UBS Utilities and Natural Gas Conference Boston, MA

March 5, 2014

“Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995

Investor

Relations

Contacts

Bette Jo Rozsa Managing Director

614-716-2840 bjrozsa@aep.com

Julie Sherwood Director

614-716-2663 jasherwood@aep.com

2

This presentation contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its

Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual

outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-

looking statements are: the economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory, inflationary

or deflationary interest rate trends, volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments

impairing our ability to finance new capital projects and refinance existing debt at attractive rates, the availability and cost of funds to finance working capital and capital

needs, particularly during periods when th time lag between incurring costs and recovery is long and the costs are material, electric load, customer growth and the impact

of retail competition, particularly in Ohio, weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through

applicable rate mechanisms, available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters,

availability of necessary generating capacity and the performance of our generating plants, our ability to recover increases in fuel and other energy costs through

regulated or competitive electric rates, our ability to build or acquire generating capacity, and transmission lines and facilities (including our ability to obtain any necessary

regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through

applicable rate cases or competitive rates, new legislation, litigation and government regulation including oversight of nuclear generation, energy commodity trading and

new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly

ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets, evolving

public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel, a reduction in the federal statutory tax

rate could result in an accelerated return of deferred federal income taxes to customers, timing and resolution of pending and future rate cases, negotiations and other

regulatory decisions including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance, resolution of

litigation, our ability to constrain operation and maintenance costs, our ability to develop and execute a strategy based on a view regarding prices of electricity and other

energy-related commodities, prices and demand for power that we generate and sell at wholesale, changes in technology, particularly with respect to new, developing or

alternative sources of generation, our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired

before the end of their previously projected useful lives, volatility and changes in markets for capacity and electricity, coal, and other energy-related commodities,

particularly changes in the price of natural gas, changes in utility regulation and the allocation of costs within regional transmission organizations, including PJM and SPP,

the transition to market generation in Ohio, including the implementation of ESPs, our ability to successfully and profitably manage our Ohio generation assets in a start-

up, nonregulated, merchant business, changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the

energy trading market, actions of rating agencies, including changes in the ratings of our debt, the impact of volatility in the capital markets on the value of the

investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact 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.

Table of Contents

3

Capital Spending/Rate Base Growth p 4 Dividends, Financing Plan and Earnings Guidance p 8 Rate Cases and Earned ROEs p 13 AEP Transmission Holding Co p 15 Competitive Business p 19

2014-2016 Capital Spending Forecast

4

Transmission: $2,118 19%

Corporate: $277 2%

Distribution: $3,312 29%

Regulated Fossil/ Hydro Generation:

$699 6%

Nuclear Generation: $685

6%

Regulated Environmental

Generation: $1,402 12%

Competitive Operations: $545

5%

Transcos: $1,960 17%

Transmission Joint Ventures: $462

4% Capital & Equity Contributions

$ in millions, excluding AFUDC

$3.8B/year

Regulated Generation Investment - $2.8B

Regulated Distribution

Investment - $3.3B

Regulated Transmission

Investment - $4.5B

95% of capital allocated to regulated businesses

Regulated Rate Base Growth

5

2012 Net Regulated Plant = $33.2B

Cumulative change from 2012 base

VERTICALLY INTEGRATED

UTILITIES

WIRES COMPANIES

TRANSCOS/TRANSOURCE

7.1% CAGR in Net Regulated Plant

Forecasted Growth in Operating Earnings Per Share

6

$3.8B capital investment per year

2014-2016; priority allocation to

transmission opportunities

Sustainable cost savings and O&M discipline support earnings growth

Rate Base Growth + Operating Discipline = 4-6% Forecasted Earnings Growth

Forecasted Sustainable Pre-tax Earnings Improvements by 2016

7

Generation (including nuclear) (largely related to competitive generation)

$70-100M

Transmission

$10-25M

Distribution

$20-40M

Corporate

$10-25M

Supply Chain/Procurement

$10-15M

Utilize transition period to execute continuous improvement plan

Dividend

8

Targeted payout ratio of 60-70% of

consolidated earnings

Declared 415 consecutive quarters

Supported by earnings from regulated

operations

* Su

bje

ct t

o a

pp

rova

l by

Bo

ard

of

Dir

ecto

rs

9

2014-2016 Financing Plan & Credit Metrics

Bonus Depreciation

$459M

Securitization

$394M*

DRP $300M

3-year total =

$1,153M

Anticipated Cash Flows Cover Planned Capital Investment

While Maintaining Solid Credit Metrics:

$ in millions 2014E 2015E 2016E

Cash from Operations - (adjusted for items listed below) 4,098 4,471 4,599

Impact of Bonus Depreciation 459 - -

Federal Cash Taxes Paid

(396)

(698)

(830)

Cash from Securitization* 244 150 -

Capital & Equity Contributions (3,800) (3,800)

(3,800)

Other Investing Activities

(267)

(273)

(179)

Common Dividends @ $2.00/share - 2014 - 2016**

(979)

(983)

(988)

Excess (Required) Capital

(641)

(1,133)

(1,198)

Financing ($ in millions) 2014E 2015E 2016E

Excess (Required) Capital

(641)

(1,133)

(1,198)

Debt Maturities (Senior Notes, PCRBs) (1,090) (1,323) (715)

Securitization Amortizations (316) (371) (380)

Interim Credit Facility*** - (1,000) -

Equity Issuances (DRP/401K) 100 100 100

Debt Capital Market Needs (New)

(1,947)

(3,727)

(2,193)

Financial Metrics

Debt to Capitalization Target Mid 50s

FFO/Total Debt Target**** Mid -to- Upper teens

*Comprised of the following securitizations: $394MM OH deferred fuel (subject to regulatory approval) **Assumes current quarterly dividend of $0.50 per share; dividend evaluated by board of directors each quarter; stated target payout ratio range is 60-70% ***Interim credit facility matures May 2015; all or a portion of the facility may be repaid prior to maturity date ****Excludes securitization debt

10 2014 Operating Earnings Guidance Range of $3.20 - $3.40/sh

2014 Operating Earnings Guidance

Drivers Rate Changes $0.21 OSS 0.05 Depreciation (0.04) O&M (0.02) Weather (0.01) Other (0.01)

$0.18

$0.04 ($0.21)

($0.07)

$0.13 $0.00

Drivers Trans. Rev $0.03 Rate Changes 0.02 O&M (0.04) Normal Load (0.01)

Drivers Transcos $0.09 JVs 0.04

Driver Int Income ($0.07)

Drivers Gen Resources ($0.19) Other (0.02)

11

2014 Key Guidance Assumptions & Sensitivities

Sensitivities

Sensitivity EPS

Retail Sales 0.5% +/- 0.04

Wholesale Market Prices - Regulated $1 MWh +/- 0.01

Wholesale Market Prices - Competitive $1 MWh +/- 0.02

O&M Expense (excludes O&M with offsets)

1.0% +/- 0.04

2014 Effective Income Tax rate @ 35.5%

1.0% +/- 0.05

Note: A $7.5M change in pre-tax earnings equals $0.01/share.

Assumptions

Rate Changes: $175M

2014 Regulated Connected Load: Residential: 58,023 GWh Commercial: 49,335 GWh Industrial: 55,631 GWh Regulated OSS: 22,108 GWh

AEP Ohio Customer Switching 71% by year-end 2014

Regulated OSS Gross Margins (after sharing): $150M

Transmission Operations: $141M

O&M, net of earnings offsets and excluding River Operations: $2.8B

AD Hub ATC Price: $33.24

Henry Hub NG Price: $3.83

No. of Shares O/S: 487M

1.5%

-0.8% -1.6% -1.1% 0.7%

-0.5% -0.6% 0.1%

-10%

-5%

0%

5%

2011A 2012A 2013A 2014E

4.1%

-0.9%

-4.5%

-2.2%

2.0% 0.0%

-1.6%

1.2%

-10%

-5%

0%

5%

2011A 2012A 2013A 2014E

0.4%

-1.6%

0.0%

-0.9%

-10%

-5%

0%

5%

2011A 2012A 2013A 2014E

-0.3%

0.3%

-0.1% -0.2%

-10%

-5%

0%

5%

2011A 2012A 2013A 2014E

AEP Residential Normalized GWh Sales % Change vs. Prior Year

AEP Commercial Normalized GWh Sales % Change vs. Prior Year

AEP Industrial GWh Sales % Change vs. Prior Year

AEP Total Normalized GWh Sales % Change vs. Prior Year

Note: Charts reflect connected load and exclude firm wholesale load & Buckeye Power backup load

Normalized Retail Load Trends – AEP System

12

Note: Line represents Industrial excluding Ormet Note: Line represents Retail excluding Ormet

2014 Announced Rate Cases

13

West Virginia Base rate case due to be filed no later than June 30, 2014 Rates can be implemented nine

months after filing of case

Oklahoma Base rate case filed Jan. 17, 2014 $45M increase requested; 10.50% ROE PSO is willing to request a delay in

implementing new rates until after October

Virginia Biennial review due to be filed no later than March 31, 2014 Two-year test period ended December 31, 2013 Rates effective February 2015

Kentucky Base rate case due to be filed no later than December 2014 Rates can be implemented subject to refund six

months after filing of case

Pro-forma Earned ROEs – 12 Months Ended 12/31/2013

14 Regulated Operations ROE of 9.9% for 12 months ended Dec. 31, 2013

9.5%

13.5%

7.4%

10.7%

7.4%

9.3%8.6%

11.3%

AEPTransHoldco

AEPTexasSWEPCOPSOI&MKPCoAPCo

OhioPower

15

$921 Net Plant* ($ in millions)

$331 Net Plant* ($ in millions)

$274 Net Plant* ($ in millions)

* As of 12/31/2013

$2,194 Net Plant*

($ in millions)

$23 Equity Investment in PWT*

($ in millions)

$77 Net Plant* ($ in millions)

$6 Net Plant*

($ in millions)

AEP Transmission Holdco Organizational Structure

Note: Private placement financing has occurred at

Electric Transmission Texas, LLC and AEP

Transmission Company, LLC

15

$0.36

$0.43

$0.56

$0.65

$0.29

$0.16

$0.80

$0.39

$0.67

$0.51

$0.30

AEP Transmission Holdco

16

4 types of projects: Regional projects for retirements,

renewables, economic and market efficiencies

Local reliability plans Aging infrastructure Customer-driven projects

Cumulative Base Case Capital Investment

High Case Incremental Capital Investment

EPS High Case Contribution

$/share

EPS Base Case Contribution

$/share

Non-firm joint venture projects not included; high case investment is strictly related to the Transcos (no assumption for securing

competitive opportunities); no projects included above subject to loss due to FERC Order 1000 right of first refusal

17

Transmission Projects/Pipeline -PJM

Regional Projects Asset Description Transco In-Service Date

Vassell 345/138 kV New Station/Lines OH May-14

Muskingum River - Sporn 345 kV OH Jun-15

Kammer 345/138 kV Rebuild/Expansion WV Dec-15

Biers Run 345/138 kV New Station/Lines OH Jun-16

Baker 765/345 kV Expansion KY Jun-16

Sorenson 765/345 kV New Station/Lines IN Jun-16

Southern Indiana Improvements IN Jun-16

Kanawha Valley Area Reinforcement Project WV Oct-16

Allen 345/138 kV Expansion/Lines IN/OH Jun-17

Local Reliability Projects Asset Description Transco In-Service Date

Northern Fort Wayne 138 kV Improvements IN Jun-15

McClung Area Improvement Project WV Jun-17

Corey - Pokagon 138 kV Conversion/Rebuild MI Jun-17

Marietta Area 69 kV Upgrade (Phase 1 of 3) OH Jun-18

Customer Projects

Asset Description Transco In-Service Date

Amlin 138 kV Station OH Jun-14

City of Wapakoneta OH Jun-14

Jug St. - Kirk 345/138 kV Rebuild OH Dec-14

Ball State Service Upgrades IN Jun-15

Shale Energy Customer Projects (Various) OH/WV Dec-15

Aging Infrastructure

Asset Description Transco In-Service Date

Rebuild, replace over 500 miles of 138 kV, and below, transmission lines MULTI Dec-2018

Replace obsolete reactors on 8 765 kV transmission lines MULTI Dec-2018

Replace/upgrade key 345/138 kV transformers and increase spare complement MULTI Dec-2018

Replace/upgrade obsolete circuit breakers, switches and protection & control at 5 765 kV

stations MULTI Dec-2018

Add monitoring and communications to support development of the Asset Health

Center MULTI Dec-2018

Replace/upgrade obsolete circuit breakers, switches and protection & control at key 345

kV stations MULTI Dec-2018

Project pipeline excludes investment related to future potential approval of VA Transco

18

Transmission Projects/Pipeline – SPP & ETT

Regional Projects Asset Description Transco/JV In-Service Date

Lobo to North Edinburg 345 kV ETT Jun-2016

North Edinburg to Loma Alta 345 kV (50%) ETT Jun-2016

Lobo to Molina 138 kV ETT May-2015

Chisholm to Gracemont 345 kV OK Mar-2018

Valliant to NW Texarkana 345 kV MULTI Jun-2015

Bluebell to Pratville 138 kV OK Jun-2015

Total Regional Projects In-Service MULTI Multiple Projects

Local Reliability Projects Asset Description Transco/JV In-Service Date

Barney Davis to Naval Base 138 kV ETT Dec-2015

Cornville to Lindsay 69 to 138 kV Conv. OK Dec-2014

Total Local Reliability In-Service MULTI Multiple Projects

Customer Projects Asset Description Transco/JV In-Service Date

Jim Treece 345 kV Station ETT May-2014

Benteler Steel OK Jun-2014

Grady POD/Phase One-Customer Shale OK Dec-2014

Grady POD/Phase TWO-Customer Shale OK Dec-2015

Wapanucka - Looped Feed OK Dec-2014

Foraker POD OK Dec-2014

Assets In-Service Below $3,000,000 MULTI 2013-2014

Total Customer Projects In-Service MULTI Multiple Projects

Project pipeline excludes investment related to future potential approval of SW Transco

Competitive Business Organizational Structure

19

AEP Co, Inc.

AEP Energy Supply

AEP Generation Resources (AGR)

PJM Generation

AEP Energy Partners AEP Energy Retail

AEP Resources

AEP River Operations

AEP Energy Supply integrates the competitive generation, wholesale and retail businesses

Wholesale, Trading & Marketing

AEP Energy Supply Timeline

20 Fleet is well-positioned from a cost and operational perspective to participate in the competitive market

2016 Fully

Competitive

Operations

2013

Corporate Separation completed December 31, 2013

2014

February – AEP Ohio load auction: 10%

March – WV filing to address Wheeling Power capacity/energy needs

May – RPM 2017/18 Auction

May – AEP Ohio load auction: 25%

September – AEP Ohio load auction: 25%

November – AEP Ohio load auction: 40%

2015

May 31 - ESP II transition ends

June - Retire 2,523MW

Obtain permanent financing

“Rationalize” Capacity

Optimize Revenues/Reduce Costs

AEP Generation Resources: PJM Fleet Profile

21

Coal, Controlled

70.2%

Gas, CC 23.4%

Gas, CT 5.8%

Hydro 0.6%

Fuel Profile

AGR has the competitive advantage of fuel and operational diversity

Fixed Resource Requirement RPM

Transfer Retire Retain

AEP Generation Resources: Expected Generation

22 Fleet is well-positioned from a cost and operational perspective to participate in the competitive market

Generation from fleet expected to be in the range of

38-42 million MWh

Cardinal

Stuart* Gavin

Zimmer*

Mitchell Waterford Lawrenceburg

Conesville

Darby

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

$20

$30

$40

$50

Installed Capacity (MW)

$ p

er

MW

h, D

isp

atch

Co

st

2016 Dispatch Stack

Note: post-retirement view of generation stack; includes estimated fuel, emissions and consumables costs * Non-AEP operated JV plants reflect AEP estimate of fuel and other variable costs

Peak

ATC

Off Peak

Energy Sales Opportunities

23

2014 Energy Sales Opportunity

Short Term 15 - 20%

Financial Instruments

15 - 30%

Wholesale Customers (Muni, Co-op, Utility Auction)

Unswitched AEP Ohio Retail Customers

25 - 35%

Competitive Retail Customers

25 - 30%

AEP Energy (Retail) Profile

Currently serving 215,000 customers Served 9.9 TWh of load in 2013 Provide hedging opportunities for AGR Customer growth in western PJM

80% of expected Gross Margin in 2014 is secured by Ohio Electric Security Plan and energy hedges; AEP Energy will complement the sales opportunity for the competitive generation fleet

PA 4%

NJ 4%

IL 22%

OH 69%

MD 1%

YTD December 2013 Delivered Load

C&I, 83%

Residential, 17%

AEP Energy Supply: Earnings & Cost Management

24

Estimated ($ in millions) 2014 2015 Range 2016 Range

Energy/Capacity Gross Margin $1,100 $825 - $925 $600 -$725

Costs 425 390 355

EBITDA $675 $435 - $535 $245 - $370

Capital Expenditures 180 145 180

Net Cash Flow* $495 $290 - $390 $65 -$190

* Excludes income taxes, interest and changes in working capital

$430 $385 $350

$60 $40 $5

2011 - 2013Average

2014 2016

Cost Trend ($ in millions)

Ongoing Disposition Units

$490 $425

$355