2016 fact book 51st eei financial conference · aep provides generation, transmission and / or...

2016 Fact Book

51st EEI Financial Conference

Phoenix, AZ

November 6-9, 2016

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 AEP’s 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 AEP’s 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, including competition for retail customers; weather conditions, including storms and drought conditions,

and AEP’s ability to recover significant storm restoration costs; the 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 AEP’s generating plants; AEP’s ability to recover fuel and other energy costs

through regulated or competitive electric rates; AEP’s ability to build transmission lines and facilities (including the 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 AEP’s 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, AEP’s ability to constrain operation and maintenance costs; AEP’s 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 AEP

generates and sells at wholesale; changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation; AEP’s 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

and capacity auction returns; 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 and AEP’s ability to recover investments in its Ohio generation assets; AEP’s ability

to successfully and profitably manage its separate competitive generation assets; changes in the creditworthiness of the counterparties with whom AEP has

contractual arrangements, including participants in the energy trading market; actions of rating agencies, including changes in the ratings of AEP’s debt; the impact of

volatility in the capital markets on the value of the investments held by AEP’s pension and 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

“Safe Harbor” Statement under the

Private Securities Litigation Reform Act of 1995

Investor

Relations

Bette Jo Rozsa

Managing Director

Investor Relations

614-716-2840

[email protected]

Bradley Funk

Director

Investor Relations

614-716-3162

[email protected] 1

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

2015 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

Retail Recovery Mechanisms Across Jurisdictions Financial & Operational Data

Storm O&M Recovery Mechanisms by Jurisdiction Customer Statistics

Jurisdictional Off-System Sales Sharing Summary Commissions Overview

Commission Overview

Regulated Generation

Transforming Our Generation Fleet Regulated Generation Summary

Transforming Our Generation Fleet Owned Regulated Generation

Investments Driving Emission Reductions Regulated Fuel Procurement - 2017 Projected

Dramatic Reductions in Emissions Regulated 2017 Projected Coal Delivery

Large-scale Renewable Opportunities Jurisdictional Fuel Clause Summary

Delivering Clean Energy Resources

Renewable Resources Transmission Initiatives

Renewable Portfolio/Energy Efficiency Standards AEP Transco Structure & Business Overview

AEPTHC Growth Plan Project Summary

Environmental Transco Project Mix & Footprint

Regulated & Competitive Retirements Transmission Investment Needs

Regulated Environmental Controls Transco State & FERC Regulatory Compacts

Competitive Environmental Controls FERC Formula Rate

Clean Power Plan - Overview Project Selection Guidelines

Clean Power Plan - Implementation Schedule Active Joint Venture Projects

Additional Environmental Regulations Competitive Transmission – Transource

Grid Assurance – Executive Summary

Financial Update BOLD™ Strategy

Capitalization & Liquidity Transmission Cost Recovery by Operating Companies

AEP Banking Group

AEP Credit Ratings Contracted Renewables & Other

Long-term Debt Maturity Profile Organizational Structure

Debt Schedules Contracted Renewables

Competitive Generation - Owned & PPA

Competitive 2015 Fleet Statistics

Competitive Coal Procurement

Retail - AEP Energy 2

AEP: America’s Energy Partner

Approximately 23,000 megawatts of regulated owned generating capacity and 4,825 megawatts of

regulated PPA capacity in 3 RTOs

Approximately 40,000 circuit miles of transmission lines, including 639 miles of Transco lines, and

2,114 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.

Nearly 224,000 miles of overhead and underground distribution lines

Our regulated electric assets include:

AEP consistently produces strong financial results:

Expecting operating earnings growth of 5% to 7%

Strong balance sheet including $64 billion of assets

Cash dividend paid every quarter since 1910. Dividend payout ratio of 60% to 70% of operating

earnings, and growing dividend in line with earnings.

AEP provides generation, transmission and / or distribution services to approximately 5.4 million customers

in eleven states. AEP’s headquarters is in Columbus, Ohio. (NYSE: AEP)

AEP Transco has approximately $3.2B of transmission assets in service with additional capital

expenditure plans of approximately $4.4B from 2017 – 2019.

AEP IS THE PREMIER

REGULATED ENERGY COMPANY

WELL POSITIONED AS A REGULATED BUSINESS

3

AEP Corporate Leadership

Nicholas K. Akins –

Chairman, President,

and Chief Executive

Officer

Lisa M. Barton -

Executive Vice President

- Transmission

David M. Feinberg –

Executive Vice

President, General

Counsel and Secretary

Mark C. McCullough -

Executive Vice President

- Generation

Robert P. Powers –

Executive Vice President and

Chief Operating Officer

Brian X. Tierney –

Executive Vice President and

Chief Financial Officer

Charles E. Zebula-

Executive Vice President-

Energy Supply

Lana L. Hillebrand-

Senior Vice President

and Chief Administrative

Officer

4

AEP Operational Structure*

* Does not represent legal structure

AEP, Inc.

Regulated Utilities

Appalachian Power Company

Indiana Michigan Power Company

Kentucky Power Company

Public Service Company of Oklahoma

Southwestern Electric Power Company

Ohio Power Company

Wheeling Power Company

Kingsport Power Company

AEP Texas Central Company

AEP Texas North Company

AEP Generating Company

AEP Transmission Holding Company

AEP Transmission Company

AEP Appalachian Transco

AEP Kentucky Transco

AEP Southwestern Transco

AEP Ohio Transco

AEP Oklahoma Transco

AEP Indiana Michigan Transco

AEP West Virginia Transco

Joint Ventures

Competitive Operations

AEP Energy Supply

AEP Energy

AEP Energy Partners

AEP Generation Resources

AEP OnSite Partners

AEP Renewables

5

AEP Service Territory

VERTICALLY INTEGRATED UTILITIES

Appalachian Power Company (APCo)

Indiana Michigan Power Company (I&M)

Kingsport Power Company (KGPCo)

Kentucky Power Company (KPCo)

Wheeling Power Company (WPCo)

Public Service Company of Oklahoma (PSO)

Southwestern Electric Power Company (SWEPCO)

6

AEP Service Territory

TRANSMISSION AND DISTRIBUTION UTILITIES

7

2015 Retail Revenue

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

Source: 2015 10-K.

*Note: Figures do not include Other Revenues

Top 10 Industrial Sectors Across the AEP System By

NAICS Code % of Total Industrial

Sales

331 Primary Metal Manufacturing 15.1%

325 Chemical Manufacturing 13.4%

324 Petroleum and Coal Prod. Manufacturing 11.4%

486 Pipeline Transportation 7.0%

322 Paper Manufacturing 6.4%

212 Mining (except Oil and Gas) 6.6%

211 Oil and Gas Extraction 5.9%

326 Plastics and Rubber Products Manufacturing 5.5%

336 Transportation Equipment Manufacturing 4.5%

311 Food Manufacturing 4.4%

CUSTOMER PROFILE AEP’S SERVICE TERRITORY ENCOMPASSES

APPROXIMATELY 5.4 MILLION CUSTOMERS IN 11 STATES

8

Generation Fleet Competitive - 2016 Generation Capacity

by Fuel Type

Based on 3,213 MW*

Regulated - 2016 Generation Capacity by Fuel Type

Based on 29,641 MW**

**Includes:

• 953 MW of OVEC entitlement

• 2,723 MW of renewable PPA’s

• 1,149 MW of gas PPA’s

• 355 MW for TNC’s portion of Oklaunion

• 1,989 MW of Demand Response /

Energy Efficiency Programs

*Includes 177 MW of wind PPA.

Excludes 355 MW of PPA for

TNC’s portion of Oklaunion.

Total Fleet - 2016 Generation Capacity by Fuel Type

Based on 32,854 MW***

***Includes:

• 953 MW of OVEC entitlement

• 2,900 MW of renewable PPA’s

• 1,149 MW of gas PPA’s

• 355 MW for TNC’s portion of Oklaunion

• 1,989 MW of Demand Response /

Energy Efficiency Programs

9

Transmission Line Circuit Miles Detail

Operating Company Level (Circuit Miles)

State Level (Circuit Miles)

Note: Transmission line circuit miles are current as of 12/31/15; excludes ETT, OVEC and Joint Ventures

Operating Company 765kV 500kV 345kV 230kV 161kV 138kV 115kV 88kV 69kV 46kV 40kV 34.5kV 23kV Total

APCo 732 95 379 107 0 2,863 0 37 982 737 0 149 0 6,080

OPCo 507 0 1,372 0 0 3,188 0 0 2,265 0 58 417 77 7,884

I&M 616 0 1,638 0 0 1,677 0 0 664 0 0 645 0 5,240

KGPCo 0 0 0 0 0 44 0 0 0 0 0 29 0 73

KPCo 258 0 8 0 48 359 0 0 429 166 0 3 0 1,271

PSO 0 0 608 34 8 2,081 10 0 646 0 0 0 0 3,388

SWEPCO 0 0 735 0 305 1,459 29 0 1,572 0 0 0 0 4,101

TCC 0 0 631 0 0 2,452 0 0 1,216 0 0 0 0 4,299

TNC 0 0 224 0 0 1,433 0 0 2,441 0 0 0 0 4,098

WPCo 0 16 15 0 0 193 0 0 84 0 0 0 0 308

Transco - IM 0 0 2 0 0 5 0 0 55 0 0 1 0 62

Transco - Ohio 1 0 35 0 0 104 0 0 153 0 3 6 8 310

Transco - OK 0 0 0 0 0 126 0 0 130 0 0 0 0 256

Transco - WV 0 0 1 0 0 6 0 0 0 4 0 0 0 11

Total 2,114 111 5,648 141 361 15,990 40 37 10,637 907 61 1,250 85 37,382

State 765kV 500kV 345kV 230kV 161kV 138kV 115kV 88kV 69kV 46kV 40kV 34.5kV 23kV Total

Arkansas 0 0 78 0 305 248 13 0 445 0 0 0 0 1,089

Indiana 600 0 1,384 0 0 1,450 0 0 418 0 0 530 0 4,382

Kentucky 257 0 8 0 48 359 0 0 429 166 0 3 0 1,270

Louisiana 0 0 105 0 0 285 1 0 328 0 0 0 0 719

Michigan 16 0 256 0 0 232 0 0 300 0 0 115 0 919

Ohio 509 0 1,407 0 0 3,251 0 0 2,418 0 61 423 85 8,154

Oklahoma 0 0 650 34 8 2,233 10 0 776 0 0 0 0 3,712

Tennessee 0 0 0 91 0 154 0 0 2 0 0 29 0 276

Texas 0 0 1,365 0 0 4,785 15 0 4,457 0 0 0 0 10,622

W. Virginia 382 16 326 0 0 1,420 0 37 433 693 0 58 0 3,365

Virginia 349 96 69 15 0 1,575 0 0 631 48 0 92 0 2,874

Total 2,114 111 5,648 141 361 15,990 40 37 10,637 907 61 1,250 85 37,382

10

Distribution Line Detail

Note: Year End 2015 data per Small World Graphics.

By

Operating

By State Line Miles* Company Line Miles*

Arkansas 4,503 | APCo 51,193

Indiana 15,059 | I&M 20,410

Kentucky 10,081 | KGPCo 1,570

Louisiana 13,266 | KPCo 10,081

Michigan 5,351 | OPCo 45,718

Ohio 45,718 | PSO 22,260

Oklahoma 22,260 | SWEPCO 26,560

Tennessee 1,570 | TCC 30,342

Texas 53,096 | TNC 13,963

Virginia 30,935 | WPCo 1,529

W. Virginia 21,787 |

Total 223,626 Total 223,626

* Includes approximately 33,000 miles of underground circuit miles

11

Rate Bases & ROEs

1 Rate base represents Net Utility Plant plus Regulatory

Assets less Net Accumulated Deferred Income Taxes

and less Regulatory Liabilities from 2015 FERC Form 1

2 Proforma adjusts GAAP results by eliminating any

material nonrecurring items and is not weather

normalized. 12-month rolling ROE. AEP Ohio ROE

reflects adjustment for Ohio SEET (significantly

excessive earnings test) purposes.

3 Represents the midpoint of the ROE range approved

in the formula rate case settled in February 2014

4 Represents approved 50/50 ratio once the company

issues debt

5 Kingsport has a Commission-approved Settlement

Agreement, but as of 10/12/16, a Final Order has not

been issued.

6 Rate base as specified under the PJM transmission

formula rate filing.

* 10.4% Allowed top of band, 70 BPS above authorized

9.7%, as approved in 2014. Base rates subsequently

frozen in VA by the Feb. 2015 Rate Freeze Law. A

9.4% ROE was approved in October, 2016 to be

applied to rate adjustment clauses only.

** Per ESP III Order

Chart excludes AEG's Rockport plant investment .

AEG sells capacity & energy to I&M and KPCo under a

PPA.

12

Summary of Rate Case Filing Requirements

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 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, legislation

(SB 251) was passed that will allow 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

in capitalization or rate base.

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 a biennial order within 8 months of filing. Rates 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, RPS-RAC or DR/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 PUCO on September 1, 2015.

Note 10: WV ENEC rates currently frozen until June 30, 2018.

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 Yes Yes No No Yes Yes

Fuel Clause Renewal Frequency Annually

Semi-

Annually Monthly Monthly Annually

N/A

Note 9 Annually Annually

Tri-

Annually Annually

Annually

Note 10 N/A N/A

Approx # of months after filing to

implement rates 10

10 @ 50% if

no order 6 4 6 9 6 9 6

10

Note 8 10 2 or 7 Varies

Approx # of months after filing order

expected 10 10 6 4 10 9 6 9 6 8 10 2 or 7 N/A

Notice of Intent

Prior PSC Notice Required? Yes Yes Yes No Optional Yes Yes Yes Yes Yes Yes No No

Notice Period (days) 60 Varies 28 N/A 45 30 45

Not

Specified 30 60 30 No No

CASE COMPONENTS

Base Case Test Year

Partially

Projected

Hist.(Forecst

Opt/ Hybrid)

Forecast

Optional

Hist,

(formula

rate)

Forecast

Optional

Partially/Fully

Projected Hist. Hist. Hist. Hist. Hist. Forecast

Historical /

Forecast Filed

Post Test/Year Adjustment Period

(Months) 12 12 12 -- -- --

Min 6,

no max 18 -- 3 12 -- Varies

Cash Return on CWIP Partial-

Limited

Note 2

Optional

Note 3

Partial

Note 1 Yes

Limited

Note 4

No

Note 1 Yes

Limited

Note 5 Yes Note 7

Limited

Note 6 Varies

13

Retail Recovery Mechanisms by Jurisdiction Company State

SO2/Nox/CO2

Allowances & GHG

Offsets

Distribution

Vegetation

Management

Environmental

Investment Energy Efficiency

Renewables

Investment REPA

Other Purchased

Power

(Energy/Capacity)

OATT

I&M Indiana ECCR BR CCTR/FMR/BR

DSM/EE Program

Cost Rider SPR/BR FAC FAC/BR BR/PJM Tracker

Michigan PSCR BR BR EO Rider BR PSCR/REP/BR PSCR/PSCR PSCR

KPCo Kentucky Surcharge BR Surcharge DSM Adj. Clause BR N/A FAC/Tariff PPA BR

AEP Ohio Ohio N/A ESRR N/A EE/PDR

Rider N/A AER N/A BTCR

KgPCo Tennessee FERC Tariff Surcharge

Available FERC Tariff

Surcharge

Available N/A N/A FERC Tariff FPPAR

APCo Virginia BR Accelerated VMP ERAC/BR EERAC/BR

GRAC/BR

RPSRAC

FF

RPSRAC/FF FAC/BR & FF TRAC

West Virginia ENEC VMP

Surcharge ENEC/BR

EE/DR Recovery

Rider BR / CS ENEC ENEC/ENEC ENEC

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 (SPP) BR BR BR EECRF BR FAC FAC/BR TCRF

AEP TX Texas (ERCOT) N/A BR N/A EECRF /BR N/A N/A N/A TCOS

PSO Oklahoma BR SRR BR DSM Cost

Recovery Rider BR FAC FAC BR/SPP Tracker

AER - Alternative Energy Rider ENEC - Expanded Net Energy Cost PPAR - Purchased Power Adjustment Rider

BR - Base Rates EO – Energy Optimization PSCR - Power Supply Cost Recovery Rider

BTCR – Basic Transmission Cost Rider ERAC - Environmental Rate Adjustment Clause RAC - Rate Adjustment Clause

CCTR - Clean Coal Technology Rider ESRR - Enhanced Service Reliability Rider REPA – Renewable Energy Purchase Agreement

CO2 - Carbon Dioxide FAC - Fuel Adjustment Clause RPSRAC - Renewable Portfolio Standard RAC

CS – Construction Surcharge FERC – Federal Energy Regulatory Commission

DSM - Demand Side Management FF – Fuel Factor SO2 - Sulfur Dioxide

EAC - Environmental Adjustment Clause FMR – Federal Mandate Rider SPP – Southwest Power Pool Regional Transmission Org

ECR - Energy Cost Recovery Rider GHG - Green House Gas SPR – Solar Power Rider

ECCR – Environmental Compliance Cost Rider GPR – Green Power Rider (Solar-only) SRR – System Reliability Rider

EE - Energy Efficiency N/A - not applicable in this jurisdiction TCOS - Transmission Cost of Service

EE/DR – Energy Efficiency/Demand Response NOx - Nitrogen Oxide TCRF - Transmission Cost Recovery Factor

EE/PDR - EE Peak Demand Response Rider OATT - Open Access Transmission Tariff TCRR - Transmission Cost Recovery Rider

EECR - EE Cost Rate Rider PJM – PA-NJ-MD Regional Transmission Org. TRAC - Transmission Rate Adjustment Clause

EECRF - Energy Efficiency Cost Recovery Factor Rider PPA - Purchased Power Agreement VMP – Vegetation Management Plan

EERAC – EE Rate Adjustment Clause

14

Storm O&M Recovery Mechanisms by Jurisdiction

State

Ability to

Defer Description

Latest

Approved

Recovery

Period

(in years)

Arkansas Yes Storm costs are normally expensed as incurred. However, if a storm is ruled to be significant, Commission

has granted authority to request recovery in base rates or a separate proceeding.

3

Indiana Yes Recovery of storm costs is requested in base rate cases. 2011 base case established a $4M annual major

storm reserve based on 5-year historical average of major storm expenses and includes over-/under-

recovery.

N/A

Kentucky Yes Recovery of storm costs is requested in base rate cases. 5

Louisiana No Storm costs are expensed as incurred and included for recovery in years of formula rate filings. N/A

Michigan No Recovery of storm costs is requested in base rate cases which use forecasted test years. N/A

Ohio Yes 2011 Distribution Base Case and 2014 Electric Security Plan orders established a $5M annual major storm

reserve and annual true-up mechanism. Recovery of significant storms are requested in separate

proceedings.

1

Oklahoma Yes Recovery of storm costs is requested in base rate cases with over-/under-recovery above/below $2.9M

annually. Recovery of significant storm costs is separately requested.

4

Tennessee Yes Recovery of storm costs is requested in base rate cases or a separate mechanism/proceeding. 1

Texas (SWEPCo) Yes Storm costs are normally expensed as incurred. However, storm costs may be deferred for recovery if the

costs are included in the test period of a base case filing.

3

Texas (TNC) No Storm costs are normally expensed as incurred and are included in base rates during the test year. N/A

Texas (TCC) Yes Approved catastrophe reserve ($1.3M annually) in base rates allows deferral of incremental storm O&M

costs. The minimum threshold for deferral is $500K per storm.

N/A

Virginia No Based on new legislation enacted in 2015, APCo will expense incremental storm costs through 2017

associated with severe weather events and/or natural disasters.

N/A

West Virginia Yes Recovery of storm costs is requested in base rate cases. 5

15

Jurisdictional Off-System Sales Sharing Summary

State OSS Sharing? Detail

Arkansas Yes, above base levels

Up to $1,200,000 annual margin, customers receive

100%. Above $1,200,000, customers receive 90%.

Indiana Yes, above and below base levels

Sharing occurs above and below levels included in

base rates of $26.9M. Customers receive 50%.

Kentucky Yes, above and below base levels Sharing occurs above and below levels included in

base rates of $15.1M. Customers receive 75%.

Louisiana Yes, above base levels Up to $874,000 annual margin, customers receive

100%. From $874,001 to $1,314,000, customers

receive 85%. Above $1,314,000, customers receive

50%.

Michigan Yes 80% of profits are shared with customers

Ohio No n/a

Oklahoma Yes 75% of profits are shared with customers

Tennessee No n/a

Texas (SWEPCO) Yes 90% of profits are shared with customers

Virginia Yes 75% of profits are shared with customers

West Virginia Yes With the exception of WPCo’s Mitchell Plant, 100% of

profits are passed back to customers through the

Expanded Net Energy Cost (ENEC) clause.

Generally, 82.5% of Mitchell Plant profits are shared

with customers.

16

Commission Overview

Commissioners

Number: 3 Appointed/Elected: Appointed Term: 5 Years Political Makeup: R: - 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.

Colette D. Honorable, Commissioner (Nonpartisan) since 2014: term expires June 2017. Commissioner Honorable came to FERC from the Arkansas

Public Service Commission, where she had served since October 2007. She had the Commission since January 2011. Prior to her APSC appointment,

Commissioner Honorable held a cabinet post as Executive Director of the Arkansas Workforce Investment Board. She also 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. She is a

past president of the National Association of Regulatory Utility Commissioners.

Cheryl A. LaFleur, Commissioner (Dem.) since 2010: second 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.

Federal Energy Regulatory Commission

17

Transforming Our Generation Fleet

• Transforming Our Generation Fleet

• Investments Driving Emission Reductions

• Dramatic Reductions in Emissions

• Large-scale Renewable Opportunities

• Delivering Clean Energy Resources

• Renewable Resources

• Renewable Portfolio/Energy Efficiency Standards

18

Transforming Our Generation Fleet *

19

Investments Driving Emission Reductions

20

Dramatic Reductions in Emissions

87%

21

Dramatic Reductions in Emissions

22

Large-scale Renewable Opportunities

Source: Current Internal Integrated Resource Plans, which largely do not reflect ITC/PTC extension, bonus depreciation

or potential impact of Clean Power Plan. Wind and solar represent nameplate MW capacity

23

Delivering Clean Energy Resources

AEP's 2016 Renewable Portfolio

Hydro, Wind, Solar & Pumped Storage Owned PPA Total

AEP Ohio 210 210

Appalachian Power Company 788 454 1,242

Indiana Michigan Power Company 38 450 488

Public Service of Oklahoma 1,139 1,139

Southwestern Electric Power Company 470 470

Competitive Wind & Hydro 359 177 536

Total 1,185 2,900 4,085

24

Renewable Resources Owned Renewables PPA Renewables Total

Company & Plant Name State Hydro Wind Solar Total

Owned Hydro Wind Solar

Total

PPA


Buck VA 9 9 9

Byllesby VA 22 22 22

Claytor VA 76 76 76

Leesville VA 50 50 50

London WV 14 14 14

Marmet WV 14 14 14

Niagara VA 2 2 2

Winfield WV 15 15 15

Smith Mtn Pumped VA 586 586 586

Camp Grove WV 75 75 75

Beech Ridge VA 100 100 100

Fowler Ridge III OH 99 99 99

Grand Ridge II & III WV 100 100 100

Gauley River / Summersville WV 80 80 80

Total 788 788 80 374 454 1,242


Berrien Springs MI 7 7 7

Buchanan MI 4 4 4

Constantine MI 1 1 1

Elkhart IN 3 3 3

Mottville MI 2 2 2

Twin Branch IN 5 5 5

Watervliet MI 5 5 5

Olive IN 5 5 5

Deer Creek IN 3 3 3

Twin Branch IN 3 3 3

Fowler Ridge I IN 100 100 100

Fowler Ridge II IN 50 50 50

Wildcat IN 100 100 100

Headwaters IN 200 200 200

Total 22 16 38 450 450 488

25

Renewable Resources Owned Renewables PPA Renewables Total

Company & Plant Name State Hydro Wind Solar Total

Owned Hydro Wind Solar

Total

PPA

Ohio Power Company

Fowler Ridge II OH 100 100 100

Wyandot Solar OH 10 10 10

Timber Road OH 100 100 100

Total 200 10 210 210


Weatherford OK 147 147 147

Sleeping Bear OK 95 95 95

Blue Canyon V OK 99 99 99

Minco OK 99 99 99

Elk City OK 99 99 99

Balko OK 200 200 200

Seling OK 200 200 200

Goodwell OK 200 200 200

Total 1,139 1,139 1,139


Majestic TX 80 80 80

Majestic II TX 80 80 80

Flat Ridge II KS 109 109 109

Canadian Hills OK 201 201 201

Total 470 470 470

Total Regulated Renewables 810 16 826 80 2,633 10 2,723 3,549

Competitive

Trent Mesa TX 150 150 150

Desert Sky TX 161 161 161

Southwest Mesa TX 177 177 177

Racine OH 48 48 48

Total Competitive Renewables 48 311 359 177 177 536

Total AEP Renewable Resources 858 311 16 1,185 80 2,810 10 2,900 4,085 26

Renewable Portfolio/Energy Efficiency Standards

27

Environmental

• Regulated & Competitive Retirements

• Regulated Environmental Controls

• Competitive Environmental Controls

• Clean Power Plan – Overview

• Clean Power Plan – Implementation Schedule

• Additional Environmental Regulations

28

Regulated & Competitive Retirements

Operating Company Plant MW Retirement Date

APCO Glen Lyn 5 95 2015

Glen Lyn 6 240 2015

Clinch River 3 235 2015

Sporn 1 150 2015

Sporn 3 150 2015

Kanawha River 1 200 2015

Kanawha River 2 200 2015

Total MW 1,270

I&M Tanners Creek 1-4 995 2015

Total MW 995

KPCO Big Sandy 2 800 2015

Total MW 800

SWEPCO Welsh 2 528 2016

Total MW 528

PSO Northeastern 4 470 2016

Total MW 470

Total Regulated retirements 4,063

Operating Company Plant MW Retirement Date

AEP Generation Resources Beckjord 53 2014

Conesville 3 165 2012

Muskingum River 1-5 1,440 2015

Picway 5 100 2015

Sporn 2,4 300 2015

Sporn 5 450 2011

Kammer 1-3 630 2015

Total Competitive Retirements 3,138 29

Regulated Environmental Controls

Plant Name

MW

Capacity SCR

Projected

In-Service FGD

Projected

In-Service ACI

Projected

In-Service DSI

Projected

In-Service Baghouse

Projected

In-Service

Gas

Conversion

Projected

In-Service

APCo

Amos 1

800

Amos 2

800

Amos 3

1,330

Clinch River 1

230

Clinch River 2

230

Mountaineer

1,320

WPCo

Mitchell 1&2*

780

KPCo

Big Sandy 1

280

Mitchell 1&2*

780

I&M/AEG (50/50 share)

Rockport 1

1,310 x 2017 x 2025

Rockport 2

1,310 x 2019 x 2028

In Service Projected * Operated by Kentucky Power

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

(Mercury Control) (SO3 Control) (SO2 Control) (NOx Control) (Particulate Matter)

30

Regulated Environmental Controls

Plant Name

MW

Capacity SCR

Projected

In-Service FGD

Projected

In-Service ACI

Projected

In-Service DSI

Projected

In-Service Baghouse

Projected

In-Service

Gas

Conversion

Projected

In-Service

PSO

Oklaunion 102

Northeastern 3 462

SWEPCO

Dolet Hills 258

Flint Creek 1 259

Pirkey 580

Turk 477

Welsh 1 528 x 2024

Welsh 3 517 x 2024

In Service Projected

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

(Mercury Control) (SO3 Control) (SO2 Control) (NOx Control) (Particulate Matter)

31

Competitive Environmental Controls

Plant Name MW Capacity SCR FGD ACI

Gore Mercury

Control


Cardinal 1 595

Conesville 4 339

Conesville 5 405

Conesville 6 405

Stuart 1-4 603

Zimmer 330

TNC

Oklaunion* 355

In Service Projected * Owned by TNC, PPA with Competitive

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

(Mercury Control) (SO2 Control) (NOx Control)

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

The Clean Power Plan is currently under a stay by the U.S. Supreme Court

33

• 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 were due Sept 2016; Final draft State Plans were due Sept 2018

• Litigation over final rule is on-going, Supreme Court issued a stay of the rule until litigation is complete.

• Significant uncertainty over schedule even if rule is found to be legal.

• 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

Clean Power Plan - Overview The Clean Power Plan is currently under a stay by the U.S. Supreme Court

34

Clean Power Plan – Implementation Schedule?

2014 2015 2016 2017 2018 2020 2019

Rule Proposed

Final Clean Power Plan & Proposed Federal Plan

2030 2022

Initial State Plan or Extension Request Due

Final SIP Due w/ 2 Year Extension

Enforceable Compliance Program Begins

CO2 Emission Reduction

Requirements Gradually Become

More Stringent

FIP Promulgated for

States w/o SIP

State Plan Approval /

Disapproval

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

------ 2021

Final Federal Plan Issued

EPA’s Rule has been stayed by Supreme Court, considerable uncertainty about implementation schedule. 35

Additional Environmental Regulations

• Revised Effluent Limitation Guidelines (“ELG”) – Final rule went into effect January, 2016

• 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”) – Final rule went into effect October, 2015

• Applies to the handling and storage of 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 - Final rule went into effect October, 2014

• Applies to the cooling water intake systems

• Does not mandate cooling towers, but does require studies of site-specific constraints

• With the rule finalized, plans are being refined and are expected to be generally consistent with prior estimates

36

Financial Update

• Capitalization and Liquidity

• AEP Banking Group

• AEP Credit Ratings

• Long-Term Debt Maturity Profile

• Debt Schedules

37

Capitalization & Liquidity

Liquidity Summary

Credit Statistics

Note: Credit statistics represent the trailing 12 months as of 9/30/2016

Total Debt / Total Capitalization

Qualified Pension Funding

Actual Target

FFO Interest Coverage 5.9x >3.6x

FFO to Total Debt 21.8% 15%-20%

(unaudited) 9/30/2016 Actual

($ in millions) Amount Maturity

Revolving Credit Facility $3,000 Jun-21

Revolving Credit Facility $500 Jun-18

Total Credit Facilities $3,500

Plus

Cash & Cash Equivalents $212

Less

Commercial Paper Outstanding (728)

Letters of Credit Issued -

Net Available Liquidity $2,984

38

Pension & OPEB Estimates

Qualified Pension Funding

Assumptions 2016E 2017E

Pension Discount Rate 4.30% 3.55%

OPEB Discount Rate 4.30% 3.55%

Assumed Long Term Rate of

Return on Pension Assets 6.00% 6.00%

Assumed Long Term Rate of

Return on OPEB Assets 6.00% 7.00%

Pension/OPEB Funding $97M $113M

Pension/OPEB Cost* $31M $39M

YTD pension returns are up

9.7% due to 11%+ returns in

the bond portfolio, which

comprises 60% of pension

assets. OPEB returns are up

7.0%, also due to strong bond

performance and modest equity

gains. OPEB obligations

remain fully funded at 104%

We expect combined pension

and OPEB costs (pre-tax and

including capitalized portion) to

increase by $8M from 2016 to

2017 subject to potential

changes in investment results,

interest rates and actuarial

assumptions

Pension funding and expense

for regulated subsidiaries are

recovered through base rates

39

*Pre-tax and pre-capitalization. On average, 35% of pension and OPEB

costs are capitalized and 65% are expensed.

AEP Banking Group

Lender Composition

Lender mix gives AEP

geopolitical

diversification

$3.5B Core Credit Facilities

%Share

Bank of America Major US Bank 6.5%

Bank of Tokyo-Mitsubishi Japanese Bank 6.5%

Barclays Bank British Bank 6.5%

Citibank Major US Bank 6.5%

JP Morgan Major US Bank 6.5%

Mizuho Japanese Bank 6.5%

The Bank of Nova Scotia Canadian Bank 6.5%

Wells Fargo Major US Bank 6.5%

Bank of New York US Regional Bank 4.0%

BNP Paribas European Bank 4.0%

Credit Agricole European Bank 4.0%

Credit Suisse Investment Bank 4.0%

Goldman Sachs Investment Bank 4.0%

Key Bank US Regional Bank 4.0%

Morgan Stanley Investment Bank 4.0%

PNC Financial US Regional Bank 4.0%

Royal Bank of Canada Canadian Bank 4.0%

SunTrust Bank US Regional Bank 4.0%

UBS Investment Bank 4.0%

Fifth-Third Bank US Regional Bank 2.6%

Huntington National Bank US Regional Bank 1.4%

Total 100.0%

40

AEP Credit Ratings

Ratings current as of September 30, 2016

Current Ratings for AEP, Inc. & Subsidiaries

Company

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 P BBB+ P

Public Service Company of Oklahoma A3 S BBB+ P

Southwestern Electric Power Company Baa2 S BBB+ P

AEP Transmission Company, LLC A2 S - -

Moody's S&P

Senior Unsecured

Outlook

Senior Unsecured

Outlook

41

Long-Term Debt Maturity Profile

($ in millions)

Year 2016 2017 2018 2019 2020 2021

AEP, Inc. $0.0 $550.0 $0.0 $0.0 $0.0 $0.0

AEP Generating Company $0.0 $45.0 $0.0 $0.0 $0.0 $0.0

AEP Generation Resources $0.0 $500.0 $0.0 $0.0 $0.0 $0.0

AEP Texas Central Company* $0.0 $40.9 $0.0 $175.0 $6.3 $0.0

AEP Texas North Company $0.0 $0.0 $30.0 $75.0 $44.3 $0.0

AEP Transmission Company $0.0 $300.0 $50.0 $85.0 $0.0 $50.0

Appalachian Power* $0.0 $354.4 $100.0 $281.0 $65.4 $367.5

Indiana Michigan Power $0.0 $84.5 $300.0 $573.4 $81.8 $0.0

Kentucky Power $0.0 $390.0 $75.0 $0.0 $0.0 $40.0

Ohio Power* $0.0 $0.0 $350.0 $0.0 $0.0 $500.0

Public Service of Oklahoma $125.0 $0.0 $0.0 $250.0 $12.7 $250.0

Southwestern Electric Power $0.0 $350.0 $381.7 $453.5 $0.0 $0.0

Wheeling Power Company $0.0 $0.0 $65.0 $0.0 $0.0 $0.0

Desert Sky Wind Farm $0.0 $5.2 $0.0 $0.0 $0.0 $0.0

Total $125 $2,620 $1,352 $1,893 $210 $1,208

* Excludes securitization bonds

Includes mandatory tenders (put bonds)

Data as of September 30, 2016

42

Debt Schedules

Note: Debt schedules current as of 9/30/16.

* PPN – Private Placement Number

AEP Texas Central Interest Maturity CUSIP / PPN* Amount

Guadalupe-Blanco River Authority PCRB, Series 2008 5.625% 10/01/2017 40053QAQ4 $40,890,000

Red River Authority of Texas PCRB (CPL, PSO, WTU) 4.450% 06/01/2020 756864BT0 $6,330,000

Matagorda PCB Series 2001A 6.300% 11/01/2029 576528DM2 $100,635,000

Matagorda Cnty Navigation Dist. #1 PCRB, Series 2008-1 4.000% 06/01/2030 576528DP5 $60,265,000

Matagorda Cnty Navigation Dist. #1 PCRB, Series 2008-2 4.000% 06/01/2030 576528DQ3 $60,000,000

Matagorda Cnty Navigation District #1, Series 1996 5.200% 05/01/2030 576528DE0 $60,000,000

Matagorda Cnty Navigation District #1, Series 2005A 4.400% 05/01/2030 576528CY7 $111,700,000

Matagorda Cnty Navigation District #1, Series 2005B 4.550% 05/01/2030 576528CZ4 $50,000,000

Bank Term Loan Floating 07/25/2019 N/A $125,000,000

Senior Note, Series B 6.650% 02/15/2033 0010EPAF5 $275,000,000

Senior Note, Series A 2.610% 04/30/2019 0010EPA*9 $50,000,000

Senior Note, Series B 3.810% 04/30/2026 0010EPA@7 $50,000,000

Senior Note, Series C 4.670% 04/30/2044 0010EPA#5 $100,000,000

Senior Note, Series D 4.770% 10/30/2044 0010EPB*8 $100,000,000

Senior Note, Series G 3.850% 10/01/2025 0010EPAN8 $250,000,000

Total $1,439,820,000

Securitization Bonds, Class 2006A-4 5.170% 01/01/2018 00110AAD6 $231,168,152

Securitization Bonds, Class 2006A-5 5.306% 07/01/2020 00110AAE4 $494,700,000

Securitization Bonds, Class 2012 A-1 0.880% 12/01/2017 00104UAA6 $68,087,949

Securitization Bonds, Class 2012 A-2 1.976% 06/01/2020 00104UAB4 $180,200,000

Securitization Bonds, Class 2012 A-3 2.845% 12/01/2024 00104UAC2 $311,900,000

Total $1,286,056,101

43



AEP Texas North Interest Maturity CUSIP / PPN* Amount


Senior Note, Series 2008A 5.890% 04/01/2018 0010EQA*7 $30,000,000

Senior Note, Series 2008B 6.760% 04/01/2038 0010EQA@5 $70,000,000

Senior Notes, Series C 3.090% 02/28/2023 0010EQA#3 $125,000,000

Senior Notes, Series D 4.480% 02/27/2043 0010EQB*6 $75,000,000


Senior Note, Series E 3.270% 09/30/2022 0010EQB@4 $25,000,000

Senior Note, Series F 3.750% 09/30/2025 0010EQB#5 $50,000,000

Senior Note, Series G 4.710% 12/15/2035 0010EQ C*5 $50,000,000

Total $544,310,000

Debt Schedules

44

Senior Notes, Series A, Tranche 1 3.300% 10/18/2022 00114*AA1 $104,000,000

Senior Notes, Series A, Tranche 2 4.000% 10/18/2032 00114*AB9 $85,000,000

Senior Notes, Series A, Tranche 3 4.730% 10/18/2042 00114*AC7 $61,000,000

Senior Notes, Series A, Tranche 4 4.780% 12/14/2042 00114*AD5 $75,000,000

Senior Notes, Series A, Tranche 5 4.830% 03/18/2043 00114*AE3 $25,000,000

Senior Notes, Series B, Tranche 1 2.730% 11/07/2018 00114*AF0 $50,000,000

Senior Notes, Series B, Tranche 2 4.050% 11/07/2023 00114*AG8 $60,000,000

Senior Notes, Series B, Tranche 3 4.380% 11/07/2028 00114*AL7 $60,000,000

Senior Notes, Series B, Tranche 4 5.320% 11/07/2043 00114*AH6 $100,000,000

Senior Notes, Series B, Tranche 5 5.420% 04/30/2044 00114*AJ2 $30,000,000

Senior Notes, Series B, Tranche 6 5.520% 10/30/2044 00114*AK9 $100,000,000

Senior Notes, Series C, Tranche A 2.680% 11/14/2019 00114*AM5 $85,000,000

Senior Notes, Series C, Tranche B 3.180% 11/14/2021 00114*AN3 $50,000,000

Senior Notes, Series C, Tranche C 3.560% 11/14/2024 00114*AP8 $95,000,000

Senior Notes, Series C, Tranche D 3.660% 03/16/2025 00114*AQ6 $50,000,000

Senior Notes, Series C, Tranche E 3.760% 06/16/2025 00114*AR4 $40,000,000

Senior Notes, Series C, Tranche F 3.810% 11/14/2029 00114*AS2 $55,000,000

Senior Notes, Series C, Tranche G 4.010% 06/15/2030 00114*AT0 $60,000,000

Senior Notes, Series C, Tranche H 4.050% 11/14/2034 00114*AU7 $25,000,000

Senior Notes, Series C, Tranche I 4.530% 11/14/2044 00114*AV5 $40,000,000

Term Loan Draw Floating 11/04/2017 0 $300,000,000

Total $1,550,000,000



AEP Transmission Company Interest Maturity CUSIP / PPN* Amount

Debt Schedules

45



Debt Schedules Appalachian Power Company Interest Maturity CUSIP / PPN* Amount


West Virginia Economic Dev. Authority, Series 2009A Floating 12/01/2042 95648VAP4 $54,375,000

West Virginia Economic Dev. Authority, Series 2009B Floating 12/01/2042 95648VAQ2 $50,000,000

West Virginia Economic Dev. Authority, Series 2008C 3.250% 05/01/2019 95648NAD9 $30,000,000

Russell County, Series K 4.625% 11/01/2021 782470AR9 $17,500,000

West Virginia Economic Dev. Authority, Series 2008D 3.250% 05/01/2019 95648NAE7 $40,000,000

Mason County, Series L 1.625% 10/01/2022 575200BB5 $100,000,000

West Virginia Economic Dev. Authority, Series 2008B Floating 02/01/2036 95648VAL3 $50,275,000

West Virginia Economic Dev. Authority, Series 2008A Floating 02/01/2036 95648VAW9 $75,000,000

West Virginia Economic Dev. Authority, Series 2010A 5.375% 12/01/2038 95648VAS8 $50,000,000

West Virginia Economic Dev. Authority, Series 2011A 1.700% 01/01/2041 95648VAZ2 $65,350,000

West Virginia Economic Dev. Authority, Series 2015A (Amos) 1.900% 03/01/2043 95648VAV1 $86,000,000

Senior Note, Series K 5.000% 06/01/2017 037735CD7 $250,000,000

Senior Note, Series H 5.950% 05/15/2033 037735BZ9 $200,000,000

Senior Note, Series L 5.800% 10/01/2035 037735CE5 $250,000,000

Senior Note, Series N 6.375% 04/01/2036 037735CG0 $250,000,000

Senior Note, Series P 6.700% 08/15/2037 037735CK1 $250,000,000

Senior Note, Series Q 7.000% 04/01/2038 037735CM7 $500,000,000

Senior Note, Series T 4.600% 03/30/2021 037735CR6 $350,000,000

Senior Note, Series U 4.400% 05/15/2044 037735CT2 $300,000,000

Senior Note, Series V 3.400% 06/01/2025 037735CU9 $300,000,000

Senior Note, Series W 4.450% 06/01/2045 037735CV7 $350,000,000

Total $3,743,500,000

Securitization Bonds, Tranche A-1 2.008% 02/01/2023 037680AA3 $157,618,952

Securitization Bonds, Tranche A-2 3.772% 08/01/2028 037680AB1 $164,500,000

Total $322,118,952

1 Liquidity Letter of Credit matures on 03/24/2017

2 Put date 10/01/2018

3 Put date 09/01/2016

4 Put date 4/01/2019

1

1

2

3

4

46



Desert Sky Wind Farm Interest Maturity CUSIP / PPN* Amount

Desert Sky 6.475% 08/31/2017 N/A $5,154,831

Total $5,154,831

Indiana Michigan Power Company Interest Maturity CUSIP / PPN* Amount

Lawrenceburg, Series I Floating 10/01/2019 520453AL5 $25,000,000

Rockport, Series D Floating 04/01/2025 N/A $0

Rockport, Series 2002 A 4.625% 06/01/2025 773835AV5 $50,000,000

Lawrenceburg, Series H Floating 11/01/2021 520453AK7 $52,000,000

City of Rockport, Series 2009A 1.750% 06/01/2025 773835BL6 $50,000,000

City of Rockport, Series 2009B 1.750% 06/01/2025 773835BM4 $50,000,000

Bank Term Loan Floating 05/15/2018 45488QAA6 $200,000,000

DCC Fuel VI Floating Rate Floating 10/15/2017 N/A $7,492,131

DCC Fuel VII Floating Rate Floating 04/28/2019 N/A $44,875,659

DCC Fuel VIII Floating Rate Floating 10/27/2019 N/A $53,543,932

DCC Fuel IX Floating Rate Floating 10/29/2020 N/A $81,777,414

Senior Note, Series H 6.050% 03/15/2037 454889AM8 $400,000,000

Senior Note, Series I 7.000% 03/15/2019 454889AN6 $475,000,000

Seinor Note, Series J 3.200% 03/15/2023 454889AP1 $250,000,000

Seinor Note, Series K 4.550% 03/15/2046 454889 AQ9 $400,000,000

Total $2,139,689,137

1 Liquidy Letter of Credit matures on 03/22/2017


3 Put date is 06/01/2018

Debt Schedules

1

2

3

3

47



Kentucky Power Interest Maturity CUSIP / PPN* Amount


Senior Note, Series A 7.250% 06/18/2021 491386C*7 $40,000,000

Senior Note, Series B 8.030% 06/18/2029 491386C@5 $30,000,000

Senior Note, Series C 8.130% 06/18/2039 491386C#3 $60,000,000

Senior Note, Series D 5.625% 12/01/2032 491386AL2 $75,000,000

Senior Note, Series E 6.000% 09/15/2017 491386AM0 $325,000,000

Senior Note, Series A 4.180% 09/30/2026 491386D*6 $120,000,000

Senior Note, Series B 4.330% 12/30/2026 491386D@4 $80,000,000

WV Economic Dev. Authority, Series 2014A (Mitchell) Floating 04/01/2036 95648VAU3 $65,000,000

Total $870,000,000


Ohio Power Company Interest Maturity CUSIP / PPN* Amount

Senior Note, Series B 6.600% 03/01/2033 199575AT8 $250,000,000

Senior Note, Series F 5.850% 10/01/2035 199575AV3 $250,000,000

Senior Note, Series G 6.050% 05/01/2018 199575AW1 $350,000,000

Senior Note, Series G Due 2/15/2033 6.600% 02/15/2033 677415CF6 $250,000,000

Senior Notes, Series M Due 10/1/2021 5.375% 10/01/2021 677415CP4 $500,000,000

Total $1,600,000,000

Securitization Bonds, Tranche A-1 0.958% 07/01/2017 67741YAA6 $38,672,593

Securitization Bonds, Tranche A-2 2.049% 07/01/2019 67741YAB4 $102,508,000

Total $141,180,593

Debt Schedules

1

48



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


Senior Note, Series H 5.150% 12/01/2019 744533BK5 $250,000,000

Senior Note, Series G 6.625% 11/15/2037 744533BJ8 $250,000,000

Senior Note, Series I 4.400% 02/01/2021 744533BL3 $250,000,000

Senior Note, Series A 3.170% 03/31/2025 744533C*9 $125,000,000

Senior Note, Series B 4.090% 03/31/2045 744533C@7 $125,000,000

Senior Note, Series C 3.050% 08/01/2026 744533C#5 $50,000,000

Senior Note, Series D 4.110% 08/01/2046 744533D*8 $100,000,000


Total $1,287,660,000

Debt Schedules

49



Southwestern Electric Power Company Interest Maturity CUSIP / PPN* Amount


Sabine Mines 6.370% 10/31/2024 78532*AC7 $25,000,000

Sabine Mines 4.580% 02/21/2032 78532*AD5 $50,375,000

Sabine River Authority of Texas, Series 2006 4.950% 03/01/2018 785652CJ5 $81,700,000

Parish of DeSoto, Series 2010 1.600% 01/01/2019 241627AW8 $53,500,000

Senior Note, Series E 5.550% 01/15/2017 845437BH4 $250,000,000

Senior Note, Series F 5.875% 03/01/2018 845437BJ0 $300,000,000

Senior Note, Series G 6.450% 01/15/2019 845437BK7 $400,000,000

Senior Note, Series H 6.200% 03/15/2040 845437BL5 $350,000,000

Senior Note, Series I 3.550% 02/15/2022 845437BM3 $275,000,000

Senior Note, Series J 3.900% 04/01/2045 845437BN1 $400,000,000

Senior Note, Series K 2.750% 10/01/2026 845437BP6 $400,000,000

Total $2,685,575,000

Wheeling Power Company Interest Maturity CUSIP / PPN* Amount

West Virginia Economic Development Authority, Series 2013A Floating 06/01/2037 N/A $65,000,000

Senior Note, Series A, Tranche A 3.360% 06/01/2022 96316#AB9 $113,000,000

Senior Note, Series A, Tranche B 3.700% 06/01/2025 96316#AC7 $122,000,000

Senior Note, Series A, Tranche C 4.200% 06/01/2035 96316#AD5 $50,000,000

Total $350,000,000

1 Put date 06/30/2018

Debt Schedules

1

50

Overview

Appalachian Power Company (APCo) (organized in Virginia in 1926) is engaged in the generation,

transmission and distribution of electric power to approximately

957,000 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, 2015, APCo had

1,836 employees. APCo is a member of PJM.

PRINCIPAL

INDUSTRIES SERVED:

Coal Mining

Primary Metals

Chemical Manufacturing

Pipeline Transportation

Paper Manufacturing

President and Chief Operating Officer:

Charles Patton

Total Customers at 12/31/15:

Residential 887,000

Commercial 146,000

Industrial 5,000

Other 8,000

Total 1,046,000

Owned Generating Capacity 7,407 MW

PPA Capacity 798 MW

Generating Capacity by Fuel Mix:

• Coal: 65.5%

• Hydro, Wind, Solar & Pump: 15.1%

• Natural Gas: 19.4%

Transmission Miles 6,461

Distribution Miles 54,292

Note: Values consolidate APCo, WPCo, and KGPCo.

Since April 2010

21 years with AEP

Wheeling Power Company (WPCo) (organized in West Virginia in 1883 and reincorporated in 1911)

provides electric service to approximately 41,000 retail customers in

northern West Virginia. As of December 31, 2015, WPCo had 56

employees. WPCo is a member of PJM.

Kingsport Power Company (KGPCo) (organized in Virginia in 1917) provides electric service to

approximately 47,000 retail customers in Kingsport and eight

neighboring communities in northeastern Tennessee. As of

December 31, 2015, KGPCo had 52 employees. KGPCo is a

member of PJM.

51

APCo Financial & Operational Data

* Source: 3Q16 Financial Statements (unaudited)

** Source: 2015 10K Financial Statements

*** GWh Sales – Weather Normalized

Credit Ratings/Outlook

Moody's S&P

Baa1/S BBB+/P

11,504 11,851 11,801

6,707 6,799 6,817

9,866 10,314 10,393

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2015 2014 2013

Gig

awat

t-h

ou

rs

Summary of Energy Sales***

Residential Commercial Industrial Other

31,140 30,074 31,002

Summary of Degree Days**

2015 2014 2013

(in degree days)

Heating Actual 2,162 2,645 2,377

Normal 2,248 2,232 2,225

Cooling Actual 1,290 1,056 1,150

Normal 1,196 1,206 1,206

2016 Asset Data* (in thousands)

As of 9/30/16

Total Assets $ 11,768,300

Net Plant Assets $ 9,646,500

Cash $ 3,300

Capital Structure (in thousands)

Capital Structure 2015** 9/30/2016*

Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 4,111,700 3,475,000 7,586,700 4,117,200 3,552,200 7,669,400

% of Capitalization Per Balance Sheet 54.2% 45.8% 100.0% 53.7% 46.3% 100.0%

FFO Interest Coverage 5.15 5.4^

FFO Total Debt 20.5% 21.1%

^ - calculated on rolling 12-month avg.

52

WPCo Financial & Operational Data


Moody's S&P

NR BBB+/P

417 417 427

445 441 451

2,748 2,397

1,811

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2015 2014 2013

Gig

awat

t-h

ou

rs



3,615 3,260 2,694

Summary of Degree Days

2015 2014 2013

(in degree days)


Normal 3,694 3,687 3,685

Cooling Actual 935 715 806

Normal 725 721 714





As of 6/30/16


Net Plant Assets $ 903,042

Cash $ 206




Capitalization Per Balance Sheet 356,332 406,461 762,793 348,454 412,173 760,627





53

KGPCo Financial & Operational Data

* Source: 2Q16 Financial Statements

** Source: 2015 Annual Financial Statements


683 682 684

395 392 391

981 981 926

-

500

1,000

1,500

2,000

2,500

2015 2014 2013

Gig

awat

t-h

ou

rs



2,094 2,091 2,038


2015 2014 2013

(in degree days)


Normal 2,221 2,219 2,215

Cooling Actual 1,260 1,088 980

Normal 1,078 1,069 1,065




Capitalization Per Balance Sheet 52,297 29,626 81,923 39,597 36,080 75,677



As of 6/30/16

Total Assets $ 141,751

Net Plant Assets $ 119,208

Cash $ 98

54

MAJOR CUSTOMERS:

Greif Brothers Corporation (VA)

Steel of WV, Inc. (WV)

WVA Manufacturing (WV)

Roanoke Electric Steel Corporation (VA)

Georgia-Pacific Corporation (VA)

Felman Production (WV)

Constellium Rolled Products (WV)

Blue Racer Midstream LLC (WV)

The Goodyear Tire and Rubber Co. (VA)

Weyerhaeuser Company (TN)

(Data for year ended December 2015)

APPALACHIAN AREA

INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON **

Top 10 Customers = 42% of industrial sales

Metropolitan areas account for 57% of ultimate sales

103 persons per square mile (U.S. = 87)

(Data for 12 months ended December 2015)

** 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, 2016.

Customer Statistics

• Customer counts are as of December 31, 2015 and were

sourced from Sales_Ult_Cust_2015.xlsx at

https://www.eia.gov/electricity/data/eia861/

West Virginia Customers

APCo

430,949

Monongahela Power Co

389,370

The Potomac Edison Company

138,588

WPCo

41,403

Black Diamond Power Co

4,028

Virginia Customers

Virginia Electric & Power Co

2,405,875

APCo

525,592

Kentucky Utilities Co

28,351

Tennessee Customers

KGPCo 47,309

West Virginia $/month

Monongahela Power Co 109.89

The Potomac Edison Company 109.89

APCo 109.82

WPCo 109.82

Virginia $/month

APCo 114.83

Virginia Electric & Power Co 111.34

Kentucky Utilities Co 107.96

Tennessee $/month

KGPCo 86.47

55



Commission Overview

Virginia State Corporation Commission

Commissioners

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


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, (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, Chairman, (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 rev iews 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% in 2010 and increases to 15% by 2025.

56

Commission Overview

Public Service Commission of West Virginia

Commissioners

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


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.


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. In June

2016, the Commission authorized new rates through a construction surcharge and the ENEC.

57

Commission Overview

Tennessee Regulatory Authority


Tennessee has no deregulation legislation and no base rate freeze or cap. Tennessee has an active fuel clause. In August 2016, the

Tennessee Regulatory Authority (TRA) authorized new base rates in Kingsport Power Company’s first base rate case since 1992. Effective

with the authorization, fuel, purchased power, and PJM transmission charges have been removed from base rates and are now recovered

through a single tracked surcharge.

Commissioners

Number: 5 Appointed/Elected: Appointed Term: 6 Years


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, Director, 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, 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, Vice Chairman, 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

58


(I&M) (organized in Indiana in 1907) is engaged in the

generation, transmission and distribution of electric power to

approximately 588,000 retail customers in northern and eastern

Indiana and southwestern Michigan, and in supplying and

marketing electric power at wholesale to other electric utility

companies, rural electric cooperatives, municipalities and other

market participants. As of December 31, 2015, I&M had 2,489

employees. I&M is a member of PJM.


Paul Chodak

PRINCIPAL INDUSTRIES SERVED:

Primary Metals


Transportation Equipment

Plastics and Rubber Products

Fabricated Metal Product Manufacturing


Residential 511,000

Commercial 70,000

Industrial 5,000

Other 2,000

Total 588,000


PPA Capacity 1,539 MW*


• Coal: 47.2%

• Nuclear: 43.2%

• Hydro, Wind & Solar: 9.6%



Overview

Since July 2010

16 years with AEP

*includes 917 MW from AEP Generating Company Rockport Plant PPA

59

Financial & Operational Data





Moody's S&P

Baa1/S BBB+/P

5,509 5,663 5,723

4,904 4,883 4,932

7,570 7,640 7,522

5,041 5,104 5,098

-

5,000

10,000

15,000

20,000

25,000

30,000

2015 2014 2013

Gig

awat

t-h

ou

rs



23,290 23,275 23,024


2015 2014 2013

(in degree days)


Normal 3,762 3,737 3,730

Cooling Actual 798 714 826

Normal 846 853 855










As of 9/30/16



Cash $ 1,600

60

INDIANA & MICHIGAN INVESTOR

OWNED UTILITIES * TYPICAL BILL COMPARISON **

1,779,184

2,156,214

** 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, 2016.

Top 10 Customers = 48% of industrial sales




MAJOR CUSTOMERS:

Steel Dynamics Inc. (IN)

Metal Technologies Inc. (MI)

American Axle and Mfg. Co, Inc. (MI)

IN TEK (IN)

Rettenmaier USA LP (MI)

Michelin North America (IN)

White Pigeon Paper Company (MI)

Air Products & Chemicals. Inc. (IN)

The Minute Maid Company (MI)

Linde LLC (IN)


Customer Statistics

Indiana Customers

Duke Energy Indiana 804,322

IP & L 484,791

NIPSCO 463,028

I & M 459,445

SIGECo 147,771

Michigan Customers

DTE Electric Company 2,153,990

Consumers Energy 1,796,196

I & M 127,807




Indiana $/month Michigan $/month

SIGECo 155.77 DTE Electric Company 154.32

NIPSCO 117.55 Consumers Energy 142.95

Duke Energy Indiana 111.26 I & M 108.40

I & M 110.82

IP & L 99.13

61



Indiana Utility Regulatory Commission

Commission Overview

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.

Sarah Freeman, Commissioner ( Dem.), since 2016; current term ends December 2017. Former senior staff attorney with the nonpartisan

Indiana Legislative Services Agency for 16 years. Before joining the legislative branch, Commissioner Freeman served as a deputy attorney

general with the Office of the Indiana Attorney General. Undergraduate degrees in psychology, French, and political science from Indiana

University – Bloomington and her juris doctor degree from the Indiana University Maurer School of Law.

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.


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, solar pilot project costs and DSM. Indiana currently has a voluntary renewable standard which phases in starting at 4%

and ending at 10% from 2013-2025.

62

Michigan Public Service Commission

Commission Overview

Commissioners

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


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

Rachel Eubanks, Commissioner, (Rep.), since 2016; current term expires July 2017. Worked in public finance for 13 years, most recently as

a director at Robert W. Baird & Co. Inc. Holds a bachelor’s degree in economics from the University of Michigan.

Sally Talberg, Chairman (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.


Customer choice began in 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 that recovers fuel, purchased energy and capacity, PJM expenses, consumables expenses and off-system

sales. Return on CWIP can be included in base rates. Michigan also has a DSM rider and has approved deferral of nuclear life cycle

management costs from 2013-2018. Michigan currently has a 10% mandatory renewable energy standard and provides for recovery of

compliance, including utility-owned renewables.

63

Overview

Kentucky Power Company (KPCo) (organized in Kentucky in 1919) is engaged in the generation,

transmission and distribution of electric power to

approximately 170,000 retail customers in eastern Kentucky,

and in supplying and marketing electric power at wholesale to

other electric utility companies, municipalities and other

market participants. As of December 31, 2015, KPCo had

558 employees. KPCo is a member of PJM.


Greg Pauley


Residential 138,000

Commercial 30,500

Industrial 1,000

Other 500

Total 170,000


PPA Capacity 393 MW*


• Coal: 80.7%





Petroleum and Coal Products Manufacturing

Coal Mining

Primary Metals


Oil and Gas Extraction

Since August 2010

42 years with AEP

*Represents 393 MW from AEP Generating Company Rockport Plant PPA 64



Moody's S&P

Baa2/S BBB+/P

2,198 2,287 2,273

1,327 1,355 1,337

2,693 2,810 2,870

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2015 2014 2013

Gig

awat

t-h

ou

rs



6,319 6,557 6,584





2015 2014 2013

(in degree days)


Normal 2,446 2,438 2,432

Cooling Actual 1,096 933 1,177

Normal 1,180 1,184 1,185


As of 9/30/16



Cash $ 913




Capitalization Per Balance Sheet 885,143 663,074 1,548,217 878,366 670,307 1,548,673





65

KENTUCKY INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON **

MAJOR CUSTOMERS:

Catlettsburg Refining LLC

AK Steel Holding Corporation

Air Products & Chemicals, Inc.

Air Liquide

Calgon Carbon Corp

Markwest Energy Appalachia LLC

Huntington Alloys

Czar Coal Corporation

Blue Diamond Mining, LLC

M C Mining, Inc.


Top 10 customers = 74% of industrial sales




** 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, 2016.

Customer Statistics

Kentucky Customers

Kentucky Utilities 515,952

LG & E 401,371

KPCo 170,020

Duke Energy Kentucky 138,605




Kentucky $/month

KPCo 116.10

LG & E 110.96

Kentucky Utilities 102.27

Duke Energy Kentucky 83.53

66



Commission Overview

Kentucky Public Service Commission


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 last implemented base rates in 2015. Kentucky does not have a renewable portfolio standard.

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

Michael J. Schmitt, Chairman (Rep.), Appointed June 2016; current term expires June 30, 2019. Prior to joining the PSC Chairman

Schmitt was a partner at the law firm Porter, Schmitt, Banks, and Baldwin where he specialized in energy and education law. J.D. from the

University of Kentucky College of Law.

Robert Cicero, Vice Chairman (Rep.), since April 2016; current term expires June 30, 2020. Before joining the PSC, Mr. Cicero, was a small

business owner and business executive. Vice Chairman Cicero served for 10 years as CFO and Treasurer for Aristech Acrylics LLC. He

also has 20 years experience in various managerial and financial positions with US Steel and its affiliates. He has a MBA from the Joseph M.

Katz Graduate School of Management and a BS in Accounting from the University of Pittsburgh.

Daniel E. Logsdon Jr., Commissioner (Dem.), since February 2015; current term expires June 2017. Prior to joining the PSC,

Commissioner Logsdon served as chairman and executive director of the Kentucky Democratic Party, a position he assumed in 2010. He has

experience in the telecommunications industry as a state government affairs representative from 2004 to 2009. BA from the Murray State

University.

67

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

1,468,000 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,

2015, OPCo had 1,552 employees. OPCo is a member of PJM.


Primary Metals

Petroleum and Coal Products Manufacturing


Rubber & Plastic Products

Fabricated Metal Products

Nonmetallic Mineral Products


Julie Sloat


Residential 1,280,000

Commercial 175,000

Industrial 10,000

Other 3,000

Total 1,468,000



Overview

Since May 2016

16 years with AEP

68



Moody's S&P

Baa1/P BBB+/P

14,159 14,328 14,261

14,468 14,326 14,102

14,653 14,541 15,916

-

10,000

20,000

30,000

40,000

50,000

60,000

2015 2014 2013

Gig

awat

t-h

ou

rs



43,408 43,326 44,412





2015 2014 2013

(in degree days)


Normal 3,226 3,230 3,229

Cooling Actual 975 949 1,029

Normal 970 960 954


As of 9/30/16



Cash $ 4,000









69

OHIO INVESTOR OWNED UTILITIES* TYPICAL BILL COMPARISON**

MAJOR CUSTOMERS:

Timken Steel Corporation

The Premcor Refining Group Inc.

Republic Steel

Globe Metallurgical, Inc.

Marathon Petroleum Company LP

Linde Gas, LLC

Owens Corning Sales, LLC

Cardinal Gas Services, LLC

Eramet Marietta, Inc.

Markwest Utica EMG, LLC


Top 10 AEP Ohio customers = 31% of industrial sales




** 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, 2016. Ohio rates represent provider

of last resort bundled residential rates.

Customer Statistics

Ohio Customers

AEP Ohio 1,464,068

FE (Ohio Edison) 1,037,216

FE (CEI) 745,640

Duke Energy Ohio Inc 701,129

DP&L 515,822

FE (Toledo Edison) 308,151




Ohio $/month

AEP Ohio (OPCo) 135.97

FE (Toledo Edison) 134.26

AEP Ohio (CSPCo) 131.62

FE (Ohio Edison) 131.15

FE (CEI) 130.60

DP&L 125.69

Duke Energy Ohio Inc 123.79

70



Ohio Public Utilities Commission

Commission Overview


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 basic transmission cost rider.

Commissioners

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


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

Asim Haque, Chairman, (Ind.) since 2013; term expires April 2021. 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.

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.

M. Howard Petricoff, Commissioner, (Dem.), since 2016;term expires April 2020. Prior to joining the commission, was employed at a large

general practice law firm where he directed the firm’s energy and utility practice. Master’s degree in public administration from Harvard

University, a juris doctorate from the University of Cincinnati College of Law, bachelor’s degree in public administration from American

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.

71

Overview

Public Service Company of Oklahoma (PSO) (organized in Oklahoma in 1913) is engaged in the generation, transmission

and distribution of electric power to approximately 545,000 retail customers

in eastern and southwestern Oklahoma, and in supplying and marketing

electric power at wholesale to other electric utility companies, municipalities,

rural electric cooperatives and other market participants. At December 31,

2015, PSO had 1,134 employees. PSO has the highest percentage of

renewables (wind) in the AEP system. PSO is a member of SPP.


Stuart Solomon


Paper Manufacturing

Oil & Gas Extraction

Transportation Equipment

Plastics and Rubber Products

Oil Refining and Steel Processing

Nonmetallic Mineral Product Manufacturing


Residential 468,000

Commercial 63,000

Industrial 6,000

Other 8,000

Total 545,000

Transmission Miles at 12/31/15 3,388

Distribution Miles at 12/31/15 22,260

Since June 2004

27 years with AEP

Capacity Resources at 9/30/2016


Gas PPA Capacity 1,023 MW

Wind PPA Capacity 1,139 MW


• Coal 9.2%

• Natural Gas 72.1%

• Wind 18.7% 72


*Source: 3Q16 Financial Statements (unaudited)

**Source: 2015 10-K Financial Statements

***GWh Sales – Weather Normalized


Capital Structure

2015** 9/30/2016*




FFO Interest Coverage 6.07

4.55^

FFO Total Debt 24.8% 17.2%^


6,143 6,253 6,198

5,146 5,133 5,059

5,410 5,237 5,083

1,242 1,260 1,253

17,941 17,883 17,593

-

5,000

10,000

15,000

20,000

2015 2014 2013

Gig

awat

t-h

ou

rs




2015 2014 2013

(in degree days)


Normal 1,774 1,777 1,763


Normal 2,127 2,130 2,133


As of 9/30/16



Cash $ 2,000


Moody's S&P

A3/S BBB+/P

73

MAJOR CUSTOMERS:

International Paper Company

Kimberly Clark Corp

Goodyear Tire & Rubber Company

HollyFrontier Corporation

American Airlines

Terra Nitrogen

Republic Paperboard


OKLAHOMA INVESTOR OWNED UTILITIES TYPICAL BILL COMPARISON ***

Oklahoma Customers

PSO* 545,000

OG&E** 754,000

Empire District** 5,000





*** 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,

2016.

Oklahoma $/month

PSO 95.12

OG&E 94.55

Empire District 99.26

* Customer count from 2015 10K

* *Customer counts are as of December 31, 2015 and were

sourced from table 10 at

http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

Customer Statistics

74



Commission Overview

Oklahoma Corporation Commission

AEP Regulated Electric Utilities


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.


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. PSO currently has a base rate case pending before the

OCC. 75

Overview

Southwestern Electric Power Company (SWEPCO) (organized in Delaware in 1912) is engaged in the generation, transmission and

distribution of electric power to approximately 531,000 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 participants. At December 31, 2015, SWEPCO

had 1,483 employees. The territory served by 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.



Petroleum & Coal Products Manufacturing

Primary Metals

Food Manufacturing

Paper Manufacturing


Venita McCellon-Allen


Residential 450,000

Commercial 73,000

Industrial 7,000

Other 500

Total 530,500


PPA Capacity 596 MW


• Coal: 45.1%


• Wind: 8.1%



Since July 2010

33 years with AEP

76



**Source: 2015 10-K Financial Statements

***GWh Sales – Weather Normalized









6,234 6,308 6,360

6,032 6,032 5,999

5,370 5,901 5,612

6,252 6,241 6,322

23,888 24,482 24,293

-

5,000

10,000

15,000

20,000

25,000

30,000

2015 2014 2013

Gig

awat

t-h

ou

rs




2015 2014 2013

(in degree days)


Normal 1,204 1,230 1,226


Normal 2,293 2,279 2,275


As of 9/30/16



Cash $ 15,200


Moody's S&P

Baa2/S BBB+/P

77

MAJOR CUSTOMERS:

XTO Energy (TX)

Domtar Corporation (AR)

Calumet Lubricants (LA)

US Steel Tubular Products, Inc. (TX)

Cooper Tire & Rubber Company (AR)

International Paper Company (TX)

Pratt Paper, LLC (LA)

Big Three Industrial Gas (TX)

Pilgrim Pride (TX)

Glad Manufacturing Company (AR)


SOUTHWESTERN INVESTOR

OWNED UTILITIES * TYPICAL BILL COMPARISON **

Arkansas Customers

SWEPCO 116,124

Entergy AR 704,170

OG&E 66,001

Empire District 4,440

Louisiana Customers

SWEPCO 229,975

CLECO 282,874

Entergy 1,256,472

Texas Customers

SWEPCO 183,705

El Paso 307,294

SPSCo 268,165

Entergy TX 432,372





** 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, 2016.

Arkansas $/month Louisiana $/month Texas $/month

OG&E 81.84 Entergy Gulf St 86.26 SWEPCO 83.72

SWEPCO 86.56 SWEPCO 88.45 SPSCo 99.65

Entergy AR 100.34

Entergy New

Orleans 92.05 El Paso 103.02

Empire District 131.46 Entergy LA 93.15

Entergy

Texas 112.29

CLECO 117.25

* Customer counts are as of December 31, 2015 and were sourced from table 10

at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

Customer Statistics

78


Commission Overview

Arkansas Public Service Commission

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.


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.

79

Louisiana Public Service Commission

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.

Vacant


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. The FRP was implemented for SWEPCO on August 1, 2008 with annual true-ups required. The LPSC

recently extended the FRP to cover the 2015 and 2017 test years. SWEPCO currently has its 2015 FRP filing (for test year 2014) pending

before the LPSC.

Commission Overview

80

Public Utility Commission of Texas

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 d irector/liaison to the

Texas House of Representatives. Bachelor’s degree in government from University of Texas and Juris Doctorate from St Mary’s University.


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. SWEPCO-TX implemented a new Distribution Cost Recovery Factor (DCRF) in Texas on July 1,

2016.

Commission Overview

81


(Based on electric meters)

Residential 704,000

Commercial 116,000

Industrial 5,000

Other 1,000

Total 826,000



Overview

AEP Texas Central Company (TCC) (organized in Texas in 1945) is engaged in the transmission and

distribution of electric power to approximately 826,000 retail metered

customers through REPs in southern Texas. The territory served by

TCC also includes several military installations. At December 31,

2015, TCC had 1,108 employees. TCC is a member of ERCOT.


Petroleum & Coal Products Manufacturing



Food Manufacturing


MAJOR CUSTOMERS:

Valero Energy Corporation

Koch Industries

Markwest Energy Partners

Formosa Utility Venture

Equistar Bay City



Metropolitan areas account for 78% ultimate sales




Judith Talavera

Since June 2016

16 years with AEP

82



**Source: 2015 Annual Report

***KWh Sales – Weather Normalized

9,475 9,582 9,092

9,101 9,246 8,782

6,047 5,721 5,419

24,729 24,656

23,396

-

5,000

10,000

15,000

20,000

25,000

30,000

2015 2014 2013

Kilo

wat

t-h

ou

rs

Summary of KWh Energy Sales*** (in millions of KWhs)



2015 2014 2013

(in degree days)

Heating Actual 251 279 193

Normal 173 178 179


Normal 2,859 2,843 2,832



Debt^ Equity Total Debt^ Equity Total



FFO Interest Coverage 3.38 4.36


^^ - calculated on rolling 12-month avg.

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


As of 9/30/16



Cash $ 100


Moody's S&P

Baa1/S BBB+/P

83

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 metered customers through REPs in west and central

Texas. The total output from TNC’s remaining active

generating unit (Oklaunion Plant) is sold to an affiliate at

TNC’s cost pursuant to an agreement effective through

2027. At December 31, 2015, TNC had 356 employees.

The territory served by TNC also includes several military

installations and correctional facilities. TNC is a member of

ERCOT.



Support Activities for Mining


Food Manufacturing

Nonmetallic Mineral Products


Judith Talavera


(Based on electric meters)

Residential 149,000

Commercial 31,000

Industrial 4,000

Other 5,000

Total 189,000

Owned Generating Capacity 355 MW


• Coal: 100%



MAJOR CUSTOMERS:

Chevron Texaco Corporation

Sheridan Production Co.

Kinder Morgan Energy Partners

Tyson Foods



Metropolitan areas account for 51% ultimate sales



Overview

Since June 2016

16 years with AEP

84



**Source: 2015 Annual Report

*** KWh Sales – Weather Normalized


Capital Structure

2015** 9/30/2016*


Capitalization Per Balance Sheet 543,165 400,673 943,838 590,080 414,272 1,004,352



FFO Total Debt 19.2% 19.6%^


1,798 1,813 1,741

1,635 1,668 1,580

1,652 1,569 1,333

471 477 477

5,556 5,527 5,131

-

1,000

2,000

3,000

4,000

5,000

6,000

2015 2014 2013

Kilo

wat

t-h

ou

rs

Summary of KWh Energy Sales*** (in millions of KWhs)



2015 2014 2013

(in degree days)


Normal 1,015 1,035 1,032


Normal 1,644 1,630 1,623


As of 9/30/16



Cash $ -


Moody's S&P

Baa1/S BBB+/P

85

Commission Overview

Public Utility Commission of Texas


TCC and TNC, collectively known as AEP Texas, 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. Distribution rate

riders are in place to recover AMI, wholesale transmission expenses and energy efficiency costs. Interim Transmission Cost of Service

(TCOS) filings can be filed twice a year to recover transmission investment. AEP Texas implemented new Distribution Cost Recovery

Factors (DCRF) in September 2016 to recover distribution investment.

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 d irector/liaison to the

Texas House of Representatives. Bachelor’s degree in government from University of Texas and Juris Doctorate from St Mary’s University.

86

Regulated Generation

• Regulated Generation Summary

• Owned Regulated Generation

• Regulated Fuel Procurement – 2017 Projected

• Regulated 2017 Projected Coal Delivery

• Jurisdictional Fuel Clause Summary

87

Regulated Generation Summary

Net Maximum Capacity

(in MW)

Company Owned

Capacity

Renewable

PPA

Gas

PPA

OVEC

PPA***

Total

Capacity

AEP Generating Company* 1,310 1,310

Appalachian Power Company 6,627 454 344 7,425

Wheeling Power Company 780 780

Kentucky Power Company 1,060 1,060

Indiana Michigan Power Company 3,539 450 172 4,161

Ohio Power Company 210 437 647

Public Service Company of Oklahoma 3,942 1,139 1,023 6,104

Southwestern Electric Power Company 5,214 470 126 5,810

Texas North Company** 355 355

Total Capacity 22,827 2,723 1,149 953 27,652

Energy Efficiency/Demand Response 1,989

Total Capacity & EE/DR 29,641

* AEP Generating Company has PPA with I&M (70%) and KPCo (30%) for its owned Rockport capacity.

** 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 Renewable Resources pages in “Transforming our Generation Fleet” for additional information on Renewable PPAs. 88

Plant Name Units State Year Plant

Commissioned Fuel Type

Owned

Coal / Lignite

Owned

Gas

Owned

Nuclear

Owned

Hydro

Owned

Solar

Owned

Net Maximum

Capacity (MW)

AEP Generating Company

Rockport * 2 IN 1984 Steam - Coal 1,310 1,310


Buck 3 VA 1912 Hydro 9 9

Byllesby 4 VA 1912 Hydro 22 22

Claytor 4 VA 1939 Hydro 76 76

Leesville 2 VA 1964 Hydro 50 50

London 3 WV 1935 Hydro 14 14

Marmet 3 WV 1935 Hydro 14 14

Niagara 2 VA 1906 Hydro 2 2

Winfield 3 WV 1938 Hydro 15 15

Smith Mountain 5 VA 1965 Pumped Storage 586 586

Ceredo 6 WV 2001 Natural Gas 516 516

Clinch River 2 VA 1958/2016 Natural Gas 460 460

Dresden 1 OH 2012 Natural Gas 613 613

Amos 3 WV 1971 Steam - Coal 2,930 2,930

Mountaineer 1 WV 1980 Steam - Coal 1,320 1,320

4,250 1,589 788 6,627

Wheeling Power Company

Mitchell 2 WV 1971 Steam - Coal 780 780

Kentucky Power Company

Big Sandy 1 KY 1963/2016 Natural Gas 280 280

Mitchell 2 WV 1971 Steam - Coal 780 780

780 280 1,060

* PPA with I&M (70%) and KPCO (30%) for capacity and energy entitlements

Owned Regulated Generation

89



Owned

Coal / Lignite

Owned

Gas

Owned

Nuclear

Owned

Hydro

Owned

Solar

Owned

Net Maximum

Capacity (MW)


Berrien Springs 12 MI 1908 Hydro 7 7

Buchanan 10 MI 1919 Hydro 4 4

Constantine 4 MI 1921 Hydro 1 1

Elkhart 3 IN 1913 Hydro 3 3

Mottville 4 MI 1923 Hydro 2 2

Twin Branch 6 IN 1904 Hydro 5 5

Deer Creek 1 IN 2016 Solar 3 3

Olive 1 IN 2016 Solar 5 5

Twin Branch 1 IN 2016 Solar 3 3

Watervliet 1 MI 2016 Solar 5 5

Rockport 2 IN 1984 Steam - Coal 1,310 1,310

Cook 2 MI 1975 Steam - Nuclear 2,191 2,191

1,310 2,191 22 16 3,539


Comanche 1 OK 1973 Steam - Natural Gas 260 260

Northeastern (1&2) 2 OK 1961 Steam - Natural Gas 912 912

Riverside (1&2) 2 OK 1974 Steam - Natural Gas 907 907

Riverside (3&4) 2 OK 2008 Steam - Natural Gas 160 160

Southwestern (1-3) 3 OK 1952 Steam - Natural Gas 465 465

Southwestern (4&5) 2 OK 2008 Steam - Natural Gas 170 170

Tulsa 2 OK 1923 Steam - Natural Gas 319 319

Weleetka 3 OK 1975 Steam - Natural Gas 185 185

Northeastern (3) 1 OK 1979 Steam - Coal 462 462

Oklaunion 1 TX 1986 Steam - Coal 102 102

564 3,378 3,942


90



Owned

Coal /

Lignite

Owned

Gas

Owned

Nuclear

Owned

Hydro

Owned

Solar

Owned

Net Maximum

Capacity (MW)


Stall 1 LA 2010 Natural Gas 534 534

Mattison 4 AR 2007 Natural Gas 291 291

Arsenal Hill 1 LA 1960 Steam - Natural Gas 110 110

Lieberman 3 LA 1947 Steam - Natural Gas 242 242

Knox Lee 4 TX 1950 Steam - Natural Gas 475 475

Wilkes 3 TX 1964 Steam - Natural Gas 893 893

Lone Star 1 TX 1954 Steam - Natural Gas 50 50

Welsh 2 TX 1977 Steam - Coal 1,045 1,045

Flint Creek 1 AR 1978 Steam - Coal 259 259

Turk 1 AR 2012 Steam - Coal 477 477

Pirkey 1 TX 1985 Steam - Lignite 580 580

Dolet Hills 1 LA 1986 Steam - Lignite 258 258

2,619 2,595 5,214

Texas North Company

Oklaunion* 1 TX 1986 Steam - Coal 355 355

Total Owned Regulated Net Maximum Capacity 11,968 7,842 2,191 810 16 22,827

* TNC sells its share of Oklaunion energy to AEP Energy Partners through a PPA


91

Coal – West Regulated

Coal – East Regulated Total Coal - Regulated

Fuel Stats:

- Expected 2017 Consumption: Coal: approx. 29M tons

Natural Gas: approx. 61 BCF

- Coal 83% contracted for 2017 and 48% contracted for 2018

- Avg. 2016 YTD Regulated Delivered Price:

Coal: System - ~$46/ton East - ~$51/ton

West - ~$38/ton

Natural Gas: ~$3/MMBtu

- Projected 2017 Regulated Coal Delivered Price:

System - ~$44/ton East - ~$48/ton

West - ~$36/ton

Regulated Fuel Procurement – 2017 Projected

92

Total AEP Regulated System

* Reflects coal delivered to AEP plants transported through a combination of rail and barge

AEP East AEP West

Regulated 2017 Projected Coal Delivery

93

Arkansas

Indiana

Kentucky

Louisiana

Michigan

Oklahoma

Tennessee

Texas (SPP)

Virginia

West Virginia

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Annually

Biannually

Monthly

Monthly

Annually

Annually

Annually

Triennially*

Annually

Annually

Jurisdiction Active Fuel Clause

Adjustment

Frequency

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

Jurisdictional Fuel Clause Summary

94

Transmission Initiatives

• AEP Transmission Holdco Structure & Business Overview

• AEPTHC Growth Plan Project Summary

• Transco Project Mix & Footprint

• Transmission Investment Needs

• Transco State & FERC Regulatory Compacts

• FERC Formula Rate

• Project Selection Guidelines

• Active Joint Venture Projects

• Competitive Transmission – Transource

• Grid Assurance – Executive Summary

• BOLD™ Strategy

• Transmission Cost Recovery by Operating Companies

95

AEP Transmission Holdco Legal Entity Structure

• AEP Transmission Company, LLC (“AEP Transco”) is wholly-owned by AEP Transmission Holding Company, LLC (“AEP Trans Holdco”)

• AEP Trans Holdco is a wholly-owned subsidiary of American Electric Power Company, Inc. (“AEP”), one of the largest utility holding companies in the U.S.

American Electric Power Company, Inc. (AEP)

AEP Transmission Company, LLC. (“AEP Transco)

AEP Indiana Michigan Transmission Co., Inc.

AEP Kentucky Transmission Co., Inc.

AEP Ohio Transmission Co., Inc.

AEP Oklahoma Transmission Co., Inc.

AEP Transmission Holding Co. LLC. (“AEP Trans Holdco)

AEP Appalachian Transmission Company,

Inc.

AEP Southwestern Transmission Co., Inc.

Pioneer Transmission,

LLC

Electric Transmission America, LLC

Transource Energy, LLC

Electric Transmission

Texas, LLC

Prairie Wind Transmission,

LLC

Transource Missouri, LLC

Fully operational

Regulatory Approval Required

Joint Venture

AEP West Virginia Transmission Co., Inc.

$2,828M Net Plant

$299M Net Plant

Net Plant totals are as of September 30 ,2016, except Pioneer and Prairie Wind, which are as of August 30, 2016.

$151M Net Plant

$66M Net Plant

96

AEP Transco Business Overview

• An unbundled transmission business focused on ensuring grid reliability at the regional and local level; formed in 2009 with seven wholly-owned FERC regulated utilities (“State Transcos”)

• Active transcos located in Indiana and Michigan, Kentucky, Ohio, Oklahoma, and West Virginia

• Regulatory approvals in Arkansas & Louisiana (AEP Southwestern) and Virginia (AEP Appalachian) are required before operation

• A petition for a joint license agreement between AP Transco and APCo has been filed with the Virginia SCC and WVPSC to support AP Transco investment in Tennessee.

• Significant investment opportunities in AEP’s transmission system provides growth opportunities for AEP Transco and provides flexibility to AEP’s integrated utility operating companies to direct capital to their distribution and generation businesses

• Improving grid reliability

• Grid security and technology

• Customer growth

• Investments to support generation

• Upgrading aging system infrastructure

• Favorable regulatory framework including forward-looking formula rates, true-up mechanisms

• Allowed returns on equity (“ROEs”) of 11.49% and 11.2% in PJM and SPP, respectively

• Limited revenue risk and have strong counterparties through their participation in the PJM Interconnection (“PJM”) and Southwest Power Pool (“SPP”) RTOs

• Headquartered in Columbus, OH, AEP Transco is supported by the entire AEP Transmission organization. This organization plans, builds and manages all of AEP’s transmission assets

97


RTO Mandated Projects

Market Efficiency

Generation

States

FERC

NERC

Reliability

RTO Mandated Projects consist of:

• Generation interconnections, including renewables

• Generation retirements

• State & Federal mandates and policies

• NERC planning criteria & standards

• Annual / periodic reliability assessments including deliverability assessments

• Market efficiency & congestion relief

RTO Mandated Projects

98

Externally Driven TO projects:

• Satisfy customer requirements

• Interconnect new generators

• Meet regulatory requirements

• Comply with NERC/industry standards

• Fulfill relocation & contract commitments

Internally Identified TO projects:

• Address safety and ratings risks

• Improve local reliability performance

• Modernize obsolete or degraded facilities

• Monitor and mitigate system/asset risks

• SCADA, PMUs and operator awareness

• Asset health monitoring and analytics

• Data and telecommunications improvements

• Improve grid resiliency and risk mitigation

• Natural events, severe weather, GMD, etc.

• Human threats - physical/cyber, EMP, etc.


Customer

Generators

Regulatory

Standards

Contractual

Safety

Reliability

Modernization

Monitoring

Resilience

External Drivers Internal Drivers

Customer, Local Reliability and Asset Replacement

Transmission Organization (TO) Identified (non-RTO) Projects

99

Transco Project Mix

Transmission has large RTO mandated projects combined with customer, asset replacement and local reliability projects

100

AEP Transco Has a Large, Diverse Footprint The Transcos exist within the expansive service territories of AEP, operating across two RTOs and 10 states.

Transco investment opportunity is directly proportional to AEP's footprint. As the largest owner, operator and developer of

transmission infrastructure in North America, AEP Transco is well positioned for consistent and stable growth.

(1) As of September 30, 2016 101

Transmission Investment Needs Continue Forward

Approximately $25 billion of investment is needed over 10 years simply on a life expectancy basis

AEP Transmission continues to balance asset replacement needs with the need to respond to customer-driven projects, resiliency and regional reliability through the use of technology

Ave Age – 41yrs Life Expectancy – 60 yrs.

102

Transco Regulatory Compacts

• AEP Transco and its seven Transco subsidiaries were formed in 2009 to focus on upgrades to AEP’s transmission system and provide financial flexibility to AEP’s electric utility Operating Companies.

• A summary of regulatory approval status is provided in the table below:

State Transco State Operational and Approval Status

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 $707M. 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 Feb. 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 can seek certification of future projects in its own name but the Virginia SCC will determine whether the project will ultimately be owned by AP Transco or APCo. AP Transco has not yet filed other project applications. A petition for a joint license agreement between AP Transco and APCO has been filed with the Virginia SCC and WVPSC to support AP Transco investment in Tennessee.

KY Transco In Feb 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. An application for regulatory approval for SWTCo is under consideration in Louisiana.

103

State Transcos 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 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:

Company RTO Capital Structure %

Equity Cap Authorized ROE

ATRR

(Effective 07/01/2016)

Rate Base

(Effective

07/01/2016)

AP Transco PJM 50% 11.49% $13 KH $72 KH

IM Transco PJM 50% 11.49% $106.7 MH $757.0 MH

KY Transco PJM 50% 11.49% $6.6 MH $59.0 MH

OH Transco PJM 50% 11.49% $308.1 MH $1,503.9 MH

WV Transco PJM 50% 11.49% $63.6 MH $459.2 MH

OK Transco SPP 50% 11.20% $69.6 MH $433.5 MH

SW Transco SPP 50% 11.20% $78 KH $6 KH

104

FERC Formula Rate

The Transcos benefit from a transparent, partially forward-looking formula rate mechanism, authorized by the FERC, which minimizes regulatory lag:

+

Operating Expenses

Prior Year (Over)/Under

Recovery

+

=

Revenue Requirement

+ Prior year-end plant in-service

+ Current year projected additions to plant in-service

- Accumulated depreciation & amortization

- Deferred income taxes

+ Average working capital

+ Operations and maintenance expense

+ Depreciation & amortization expense

+ Tax expense

Based on prior year-end actual capital structure

11.49% ROE for Transcos in PJM; 11.20% ROE for Transcos in SPP

+ Annual true-up revenue amount to (return)/collect any (over)/under recovery of revenues (See appendix for true-up calculation example)

= Annual Transmission Revenue Requirement (ATRR) for collection during Rate Year (July of current year to June of following year)

x

Rate Base

WACC

105

FERC 206 Filing

206 complaint against AEP east companies filed

AEP plans to file a 205 application for a modified formula rate that seeks to mitigate regulatory lag

Seeking formula rates consistent with other transmission owners in PJM

Transmission investment strategy unchanged

106

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

Greenfield New transmission assets that do not require replacement or modification of existing

facilities or components

Facility Additions New transmission components installed at existing AEP Operating Company-owned

transmission or distribution facilities

Facility

Replacements

Replacement of an entire existing AEP Operating Company-owned facility with a new

AEP Transco-owned facility

Component

Replacements

An apportioned replacement of an existing AEP Operating Company-owned

transmission facility or replacement of component(s) within a transmission facility

Spare/Mobile

Equipment

Purchases of major transmission equipment as capitalized spares or mobiles used to

supply any Transco companies

107

Active Joint Venture Projects

*Base ROE pending settlement

Non active joint ventures and prospects excluded from the financial forecasts

Project Name Location

Projected Completion

Date Owners (ownership %)

Total Estimated Project costs at

completion

Approved Return on Equity

Base RTO Project Risk Total

ETT Texas (ERCOT) Ongoing BHE Texas Transco, LLC (50%), AEP (50%) $3.1 billion 9.96% 0.00% 0.00% 9.96%

Prairie Wind Kansas 2014 Westar Energy(50%), ETA (50%) $158.1 million 10.80% 0.50% 1.50% 12.80%

Pioneer Indiana 2018 Duke Energy (50%), AEP (50%) $386 million 10.54% 0.50% 1.50% 12.54%

Transource-Iatan-Nashua Missouri 2015 AEP (86.5%), Great Plains Energy (13.5%) $64 million 9.80% 0.50% 0.00% 10.30%

Transource-Nebraska-Sibley Missouri 2016 AEP (86.5%), Great Plains Energy (13.5%) $266 million 9.80% 0.50% 1.00% 11.30%

Transource-WV* West Virginia 2019 AEP (86.5%), Great Plains Energy (13.5%) $72 million 10.00% 0.50% 0.00% 10.50%

Transource-PA& MD Pennsylvania & Maryland 2020 AEP (86.5%), Great Plains Energy (13.5%) $225 million TBD TBD TBD TBD

108

Competitive Transmission -

• The Iatan – Nashua 345 kV transmission line was placed in-service on April 8, 2015

• Construction is nearing completion for the Sibley - Nebraska City 345 kV line project and associated Mullin Creek substation with energization expected in December 2016

• In 2015, Transource was designated the Thorofare Area Project in West Virginia, the first competitive project awarded in PJM

• The project is a ~25-mile 138kV line from AEP’s Thorofare Creek Station to FirstEnergy’s Powell-Mountain-Goff Run 138 kV line with expected in-service date of June 2019

• Line routing and environmental studies are underway

• Material procurement expected to begin in 2017

Transource Missouri

Net CWIP/PPE Balance $290 million

YTD After-tax Net Income $10.7 million

Hypothetical Capital Structure

40% debt 60% equity

Authorized ROE1 11.15%

1 Transource Missouri is authorized a 10.3% ROE for the Iatan-Nashua and a 11.3% ROE for Sibley-Nebraska City, resulting in a combined authorized ROE of 11.15% 2 Transource West Virginia’s base ROE of 10.0% is pending FERC approval of a settlement; 0.50% ROE adder for RTO participation is approved

Transource West Virginia

Total Estimated Project Size ~$72 million


40% debt 60% equity

Authorized ROE2 10.5%

Transource Pennsylvania & Maryland

Total Estimated Project Size ~$225 million


TBD

Authorized ROE TBD

• On August 2, 2016, PJM Board approved a Transource project that will improve congestion in the AEP-Dominion interface

• Transource’s PJM-approved project includes the construction of two greenfield 230 kV lines (each in Pennsylvania and Maryland) and two greenfield 500/230 kV substations (both in Pennsylvania)

• The targeted in-service date for this project is June 2020 pending regulatory approval

Transource

Business

Development

Update

• Active participation in PJM’s short-term planning windows

• Long-term market efficiency analysis is expected in Nov 2016 – Feb 2017

• Awaiting results of 2017 ITP 10-year analysis for potential competitive projects in 2018

• Submitted bid for MISO’s 345kV Duff-Coleman transmission line project

• Award of this project expected by year-end 2016

109

Competitive Transmission -

110

FERC Formula Rate Mechanism Example

Grid Assurance - Executive Summary

Company Overview

• Unregulated company that provides three cost-based services • Purchase optimized inventory of transformers and circuit breakers • Store and maintain equipment in a secure warehouse with transferrable warranty • Provide logistics support to assist in equipment movement from warehouse to impacted

location

Schedule

• LLC Agreement executed by 6 companies1 and commenced active marketing – May 6, 2016

• Acceptance Date (Subscriber commitment & company capitalization) – November 6, 2017

• Initial Fee Commencement Date (Inventory in warehouse) – December 1, 2019

Current Status

• Marketing to Potential Subscribers – Met with 19 additional investor-owned utilities to date

• Developing projected subscription levels - 14 companies including founding members

• Developing technical specifications & operational plans

• Initial subscription commitments targeted to be acquired in early November

Company Objective

• Provide the most cost-effective solution to improve the resiliency of the bulk electric transmission system by speeding restoration following a catastrophic event

1- Affiliates of American Electric Power (NYSE:AEP), Berkshire Hathaway Energy, Duke Energy (NYSE:DUK), Edison International (NYSE:EIX), Eversource Energy (NYSE:ES), and Great Plains Energy (NYSE:GXP) 111

BOLD™ Strategy

• Strategic Objectives • Establish BOLD™ as the best-in-class technology solution for high capacity, high efficiency transmission lines • Adapt and refine BOLD™ design options to provide maximum value to customers and improve cost

competitiveness • Grow transmission opportunities by leveraging AEP’s intellectual property and engineering know-how

BOLD™ – “Breakthrough Overhead Line Design” – is a patented compact transmission line design developed by AEP that delivers more capacity and more efficiency in a smaller and more aesthetically pleasing low-profile structure

Voltage Class

Conductor 4-Bundle 3-Bundle 2-Bundle 3-Bundle 2-Bundle Single 2-Bundle Single

Tubular Arch Tower

Lattice Tower

Lower Height + + + + + +

Lower EMF + + + + + + + +

Higher Capacity ++ + +

Lower Line Losses + +

Lower Audible Noise +

200-300 kV 100-200 kV

BOLD Product Options

300-400 kV

112

BOLD™ Strategy

BOLD™ line near Fort Wayne, IN (July 2016)

• Opportunities

• New AEP Projects

• Direct Participation in Off-footprint Projects

• Domestic markets

• Large-scale projects

• Competitive projects

• Suitable partners

• Stable regulatory environments

• Technology Licensing

• International markets

• Small-scale projects

• Rebuilds and non-competitive projects

• “Hands-off” approach

• Sublicense options

• Activity Status • Designs completed for multiple voltage classes, with

electrical testing ongoing

• BOLD™ proposed on four AEP projects

• Commercial efforts leading to detailed discussions with several utilities in the U.S. and internationally

113

Base Rates

Trackers

Evolution of Transmission Trackers in the Operating Companies

2005 2010 2016

PJM Trackers Other Utilities T Recovery

Base Rates

Trackers

SPP Trackers

Base Rates

Trackers

ERCOT Trackers

AEP has made tremendous progress securing trackers for transmission investment over the past decade.

100% 100% 100%

17%

83% 75%

25%

88%

12%

26%

74%

38%

62% 65%

35%

114

Favorable Recovery of Transmission Investment

Projected $812 Million of 2016 PJM and SPP Expenses

will be recovered through Trackers

Projected $304 Million of 2016 PJM and SPP Expenses

must be recovered through either existing or future

Base Rates

Projected $7.4 Billion of 2016 Net Plant in

Service is recoverable through Trackers and

from Wholesale Customers

Projected $1.1 Billion of 2016 Net Plant in

Service is recoverable through Base Rates

Jurisdictional Trackers provide most efficient recovery of Transmission Investment

Jurisdictional Capital Investment Recovery Mechanism Recovery of OATT Expenses

2016 Recoverable Plant in Service ($M)

Projected 2016 OATT Expense ($M) 2016 Capital – Projected Recovery by RTO

115

Contracted Renewables & Other

• Organizational Structure

• Contracted Renewables

• Competitive Generation – Owned & PPA

• Competitive 2015 Fleet Statistics

• Competitive Coal Procurement

• Retail - AEP Energy

116

AEP

AEP Energy Supply


AEP Energy Partners

AEP Energy AEP OnSite

Partners AEP Renewables

Competitive Operations Organizational Structure

Generation Wholesale Trading & Marketing

Oklaunion PPA

Wind Operations

Retail

117

Contracted Renewables

$1B capital allocated 2017-2019

Renewable Generation Asset

Owner

“Behind-the-Meter” Energy Assets

Universal Scale Energy Assets

Key Customers Schools, Cities, Hospitals

and Commercial / Industrial

Accounts

Utilities, Municipalities,

Corporations and

Cooperative Accounts

Key Technologies Solar, energy storage

and combined heat

and power

Wind and Solar

118

Contracted Renewables

2016 Accomplishments

119

Competitive Generation – Owned & PPA

Plant Name State Fuel Type Owned

Coal

Owned

Hydro

Owned

Wind

Owned

Net Maximum

Capacity (MW)

Cardinal 1 OH Steam - Coal 595 595

Conesville 4* OH Steam - Coal 339 339

Conesville 5 & 6 OH Steam - Coal 810 810

Zimmer** OH Steam - Coal 330 330

Stuart 1-4** OH Steam - Coal 603 603

Racine OH Hydro 48 48

Trent Mesa Wind TX Wind 150 150

Desert Sky Wind TX Wind 161 161

Total Owned 2,677 48 311 3,036

PPA Resource State Fuel Type PPA

Coal

PPA

Wind

Total PPA

Capacity (MW)

Oklaunion*** TX Steam - Coal 355 355

Southwest Mesa TX Wind 177 177

Total PPA 355 - 177 532

Coal Hydro Wind Total

Capacity (MW)

Total Owned & PPA 3,032 48 488 3,568

*

**

***

Represents AEP’s capacity portion of jointly owned unit, operated by AEP.

Represents AEP’s capacity portion of jointly owned unit, operated by non-affiliate.

Represents capacity owned by TNC, operated by PSO. Competitive has PPA with TNC.

(excluding Gavin, Waterford, Darby and Lawrenceburg which are pending sale)

120

Plant / Unit Fuel Type Delivery

FGD

Reagent

2015 FOB

Plant $/Ton

2015

$/MMBtu

2015

MWh

Produced

2015

Capacity

Factor

Cardinal 1 NAPP Barge & Truck Limestone 47.57 1.91 3,098,592 59.45%

Conesville 4 NAPP Rail & Truck Limestone 65.22 2.72 1,270,107 42.77%

Conesville 5 & 6 NAPP Rail & Truck Lime 56.54 2.40 2,252,124 31.35%

Zimmer NAPP 30%, ILB 70% Barge Limestone 55.65 2.31 1,483,977 51.33%

Stuart 1-4 NAPP 30%, ILB 70% Barge Limestone 53.05 2.26 2,450,854 46.63%

Oklaunion Powder River Basin Rail Limestone 37.90 2.26 1,212,438 38.99%

Racine Hydro n/a n/a 210,131 49.97%

11,978,223

Plant / Unit

Fuel

Type

2015 FOB Plant

$/Ton

2015

$/MMBtu

2015

MWh

Produced

2015

Capacity Factor

Gavin 1 & 2 Coal 51.88 2.09 14,171,621 60.59%

Lawrenceburg* Gas n/a 3.47 6,775,340 65.21%

Waterford Gas n/a 2.21 6,151,599 83.60%

Darby Gas n/a 3.88 58,085 1.30%

27,156,645

Plants Currently Contracted for Sale

* Owned by AEP Generating Company, which currently has a PPA with AEP Energy Partners

Competitive 2015 Fleet Statistics

121

Coal Statistics:

• Expected 2017 coal burn: 5.9 M tons

• Burn is 100% NAPP

• 100% contracted for 2016, 92% contracted for

2017, and 80% contracted for 2018

• Second Qtr. 2016 delivered price: $52.24/ton

* Data is for the AEP Generation Resources facilities AEP owns and

operates. 2017/2018 data is for AEP Generation Resources, excluding

Gavin which is pending sale. See fleet characteristics footnotes for

ownership and operation of units.

Competitive Coal Procurement

122

Geography of customers* Customer Accounts*

YTD Sept 2016 Delivered Load

* As of September 30, 2016

• 435,000 retail customer accounts*

• YTD served 11.3 TWh of load*

• Seven states, focus on Ohio

C&I 70%

Residential 30%

C&I 10%

Residential 90%

Ohio 72.3%

Illinois 13.5%

Pennsylvania 12.1%

New Jersey 1.1%

Maryland 0.8% Delaware 0.1% Washington

DC 0.1%

Retail – AEP Energy

123

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