Brian X. Tierney, American Electric Power executive vice president and chief financial officer presented to an audience of investors at the Credit Suisse Energy Summit in Vail, Colo., on Feb. 8, 2011. A webcast of the presentation can be accessed through the Internet at http://www.aep.com/investors/webcasts/. During the conference, AEP reaffirmed its 2011 ongoing earnings guidance of $3.00 to $3.20 per share.

1. Credit Suisse 2011
Energy Summit
February 7-8, 2011
1

2. “Safe Harbor” Statement under the Private
Securities Litigation Reform Act of 1995
This presentation contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its
Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause
actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the
forward-looking statements are: the economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic
patterns, inflationary or deflationary interest rate trends, volatility in the financial markets, particularly developments affecting the availability of capital on reasonable
terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates, the availability and cost of funds to
finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material,
electric load, customer growth and the impact of retail competition particularly in Ohio, weather conditions, including storms, 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 I&M’s Donald C.
Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process, our ability to recover regulatory assets and stranded costs in
connection with deregulation, 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, including the Turk Plant, and transmission line 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 energy commodity trading and new of 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 and cost recovery of our plants, 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, natural gas and other energy-related commodities, 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 debt, volatility and changes in markets for
electricity, natural gas, coal, nuclear fuel and other energy-related commodities, changes in utility regulation, including the implementation of ESPs and related
regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP, accounting pronouncements periodically issued
by accounting standard-setting bodies, the impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement
benefit plans and nuclear decommissioning trust and the impact on future funding requirements, 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, other risks and unforeseen events, including
wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events and our ability to recover through rates the remaining
unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
Investor Relations Contacts
Chuck Zebula Bette Jo Rozsa Julie Sherwood Sara Macioch
Treasurer Managing Director Director Analyst
SVP Investor Relations Investor Relations Investor Relations Investor Relations
614-716-2800 614-716-2840 614-716-2663 614-716-2835
cezebula@aep.com bjrozsa@aep.com jasherwood@aep.com semacioch@aep.com
2

3. Brian X. Tierney - EVP and CFO
3

4. American Electric Power
Serving electric customers in
Regulated Electric Utility 11 states
– Regulatory and economic diversity
– Operating Company Model
Focus on Capital Allocation
– Capital for Growth
– Return of Capital to Shareholders
– Pension Funding
Strong Balance Sheet
– Stable credit ratings
– Capital plan supported by cash flow
– Strong liquidity position
AEP Fast Facts
Growth Opportunities
– Capital for utility platform 5.3 million customers
– Transmission projects 39 GW of generation capacity
39,000 miles of transmission lines
Dividend yield over 5% $17.3B Market Capitalization
BBB/Baa2/BBB credit rating
4

5. 2011 Earnings Drivers
$3.50
$3.10
$3.03 0.32
$3.00 0.10
0.06
0.01 0.05
(0.22) (0.08)
$2.50 (0.07) (0.05) (0.05)
$2.00
$1.50
$1.00
$0.50
$0.00
Weather Other Utility Ohio OSS, net of Non-Utility Trans O&M, net of SEET Load Rate 2011E
2010A Costs, net Switching sharing / Parent Operations offsets Recovery Changes,
net of
offsets
$235M in rate changes (69% secured) Continued discipline in O&M
Weather normalized load growth of 1.7% Ohio switching assumptions ($53M – 14% of
CSP total load)
2011 Guidance Range: $3.00 - $3.20/share 5

6. Normalized Load Trends
AEP Residential Normalized GWh Sales AEP Commercial Normalized GWh Sales
%Change vs. Prior Year %Change vs. Prior Year
15% 15%
10% 10%
5% 5%
2.1% 1.3% 2.0%
-0.3% 0.6% 1.9%
0.7%
0% 0%
-1.2% -0.3% -0.4%
-1.6% -1.6%
-5% -5%
1Q10 2Q10 3Q10 4Q10 YTD 10 2011E 1Q10 2Q10 3Q10 4Q10 YTD 10 2011E
AEP Industrial Normalized GWh Sales AEP Total Normalized GWh Sales*
%Change vs. Prior Year %Change vs. Prior Year
15% 15%
10% 9.4% 10%
7.0%
6.0% 5.3%
5% 5% 2.5%
1.9% 1.7%
1.9%
0.8% 1.1%
0% 0%
-1.0% -1.6%
-5% -5%
1Q10 2Q10 3Q10 4Q10 YTD 10 2011E 1Q10 2Q10 3Q10 4Q10 YTD 10 2011E
*includes firm wholesale load
Note: Chart represents connected load
6

7. 2011 Guidance and Business Initiatives
2011 Guidance: $3.00 - $3.20 per share
2011 Earnings Drivers Business Initiatives
Recovering Economy Operating Transcos in OH,
Rate changes (69% secured) OK and MI; filings pending in
other states
Continued O&M discipline -
$34M decrease net of offsets AEP Eastern System
Interconnection Agreement
Customer switching – Ohio
2010 SEET at Columbus Bonus Depreciation
Southern Power Capital Allocation
7

8. AEP Ohio ESP Filing – Core Policy Issues
Investment in Ohio Jobs in Ohio Energy Security
Supports economic Jobs are a key Secure, reliable and
development and component of growth predictable electricity
essential tax base potential in Ohio supply is basis for
sustained investment and
employment in Ohio
Without regulatory assurances
Fundamental barriers must be
over time we could see loss of
addressed to attract Volatility in power prices
direct & indirect jobs related to
investment for Environmental can lead to major loss of
power generation, and
Compliance and New economic activity over time
business relocations to
Generation
surrounding states
Primary objective of ESP: Stabilize rates and support economic development in the state of Ohio
Merged Distribution
Rate Redesign 29-Month ESP Alternative Long Ohio Growth Components
AEP Ohio Period Term Option
Fund Included
Single merged Generation rates ESP period Jan 1, Alternative longer- Creation of Inclusion of certain
AEP Ohio redesigned to 2012 through May term price certainty significant private distribution
company resemble market 31,2014 (May 31 option offered for sector economic components while
presumed with pricing structures date aligns with qualifying development to pursuing a parallel
supporting PJM annual commercial & attract investment distribution base
information on an planning cycle) industrial and job growth in rate case
individual OP/CSP customers AEP Ohio service
basis territory
8

9. Transmission as a Growth Engine
Cumulative Capital Spending,
Electric Transmission Texas (ETT) After Ownership Division ($M) Annual Earnings Potential ($M)
$7,000 $350
– Growing Rate Base High Case
– $1.1B CREZ opportunity; Received $6,000 AEP Transco $300
CCN approval on one CREZ line; 3 PATH + Prairie Wind
$5,000 $250
ETT
more approvals expected in 2011
High Case Earnings
– $1.6B Non-CREZ projects in the $4,000
Base Case Earnings
$200
pipeline $3,000 $150
AEP Transmission Company (AEP
$2,000 $100
Transco)
$1,000 $50
– Settlement filed at FERC for
wholesale rates $0 $0
2010 2011 2012 2013 2014 2015 2016
– $50M spend for 2010; $160M
forecasted for 2011 1 High Case includes: Pioneer (50% ownership), Prairie Wind at 765kV (25% ownership), Tallgrass
at 765kV (25% ownership), ETA-Exelon (25% ownership) and other future opportunities
Progress on Joint Ventures in 2010 2 AEP Transco (100% ownership) includes spending in OH, MI & OK only through 2011 and in
– PATH other jurisdictions for 2012 and beyond
3 PATH (50% ownership) assumes an in-service date of 2015 and Prairie Wind (25% ownership)
– Prairie Wind assumed at 345kV
4 ETT (50% ownership) includes CREZ and additional projects
– Pioneer 5 Projection of earnings potential at the transmission holding company level assuming 50/50
– MEC & RITELine debt/equity capitalization and ROE of 12-13% for FERC projects; 60/40 debt/equity capitalization
and 10.25% ROE (2011 forward) for ERCOT projects; and 50/50 debt/equity capitalization and
ROE of 11.2-11.49% for Transco projects
Transmission investments present significant growth opportunities within and outside of
AEP's traditional service territories 9

10. Earnings and Dividends
On-Going EPS History Since 2004 Dividend History Since 2004
$/share $/share
3.60 2.00
3.40 % %
4.1 4.0
$1.84
R = $3.24 1.80 =
3.20
C AG $3.10
GR$1.64
$1.71
$3.00 $2.97
$3.03
C A $1.64
3.00 1.60 $1.58
$2.77 $1.50
2.80 $2.73
$1.40 $1.42
2.60 1.40
$2.33
2.40
1.20
2.20
2.00 1.00
2011E
2011E
2004
2005
2006
2007
2008
2009
2010
2004
2005
2006
2007
2008
2009
2010
= subject to Board of Directors approval
Earnings growth largely attributed to
capital investment program
Pre-recession earnings supported by Dividend increased 12% in 2010
robust wholesale market activity and 403rd consecutive quarterly dividend
high power prices declared in January 2011
Equity offering in 2009 stabilized 50-60% payout ratio target
credit and strengthened balance sheet Current yield over 5%
2011 guidance range of $3.00 to
$3.20 per share 10

11. Long-term EPS Growth Rate
4-6% EPS growth 2012-14
– Average annual capital spend
between $2.9-3.4B Average Annual EPS Growth
– Utility platform replacement capital defined over two periods
of about $1.4B (annual
depreciation)
– Growth in rate base of $1.5-2.0B Period of 4-6% average
per year, allocated between utility annual growth
platform and transmission projects
3.25
– Blended ROE of 10.5 - 11% 3.03 3.10
Period of 5-7% average annual
– Slow, steady recovery in economy growth
5-7% EPS growth post 2014
– Base utility platform capital including
generation transformation
– Higher allocation of discretionary
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
capital going to opportunities in the
transmission development pipeline
– Higher overall blended ROE
opportunity
– Robust economic growth
11

12. AEP Highlights
Premier Utility Platform
Traditional and Effective
Regulatory Relationships
Energy Policy Initiatives Create
Technology Deployment and
Investment Opportunity
Strong Value and Total Return
Proposition Mountaineer Plant (WV)
12

13. Appendix
13

14. Highly Diversified Regulated Utility Platform
2010 On-Going Earnings
2010 Retail Load
Contribution
Public
Service of Kentucky
Southwestern Oklahoma Power
3% Wholesale * 10%
Electric 6%
Power
11% Residential
Ohio
Power 30%
24%
Texas Industrial
8% 33%
All Others Columbus
5% Southern
Power
Indiana & 17%
Michigan
10% Appalachian Commercial
Power 27%
16%
* Wholesale includes sales to municipal and cooperative
power systems, other wholesale, and other retail sales
Region # of customers
Appalachian Power (incl. TN) 1,004,000
Indiana & Michigan 582,000
Kentucky Power 174,000
Ohio & Wheeling 1,497,000
PSO (Oklahoma) 532,000
SWEPCO (AR, LA, TX) 520,000
Texas 961,000
14

15. Detailed Ongoing Earnings Guidance
2010A: $3.03 2011E: $3.00 - $3.20
American Electric Power
Financial Results for 2011 Guidance vs 2010 Actual
2010 2011
Actual Guidance
Performance Driver ($ millions) Performance Driver ($ millions)
UTILITY OPERATIONS:
Gross Margin:
1 East Regulated Integrated Utilities 68,761 GWh @ $ 41.9 /MWhr = 2,882 67,739 GWh @ $ 43.4 /MWhr = 2,940
2 Ohio Companies 49,465 GWh @ $ 56.6 /MWhr = 2,800 49,747 GWh @ $ 56.1 /MWhr = 2,793
3 West Regulated Integrated Utilities 42,131 GWh @ $ 31.4 /MWhr = 1,322 41,536 GWh @ $ 32.8 /MWhr = 1,361
4 Texas Wires 27,348 GWh @ $ 22.3 /MWhr = 611 27,870 GWh @ $ 22.0 /MWhr = 614
5 Off-System Sales 19,172 GWh @ $ 15.6 /MWhr = 299 21,786 GWh @ $ 12.0 /MWhr = 262
6 Transmission Revenue - 3rd Party 369 429
7 Other Operating Revenue 511 481
8 Utility Gross Margin 8,794 8,880
9 Operations & Maintenance (3,427) (3,529)
10 Depreciation & Amortization (1,598) (1,553)
11 Taxes Other than Income Taxes (801) (818)
12 Interest Exp & Preferred Dividend (945) (921)
13 Other Income & Deductions 154 211
14 Income Taxes (758) (787)
15 Utility Operations On-Going Earnings 1,419 1,483
16 Transmission Operations On-Going Earnings 10 17
NON-UTILITY OPERATIONS:
17 AEP River Operations 40 51
18 Generation & Marketing 25 6
19 Parent & Other On-Going Earnings (43) (61)
20 ON-GOING EARNINGS 1,451 1,496 15

16. Capital Expenditures
$3,000
$2,900
$2,615 AEP Transco
$2,487 $350
$2,500 $160 JV Equity
$1 $47
$113 $280 Contributions, net
$77 $2,243
$34
AEP River Ops &
$50 $223 Other Non-Utility
$457 $24 $56
Environm ental
$2,000
$303 $319
$256 New Generation
$ in millions
$62
$263
$82 $133
Corporate/Other
$1,500 $130 $93
$108
Nuclear
Generation
$776
$2,270
$729 Distribution
$1,000
$808
Transm ission
Fossil & Hydro
$331 $434
$500 Generation
$272
$377 $361
$266
$0
2009A 2010A 2011E 2012E
Investment levels greater than depreciation of $1.4B per year cause rate base growth in 2011
and 2012 16

17. Capitalization & Liquidity
70% Total Debt/Capitalization Current Liquidity Summary
65% Liquidity Summary Actual
62.5% (unadited) 12/31/10
60.7% ($ in millions) Amount Maturity
59.1% 59.1% Revolving Credit Facility $1,500 Jun-13
60%
Revolving Credit Facility 1,454 Apr-12
57.2% 57.2% 57.0% 1 Revolving Credit Facility 478 Apr-11
Total Credit Facilities 3,432
55%
Plus
Cash & Cash Equivalents 294
50%
Less
Commercial Paper Outstanding (650)
45%
Letters of Credit Issued (124)
Letters of Credit Issued for VRDNs (477)
Net Available Liquidity $2,475
40%
A
A
A
A
A
A
A
04
05
06
07
08
09
10
20
20
20
20
20
20
20
Note: Total Debt is calculated according to GAAP and includes securitized debt
: Effective January 1, 2010 in accordance with Transfers and Servicing accounting
1
guidance (formerly SFAS 166), factored receivables of AEP Credit of $750 million are
classified as short-term debt; The 4Q2010 debt/capitalization ratio would be 56.1%,
excluding AEP Credit. 17

18. Cash Flow Guidance
$ in millions
2010A 2011E
Cash From Operations
Income from Continuing Operations $ 1,218 $ 1,499
Depreciation & Amortization 1,641 1,611
Pension Funding (500) (150)
Other Cash Flow Items 659 834
Ligigation Resolution 1 - (449)
Working Capital 2 279 7
Cash From Operations $ 3,297 $ 3,352
Investing Activities
Construction Expenditures (2,318) (2,644)
Other Investing Activity (184) (205)
Total Investing Activities $ (2,502) $ (2,849)
Financing Activities
Dividends (824) (892)
1
Net Debt Issued/(Retired) (160) 234
Common Equity 93 150
Other Financing Activities (100) (72)
Total from Financing Activities $ (991) $ (580)
Beginning Cash Balance $ 490 $ 294
Ending Cash Balance $ 294 $ 217
1
Refer to September 30, 2010 10Q Enron Bankruptcy pages 56-57 for futher discussion
2
Pro forma to exclude effects of consolidation of AEP Credit ($656M) in 2010
18

19. Rate Changes
$700
Pending/Future
$600
Settlement on file
pending approval
$500 Secured
$ in millions
$400
$659
$300
$527 $235
$450 $28
$200 $45
$352 $329
$100
$162
$0
2006A 2007A 2008A 2009A 2010E 2011E
Note: Rate changes in this chart exclude revenues with offsetting costs
Active or pending rate cases include West Virginia and others yet to be
filed
19

20. Approved Rate Bases & ROEs
Jurisdiction Rate Base Approved ROE Approved Debt/Equity Effective
Date
APCo-Virginia * 10.53% 58/42 8/1/2010
$2,060MM
APCo-West Virginia $1,656MM 10.50% 57/43 7/28/2006
KPCo-Kentucky $995MM 10.50% 57/43*** 6/30/2010
I&M-Indiana $2,000MM 10.50% 44/56 3/4/2009
I&M-Michigan $595MM 10.35% 50/50 10/14/2010
PSO-Oklahoma $1,706MM 10.15% 54/46 1/5/2011
SWEPCo-Louisiana $649MM ** 50/50 8/1/2010
10.57%
SWEPCo-Arkansas $612MM 10.25% 54/46 11/25/2009
SWEPCo-Texas $665MM 10.33% 49/51 4/15/2010
TCC-Texas $1,566MM 9.96% 60/40 10/17/2007
TNC-Texas $530MM 9.96% 60/40 6/1/2007
* represents Generation and Distribution rate base only.
** represents the midpoint of the ROE range approved in the formula rate case settled in April 2008.
***represents a negotiated settlement
20