AEP, Inc. Short Term Rating P2 S A2 S AEP Texas Central Company Baa1 S BBB P AEP Texas North Company Baa1 S BBB P Appalachian Power Company Baa1 S BBB P Indiana Michigan Power Company Baa1 S BBB P Kentucky Power Company Baa2 S BBB P Ohio Power Company Baa1 S BBB P Public Service Company of Oklahoma A3 S BBB P Southwestern Electric Power Company Baa2 S BBB P

Ratings current as of September 30, 2015

42 Long-term Debt Maturity Profile

($ in millions) Year 2015 2016 2017 2018 2019 2020

AEP, Inc. - - $550 - - - AEP Generating Company - - $45 - - - AEP Generation Resources $79 $60 $500 - - - AEP Texas Central Company* - $144 $169 $380 $50 $681 AEP Texas North Company - $75 - $30 - $44 AEP Transmission Company - - - $50 $85 - Appalachian Power - $170 $375 $100 $156 - Indiana Michigan Power $125 $29 $77 $200 $650 - Kentucky Power - - $390 $50 - - Ohio Power* - $350 $85 $350 $103 - Public Service of Oklahoma - $275 - - $250 $13 Southwestern Electric Power - - $350 $382 $454 - Wheeling Power Company - $65 - - - - Desert Sky Wind Farm - - $10 - - - Total $204 $1,168 $2,551 $1,542 $1,748 $738

* Includes $1.4B of securitization bonds based upon scheduled final payment data

Includes mandatory tenders (put bonds) Data as of September 30, 2015

43 Debt Schedules

American Electric Power, Inc Interest Maturity CUSIP / PPN* Amount

Senior Notes 1.650% 12/15/2017 025537AF8 $550,000,000 Senior Notes 2.950% 12/15/2022 025537AG6 $300,000,000

Total $850,000,000

AEP Generating Company Interest Maturity CUSIP / PPN* Amount

Tax Exempt Rockport, Series 1995 A Floating 07/01/20251 773835BG7 $22,500,000 Tax Exempt Rockport, Series 1995 B Floating 07/01/20251 773835BH5 $22,500,000

Senior Notes 6.330% 09/30/2037 00113AA2 $160,000,060

Total $205,000,060

1 Liquidity Letter of Credit matures on 7/15/2017

AEP Generation Resources Interest Maturity CUSIP / PPN* Amount

Term Loan Floating 04/30/2017 00105TAA8 $500,000,000 Tax Exempt OAQDA, Series 2014A Floating 12/1/20382 677525VL8 $60,000,000 Tax Exempt OAQDA, Series 2014B Floating 6/1/20413 N/A $79,450,000

Total $639,450,000

2 Liquidity Letter of Credit matures on 6/02/2016 3 Put date 12/31/2015

Note: Debt schedules current as of 9/30/15. 44 * PPN – Private Placement Number Debt Schedules

AEP Texas Central Interest Maturity CUSIP / PPN* Amount

Tax Exempt Guadalupe-Blanco River Authority, Series 2008 5.625% 10/01/2017 40053QAQ4 $40,890,000 Tax Exempt Red River Authority of Texas 4.450% 06/01/2020 756864BT0 $6,330,000 Tax Exempt Matagorda County, Series 2001A 6.300% 11/01/2029 576528DM2 $100,635,000 Tax Exempt Matagorda County, Series 1996 5.200% 05/01/2030 576528DE0 $60,000,000 Tax Exempt Matagorda County, Series 2008-1 4.000% 06/01/2030 576528CX9 $60,265,000 Tax Exempt Matagorda County, Series 2008-2 4.000% 06/01/2030 576528CW1 $60,000,000 Tax Exempt Matagorda County, Series 2005A 4.400% 05/01/2030 576528CY7 $111,700,000 Tax Exempt Matagorda County, Series 2005B 4.550% 05/01/2030 576528CZ4 $50,000,000

Senior Notes 2.610% 04/30/2019 0010EPA*9 $50,000,000 Senior Notes 3.850% 10/01/2025 0010EPAN8 $250,000,000 Senior Notes 3.810% 04/30/2026 0010EPA@7 $50,000,000 Senior Notes 6.650% 02/15/2033 0010EPAF5 $275,000,000 Senior Notes 4.670% 04/30/2044 0010EPA#5 $100,000,000 Senior Notes 4.770% 10/30/2044 0010EPB*8 $100,000,000

Term Loan Floating 07/31/2016 N/A $100,000,000

Total $1,414,820,000

Securitization Bond - TC1 6.250% 01/15/2016 12617AAE7 $44,198,278 Securitization Bond - TC2 5.170% 01/01/2018 00110AAD6 $380,247,750 Securitization Bond - TC2 5.306% 07/01/2020 00110AAE4 $494,700,000 Securitization Bond - TC3 0.880% 12/01/2017 00104UAA6 $128,259,684 Securitization Bond - TC3 1.976% 06/01/2020 00104UAB4 $180,200,000 Securitization Bond - TC3 2.845% 12/01/2024 00104UAC2 $311,900,000

Total $1,539,505,712

Note: Debt schedules current as of 9/30/15. * PPN – Private Placement Number 45 Debt Schedules

AEP Texas North Interest Maturity CUSIP / PPN* Amount

Tax Exempt Red River Authority of Texas 4.450% 06/01/2020 756864BT0 $44,310,000

Senior Notes 5.890% 04/01/2018 0010EQA*7 $30,000,000 Senior Notes 3.090% 02/28/2023 0010EQA#3 $125,000,000 Senior Notes 6.760% 04/01/2038 0010EQA@5 $70,000,000 Senior Notes 4.480% 02/27/2043 0010EQB*6 $75,000,000 Senior Notes 3.270% 09/30/2022 0010EQB@4 $25,000,000 Senior Notes 3.750% 09/30/2025 0010EQB#5 $50,000,000

Term Loan Floating 07/31/2016 N/A $75,000,000

Total $494,310,000

Note: Debt schedules current as of 9/30/15. 46 * PPN – Private Placement Number Debt Schedules

AEP Transmission Company Interest Maturity CUSIP / PPN* Amount

Senior Notes, Series A 3.300% 10/18/2022 00114*AA1 $104,000,000 Senior Notes, Series A 4.000% 10/18/2032 00114*AB9 $85,000,000 Senior Notes, Series A 4.730% 10/18/2042 00114*AC7 $61,000,000 Senior Notes, Series A 4.780% 12/14/2042 00114*AD5 $75,000,000 Senior Notes, Series A 4.830% 3/18/2043 00114*AE3 $25,000,000 Senior Notes, Series B 2.730% 11/7/2018 00114*AF0 $50,000,000 Senior Notes, Series B 4.050% 11/7/2023 00114*AG8 $60,000,000 Senior Notes, Series B 4.380% 11/7/2028 00114*AL7 $60,000,000 Senior Notes, Series B 5.320% 11/7/2043 00114*AH6 $100,000,000 Senior Notes, Series B 5.420% 4/30/2044 00114*AJ2 $30,000,000 Senior Notes, Series B 5.520% 10/30/2044 00114*AK9 $100,000,000 Senior Notes, Series C 2.680% 11/14/2019 00114*AM5 $85,000,000 Senior Notes, Series C 3.180% 11/14/2021 00114*AN3 $50,000,000 Senior Notes, Series C 3.560% 11/14/2024 00114*AP8 $95,000,000 Senior Notes, Series C 3.660% 3/16/2025 00114*AQ6 $50,000,000 Senior Notes, Series C 3.760% 6/15/2025 00114*AR4 $40,000,000 Senior Notes, Series C 3.810% 11/14/2029 00114*AS2 $55,000,000 Senior Notes, Series C 4.010% 6/15/2030 00114*AT0 $60,000,000 Senior Notes, Series C 4.050% 11/14/2034 00114*AU7 $25,000,000 Senior Notes, Series C 4.530% 11/14/2044 00114*AV5 $40,000,000

Total $1,250,000,000

Note: Debt schedules current as of 9/30/15. 47 * PPN – Private Placement Number Debt Schedules

Appalachian Power Company Interest Maturity CUSIP / PPN* Amount

Tax Exempt WVEDA, Series 2008C 3.250% 05/01/2019 95648NAB3 $30,000,000 Tax Exempt WVEDA, Series 2008D 3.250% 05/01/2019 95648NAC1 $40,000,000 Tax Exempt Russell County, Series K 4.625% 11/01/2021 782470AR9 $17,500,000 Tax Exempt Mason County, Series L 1.625% 10/1/20224 575200BA7 $100,000,000 Tax Exempt WVEDA, Series 2008B Floating 2/1/20365 95648VAL3 $50,275,000 Tax Exempt WEVDA, Series 2008A Floating 2/1/20365 95648VAK5 $75,000,000 Tax Exempt WVEDA, Series 2010A 5.375% 12/01/2038 95648VAS8 $50,000,000 Tax Exempt WVEDA, Series 2011A 2.250% 1/1/20416 95648VAT6 $65,350,000 Tax Exempt WVEDA, Series 2009A Floating 12/1/20427 95648VAP4 $54,375,000 Tax Exempt WVEDA, Series 2009B Floating 12/1/20427 95648VAQ2 $50,000,000 Tax Exempt WVEDA, Series 2015A (Amos) 1.900% 3/1/20438 95648VAV1 $86,000,000

Senior Notes 5.000% 06/01/2017 037735CD7 $250,000,000 Senior Notes 4.600% 03/30/2021 037735CR6 $350,000,000 Senior Notes 3.400% 06/01/2025 037735CU9 $300,000,000 Senior Notes 5.950% 05/15/2033 037735BZ9 $200,000,000 Senior Notes 5.800% 10/01/2035 037735CE5 $250,000,000 Senior Notes 6.375% 04/01/2036 037735CG0 $250,000,000 Senior Notes 6.700% 08/15/2037 037735CK1 $250,000,000 Senior Notes 7.000% 04/01/2038 037735CM7 $500,000,000 Senior Notes 4.400% 05/15/2044 037735CT2 $300,000,000 Senior Notes 4.450% 06/01/2045 037735CV7 $350,000,000

Total $3,618,500,000

Securitization Bond - APCRR A-1 2.008% 02/01/2023 037680AA3 $180,597,742 Securitization Bond - APCRR A-2 3.772% 08/01/2028 037680AB1 $164,500,000

Total $345,097,742

4 Put date 10/01/2018 5 Liquidity Letter of Credit matures on 03/17/2017 6 Put date 09/01/2016 7Liquidity Letter of Credit matures on 03/24/2016 8 Put date 4/01/2019

Note: Debt schedules current as of 9/30/15. 48 * PPN – Private Placement Number Debt Schedules

Desert Sky Wind Farm Interest Maturity CUSIP / PPN* Amount

Notes Payable 6.475% 08/31/2017 N/A $10,275,443

Total $10,275,443

Indiana Michigan Power Company Interest Maturity CUSIP / PPN* Amount

Tax Exempt City of Lawrenceburg, Series I Floating 10/01/20199 520453AL5 $25,000,000 Tax Exempt City of Lawrenceburg, Series H Floating 11/01/202110 520453AK7 $52,000,000 Tax Exempt City of Rockport, Series 2002 A 4.625% 06/01/2025 773835AV5 $50,000,000 Tax Exempt City of Rockport, Series 2009 B 1.750% 06/01/202511 773835BL6 $50,000,000 Tax Exempt City of Rockport, Series 2009 A 1.750% 06/01/202511 773835BM4 $50,000,000

Nuclear Fuel Lease 2.120% 05/01/2016 N/A $830,013 Nuclear Fuel Lease Floating 05/01/2016 N/A $1,198,447 Nuclear Fuel Lease Floating 10/15/2016 N/A $27,013,051 Nuclear Fuel Lease Floating 04/28/2019 N/A $79,788,109 Nuclear Fuel Lease Floating 10/27/2019 N/A $95,034,850

Term Loan Floating 05/15/2018 45488QAA6 $100,000,000

Senior Notes 5.650% 12/01/2015 454889AL0 $125,000,000 Senior Notes 7.000% 03/15/2019 454889AN6 $475,000,000 Senior Notes 3.200% 03/15/2023 454889AP1 $250,000,000 Senior Notes 6.050% 03/15/2037 454889AM8 $400,000,000

Total $1,780,864,470

9 Liquidy Letter of Credit matures on 03/22/2017 10 Liquidity Letter of Credit matures on 03/16/2017

11 Put date is 06/01/2018

Note: Debt schedules current as of 9/30/15. 49 * PPN – Private Placement Number Debt Schedules

Kentucky Power Interest Maturity CUSIP / PPN* Amount

Tax Exempt WVEDA Series 2014A (Mitchell) Floating 4/1/203612 95648VAU3 $65,000,000

Senior Notes 6.000% 09/15/2017 491386AM0 $325,000,000 Senior Notes 7.250% 06/18/2021 491386C*7 $40,000,000 Senior Notes 4.180% 09/30/2026 491386D*6 $120,000,000 Senior Notes 4.330% 12/30/2026 491386D@4 $80,000,000 Senior Notes 8.030% 06/18/2029 491386C@5 $30,000,000 Senior Notes 5.625% 12/01/2032 491386AL2 $75,000,000 Senior Notes 8.130% 06/18/2039 491386C#3 $60,000,000

Term Loan Floating 11/05/2018 N/A $50,000,000

Total $845,000,000

12 Liquidity Letter of Credit matures on 06/26/2017

Ohio Power Company Interest Maturity CUSIP / PPN* Amount

Tax Exempt OAQDA, Series 2009B 5.800% 12/01/2038 N/A $32,245,000

Senior Notes 6.000% 06/01/2016 677415CL3 $350,000,000 Senior Notes 6.050% 05/01/2018 199575AW1 $350,000,000 Senior Notes 5.375% 10/01/2021 677415CP4 $500,000,000 Senior Notes 6.600% 02/15/2033 677415CF6 $250,000,000 Senior Notes 6.600% 03/01/2033 199575AT8 $250,000,000 Senior Notes 5.850% 10/01/2035 199575AV3 $250,000,000

Total $1,982,245,000

Securitization Bond - OHPIR A-1 0.958% 07/01/2017 67741YAA6 $84,536,959 Securitization Bond - OHPIR A-2 2.049% 07/01/2019 67741YAB4 $102,508,000

Total $187,044,959

Note: Debt schedules current as of 9/30/15. 50 * PPN – Private Placement Number Debt Schedules

Public Service Company of Oklahoma Interest Maturity CUSIP / PPN* Amount

Term Loan Floating 11/14/2016 N/A $125,000,000 Gridsmart Loan 3.000% 06/01/2027 N/A $6,010,543

Tax Exempt Red River Authority of Texas 4.450% 06/01/2020 756864BT0 $12,660,000

Senior Notes 6.150% 08/01/2016 744533BH2 $150,000,000 Senior Notes 5.150% 12/01/2019 744533BK5 $250,000,000 Senior Notes 4.400% 02/01/2021 744533BL3 $250,000,000 Senior Notes 3.170% 03/31/2025 744533C*9 $125,000,000 Senior Notes 6.625% 11/15/2037 744533BJ8 $250,000,000 Senior Notes 4.090% 03/31/1945 744533C@7 $125,000,000

Total $1,293,670,543

Note: Debt schedules current as of 9/30/15. 51 * PPN – Private Placement Number Debt Schedules

Southwestern Electric Power Company Interest Maturity CUSIP / PPN* Amount

Notes Payable 6.370% 10/31/2024 78532*AC7 $25,000,000 Notes Payable 4.580% 02/21/2032 78532*AD5 $53,625,000

Tax Exempt Sabine River Authority of Texas, Series 2006 4.950% 03/01/2018 785652CJ5 $81,700,000 Tax Exempt Parish of DeSoto, Series 2010 1.600% 01/01/201913 241627AW8 $53,500,000

Senior Notes 5.550% 01/15/2017 845437BH4 $250,000,000 Senior Notes 5.875% 03/01/2018 845437BJ0 $300,000,000 Senior Notes 6.450% 01/15/2019 845437BK7 $400,000,000 Senior Notes 3.550% 02/15/2022 845437BM3 $275,000,000 Senior Notes 6.200% 03/15/2040 845437BL5 $350,000,000 Senior Notes 3.900% 04/01/2045 845437BN1 $400,000,000

Term Loan Floating 07/11/2017 N/A $100,000,000

Total $2,288,825,000

13 Put date 01/02/2015

Wheeling Power Company Interest Maturity CUSIP / PPN* Amount

Tax Exempt WVEDA, Series 2013A Floating 06/01/203714 N/A $65,000,000

Senior Notes 3.360% 06/01/2022 96316#AB9 $113,000,000 Senior Notes 3.700% 06/01/2025 96316#AC7 $122,000,000 Senior Notes 4.200% 06/01/2035 96316#AD5 $50,000,000

Total $350,000,000

14 Put date 07/01/2016

Note: Debt schedules current as of 9/30/15. 52 * PPN – Private Placement Number Overview

President and Chief Operating Officer: Charles Patton Since April 2010 20 years with AEP

Appalachian Power Company (APCo) (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 959,000 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. As of December 31, 2014, APCo had Total Customers at 12/31/14: 1,902 employees. APCo is a member of PJM. Residential 889,000 Commercial 145,000 Industrial 5,000 Wheeling Power Company (WPCo) (organized in West Virginia in 1883 and reincorporated in 1911) Other 8,000 provides electric service to approximately 41,000 retail customers in PRINCIPAL Total 1,047,000 northern West Virginia. As of December 31, 2014, WPCo had 53 INDUSTRIES SERVED: employees. WPCo is a member of PJM. Coal Mining Owned Generating Capacity* 7,414 MW Kingsport Power Company (KGPCo) Primary Metals Generating Capacity by Fuel Mix*: (organized in Virginia in 1917) provides electric service to Chemical Manufacturing approximately 47,000 retail customers in Kingsport and eight • Coal: 67.4% Pipeline Transportation neighboring communities in northeastern Tennessee. As of • Hydro/Pump: 10.8% December 31, 2014, KGPCo had 49 employees. KGPCo is a Paper Manufacturing member of PJM. • Natural Gas: 21.8%

Transmission Miles 6,460 Distribution Miles 54,206

Note: Values consolidate APCo, WPCo, and KGPCo. 53 * Reflects fuel type conversion of Clinch River in 2016. APCo Financial & Operational Data

Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Debt Equity Total Debt Equity Total Credit Ratings/Outlook

Capitalization Per Balance Sheet 3,980,274 3,366,928 7,347,202 3,990,519 3,459,654 7,450,173 Moody's S&P % of Capitalization Per Balance Sheet 54.2% 45.8% 100.0% 53.6% 46.4% 100.0% Baa1/S BBB/P

FFO Interest Coverage 4.12 5.11^ FFO Total Debt 17.2% 21.5% ^ - calculated on rolling 12-month avg.

Summary of Degree Days** Summary of KWh Energy Sales*** (in millions of KWhs) 2014 2013 2012 35,000 (in degree days) 31,002 31,140 31,492 Actual 2,645 2,377 1,783 30,000 Heating Normal 2,232 2,225 2,265 25,000 10,314 10,393 10,778 Actual 1,056 1,150 1,354 Cooling hours 20,000 - Normal 1,206 1,206 1,201 15,000 6,799 6,817 6,843

Kilowatt 10,000 2015 Asset Data* (in thousands) 5,000 11,851 11,801 11,762 - As of 9/30/15 2014 2013 2012 Total Assets $ 11,406,209 Residential Commercial Industrial Other Net Plant Assets$ 9,294,946

* Source: 3Q15 Financial Statements (unaudited) Cash $ 2,411 ** Source: 2014 10K Financial Statements *** KWh Sales – Weather Normalized 54 WPCo Financial & Operational Data

Capital Structure (in thousands)

2014** 6/30/2015* Capital Structure Debt Equity Total Debt Equity Total Credit Ratings/Outlook

Capitalization Per Balance Sheet 356,719 371,702 728,421 355,868 407,958 763,826 Moody's S&P % of Capitalization Per Balance Sheet 49.0% 51.0% 100.0% 46.6% 53.4% 100.0% NR BBB/P

FFO Interest Coverage 32.99 9.17^ FFO Total Debt 57.3% 13.2% ^ - calculated on rolling 12-month avg.

Summary of Degree Days Summary of KWh Energy Sales*** (in millions of KWhs) 2014 2013 2012 4,000 (in degree days) 3,260 2,694 2,494 3,500 Actual 4,113 3,781 2,966 Heating Normal 3,687 3,685 3,731 3,000 Actual 715 806 1,028 2,500 Cooling hours

- Normal 721 714 709 2,000 2,397 1,811 1,600 1,500 Kilowatt 1,000 2015 Asset Data* (in thousands) 455 500 441 451 417 427 434 - As of 6/30/15 2014 2013 2012 Total Assets $ 1,071,892 Residential Commercial Industrial Other Net Plant Assets $ 910,348

* Source: 2Q15 Financial Statements Cash $ 523 ** Source: 2Q15 Financial Statements – 2014 statement reissued with Mitchell transfer *** KWh Sales – Weather Normalized 55 KGPCo Financial & Operational Data

Capital Structure (in thousands)

2014** 6/30/2015* Capital Structure Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 42,039 31,277 73,316 47,769 30,560 78,329 % of Capitalization Per Balance Sheet 57.3% 42.7% 100.0% 61.0% 39.0% 100.0%

Summary of Degree Days Summary of KWh Energy Sales*** (in millions of KWhs) 2014 2013 2012 2,500 (in degree days) 2,091 2,038 2,102 Actual 2,532 2,366 1,790 Heating 2,000 Normal 2,219 2,215 2,256

Actual 1,088 980 1,147 1,500 981 926 971 Cooling hours

- Normal 1,069 1,065 1,057

1,000 392 391 397 Kilowatt 500 2015 Asset Data* (in thousands) 682 684 696 - As of 6/30/15 2014 2013 2012 Total Assets $ 132,378 Residential Commercial Industrial Other Net Plant Assets $ 110,236

* Source: 2Q15 Financial Statements Cash $ 68 ** Source: 2014 Annual Financial Statements *** KWh Sales – Weather Normalized 56 Customer Statistics

APPALACHIAN AREA TYPICAL BILL COMPARISON ** INVESTOR OWNED UTILITIES * West Virginia $/month Virginia $/month West Virginia Customers Potomac Edison 92.38 Virginia Electric & 100.25 APCo 433,391 Power Co. Monongahela 388,542 Monongahela Power 92.38 Dominion Virginia 114.05 Power APCo 93.78 APCo 118.11 Potomac Edison 137,482 WPCo 93.78 WPCo 41,296

Tennessee $/Month Virginia Customers KGPCo 87.14 APCo 524,638 ** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage. Virginia Electric & 2,381,312 Billing amounts sourced from the EEI Typical Bills and Average Rates Report as Power Co. of January 1, 2015. Kentucky Utilities 28,526 MAJOR CUSTOMERS: Roanoke Cement Co. LLC (VA) Greif Brothers Corporation (VA) Tennessee Customers Steel of WV, Inc. (WV) WVA Manufacturing (WV) KGPCo 47,253 Roanoke Electric Steel Corporation (VA) * Customer counts are as of December 31, 2014 and were Georgia-Pacific Corporation (VA) sourced from Sales_Ult_Cust_2014.xls at Bayer Crop Science LP (WV) http://www.eia.gov/electricity/data/eia861/index.html Felman Production (WV) Constellium Rolled Products (WV) The Goodyear Tire and Rubber Co. (VA) Top 10 Customers = 32% of industrial sales (Data for year ended December 2014) Metropolitan areas account for 56% of ultimate sales

103 persons per square mile (U.S. = 87) (Data for 12 months ended December 2014) 57 Commission Overview

Virginia State Corporation Commission

Commissioners

Number: 3 Appointed/Elected: Elected Term: 6 Years Political Makeup: R: 2 D: 1 Qualifications for Commissioners

The Virginia State Corporation Commission (VSCC) is composed of three members elected by the General Assembly. Commissioners are elected to serve six-year terms, staggered in two year increments. The chair rotates annually among the three commissioners on February 1. Commissioners

Mark C. Christie, Chairman, (Rep.), since 2004; current term expires 2016. Prior counsel to the Speaker of the House of delegates of the Virginia General Assembly. Lawyer, private practice. Law degree from Georgetown. Judith Williams Jagdmann, (Rep.), since 2006; current term expires 2018. Law degree from T.C. Williams School of Law at the University of Richmond. Served as Deputy Attorney General for Civil Litigation Division from 1998 to 2005. Attorney General for Commonwealth of Virginia from 2005 to 2006. James C. Dimitri, (Dem.), since 2008; current term expires 2020. Prior to being named Commissioner, Dimitri was in private practice in Richmond. From 1994 to 2000 he served as Senior Counsel, then General Counsel at the SCC. He was an assistant Attorney General from 1983 to 1987. Dimitri received his undergraduate degree in economics from the University of Virginia and his J.D. from the Boston University School of Law.

AEP Regulatory Status

APCo-VA provides retail electric service in Virginia at unbundled rates. In early 2015, the General Assembly of VA passed the “Rate Freeze Law”, effective in July 2015. Under the new law, no changes can be made to the existing tariff rates until biennial rate reviews resume. For APCo, biennial reviews are suspended until 2020 with the first biennial review applying to the earnings for calendar years 2018 and 2019. APCo-VA is entitled to adjustments to fuel, transmission, and certain other rates to recover its actual costs. Virginia currently has a voluntary renewable energy standard which phased in starting at 4% and increases to 10% from 2010 - 2025.

58 Commission Overview

Public Service Commission of West Virginia

Commissioners

Number: 3 Appointed/Elected: Appointed Term: 6 Years Political Makeup: R: 1 D: 2 Qualifications for Commissioners

The West Virginia Public Service Commission (WVPSC) consists of three members, appointed by the Governor, with the advice and consent of the senate. No more than two members of the commission may belong to the same political party. The Commissioners serve six year staggered terms, with one term expiring as of July 1 of each odd numbered year. One Commissioner is designated as Chairman of the Commission by the Governor. The Chairman serves as the chief fiscal officer of the Commission. Commissioners

Michael A. Albert, Chairman (Rep.), since 2007; term expires June 2019. Served as a member in the Business Law Department of Jackson Kelly. President and Chairman of the board of directors of the Kanawha County Public Library. Bachelor’s degree and Doctorate of Jurisprudence, West Virginia University. Kara C Williams, Commissioner (Dem.), since 2015; term expires June 2017. Practiced commercial litigation at Steptoe & Johnson PLLC. Currently serves on the Board of Directors for Carnegie Hall, Inc. Graduate of Washington & Lee University and Harvard Law School. Brooks McCabe, Commissioner (Dem.), since 2014; term expires June 2021. Commissioner McCabe is the Managing Member and Broker of West Virginia Commercial, LLC. Served as a Senator representing Kanawha County from 1998-2014. Doctor of Education degree from West Virginia University.

AEP Regulatory Status

APCo and Wheeling Power in WV provide retail electric service at bundled rates approved by the WV PSC. West Virginia has an active annual ENEC (Expanded Net Energy Cost) mechanism, which provides for a rate adjustment for fuel costs, among other items. Wheeling Power acquired ½ of Unit 1 and ½ of Unit 2 of Mitchell Plant from AGR, an affiliate, in 2015. In May, 2015, the Public Service Commission of West Virginia authorized new base rates and an annual vegetation management surcharge.

59 Commission Overview

Tennessee Regulatory Authority Commissioners

Number: 5 Appointed/Elected: Appointed Term: 6 Years Qualifications for Commissioners

The Tennessee Regulatory Authority (TRA) directors are appointed, one each, by the Governor, Lieutenant Governor (as Speaker of the Senate), Speaker of the House and two joint appointments by the three together, and are confirmed by the Tennessee General Assembly. The directors are appointed for six and three-year staggered terms. The chairmanship rotates every year in an agreed upon decision by the directors. Commissioners

Herbert H Hilliard, Chairman, since 2012; current term expires June 2017. Former Executive Vice President and Chief Government Relations Officer for Frist Horizon National Corporation. Serves as Chairman of the Board of Directors of The National Civil Rights Museum, Board member of Blue Cross Blue Shield of Tennessee and Commissioner for the Memphis Shelby County Airport Authority. BBA in Personnel Administration and Industrial Relations from University of Memphis. David Jones, Vice-Chairman, since 2012; current term expires June 2018. President of Complete Holding Group. Certified facilitator/executive coach with the Alternative Board. BS in Business from University of Tennessee, Knoxville and an MBA from the University of Houston. Kenneth C. Hill, Director (Rep.), since 2009; current term expires June 2015. At the time of his appointment to the TRA, Hill was Chief Executive Officer of Appalachian Educational Communication Corporation and served as General Manager of five radio stations reaching portions of East Tennessee and four surrounding states. Doctor of Religious Education, Andersonville Baptist Seminary. Robin Morrison, Director , since 2013; current term expires June 2020. Vice President and financial center manager for First Tennessee bank. Member Chattanooga Bar Association Auxiliary. Bachelor’s degree in Business Administration-Finance from the University of Tennessee-Chattanooga. Vacant

AEP Regulatory Status

Tennessee has no deregulation legislation and no base rate freeze or cap. Tennessee has an active fuel clause. In September, 2015, the company filed its first base case since 1992, which is currently pending before the Tennessee Regulatory Authority. Currently, fuel rates are adjusted monthly, while purchased power and transmission costs are updated annually.

60 Overview

President and Chief Operating Officer: Paul Chodak Since July 2010 14 years with AEP

Indiana Michigan Power Company Total Customers at 12/31/14: (I&M) (organized in Indiana in 1907) is engaged in the Residential 511,000 generation, transmission and distribution of electric power to Commercial 70,000 approximately 588,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and Industrial 5,000 marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other Other 2,000 market participants. As of December 31, 2014, I&M had 2,551 Total 588,000 employees. I&M is a member of PJM.

Owned Generating Capacity* 3,539MW Generating Capacity by Fuel Mix*: • Coal: 37.0% PRINCIPAL INDUSTRIES SERVED: • Nuclear: 61.9% Primary Metals Chemical Manufacturing • Hydro: 0.6% Transportation Equipment • Solar: 0.5% Plastics and Rubber Products Transmission Miles 5,258 Nonmetallic Mineral Products Distribution Miles 20,375

* Includes solar coming online in 2016. 61 Financial & Operational Data

Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Debt Equity Total Debt Equity Total Credit Ratings/Outlook

Capitalization Per Balance Sheet 2,169,898 1,953,949 4,123,847 2,211,655 2,044,691 4,256,346 Moody's S&P % of Capitalization Per Balance Sheet 52.6% 47.4% 100.0% 52.0% 48.0% 100.0% Baa1/S BBB/P FFO Interest Coverage 5.53 5.73^ FFO Total Debt 24.8% 24.8% ^ - calculated on rolling 12-month avg.

Summary of KWh Energy Sales*** Summary of Degree Days** (in millions of KWhs) 2014 2013 2012 30,000 (in degree days) 23,290 23,275 23,359 Actual 4,664 4,076 3,042 25,000 Heating

Normal 3,737 3,730 3,772 5,104 5,098 5,085 20,000 Actual 714 826 1,098

hours Cooling - Normal 853 855 861 15,000 7,640 7,522 7,556 10,000 Kilowatt 4,883 4,932 4,965 5,000 2015 Asset Data* (in thousands) 5,663 5,723 5,753 - As of 9/30/15 2014 2013 2012 Total Assets $ 8,629,524 Residential Commercial Industrial Other Net Plant Assets$ 5,239,724 * Source: 3Q15 Financial Statements (unaudited) ** Source: 2014 10K Financial Statements Cash $ 1,264 *** KWh Sales – Weather Normalized 62 Customer Statistics

INDIANA & MICHIGAN INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON ** Indiana Customers Indiana $/month Michigan $/month I & M 458,140 IP & L 97.82 I & M 104.00 IP & L 477,921 I & M 110.51 Detroit Edison 140.87 NIPSCO 461,010 Duke Energy Indiana 119.17 Consumers Energy 143.90 Duke Energy Indiana 797,580 NIPSCO 131.97

SIGECo 147,171 SIGECo 157.39 ** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage. Michigan Customers Billing amounts sourced from the EEI Typical Bills and Average Rates Report as of January 1, 2015. I & M 127,734

Consumers Energy 1,779,1841,792,421 MAJOR CUSTOMERS:

The DTE Electric Company 2,148,142 2,156,214 Steel Dynamics Inc. (IN) * Customer counts are as of December 31, 2014 and were Metal Technologies Inc. (MI) sourced from Sales_Ult_Cust_2014.xls at American Axle and Mfg. Co, Inc. (MI) http://www.eia.gov/electricity/data/eia861/index.html IN TEK (IN) Rettenmaier USA LP (MI) Michelin North America (IN) Top 10 Customers = 45% of industrial sales White Pigeon Paper Company (MI) Air Products & Chemicals. Inc. (IN) Metropolitan areas account for 66% of ultimate sales The Minute Maid Company (MI) 205 persons per square mile (U.S. = 87) Linde LLC (IN)

(Data for 12 months ended December 2014) (Data for year ended December 2014)

63 Commission Overview

Indiana Utility Regulatory Commission

Commissioners

Number: 5 Appointed/Elected: Appointed Term: 4 Years Political Makeup: R: 3 D: 2 Qualifications for Commissioners

Five members, appointed by the Governor from among persons nominated by a legislatively mandated utility commission nominating committee; four-year, staggered terms, full-time positions. Not more than three of the members of the IURC shall be members of the same political party. At least one of the commissioners must be an attorney qualified to practice law before the Indiana Supreme Court. The Governor appoints one of the five as chairperson. Commissioners Carol A. Stephan, Chair, (Rep.), Since 2014; current term ends December 2015. Formerly served as the Commission’s Assistant General Counsel and General Counsel, Director of Case Management. Also served as Interim Deputy Commissioner of the Indiana Department of Workforce Development. Law degree from the Indiana University Robert H. Mckinney School of Law. Carolene R. Mays, Vice-Chair (Dem.), since 2010; current term ends December 2017. Former publisher and president of the Indianapolis Recorder Newspaper and the Indiana Minority Business Magazine. From 2002 to 2008, served in the Indiana House of Representatives and sat on the committees for Small Business and Economic Development, Ways and Means and Public Health.

Angela Weber, Commissioner (Rep.), since 2014; current term ends March 2018. Former Marion County deputy prosecuting attorney, former staff attorney for the Indiana Department of Education. Received juris doctor from the Indiana University Maurer School of Law in 2006. David E. Ziegner, Commissioner (Dem.), since 1990; current term ends April 2019. Lawyer, staff attorney for Legislative Services Agency, General Counsel for IURC. Treasurer of NARUC, vice-chair NARUC Committee on Electricity and former chairman of the NARUC clean coal and carbon sequestration subcommittee. Law degree from the Indiana University School of Law in Indianapolis. James Huston, Commissioner (Rep.), Since September 2014; current term ends March 2017. Currently serves as Chief to Staff at the Indiana State Department of Health. Prior to that also served as assistant deputy treasurer and Deputy Commissioner for the Bureau of Motor Vehicles. Huston received his undergraduate degree from Ball State University.

AEP Regulatory Status

I&M–Indiana provides retail electric service at bundled rates approved by the IURC. Rates are set on a cost-of-service basis with a fuel recovery mechanism. I&M–Indiana has trackers in place for PJM expenses, OSS sharing, clean coal technology, environmental, nuclear life cycle management and DSM. Indiana currently has a voluntary renewable standard which phases in starting at 4% and ending at 10% from 2013-2025.

64 Commission Overview

Michigan Public Service Commission Commissioners

Number: 3 Appointed/Elected: Appointed Term: 6 Years Political Makeup: I: 2 R: 1 Qualifications for Commissioners

The Michigan Public Service Commission (MPSC) is composed of three members appointed by the Governor with the advice and consent of the Senate. Commissioners are appointed to serve staggered six-year terms. No more than two commissioners may represent the same political party. One commissioner is designated as chairman by the Governor. Commissioners

John D. Quackenbush, Chairman (Rep.), since 2011; current term expires July 2017. Former managing director and senior investment analyst at UBS Global Asset Management responsible for equity research of transportation, utilities and coal industries in the US and Canada. Undergraduate degree in business economics from Calvin College and masters degree in finance from Michigan State University. Sally Talberg, Commissioner (Ind.), since 2013; current term expires July 2019. Former senior consultant at Public Sector Consultants. Previously served as an analyst at the MPSC, managed enforcement and contested cases at the Michigan Department of Environmental Quality and advised commissioners at the Public Utility Commission of Texas. Holds a bachelor of science from Michigan State University and a masters of Public Administration from the University of Texas – Austin..

Norman J. Saari, Commissioner, (Ind.) , since 2015; current term expires July 2021. Served as an executive director of governmental affairs for 20 years at the Consumers Energy Company. Commissioner Saari is a member of the National Association of Regulatory Utility Commissioners and sits on the Board of Directors of the Organization of PJM States, Inc. Earned a bachelor’s degree from Michigan State University.

AEP Regulatory Status

Customer choice began January 2002. Generation was not deregulated. Retail rates were unbundled (though they continue to be regulated) to allow customers to evaluate generation costs. In 2008, legislation was enacted to limit customer choice load to no more than 10% of the annual retail load for the preceding calendar year but there is currently active legislation attempting to increase this cap. I&M-Michigan has an active fuel clause and return on CWIP can be included in base rates. Michigan currently has a mandatory renewable energy standard which phases in starting at 2% and ending at 10% from 2012-2015 .

65 Overview

President and Chief Operating Officer: Greg Pauley Since August 2010 41 years with AEP

Kentucky Power Company (KPCo) (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to Total Customers at 12/31/14: approximately 171,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to Residential 139,000 other electric utility companies, municipalities and other Commercial 30,000 market participants. As of December 31, 2014, KPCo had 595 employees. KPCo is a member of PJM. Industrial 1,500 Other 500 Total 171,000

Owned Generating Capacity* 1,048 MW PRINCIPAL INDUSTRIES SERVED: Generating Capacity by Fuel Mix*: Petroleum and Coal Products Manufacturing • Coal: 74.4% Coal Mining • Natural Gas: 25.6% Primary Metals

Chemical Manufacturing Transmission Miles 1,251 Oil and Gas Extraction Distribution Miles 10,064

* Reflects fuel type conversion of Big Sandy in 2016.

66 Financial & Operational Data

Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Credit Ratings/Outlook Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 864,683 663,643 1,528,326 851,765 656,214 1,507,979 Moody's S&P % of Capitalization Per Balance Sheet 56.6% 43.4% 100.0% 56.5% 43.5% 100.0% Baa2/S BBB/P

FFO Interest Coverage 4.40 4.14^ FFO Total Debt 15.8% 16.3% ^ - calculated on rolling 12-month avg.

Summary of Degree Days Summary of KWh Energy Sales*** (in millions of KWhs) 2014 2013 2012 8,000 (in degree days) 6,557 6,584 6,845 7,000 Actual 2,928 2,630 2,013 Heating 6,000 Normal 2,438 2,432 2,470

Actual 993 1,177 1,276 5,000 2,810 2,870 3,060 Cooling hours

- Normal 1,184 1,185 1,188 4,000

3,000 1,355 1,337 1,364 Kilowatt 2,000 2015 Asset Data* (in thousands) 1,000 2,287 2,273 2,315 As of 9/30/15 - 2014 2013 2012 Total Assets $ 2,380,795 Residential Commercial Industrial Other Net Plant Assets$ 1,722,947

* Source: 3Q15 Financial Statements (unaudited) Cash $ 541 ** Source: 2014 10K Financial Statements *** KWh Sales – Weather Normalized 67 Customer Statistics

KENTUCKY INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON ** Kentucky Customers Kentucky $/month

KPCo 171,011 Duke Energy Kentucky 86.19 Duke Energy Kentucky 137,869 KPCo 96.16 Kentucky Utilities 513,697 Kentucky Utilities Comp 97.22 LG & E 398,041 LG&E 103.20 * Customer counts are as of December 31, 2014 and were ** Typical bills are displayed in $/month, based on sourced from Sales_Ult_Cust_2014.xls at 1,000 kWh of residential usage. Billing amounts http://www.eia.gov/electricity/data/eia861/index.html sourced from the EEI Typical Bills and Average Rates Report as of January 1, 2015.

MAJOR CUSTOMERS:

Catlettsburg Refining LLC AK Steel Holding Corporation Air Products & Chemicals, Inc. Top 10 customers = 71% of industrial sales Air Liquide Metropolitan areas account for 41% of ultimate sales Calgon Carbon Corp Markwest Energy Appalachia LLC 68 persons per square mile (U.S. = 87) Huntington Alloys (Data for 12 months ended December 2014) Czar Coal Corporation Perry County Coal Corp M C Mining Inc.

(Data for year ended December 2014)

68 Commission Overview

Kentucky Public Service Commission

Commissioners

Number: 3 Appointed/Elected: Appointed Term: 4 Years Political Makeup: R: 0 D: 2 Qualifications for Commissioners

Typically three members, appointed by the governor and confirmed by the state Senate for four-year, staggered terms, full-time positions. The governor appoints one of the three as chairman and another of the three as vice chairman to serve in the chairman’s absence. Not more than two members of the KPSC shall be of the same profession or occupation. Commissioners

James W. Gardner, Chairman (Dem.), since 2008; current term expires June 2016. Prior to joining the PSC Mr. Gardner was a partner at the law firm Henry Watz Gardner & Sellars PLLC where he specialized in bankruptcy law. J.D. from the University of Kentucky College of Law. Daniel E. Logsdon Jr., Vice Chairman (Dem.), since February 2015; current term expires June 2017. Before joining the PSC, Commissioner Logsdon served as chairman and executive director of the Kentucky Democratic Party, a position he assumed in 2010. He also has experience in the telecommunications industry as a state government affairs representative from 2004 to 2009. BA from the Murray State University. Vacant – Commissioner will likely be appointed following November 2015 gubernatorial election.

AEP Regulatory Status

KPCo provides retail electric service at regulated bundled rates in Kentucky. Kentucky has an environmental surcharge to recover approved environmental costs and it has an active fuel clause. Kentucky also has an OSS sharing mechanism and a monthly adjustment clause in place for DSM. KPCo implemented new rates in 2015, including an increase in base rates, inclusion of Mitchell Plant in rate base, and establishment of surcharges to recover certain plant retirement costs.

69 Overview

President and Chief Operating Officer: Pablo Vegas

Since May 2012 10 years with AEP

AEP Ohio - Ohio Power Company (OPCo) (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the transmission and distribution of electric power to approximately 1,466,000 retail customers in Ohio. Following corporate separation of OPCo's generation assets in December 2013, OPCo purchases energy and capacity to serve generation service customers. As of December 31, 2014, OPCo had 1,516 employees. OPCo is a member of PJM. Total Customers at 12/31/14: Residential 1,278,000 Commercial 175,000 Industrial 10,000 PRINCIPAL INDUSTRIES SERVED: Other 3,000 Primary Metals Petroleum and Coal Products Manufacturing Total 1,466,000 Chemical Manufacturing Rubber & Plastic Products Transmission Miles 8,097 Fabricated Metal Products Distribution Miles 45,693 Nonmetallic Mineral Products

70 Financial & Operational Data

Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Credit Ratings/Outlook Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 2,297,123 1,980,210 4,277,333 2,166,050 2,007,618 4,173,668 Moody's S&P % of Capitalization Per Balance Sheet 53.7% 46.3% 100.0% 51.9% 48.1% 100.0% Baa1/S BBB/P

FFO Interest Coverage 5.24 6.19^ FFO Total Debt 26.1% 33.4% ^ - calculated on rolling 12-month avg.

Summary of KWh Energy Sales*** Summary of Degree Days** (in millions of KWhs) 2014 2013 2012 60,000 (in degree days) 43,326 44,412 46,659 Actual 3,734 3,383 2,610 50,000 Heating

Normal 3,230 3,229 3,276 40,000 Actual 949 1,029 1,248 14,541 15,916 18,125 hours Cooling - 30,000 Normal 960 954 948

20,000 14,326 14,102 14,047 Kilowatt 10,000 2015 Asset Data* (in thousands) 14,328 14,261 14,360 - As of 9/30/15 2014 2013 2012 Total Assets $ 6,945,503 Residential Commercial Industrial Other Net Plant Assets$ 4,984,087 * Source: 3Q15 Financial Statements (unaudited) ** Source: 2014 10K Financial Statements Cash $ 3,248 *** KWh Sales – Weather Normalized 71 Customer Statistics

OHIO INVESTOR OWNED UTILITIES* TYPICAL BILL COMPARISON**

Ohio Customers Ohio $/month

AEP Ohio 1,463,883 Duke Energy Ohio 120.56

Duke Energy Ohio 696,157 FE (CEI) 123.59 DP&L 514,952 FE (Toledo Edison) 125.08 FE (Ohio Edison) 1,035,096 FE (Ohio Edison) 127.03 FE (CEI) 744,409 DP&L 129.23 FE (Toledo Edison) 307,853 AEP (CSPCo) 155.87

* Customer counts are as of December 31, 2014 and were AEP (OPCo) 158.15 sourced from Sales_Ult_Cust_2014.xls at http://www.eia.gov/electricity/data/eia861/index.html ** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage. Billing amounts sourced from the EEI Typical Bills and Average Rates Report as of January 1, 2015. Ohio rates represent provider of last resort bundled residential rates. MAJOR CUSTOMERS:

Timken Steel Corporation The Premcor Refining Group Inc. Republic Steel Globe Metallurgical, Inc. Marathon Petroleum Company LP Linde Gase, LLC Top 10 OPCo customers = 42% of industrial sales Owens Corning Sales LLC Sunoco Inc (R&M) Metropolitan areas account for 52% of ultimate sales RockTenn CP LLC 139 persons per square mile (U.S. = 87) Pro-Tec Coating Company (Data for 12 months ended December 2014) (Data for year ended December 2014)

72 Commission Overview

Ohio Public Utilities Commission

Commissioners

Number: 5 Appointed/Elected: Appointed Term: 5 Years Political Makeup: R: 3 D: 0 I: 2 Qualifications for Commissioners

Five members, appointed by the governor and confirmed by the state senate; five-year staggered terms, full-time positions, commissioners shall be selected from the lists of qualified persons submitted to the governor by the PUC nominating council. Not more than three of the members of the PUCO shall be members of the same political party. The governor appoints one of the five as chairman, who serves at the pleasure of the governor until a successor has been designated. Commissioners

Andre T. Porter, Chairman, (Rep.) , since 2015; term expires April 2020. Previously served as a PUCO commissioner from 2011-2013. Prior his appointment to chairman of the PUCO, Porter led the Ohio Department of Commerce. Prior to serving the State of Ohio, Porter was an energy, public utilities and real estate taxation attorney with a leading Columbus, Ohio law firm. Law degree from The Ohio State University Moritz College of Law. M. Beth Trombold, Commissioner, (Ind.) since 2013; term expires April 2018. Prior to joining the commission, was the assistant director of the Ohio Development Services Agency. Prior to that was on PUC staff for 16 years. Bachelor’s degree in business administration from Ohio University and master’s in public policy from Ohio State University.

Thomas W. Johnson, (Rep.) , since 2014; term expires April 2019. Prior to joining the commission, was on the Ohio House of Representatives for 22 years serving Southeastern Ohio. After that served as Governor Bob Taft’s director of the Office of Budget and Management from 1999 to 2006. Bachelor’s degree in government from Muskingum University.

Asim Haque, Commissioner, (Ind.) since 2013; term expires April 2016. Prior to joining the commission was assistant counsel at Honda North America. Prior to that was an attorney with Ice Miller LLP. Bachelor’s degrees in chemistry and political science from Case Western Reserve University and Juris Doctorate from Ohio State University. Lynn Slaby, Commissioner, (Rep.) since 2012; term expires April 2017. Juris Doctorate and Bachelor of Science from University of Akron; previously served in Ohio House of Representatives representing 41st District. For 14 years Commissioner Slaby served as Summit County Prosecuting Attorney.

AEP Regulatory Status

OPCo currently has an approved electric security plan through May 2018. Transmission rates are currently regulated by FERC as reflected in the OATT and billed to retail customers via the transmission cost recovery rider. Ohio currently has a mandatory renewable energy standard of 12.5% by 2026, phased in beginning in 2009; however, SB 310 put a temporary hold on the energy efficiency and renewable mandates. 73 Overview

President and Chief Operating Officer: Stuart Solomon Since June 2004 26 years with AEP

Public Service Company of Oklahoma (PSO) (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 542,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing Total Customers at 12/31/14: electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, Residential 466,000 2014, PSO had 1,133 employees. PSO has the highest percentage of Commercial 62,000 renewables (wind) in the AEP system. PSO is a member of SPP. Industrial 6,000 Other 8,000 Total 542,000

Owned Generating Capacity * 4,436 MW PRINCIPAL INDUSTRIES SERVED: Generating Capacity by Fuel Mix: Paper Manufacturing Oil & Gas Extraction • Coal: 23.4% Transportation Equipment • Natural Gas: 76.6% Plastics and Rubber Products

Oil Refining and Steel Processing Transmission Miles 3,384 Nonmetallic Mineral Product Manufacturing Distribution Miles 22,212

*As of 9/30/15. 74 Financial & Operational Data Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Debt Equity Total Debt Equity Total Credit Ratings/Outlook Capitalization Per Balance Sheet 1,195,285 1,028,215 2,223,500 1,290,973 1,113,168 2,404,141 % of Capitalization Per Balance Sheet 53.8% 46.2% 100.0% 53.7% 46.3% 100.0% Moody's S&P A3/S BBB/P FFO Interest Coverage 4.76 6.57^ FFO Total Debt 17.4% 26.3% ^ - calculated on rolling 12-month avg.

Summary of Degree Days**

2014 2013 2012 Summary of KWh Energy Sales*** (in degree days) (in millions of KWhs) Actual 2,113 2,107 1,271 Heating Normal 1,777 1,763 1,803 20,000 17,883 17,593 17,588 Actual 2,054 2,082 2,663 1,260 1,253 1,319 Cooling 15,000 Normal 2,130 2,133 2,119 5,237 5,083 5,066 hours - 10,000 5,133 5,059 5,045 2015 Asset Data* (in thousands) Kilowatt 5,000 As of 9/30/15 6,253 6,198 6,158 - Total Assets $ 4,114,726 2014 2013 2012

Residential Commercial Industrial Other Net Plant Assets$ 3,615,365

*Source: 3Q15 Financial Statements (unaudited) Cash $ 1,663 **Source: 2014 10-K Financial Statements 75***KWh Sales – Weather Normalized Customer Statistics

OKLAHOMA INVESTOR OWNED UTILITIES TYPICAL BILL COMPARISON ***

Oklahoma Customers Oklahoma $/month

PSO* 542,000 PSO 84.10

OG&E** 745,000 OG&E 98.99 Empire District** 5,000 Empire District 105.90

*** Typical bills are displayed in $/month, based * Customer count from 2014 10K on 1,000 kWh of residential usage. Billing amounts sourced from the EEI Typical Bills * *Customer counts are as of December 31, 2014 and were and Average Rates Report as of January 1, sourced from table 10 at 2015. http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

MAJOR CUSTOMERS:

International Paper Company Top 10 customers = 42% of industrial sales Kimberly Clark Corp Goodyear Tire & Rubber Company Metropolitan areas account for 75% of ultimate sales HollyFrontier Corporation 49 persons per square mile (U.S. = 87) American Airlines Terra Nitrogen (Data for 12 months ended December 2014) Federal Government

(Data for year ended December 2014)

76 Commission Overview

Oklahoma Corporation Commission

AEP Regulated Electric Utilities

Public Service Company of Oklahoma

Commissioners

Number: 3 Appointed/Elected: Elected Term: 6 Years Political Makeup: R: 3 D: 0

Qualifications for Commissioners

The Oklahoma Corporation Commission (OCC) is composed of three commissioners who are elected by state-wide vote. Commissioners serve staggered six-year terms. The election pattern was established when the Commission was created by the state constitution. Commissioners

Bob Anthony, Chairman, (Rep.), since 1989; current term expires January 2019. Member, NARUC. Served on the boards of the Oklahoma State, Oklahoma City, and South Oklahoma City chambers of commerce. Earned an M.Sc. from the London School of Economics, an M.A. from Yale University and an M.P.A. from the Kennedy School of Government at Harvard University.

Todd Hiett, Commissioner (Rep.), since 2015; current term ends January 2021. Elected to the Oklahoma House of Representatives in 1994, selected as House Minority Leader in 2002 and Speaker of House from 2004-2006. After 12 years in the Legislature, he returned to the business world and ran his cattle ranch until his election as a Commissioner. He received his undergraduate degree in Animal Science/Business from Oklahoma State University. Dana Murphy, Vice Chairman (Rep.), since 2008; current term expires January 2017. Member, NARUC. Murphy’s prior experience includes working as an administrative law judge at the Commission. She has more than 20 years experience in the petroleum industry including owning and operating her own private law practice and working as a geologist in the Oklahoma petroleum industry. Juris Doctorate Oklahoma City University.

AEP Regulatory Status

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 power costs are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is generally adjusted annually and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are returned to or recovered from customers when new annual factors are established. PSO has an OSS margin sharing mechanism. Oklahoma currently has a voluntary renewable energy standard of 15% by 2015.

77 Overview

President and Chief Operating Officer: Venita McCellon-Allen

Since July 2010 32 years with AEP

Southwestern Electric Power Company (SWEPCO) (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 528,000 retail customers in northeastern 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 Total Customers at 12/31/14: participants. At December 31, 2014, SWEPCO had 1,468 employees. The territory served by Residential 448,000 SWEPCO also includes several military installations, colleges, and universities. SWEPCO also owns and operates a lignite coal mining operation. SWEPCO is a member of SPP. Commercial 73,000

Industrial 7,000 Other 500 Total 528,500 Owned Generating Capacity* 5,779 MW Generating Capacity by Fuel Mix: PRINCIPAL INDUSTRIES SERVED: Oil and Gas Extraction • Coal: 40.2% Petroleum & Coal Products Manufacturing • Natural Gas: 45.3% Primary Metals • Lignite: 14.5% Food Manufacturing Transmission Miles 4,096 Paper Manufacturing Distribution Miles 26,486

78 * As of 9/30/15 Financial & Operational Data Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Debt Equity Total Debt Equity Total Credit Ratings/Outlook

Capitalization Per Balance Sheet 2,140,437 2,096,786 4,237,223 2,283,966 2,194,865 4,478,831 % of Capitalization Per Balance Sheet 50.5% 49.5% 100.0% 51.0% 49.0% 100.0% Moody's S&P Baa2/S BBB/P

FFO Interest Coverage 4.97 4.37^ FFO Total Debt 23.5% 19.1% ^ - calculated on rolling 12-month avg.

Summary of Degree Days** Summary of KWh Energy Sales*** (in millions of KWhs) 2014 2013 2012 30,000 (in degree days) 24,482 24,293 24,175 Actual 1,553 1,421 860 Heating 25,000 Normal 1,230 1,226 1,259 6,241 6,322 6,249 Actual 2,043 2,248 2,605 20,000 Cooling

hours Normal 2,279 2,275 2,256 - 15,000 5,901 5,612 5,661

10,000

Kilowatt 6,032 5,999 6,044 2015 Asset Data* (in thousands) 5,000 6,308 6,360 6,221 As of 9/30/15 - 2014 2013 2012 Total Assets $ 7,101,606

Residential Commercial Industrial Other Net Plant Assets$ 6,203,376

*Source: 3Q15 Financial Statements (unaudited) Cash $ 14,258 **Source: 2014 10-K Financial Statements 79 ***KWh Sales –Weather Normalized Customer Statistics

SOUTHWESTERN INVESTOR TYPICAL BILL COMPARISON ** OWNED UTILITIES *

Arkansas Customers Arkansas $/month Louisiana $/month Texas $/month OG&E 68.90 SWEPCO 87.67 SWEPCO 106.98 SWEPCO 115,414 SWEPCO 87.07 Entergy LA 96.76 SPSCo 84.03 Entergy AR 701,085 Entergy AR 95.47 Entergy Gulf St 98.24 El Paso 109.48 Entergy New Entergy OG&E 65,732 Empire District 119.55 Orleans 94.95 Texas 116.51 CLECO 117.89 Empire District 4,405

Louisiana Customers ** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage. Billing amounts sourced from SWEPCO 229,239 the EEI Typical Bills and Average Rates Report as of January 1, 2015.

CLECO 281,583 Entergy 1,243,684

Texas Customers MAJOR CUSTOMERS:

SWEPCO 182,584 Exxon Mobil Corp (TX) El Paso 302,738 US Steel Corporation (TX) Tyson Foods, Inc. (AR) SPSCo 266,833 Calumet Lubricants (LA) Domtar Corporation (AR) Entergy TX 425,554 Pilgrim’s Pride Corporation (AR) * Customer counts are as of December 31, 2014 and were sourced from table 10 Wal-Mart Stores, Inc. (AR) at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html Cooper Tire & Rubber Company (AR) Pratt Paper, LLC (LA) Top 10 customers = 40% of industrial sales International Paper Company (TX) Metropolitan areas account for 71% of ultimate sales (Data for year ended December 2014) 70 persons per square mile (U.S. = 87)

80 (Data for 12 months ended December 2014) Commission Overview

Arkansas Public Service Commission

Commissioners

Number: 3 Appointed/Elected: Appointed Term: 6 Years Political Makeup: R: 1 D: 2 Qualifications for Commissioners

The Arkansas Public Service Commission (APSC) is composed of 3 members. The Governor appoints the Commissioners as well as the Chairman. Governor Asa Hutchinson appointed the Chairman Thomas while former Governor Mike Beebe appointed Commissioners Davis and Willis. Commissioners

Ted Thomas Chairperson (Rep.), since 2015; current term expires in Jan 2021. Commissioner Thomas previously served as Chief Deputy Prosecuting Attorney, Administrative Law Judge at the Public Service Commission, Budget Director for the Governor and in the Arkansas House of Representatives. Chairman Thomas received his Juris Doctorate from the University of Arkansas School of Law. Lamar B. Davis Commissioner (Dem.), since 2015; current term expires in Jan 2017. Served as Deputy Chief of Staff for the Office of Governor Mike Beebe from 2007 to 2015. Previously served as Assistant Attorney General in the Consumer Protection Department and Adjunct Professor at William H. Bowen School of Law in Little Rock. Received his Juris Doctorate from the University of Arkansas School of Law. Elana C. Wills, Commissioner (Dem.), since 2011; current term expired Jan 2013, however, she will continue to serve at the request of the Governor. Served as an Associate Justice on the Arkansas Supreme Court by gubernatorial appointment from October 2008 – December 2010. Received her Juris Doctorate from the University of Arkansas School of Law in Fayetteville.

AEP Regulatory Status

SWEPCO-AR provides service at regulated bundled rates in Arkansas. Arkansas has an active fuel pass-through clause. Arkansas has an OSS margin sharing mechanism and allows CWIP in rate base for a plant that is placed in service within six months after the end of the test year.

81 Commission Overview

Louisiana Public Service Commission Commissioners

Number: 5 Appointed/Elected: Elected Term: 6 Years Political Makeup: R: 3 D: 2 Qualifications for Commissioners

The Louisiana Public Service Commission (LPSC) is composed of five elected members. The commissioners serve overlapping terms of six years. Commissioners

Scott Angelle, (Rep.), since 2013; current term ends December 2018. Appointed in 2004 as Secretary of the Department of Natural Resources and Chairman of State’s Mineral Board. Left the DNR to seek office on PSC. Bachelor’s degree in petroleum land management from University of Louisiana-Lafayette.

Foster L. Campbell, (Dem.), since 2003; current term ends December 2020. Member, Louisiana State Senate (1976-2002). Independent insurance businessman and farmer, former school teacher and agricultural products salesman. Bachelor’s degree from Northwestern State University. Lambert C. Bossiere, III (Dem.), since 2005; current term ends December 2016. B.S. Business Administration from Southern University. American University of Paris – International Trade Law – Paralegal Certificate. Former First City Court Constable for the City of New Orleans. Member of NARUC. Eric Skrmetta, (Chairman) (Rep.), since 2009; current term ends December 2020. Practicing Attorney since 1985. Practicing Mediator since 1989. Republican State Central Committee District 81. Juris Doctorate Southern University Law School. Clyde Holloway, (Vice-Chairman) (Rep.), since 2009; current term ends December 2016. Elected to Congress in 1987 and served in the United States House of Representatives until 1993. In October 2006 he received an appointment by President Bush as the USDA State Director of Rural Development where he served until 2009.

AEP Regulatory Status

SWEPCO-LA provides service at regulated bundled rates in Louisiana. Louisiana has an active fuel pass-through clause and an OSS margin sharing mechanism. All IOUs are regulated pursuant to formula rate plans (FRP). Louisiana has allowed CWIP return on new generation projects, in limited circumstances. A formula rate plan was implemented August 1, 2008 with annual true-ups required. A new FRP implemented in January 2013 was applicable up to test year ending December 31, 2014. LPSC may renew FRP, subject to agreement by SWEPCO.

82 Commission Overview

Public Utility Commission of Texas

Commissioners

Number: 3 Appointed/Elected: Appointed Term: 6 Years Political Makeup: R: 3 D: 0 Qualifications for Commissioners

To be eligible for appointment, a commissioner must be: a qualified voter and a citizen of the U.S.; a competent and experienced administrator; well informed and qualified in the field of public utilities and public utility regulation; and, have at least five years of experience in the administration of business or government or as a practicing attorney or certified public accountant. Chairman appointed by the Governor. Commissioners

Donna L. Nelson, Chairman (Rep.), since August 2008; current term expires September 1, 2021. Nelson served as a special assistant and advisor to Governor Perry on energy, telecommunications and cable budget and policy issues. She previously served as director of the PUC telecommunication's section and legal advisor to the PUC chairman. Nelson holds a law degree from Texas Tech University. Kenneth W. Anderson Jr. (Rep.) , since September 2008; current term expires August 31, 2017. Past Director of Governmental Appointments under Governor Perry. Prior to that Anderson served in private practice as a corporate attorney in the area of securities law and regulatory matters. He also served as a member of the Texas Securities Board from 1999-2006. Anderson holds a law degree from Southern Methodist University. Brandy Marty Marquez (Rep.), since 2013; current term expires September 1, 2019. Formerly Governor Perry’s chief of staff. Has also held positions as: governor’s Deputy Chief of Staff, Director of the Budget, Planning and Policy Division and deputy legislative director/liaison to the Texas House of Representatives. Bachelor’s degree in government from University of Texas and Juris Doctorate from St Mary’s University.

AEP Regulatory Status

Retail competition in the SPP area of Texas, including SWEPCO’s, has been delayed by legislation. SWEPCO-TX has an active fuel pass- through clause as well as OSS margin sharing. In limited circumstances, CWIP is allowed in rate base. Texas currently has a mandatory renewable energy standard of 5% by 2015.

83 Overview

President and Chief Operating Officer: Bruce Evans Since Aug 2015 24 years with AEP

AEP Texas Central Company (TCC) (organized in Texas in 1945) is engaged in the transmission and distribution of electric power to approximately 817,000 retail customers through REPs in southern Texas. The territory served by TCC also includes several military installations. At December 31, 2014, TCC had 1,056 employees. TCC is a member of ERCOT.

MAJOR CUSTOMERS: Valero Energy Corporation PRINCIPAL INDUSTRIES SERVED: Mark West Energy Partners Petroleum & Coal Products Manufacturing Lyondell Chemicals Company Chemical Manufacturing Total Customers at 12/31/14: Koch Industries Oil and Gas Extraction (Based on electric meters) Air Liquide America Food Manufacturing Residential 696,000 (Data for year ended December 2014) Pipeline Transportation Commercial 115,000 Industrial 5,000 Other 1,000 Top 10 customers = 46% of industrial sales Total 817,000 Metropolitan areas account for 78% ultimate sales

60 persons per square mile (U.S. = 87) Transmission Miles 4,294 (Data for 12 months ended December 2014) 84 Distribution Miles 30,159 Financial & Operational Data Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Debt^ Equity Total Debt^ Equity Total Credit Ratings/Outlook Capitalization Per Balance Sheet 3,016,238 856,215 3,872,453 2,950,853 1,078,698 4,029,551 % of Capitalization Per Balance Sheet 77.9% 22.1% 100.0% 73.2% 26.8% 100.0% Moody's S&P Baa1/S BBB/P FFO Interest Coverage 3.98 4.12^^ FFO Total Debt 13.8% 14.1% ^^ - calculated on rolling 12-month avg.

^includes securitization debt of $1.780M and $1.539M at December 31, 2014 and Sept. 30, 2015 respectively Summary of Degree Days

Summary of KWh Energy Sales** 2014 2013 2012 (in millions of KWhs) (in degree days) Actual 279 193 52 30,000 Heating 24,656 23,396 23,475 Normal 178 179 191 25,000 Actual 2,721 2,944 3,334

Cooling 5,721 20,000 5,419 5,506 Normal 2,843 2,832 2,807 hours - 15,000 9,246 8,782 8,734 2015 Asset Data* (in thousands) 10,000 Kilowatt As of 9/30/15 5,000 9,582 9,092 9,132 Total Assets $ 6,054,431 - 2014 2013 2012 Net Plant Assets$ 3,823,030 Residential Commercial Industrial Other Cash $ 100 *Source: 3Q15 Financial Statements (unaudited) 85 **Source: 2014 10-K Financial Statements ***KWh Sales – Weather Normalized Overview

President and Chief Operating Officer: Bruce Evans Since Aug 2015 24 years with AEP

AEP Texas North Company (TNC) (organized in Texas in 1927) is engaged in the transmission and distribution of electric power to approximately 189,000 retail customers through REPs in west and central Texas. TNC’s remaining generating capacity that is not deactivated has been transferred to an affiliate at TNC’s cost pursuant to an agreement effective through 2027. At December 31, 2014, TNC had 323 employees. The territory served by TNC also includes several military installations and correctional facilities. TNC is a member of ERCOT.

Total Customers at 12/31/14: MAJOR CUSTOMERS: PRINCIPAL INDUSTRIES SERVED: (Based on electric meters) Chevron Texaco Corporation Oil and Gas Extraction Residential 149,000 Sheridan Production Co. Kinder Morgan Energy Partners Support Activities for Mining Commercial 31,000 Tyson Foods Pipeline Transportation Industrial 4,000 Food Manufacturing (Data for year ended December 2014) Nonmetallic Mineral Products Other 5,000 Total 189,000 Owned Generating Capacity* 355 MW Top 10 customers = 32% of industrial sales Generating Capacity by Fuel Mix: Metropolitan areas account for 52% ultimate sales • Coal: 100% 9 persons per square mile (U.S. = 87) Transmission Miles 4,092 (Data for 12 months ended December 2014) 86 Distribution Miles 13,929 *As of 9/30/15 Financial & Operational Data

Capital Structure (in thousands)

2014** 9/30/2015* Capital Structure Debt Equity Total Debt Equity Total Credit Ratings/Outlook Capitalization Per Balance Sheet 493,001 372,090 865,091 512,898 405,686 918,584 % of Capitalization Per Balance Sheet 57.0% 43.0% 100.0% 55.8% 44.2% 100.0% Moody's S&P Baa1/S BBB/P FFO Interest Coverage 6.01 5.85^ FFO Total Debt 20.1% 18.8% ^ - calculated on rolling 12-month avg.

Summary of Degree Days

Summary of KWh Energy Sales*** 2014 2013 2012 (in millions of KWhs) (in degree days) 6,000 5,527 Actual 1,084 1,137 726 5,131 5,055 Heating 477 Normal 1,035 1,032 1,061 5,000 477 482 Actual 1,813 1,829 2,074 1,569 Cooling 4,000 1,333 1,270 Normal 1,630 1,623 1,607 hours - 3,000 1,668 1,580 1,591 2015 Asset Data* (in thousands) 2,000 Kilowatt As of 9/30/15 1,000 1,813 1,741 1,712 - Total Assets $ 1,467,002 2014 2013 2012 Net Plant Assets$ 1,297,010 Residential Commercial Industrial Other Cash $ - *Source: 3Q15 Financial Statements (unaudited) 87**Source: 2014 10-K Financial Statements *** KWh Sales – Weather Normalized Commission Overview

Public Utility Commission of Texas

Commissioners

Number: 3 Appointed/Elected: Appointed Term: 6 Years Political Makeup: R: 3 D: 0 Qualifications for Commissioners

Donna L. Nelson, Chairman (Rep.), since August 2008; current term expires September 1, 2021. Nelson served as a special assistant and advisor to Governor Perry on energy, telecommunications and cable budget and policy issues. She previously served as director of the PUC telecommunication's section and legal advisor to the PUC chairman. Nelson holds a law degree from Texas Tech University. Kenneth W. Anderson Jr. (Rep.), since September 2008; current term expires August 31, 2017. Past Director of Governmental Appointments under Governor Perry. Prior to that Anderson served in private practice as a corporate attorney in the area of securities law and regulatory matters. He also served as a member of the Texas Securities Board from 1999-2006. Anderson holds a law degree from Southern Methodist University. Brandy Marty Marquez (Rep.), since 2013; current term expires September 1, 2019. Formerly Governor Perry’s chief of staff. Has also held positions as: governor’s Deputy Chief of Staff, Director of the Budget, Planning and Policy Division and deputy legislative director/liaison to the Texas House of Representatives. Bachelor’s degree in government from University of Texas and Juris Doctorate from St Mary’s University.

AEP Regulatory Status

TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. Transmission riders provide annual recovery dependent on the level of transmission investment and ERCOT load growth rates. AFUDC is permitted in limited circumstances.

Regulated Generation

• Units • Generation and Fuel Statistics • Regulated Coal Procurement and Delivery

89 Regulated Generation

Generation Capacity* Company MW Capacity AEP Generating Co** 2,496 Appalachian Power Co 6,634 Indiana Michigan Power Co 3,539 Kentucky Power Co 1,048 Public Service Company of Oklahoma 4,436 Southwestern Electric Power Co 5,779 Texas North Co** 355 Wheeling Power Co 780 OVEC Capacity *** 953 Long Term Renewable Purchase Power Agreements**** 2,273 28,293

* Capacity amounts represent the maximum capacity

** AEG has a PPA for Lawrenceburg Plant (with AGR) and a PPA for its share of Rockport Plant (with I&M and KPCo). Texas North Co. has a PPA for its share of Oklaunion (with Competitive operations).

*** Represents AEP's 43.5% interest in Ohio Valley Electric Corporation (OVEC)

**** See Long Term Renewable PPA slide in Transforming our Generation Fleet for details. This figure does not include an additional 599 MW of wind PPA’s scheduled to begin on 1/1/2016 or 59 MW of biomass PPA currently pending regulatory approval.

90 Regulated Generation

Net Maximum Capacity Year Plant Plant Name Units State Fuel Type (MW) Commissioned AEP Generating Company Rockport * 2 IN Steam - Coal 1,310 1984 Lawrenceburg** 6 IN Natural Gas 1,186 2004 2,496 Appalachian Power Company 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 Smith Mountain 5 VA Pumped Storage 586 1965 Amos 3 WV Steam - Coal 2,900 1971 Clinch River^ 2 VA Natural Gas 484 1958/2016 Mountaineer 1 WV Steam - Coal 1,320 1980 Dresden 1 OH Natural Gas 613 2012 Ceredo 6 WV Natural Gas 516 2001 6,634 Wheeling Power Company Mitchell 2 WV Steam - Coal 780 1971

Kentucky Power Company Big Sandy^ 1 KY Natural Gas 268 1963/2016 Mitchell 2 WV Steam - Coal 780 1971 1,048

91 * PPA with I&M (70%) and KPCO (30%) for capacity and energy entitlements ** Capacity and energy entitlements considered part of AEP Generation Resources as of January 1, 2014 ^ Capacity amounts represent natural gas fuel type. Units are being converted from Coal to Natural Gas. Regulated Generation

Net Maximum Capacity Year Plant Plant Name Units State Fuel Type (MW) Commissioned Indiana Michigan Power Company Berrien Springs 12 MI Hydro 7 1908 Buchanan 10 MI Hydro 4 1919 Constantine 4 MI Hydro 1 1921 Elkhart 3 IN Hydro 3 1913 Mottville 4 MI Hydro 2 1923 Twin Branch 6 IN Hydro 5 1904 Watervliet* 1 MI Solar 5 2016 Olive* 1 IN Solar 5 2016 Deer Creek* 1 IN Solar 3 2016 Twin Branch* 1 IN Solar 3 2016 Rockport 2 IN Steam - Coal 1,310 1984 Cook 2 MI Steam - Nuclear 2,191 1975 3,539 Public Service Company of Oklahoma Tulsa 2 OK Steam - Natural Gas 318 1923 Riverside (1&2) 2 OK Steam - Natural Gas 908 1974 Riverside (3&4) 2 OK Steam - Natural Gas 152 2008 Northeastern (1&2) 2 OK Steam - Natural Gas 923 1961 Southwestern (1-3) 3 OK Steam - Natural Gas 462 1952 Southwestern (4&5) 2 OK Steam - Natural Gas 170 2008 Comanche 3 OK Steam - Natural Gas 266 1973 Weleetka 3 OK Steam - Natural Gas 198 1975 Northeastern (3&4)^ 2 OK Steam - Coal 937 1979 Oklaunion 1 TX Steam - Coal 102 1986 4,436

* Expected commercial operation date is in 2016 92 ^ Planned 2016 Retirement: Northeastern Unit 4 (470MW) Regulated Generation

Net Maximum Capacity Year Plant Plant Name Units State Fuel Type (MW) Commissioned Southwestern Electric Power Company Arsenal Hill 1 LA Steam - Natural Gas 110 1960 Lieberman 3 LA Steam - Natural Gas 242 1947 Knox Lee 4 TX Steam - Natural Gas 475 1950 Wilkes 3 TX Steam - Natural Gas 893 1964 Lone Star 1 TX Steam - Natural Gas 50 1954 Stall 1 LA Natural Gas 534 2010 Mattison 4 AR Natural Gas 313 2007 Welsh^ 3 TX Steam - Coal 1,584 1977 Flint Creek 1 AR Steam - Coal 264 1978 Turk 1 AR Steam - Coal 477 2012 Pirkey 1 TX Steam - Lignite 580 1985 Dolet Hills 1 LA Steam - Lignite 257 1986 5,779 Texas North Company Oklaunion* 1 TX Steam - Coal 355 1986

^ Planned 2016 Retirement: Welsh Unit 2 (528MW) * Entitlement share of AEP Energy Partners

93 Regulated Fuel Procurement – 2016 Projected

Total Coal - Regulated Coal – East Regulated

Coal – West Regulated

Fuel Stats: - Expected 2016 Consumption: Coal: approx. 38M tons Natural Gas: approx. 96M MMBtu - Coal 79% contracted for 2016 and 62% contracted for 2017 - Avg. 2015 YTD Regulated Delivered Price: Coal: System - ~$46/ton East - ~$52/ton West - ~$37/ton Natural Gas: ~$3/MMBtu

- Projected 2016 Regulated Coal Delivered Price:

94 System - ~$46/ton East - ~$51/ton West - ~$37/ton Regulated 2016 Projected Coal Delivery

Total AEP Regulated System

AEP East AEP West

95 * Reflects coal delivered to AEP plants transported through a combination of rail and barge Jurisdictional Fuel Clause Summary

Adjustment Jurisdiction Active Fuel Clause Frequency Arkansas Yes Annually Indiana Yes Biannually Kentucky Yes Monthly Louisiana Yes Monthly Michigan Yes Annually Oklahoma Yes Annually Tennessee Yes Monthly Texas (SPP) Yes Triennially* Virginia Yes Annually West Virginia Yes Annually

* Fuel clause may be adjusted more frequently if a prescribed variance occurs.

Competitive Operations

• Structure • Fleet Footprint • Fleet Characteristics • 2013 Fleet Statistics • Coal Procurement • AEP Retail

97 Competitive Business Organizational Structure

AEP Co, Inc.

AEP Energy Supply

AEP Generation Resources (AGR) AEP Energy Partners AEP Energy

PJM Generation Wholesale, Trading & Marketing Retail

98 * AEP River Operations has been removed from the organizational structure pending fourth qtr. 2015 sale. AEP Generation Resources Footprint

Fleet Characteristics

(In MWs) Wholly-owned, AEP operated, 69% of fleet Gavin 2,665 Coal, controlled PJM: 7,923 MW Cardinal 1 595 Coal, controlled Conesville 5, 6 810 Coal, FGD only Waterford 840 Gas, CC , SCR Darby 507 Gas, CT Racine 48 Hydro

Joint Venture, AEP operated, 4% of fleet Conesville 4 339 Coal, controlled

Joint Venture, operated by others, 12% of fleet Zimmer 330 Coal, controlled Stuart 603 Coal, controlled

Capacity / energy entitlements, 15% of fleet Lawrenceburg 1,186 Gas, CC, SCR

Total 7,923

The AEP Energy Supply portfolio also includes non-PJM assets including the Oklaunion Coal Plant PPA (355MW), Texas Wind Farms (311MW), and Renewable PPAs at Southwest Mesa and South Trent (177MW)

99 Competitive Fleet Characteristics

Plant/Unit Capacity Fuel Type Coal Type Fuel Delivery FGD SCR Gavin 1, 2 2,665 coal NAPP barge Y-lime Y Cardinal 1 595 coal NAPP barge & truck Y-limestone Y Conesville 4* 339 coal NAPP rail & truck Y-limestone Y Conesville 5, 6 810 coal NAPP rail & truck Y-lime N Zimmer** 330 coal NAPP 30%/ILB 70% barge Y-lime Y Stuart 1-4** 603 coal NAPP 10%/ILB 90% barge Y-limestone Y Oklaunion*** 355 coal PRB rail Y-limestone N Lawrenceburg **** 1,186 gas n/a TX Gas Transmission (Zone 4) n/a Y Waterford 840 gas n/a TX Eastern Transmission (Zone M2) n/a Y Darby 507 gas n/a Columbia Gas Transmission/Dominion Transmission n/a n/a Racine 48 hydro n/a n/a n/a n/a Trent Mesa/Desert Sky 311 wind n/a n/a n/a n/a Renewable PPAs 177 wind n/a n/a n/a n/a

8,766

* Jointly owned unit operated by AEP ** Jointly owned unit operated by third-party utility *** PPA with TNC, jointly owned unit operated by PSO **** PPA with AEG, unit operated by I&M

100 Competitive 2014 Fleet Statistics

2014 2014 2014 2014 FOB Plant 2014 MWh Capacity Plant/Unit Capacity Fuel Type ($ per ton) $/MMBtu Produced Factor

Gavin 1, 2 2,665 coal 56.68 2.29 15,710,692 67.30% Cardinal 1 595 coal 50.70 2.04 2,848,078 54.64% Conesville 4* 339 coal 81.59 3.50 1,736,283 58.47% Conesville 5, 6 810 coal 54.82 2.35 3,795,706 53.49% Zimmer** 330 coal 53.31 2.22 1,713,171 59.26% Stuart 1-4** 603 coal 52.31 2.30 2,626,610 49.72% Okalunion*** 355 coal 36.63 2.21 1,897,864 61.03% Lawrenceburg**** 1,186 gas n/a 4.80 3,317,362 31.93% Waterford 840 gas n/a 3.97 3,924,872 53.34% Darby 507 gas n/a 12.22 31,837 0.72% Racine 48 hydro n/a n/a 251,322 59.77% 8,278

* Jointly owned unit operated by AEP ** Jointly owned unit operated by third-party utility *** PPA with TNC, jointly owned unit operated by PSO **** PPA with AEG, unit operated by I&M

101 Competitive Coal Procurement

Coal Statistics:

 Expected 2016 coal burn: 9.75 M tons

 Burn is approximately 100% NAPP

 100% contracted for 2015, 100% contracted for 2016, and 84% contracted for 2017

 Third Qtr. 2015 delivered price: $52.30/ton

*Data is for the AEP Generation Resources facilities we own and operate. See fleet characteristics footnotes for ownership and operation of units.

102 AEP Energy

Customer Accounts* Geography of customers*

New Jersey Maryland Delaware C&I 2.5% 0.9% 0.1% Washington 13% DC 0.1% Pennsylvania 8.8%

Illinois 14.7%

Residential 87%

YTD Sept 2015 Delivered Load

Ohio 72.8% Residential 24%  341,000 retail customer accounts*

 YTD served 9.9 TWh of load*

 Seven states, focus on Ohio

* As of September 30, 2015

C&I 76% 103

Transmission Initiatives

• Ownership Structure • Growth Plan Project Summary • Transcos • Joint Ventures • Competitive Transmission

104 AEP Transmission Ownership Structure

American Electric Power Company, Inc.

100% AEP Transmission Holding Company, LLC (“AEP Trans Holdco”) AEP Transmission 100% 50% 50% 86.5% 50% Company, LLC (“AEP Transco”) Pioneer Electric Electric Transource Transmission, Transmission Transmission Energy, LLC LLC America, LLC Texas, LLC AEP Appalachian AEP Kentucky Transmission Transmission Company, Inc. Company, Inc. $14M Net Plant * $154M Net Plant in $184M Net Plant* $2,587M Net Plant* Prairie Wind* $48M Net Plant * AEP Indiana AEP Ohio Michigan $715M Net Plant * Transmission $1,687M Net Plant * Transmission Company, Inc. Company, Inc.

AEP AEP Oklahoma Southwestern $497M Net Plant * Transmission Transmission Company, Inc. Company, Inc.

Transco Issuing Entity AEP West Virginia Currently Operating $420M Net Plant * Transmission Note: Private placement financing has occurred at Company, Inc. Not Currently Operating Electric Transmission Texas, LLC and AEP Transmission Company, LLC

105 * As of 09/30/2015 AEPTHC Growth Plan Project Summary

Regional Projects Local Reliability Plans

 Generation Retirements/Regional Reliability  Local transmission facilities (<138 kV) account for the majority of AEP  Projects to address 14 GW of generation retiring in Transmission facilities. PJM to be completed by 2016.  Additional reliability criteria (e.g. Winter Criteria in PJM  Local facilities tend to be older and more susceptible to trees, storms, resulting in RTO mandated projects) and other threats to reliability and have a direct impact on customers.  Clean Power Plan regulations may result in an additional 18 GW of retirements in PJM and SPP in the  Recent storms such as the Derecho, Superstorm Sandy, and the Polar next 10-15 years, with significant reliability Vortex have raised awareness of the vulnerability of these facilities, and implications. the need to strengthen local transmission facilities against future events.

 Integration of Renewables  AEP has developed a $2B portfolio of projects designed to address  Renewable Portfolio Standards (RPS) and tax credits transmission facilities and areas with poor performance. Roughly half of continue to promote renewable energy development. these projects have been completed or are underway, and additional  Renewable resources – primarily wind and solar – projects are being evaluated based on analysis of reliability statistics require a flexible transmission system for reliable and seasonal planning studies. delivery to customers.  Opportunities expected to increase as a result of Customer Driven Projects proposed Clean Power Plan regulations.

 Customer interconnection requests dominated by shale gas activity.  Competitive Transmission Projects  Over 750 MW placed in service since 2010.  FERC Order 1000 resulting in competitive  Over 3,150 MW of total requests to date. transmission proposals across the country.  AEP using innovative technology, including skid stations, to  Reliability and economic-driven projects subject of provide quick service in as little as 6 weeks. multiple competitive windows in PJM, SPP, and MISO.

 Pursuing incremental opportunities in other regions  AEP transmission system encompasses large portions of major shale throughout U.S. plays.

 Aging Infrastructure Marcellus, Utica, Huron (East).  Barnett, Eagle Ford, Woodford, Fayetteville (West).  Potential to invest $9-$12 billion, growing at $1 billion per year.  Line Assets: 3,000 miles of transmission lines.  Midstream processing facilities require transmission service (10-100 MW),  Station Assets: 780 substations with major equipment. and rural locations may require significant, long-term transmission build-  Control and Communications: Replace telecom out. 106 circuits to 950 substations.  Pumping loads (<5 MW) also adding to localized load growth in some areas.

AEP Transco Has a Large, Diverse Footprint

The Transcos exist within the expansive service territories of AEP’s companies, operating within two RTOs.

RTO Regions PJM SPP

AEP State Transcos AEP Appalachian Transmission Company, Inc. (non-operating) AEP Kentucky Transmission Company, Inc. AEP Indiana Michigan Transmission Company, Inc. AEP Ohio Transmission Company, Inc. AEP Oklahoma Transmission Company, Inc. AEP Southwestern Transmission Company, Inc. (non-operating) AEP West Virginia Transmission Company, Inc.

ERCOT ISO 107 Electric Transmission Texas, LLC (Joint Venture) Transco Regulatory Compacts

 AEP Transco and its seven Transco subsidiaries were formed in 2009 to focus on upgrades to AEP’s transmission system and providing flexibility to AEP’s electric utility Operating Companies.  A summary of regulatory approval status is provided in the table below:

State State Operational and Approval Status Transco OH Transco No state regulatory agency approval was required to construct and operate transmission assets in the state of Ohio. OH Transco is fully operational with assets in-service.

IM Transco Indiana Utility Regulatory Commission approval for utility status received November 2011; no Michigan approval required. IM Transco is fully operational with assets in-service. OK Transco No state regulatory approval required for utility status. OK Transco is fully operational with assets in-service. WV Transco In a December 2012 order, the West Virginia Public Service Commission (“WVPSC”) required WV Transco to obtain a Certificate of Public Convenience and Necessity (“CPCN”) before beginning construction on each proposed project, until WV Transco established a track record, revenue stream and utility plant base. WV Transco subsequently filed for and received 21 CPCN’s for projects with total estimated costs of $707 million. In September, 2015, the WVPSC recognized that WV Transco had established the required track record, and granted WV Transco’s petition to exempt projects from the CPCN requirement, when such projects met the “ordinary extension of existing systems” condition, as established for public utilities in the West Virginia Code. WV Transco is fully operational with assets in service. AP Transco In February 2012, the Virginia State Corporation Commission (“VSCC”) approved a service agreement between AP Transco and APCo limited to studying and evaluating potential transmission projects and for preparation of applications for future submission of project certificate applications to the VSCC. In May 2013, AP Transco and APCo filed a joint application with the Virginia SCC for the approval of the Cloverdale Extra High Voltage Transmission Improvements Project. The VSCC approved the project for APCo to construct. AP Transco has not yet filed other project applications. KY Transco In February 2011, KY Transco filed an application with the Kentucky Public Service Commission (“KPSC”) in Case No. 2011-00042 seeking a CPCN to operate as a transmission-only public utility in Kentucky. In June 2013, the KPSC denied the application, stating that KY Transco could not be defined as a public utility under Kentucky statute and therefore was not subject to KPSC regulatory jurisdiction. KY Transco is fully operational with assets in service.

SW Transco Applied for public utility status in Arkansas and Louisiana in May 2011 and August 2011, respectively, with supplemental filings made in both jurisdictions. In January, 2015, the Arkansas Public Service Commission denied the application. A procedural schedule is under discussion in Louisiana.

108 State Transco Rates are Regulated by FERC

Conservative FERC regulation results in timely recovery of costs  In April 2011, the FERC approved a formula rate mechanism for the State Transcos  The FERC order dictates how the State Transcos determine their rates, including the recovery of all authorized expenses and the return on and of invested plant  The approved formula rate mechanism established an annual revenue requirement for transmission services over the facilities of the State Transcos under the PJM and SPP OATTs, as applicable, and implemented a transmission cost of service formula rate  Annual rate updates provide a highly predictable and stable source of revenues and income  Each State Transco’s annual transmission revenue requirement (“ATRR”) is reset in July, establishing rates for the one-year forward period of July to June. The rate base component of the formula rate calculation includes the prior year’s transmission plant in service ending balance, plus the current year’s projected plant in service additions  The revenue requirements are derived from the following capital structure and authorized ROEs:

Rate Base Capital Structure % ATRR Company RTO Authorized ROE* (Effective (Effective Equity Cap 07/01/2015) 07/01/2015)

IM Transco PJM 50% 11.49% $51.8 M $311.1 M KY Transco PJM 50% 11.49% $3.3 M $26.5 M OH Transco PJM 50% 11.49% $221.5 M $1,299.3 M WV Transco PJM 50% 11.49% $38.0 M $281.1 M OK Transco SPP 50% 11.20% $47.6 M $339.2 M

* Includes 50bps adder for RTO participation 109 Project Selection Guidelines

 State Transcos will develop new projects that are attached to AEP’s existing system  A Project Selection Guideline (“PSG”) is used to determine which facilities are developed by the State Transco and which are developed by an AEP Operating Company  All projects developed by AEP go through an internal process that requires approval by AEP management and ensures compliance with all selection guidelines and financial controls  Projects developed as part of an RTO-driven process are subject to approval by the RTO Board of Directors, and certain high-voltage projects must meet state siting requirements  The following projects are eligible for development by a State Transco:

Type of Project Definition New transmission assets that do not require replacement or Greenfield modification of existing facilities or components New transmission components installed at existing AEP Operating Facility Additions Company-owned transmission or distribution facilities Facility Replacement of an entire existing AEP Operating Company-owned Replacements facility with a new AEP Transco-owned facility An apportioned replacement of an existing AEP Operating Component Company-owned transmission facility or replacement of Replacements component(s) within a transmission facility Spare/Mobile Purchases of major transmission equipment as capitalized spares or

110 Equipment mobiles Active Joint Venture Projects

111 Competitive Transmission

 Transource Energy, a joint venture with Great Plains Energy (GPE), is the exclusive vehicle through which AEP pursues new competitive transmission projects . Transource is owned 86.5% by AEP and 13.5% by GPE

 Transource is currently developing projects in SPP and PJM:

. SPP Projects - $330 million of total projected investment – Placed the $64 million Iatan – Nashua 345 kV transmission line in-service on April 8, 2015 – Construction is underway on the Sibley – Nebraska City 345 kV line project with completion expected in December 2016 – The two projects have a blended authorized ROE of approximately 11.15%

. PJM Project - $59.5 million estimated project cost – Transource was designated the Thorofare Area Project in West Virginia, the first competitive project awarded in PJM – 15-mile 138kV line from AEP’s Thorofare Creek Station to a new tap station on FirstEnergy’s Powell-Mountain- Goff Run 138 kV line and associated new station with expected in-service date of May 2019 – FERC order received on September 4, 2015 authorizing CWIP incentive and 60% equity / 40% debt hypothetical capital structure during construction

 Transource has been and will continue to be highly active in the emerging regional and interregional competitive processes across North America.

112 BOLD™ Transmission Technology

What is BOLD?

• BOLD is a technological advance in transmission line design that optimizes the physical arrangement of the conductors to enhance electrical performance and compact the structure.

• BOLD is unique because it provides both form and function. Capacity, efficiency, and improved aesthetics are all part of the design.

• BOLD provides: • High-performance solution that maximizes capacity and reliability in less right-of-way. • Best available technology that minimizes community and environmental impact. • Economic savings through reduced congestion and energy losses. BOLD 345 kV Conventional • Superior alternative to other options more 345 kV expensive/ less effective such as underground lines, series compensation, Compacting the individual phases of the line allows etc. for a tower approx. 1/3 shorter than conventional designs.

113 BOLD™ Transmission Technology

How does BOLD work? Single arched cross-arm to hold both circuits • Transmission line power delivery capability is a function of voltage, line Unique inter-phase length, and the electrical characteristics insulator assembly of the line’s physical arrangement.

• If higher voltages can’t be applied, the physics can be optimized to boost line capacity at the same voltage.

• Reducing phase separation (1) and increasing bundle diameter (2) each help reduce inductance (L) and increase capacitance (C), which results in lower impedance (Z) and a higher degree of intrinsic “self-compensation”.

• Arched cross arm and inter-phase insulators designed to hold conductors in exact optimal locations. (2) Optimization of (1) Compaction of entire individual conductors in a three-phase circuit 2 or 3 conductor bundle arrangement into a delta

114 BOLD™ Transmission Technology

The math behind BOLD • Power delivery capability is measured  Surge Impedance changes with 퐿 +/퐶 + (ohm) by Surge Impedance Loading (SIL).  BOLD leverages the equations below to provide roughly 30% lower inductance (L) and 30% higher capacitance (C) • SIL = 〖푘푉〗^2⁄(푆푢푟푔푒 퐼푚푝푒푑푎푛푐푒)

휇표 풅풆풒 풅풆풒 o 푳+ ≈ 풍풏 = 0.3219 풍풏 ( ) 푚퐻/푚𝑖 • BOLD decreases Surge Impedance by 2휋 푹풆풒 푹풆풒

30% (푆푢푟푔푒 퐼푚푝푒푑푎푛푐푒 = 0.7 x + 2휋휖표 89.41 o 푪 ≈ 풅풆풒 = 풅풆풒 푛퐹/푚𝑖 풍풏 ( ) 풍풏 ( ) conventional) 푹풆풒 푹풆풒

풅풆풒 o 풁+ ≈ 60 풍풏 Ω • Therefore SIL increases by 42% 푹풆풒 o Where: (1/0.7) at the same 345 kV voltage. 3 • 푑푒푞 = 푑푎푏푑푏푐푑푐푎 Eq. Phase Spacing (ft)

푁 푁−1 • 푅푒푞 = 푁푟푅 Eq. Bundle Radius (ft)

• Energy losses are directly related to a • 푑푎푏, 푑푏푐 , 푑푐푎 = 푃ℎ푎푠푒 푠푝푎푐𝑖푛푔푠 (푓푡) line’s current (I) and resistance (R). • 푁 = 푁푢푚푏푒푟 표푓 푠푢푏푐표푛푑푢푐푡표푟푠 per phase

• Losses = I^2 x R • 푟 = 푆푢푏푐표푛푑푢푐푡표푟 푟푎푑𝑖푢푠 푓푡 • 푅 = 푆푢푏푐표푛푑푢푐푡표푟 푏푢푛푑푙푒 푟푎푑𝑖푢푠 (푓푡)

• BOLD’s 3-bundle conductor adds

another set of wires which decreases resistance by 33%, so losses inherently decrease by 33%.

115 BOLD™ Transmission Technology

Where is BOLD being applied? • BOLD’s benefits can be applied to any utility’s system. AEP is using BOLD for rebuild and new build lines at 345 kV.

• Meadow Lake-Reynolds rebuild (Lafayette, Indiana) • 9-mile segment of 130-mile corridor 345 kV • Approved; construction to begin in 2017

• Robison Park-Sorenson rebuild (Fort Wayne, Indiana) • 22-mile line with two voltages: 345 kV and 138 kV • Under construction: Line scheduled in service June 2016

• Lower Rio Grande Valley Proposal (Southeast Texas) • 130-mile 345 kV proposal • Decision expected Q4 2015

• A new 230 kV design is currently being tested at EPRI and ready to deploy Q2 2016. Fort Wayne, IN – July 2015 • BOLD is available to the industry through licensing and partnership opportunities. 116

Evolution of Transmission Trackers in the OpCo’s

PJM Trackers Other Utilities T Recovery

17% 25% 18% Base Rates

Trackers 83% 75% 82%

SPP Trackers

26% 38% 40% Base Rates 62% 60% 74% Trackers

ERCOT Trackers

Base Rates 100% 100% 100% Trackers

117 106 AEP has made tremendous progress securing trackers for transmission investment over the past decade. Favorable Recovery of Transmission Investment

Jurisdictional Capital Investment Recovery Mechanism Recovery of OATT Expenses

 Projected $6.3 Billion of 2015 Net Plant in  Projected $577 Million of 2015 PJM and SPP Service is recoverable through Trackers Expenses will be recovered through Trackers and from Wholesale Customers   Projected $1.4 Billion of 2015 Net Plant in Projected $343 Million of 2015 PJM and SPP Service is recoverable through Base Expenses must be recovered through either Rates existing or future Base Rates

2015 Recoverable Plant in Service ($M)

Projected 2015 OATT Expense ($M) 2015 Capital – Projected Recovery by RTO

118  Jurisdictional Trackers provide most efficient recovery of Transmission Investment