49 th EEI Financial Conference Handout Dallas, Texas November 11-14, 2014

Transcription

1 49 th EEI Financial Conference Handout Dallas, Texas November 11-14, 2014

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 Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: the economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory, inflationary or deflationary interest rate trends, volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates, the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material, electric load, customer growth and the impact of retail competition, weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs, available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters, availability of necessary generation capacity and the performance of our generation plants, our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates, our ability to build or acquire generation 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, new legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets, evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel, a reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers, timing and resolution of pending and future rate cases, negotiations and other regulatory decisions including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance, resolution of litigation, our ability to constrain operation and maintenance costs, our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities, prices and demand for power that we generate and sell at wholesale, changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation, our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives, volatility and changes in markets for capacity and electricity, coal, and other energy-related commodities, particularly changes in the price of natural gas, changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP, the transition to market for generation in Ohio, including the implementation of ESPs, our ability to successfully and profitably manage our separate competitive generation assets, changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market, actions of rating agencies, including changes in the ratings of our debt, the impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements, accounting pronouncements periodically issued by accounting standard-setting bodies and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events. Investor Relations Contacts Bette Jo Rozsa Managing Director Investor Relations bjrozsa@aep.com Ryan Mills Analyst Investor Relations rtmills@aep.com

3 American Electric Power Company Overview $58B TOTAL ASSETS 5.3M CUSTOMERS IN 11 STATES $28B CURRENT MARKET CAPITALIZATION 38GW OWNED GENERATION 40,000+ LINE MILES OF TRANSMISSION Note: Statistics as of September 30, 2014, except market capitalization which is as of November 7,

4 AEP: The Next Premium Regulated Company 4

5 Steady as She Goes, Executing on Plan through Rough or Calm Waters Consistent Growth in Shareholder Value Quality of Investments Agility to React to Headwinds Balance Sheet Strength Long History of Dividend Growth AEP has performed by credibly managing headwinds and tailwinds 5

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7 Forecasted 4-6% EPS Growth Rate Reaffirmed 4% - 6% EPS growth is off of 2014 original guidance range Earnings growth achieved through capital investment and rate recovery, identified sustainable cost savings and O&M spending discipline EPS Growth + Dividend Yield = 8% - 10% Annual Return Opportunity 7

8 Capital Spending Forecast Capital & Equity Contributions $ in millions, excluding AFUDC 2015: $4.4B; 2016: $3.8B 2017: $3.9B Regulated Generation Investment - $2.7B Regulated Distribution Investment - $3.6B Regulated Transmission Investment - $4.8B Competitive Operations $502 4% Capital & Equity Contributions $12B , excluding AFUDC AEP Transmission Holdco: $2,920 24% Regulated Environmental Generation $1,315 11% Nuclear Generation: $641, 5% Regulated Fossil/Hydro Generation $761 6% Transmission: $1,922 16% Distribution: $3,604 30% Corporate $502 4% 96% of capital allocated to regulated businesses; 70% allocated to wires 8

9 Regulated Rate Base Growth Cumulative change from 2012 base TRANSCOS/TRANSOURCE WIRES COMPANIES VERTICALLY INTEGRATED UTILITIES 2012 Net Regulated Plant = $33.2B $2.8 $3.4 $4.2 $1.1 $ % CAGR in Net Regulated Plant 9

10 Pro-forma 2015 Regulated ROE s Expected Earned ROE s (Operating Earnings*) * operating adjusts GAAP results by eliminating any material non operating items and is not weather normalized 10

11 * Subject to approval by Board of Directors Dividend Targeted payout ratio of 60-70% of operating earnings Supported by earnings from regulated operations Declared 418 consecutive quarters 11

12 O&M Projections $3.4 $3.2 $3.0 $2.8 $2.6 $2.4 $2.2 $2.0 $1.8 $1.6 $1.4 $1.2 $1.0 $0.8 $0.6 $0.4 $0.2 Total Annual O&M (excluding River Operations and items recovered in riders/trackers) $ in billions $ A 2012A 2013A 2014E 2015E 2016E Continue O&M cost discipline through LEAN initiatives while reinvesting as needed to support our operations, customers and employees 12

13 Forecasted Sustainable Pre-tax Earnings Improvements by 2016 Generation (including nuclear) (largely related to competitive generation) $70-100M Transmission $10-25M Distribution $20-40M Corporate $10-25M Supply Chain/Procurement $10-15M Managing transition period by executing on continuous improvement plan 13

14 Financing Plan & Credit Metrics $ in millions 2014E 2015E 2016E 2017E Cash from Operations - Excl. Impact of Bonus Depreciation & FIT Payments 3,900 4,500 4,900 4,900 Impact of Bonus Depreciation 700 (300) - - Federal Cash Taxes Refunded (Paid) (100) (500) (800) (800) Cash from Securitization * Capital & JV Equity Contributions (4,200) (4,400) (3,800) (3,900) Other Investing Activities (400) (200) (200) (200) Common $2.03/share 2014; $2.12/share ** (1,000) (1,000) (1,000) (1,000) Excess (Required) Capital (1,100) (1,900) (600) (1,000) Financing ($ in millions) 2014E 2015E 2016E 2017E Excess (Required) Capital (1,100) (1,900) (600) (1,000) Debt Maturities (Senior Notes, PCRBs) (1,500) (1,700) (1,200) (1,800) Securitzation Amortizations (300) (300) (300) (300) AGR Credit Facility *** Equity Issuances (DRP/401K) Debt Capital Market Needs (New) (2,800) (3,300) (2,000) (3,000) Financial Metrics 2014E 2015E 2016E 2017E Debt to Capitalization Target FFO/Total Debt **** Mid 50s Mid -to- Upper teens *$300MM OH deferred fuel securitized(subject to regulatory approval) **Assumes current quarterly dividend of $0.53 per share; dividend evaluated by board of directors each quarter; stated target payout ratio range is 60-70% ***Interim credit facility matures May 2015, and is assumed to be refinanced for modeling purposes ****Excludes securitization debt Anticipated cash flows cover planned capital investment while maintaining solid credit metrics 14

15 2015 Operating Earnings Guidance $0.02 $0.08 $3.45/sh $3.45/sh $3.45/sh Drivers ($0.38) $0.31 $0.31 ($0.44) Drivers Rate Changes $0.03 O&M 0.05 Normal Load (0.01) Weather (0.01) Depreciation (0.02) Other (0.02) Transcos $0.07 JVs 0.01 Drivers Capacity Rev $(0.35) Other (0.03) $0.00 $0.02 $3.50/sh $3.50/sh $3.45/sh Drivers Rate Changes $0.27 O&M 0.09 AFUDC 0.07 Normal Load 0.05 Depreciation (0.01) Weather (0.03) OSS (0.09) Other (0.04) 2015E midpoint $1.85 $0.69 $0.38 $0.50 $0.08 $ Operating Earnings Guidance Range of $ $3.60/sh 15

16 2015 Key Guidance Assumptions & Sensitivities Sensitivities Sensitivity EPS Retail Sales-Average Mix 0.5% +/ Wholesale Market Prices - Regulated $1 MWh +/ Wholesale Market Prices - Competitive $1 MWh +/ Assumptions Rate Changes: $223M 2015 Regulated Connected Load: Residential: 59,306 GWh Commercial: 50,066 GWh Industrial: 58,254 GWh Regulated OSS: 17,485 GWh O&M Expense (excludes O&M with offsets) 1.0% +/ Effective Income Tax 34.7% 1.0% +/ Note: A $7.5M change in pre-tax earnings equals $0.01/share Regulated OSS Gross Margins (after sharing): $177M Generation Hub Prices: Peak: $45 Off-Peak: $30 Henry Hub NG Price: $3.95 Average Shares Outstanding: 490M 16

17 Normalized Retail Load Trends AEP System 5% AEP Residential Normalized GWh Sales % Change vs. Prior Year 5% AEP Commercial Normalized GWh Sales % Change vs. Prior Year 0% -1.6% 0.0% 0.8% 0.7% 0.6% 0% -0.6% -0.1% 1.1% 1.2% 0.1% -5% -5% -10% 2012A 2013A YTD E 2015E -10% 2012A 2013A YTD E 2015E 5% 0% 0.8% -0.1% AEP Industrial GWh Sales % Change vs. Prior Year -1.6% 3.8% -0.7% 0.4% 3.8% 2.1% 5% 0% -0.8% AEP Total Normalized GWh Sales % Change vs. Prior Year -0.5% -0.6% -1.6% 1.9% 1.9% 0.4% 0.7% 0.9% -5% -4.5% -5% -10% Note: Line represents growth excluding Ormet 2012A 2013A YTD E 2015E -10% Note: Line represents growth excluding Ormet 2012A 2013A YTD E 2015E EPS impact of $0.04 for Retail Load 17

18 Normalized Load Trends by Segment 5% Vertically Integrated Utilities GWh Sales % Change vs. Prior Year 5% Transmission & Distribution Utilities GWh Sales % Change vs. Prior Year 2.8% 2.7% 0% -5% -0.4% -0.6% 1.1% 1.3% 1.1% R: +0.8% C: -0.1% I: +2.3% 0% -5% -0.6% -0.6% -1.3% -3.0% -0.6% 0.0% 0.7% R: +0.3% C: +0.3% I: +1.6% -10% 2012A 2013A YTD E 2015E -10% Note: Line represents growth excluding Ormet 2012A 2013A YTD E 2015E Included Companies: Appalachian Power Indiana Michigan Power Kentucky Power Kingsport Power Public Service Co of OK Southwestern Electric Power Wheeling Power Included Companies: Ohio Power AEP Texas Central AEP Texas North EPS impact of $0.04 for Retail Load 18

19 GWh Growth vs PY GWh Growth vs PY Industrial Class Data 50% 40% 30% 20% 10% 0% -10% 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0% -10.0% -20.0% 4% AEP Industrial Sales Growth Shale Counties Non-Shale Counties 9% Industrial Sales Growth in Shale Regions Eagle Ford (TX) Marcellus (WV) Permian (TX) Utica (OH) Woodford (OK) 17% 28% 30% 39% 28% 1.1% -0.7% -1.7% -1.6% -5.3% -3.5% -3.8% Q1-13 Q2-13 Q3-13 Q4-13 Q1-14 Q2-14 Q3-14 * Excluding Ormet Q3-13 Q4-13 Q1-14 Q2-14 Q3-14 AEP Shale Gas Counties Shale Counties in AEP service territory Non-Shale Counties in AEP service territory Shale gas development driving industrial load growth 19

20 Pension & OPEB Estimates Qualified Pension Liability Funding Investment returns for our pension plan are positive YTD in 2014, led by strong gains in fixed income. OPEB funds also show positive returns year to date through September. We expect combined pension and OPEB costs (pre-tax and including capitalized portion) to decrease by about $30M from 2014 to 2015 subject to potential changes in investment results, interest rates and actuarial assumptions. Adoption of an updated actuarial Mortality Table at YE 2014 is being evaluated and is currently included in the 2015 projection. Pension funding and expense for regulated subsidiaries are recovered through rates. Assumptions 2014E 2015E Pension Discount Rate 4.70% 4.20% OPEB Discount Rate 4.70% 4.20% Assumed Long Term Rate of Return on Pension Assets Assumed Long Term Rate of Return on OPEB Assets 6.00% 6.00% 6.75% 6.75% Pension/OPEB Funding $88M $102M Pension/OPEB Cost* $81M $50M * Cost component is pretax and pre-capitalization; on average, 35% of pension and OPEB costs are capitalized and 65% are expensed 20

21 2014 Announced Rate Cases Oklahoma Settlement filed June 17, 2014 Rate increase related to AMI Rider - $27M annually ROE for AFUDC purposes of 9.85% Order expected first quarter 2015 Interim rates effective Nov. 1, 2014 Virginia Biennial review filed March 31, 2014 Two-year earnings test period ended Dec. 31, 2013 No rate increase requested; Earned ROE of 10.8% for two year period; within allowed earnings band Staff testimony argues APCo achieved a 12.85% ROE thereby supporting a refund to customers of $22.5M; the recommended prospective ROE is 9.3% (range of 8.8% to 9.8%) Hearings commenced Sept. 16, 2014 Rates effective Feb. 2015, if any change occurs West Virginia Base rate case filed June 30, 2014 Requested increase of $226M with an ROE of 10.62% Intervenor and Staff testimony due Dec. 8, 2014 Hearing commences Jan. 15, 2015 Order due May 26, 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 21

22 AEP Ohio Regulatory Filings ESP III Continuation and updates of various riders, including Distribution Investment Rider (DIR) and several others Proposed new recovery mechanisms for GridSMART Phase II, NERC Compliance & Cybersecurity, and several others Power Purchase Agreement Rider (PPA), with recommendation to include OVEC in the rider Auction based supply for non-shopping customers Proposed term June 2015 through May 2018 Waiting for order, expected by year-end Purchase Power Agreement Filing Stabilizes retail rates in AEP Ohio s service area and protects reliability and the economy in Ohio. Utilize PPA recovery mechanism proposed in ESP III, if approved, to include 100% of AEPGR s share of 4 plants * for the remaining life of the units Proposed effective date is June 1, 2015 PPA is FERC jurisdictional, with projected initial ROE of approximately 11.2% Estimated rate base is $1.6B, with 50/50 cap structure Average remaining life of assets is 20 years *Plants included in PPA filing: Unit/Plant Cardinal Unit 1 Conesville Stuart Zimmer Total MW 592 MW Unit 4 (CCD): 339 MW Units 5&6: 810 MW 4 Coal Units: 600 MW 330 MW 2,671 MW 22

23 Rate Base & ROE s by Jurisdiction/Company Vertically Integrated Utilities Jurisdiction Rate Base 1 ($ millions) Proforma 2 Earned ROE as of 09/30/2014 Approved ROE Approved Debt/Equity Effective Date of last approved rate case APCo-Virginia 10.90% 57/43 1/29/2012 APCo-West Virginia 10.00% 57/43 3/31/2011 APCo - FERC 10.98% 55/45 6/1/2014 APCo Total $ 6, % KPCo-Kentucky $ 1, % 10.50% 57/43 3 6/29/2010 I&M-Indiana 10.20% 48/52 2/28/2013 I&M-Michigan 10.20% 49/51 3/29/2012 I&M - FERC 10.73% 47/53 6/1/2014 I&M Total $ 3, % PSO-Oklahoma $ 2, % 10.15% 54/46 1/31/2011 SWEPCO-Louisiana 10.00% 4 49/51 2/28/2013 SWEPCO-Arkansas 10.25% 54/46 11/25/2009 SWEPCO-Texas 9.65% 51/49 1/29/2013 SWEPCO - FERC 11.10% 50/50 1/1/2014 SWEPCO Total $ 4, % Transmission and Distribution Companies Jurisdiction Rate Base 1 ($ millions) Proforma 2 Earned ROE as of 09/30/2014 Approved ROE Approved Debt/Equity Effective Date of last approved rate case AEP Ohio - Distribution 10.20% 47/53 1/1/2012 AEP Ohio - Transmission 11.49% 45/55 7/1/2013 AEP Ohio total $ 4, % AEP Texas Central $ 1, % 9.96% 60/40 8/28/2013 AEP Texas North $ % 9.96% 60/40 1/25/2013 AEP Texas Total $ 2,658 Transcos Company Rate Base 1 ($ millions) Proforma 2 Earned ROE as of 09/30/2014 Approved ROE Approved Debt/Equity Effective Date of last approved formula rate filing AEP Ohio Transco $ % 11.49% 50/50 7/1/2014 AEP Indiana Michigan Transco $ % 11.49% 50/50 7/1/2014 AEP West Virginia Transco $ % 11.49% 50/50 7/1/2014 AEP Oklahoma Transco $ % 11.20% 50/50 7/1/ Rate base represents Net Utility Plant plus Regulatory Assets less Net Accumulated Deferred Income Taxes and less Regulatory Liabilities from 2013 FERC Form 1 2 Pro-forma adjusts GAAP results by eliminating any material nonrecurring items and is not weather normalized 3 Represents a negotiated settlement 4 Represents the midpoint of the ROE range approved in the formula rate case settled in February

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25 Transmission Ownership Structure $3 Equity Investment* ($ in millions) $9 Net Plant* ($ in millions) $26 Equity Investment in PWT* ($ in millions) $82 Net Plant* ($ in millions) $2,277 Net Plant* ($ in millions) $423 Net Plant* ($ in millions) $1,255 Net Plant* ($ in millions) $403 Net Plant* ($ in millions) Transco Issuing Entity $187 Net Plant* ($ in millions) Note: Private placement financing has occurred at Electric Transmission Texas, LLC and AEP Transmission Company, LLC * As of 9/30/

26 Transmission Holdco Cumulative Base Case Capital Investment High Case Incremental Capital Investment 4 types of projects: Regional projects for retirements, renewables, economic and market efficiencies Local reliability plans Aging infrastructure Customer-driven projects $5.2 B $0.51 $6.6 B $0.67 $5.4 B $8.2 B $0.81 $6.4 B $0.66 $3.8 B $0.40 $4.5 B $0.56 EPS Base Case Contribution $/share $3.6 B $0.38 $0.46 EPS High Case Contribution $/share $0.16 $0.30 Non-firm joint venture projects not included; high case investment is strictly related to the existing Transcos (no assumption for securing competitive opportunities); no projects included above subject to loss due to FERC Order 1000 right of first refusal 26

27 Transmission Joint Venture Active Projects 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 MEHC Texas Transco, LLC (50%), AEP (50%) $3 billion 9.96% 0.00% 0.00% 9.96% Prairie Wind Kansas 2014 Westar Energy(50%), ETA (50%) $161.5 million 10.80% 0.50% 1.50% 12.80% Pioneer Indiana 2018 Duke Energy (50%), AEP (50%) $330 million 10.54% 0.50% 1.50% 12.54% Transource Missouri 2017 AEP (86.5%), Great Plains Energy (13.5%) $397 million 9.80% 0.50% 1.00%* % *Only approved for Sibley-Nebraska City Line Transource - Weighted average of 11.15% based on projected cost of each project Non active joint ventures and prospects excluded from the financial forecasts 27

28 Transmission Projects/Pipeline - PJM Aging Infrastructure Asset Description Transco In-Service Date Rebuild, replace over 500 miles of 138 kv, and below, transmission lines MULTI Dec-2019 Replace obsolete reactors on kv transmission lines MULTI Dec-2019 Replace/upgrade key 345/138 kv transformers and increase spare complement MULTI Dec-2019 Replace/upgrade obsolete circuit breakers, switches and protection & control at kv stations MULTI Dec-2019 Add monitoring and communications to support development of the Asset Health Center MULTI Dec-2019 Replace/upgrade obsolete circuit breakers, switches and protection & control at key 345 kv stations MULTI Dec-2019 Regional Projects Asset Description Transco In-Service Date Muskingum River - Sporn 345 kv OH/WV 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 Kanawha Valley Area Reinforcement Project WV Oct-16 Allen 345/138 kv Expansion/Lines IN/OH Jun-17 Wyoming 765 kv Shunt Reactors WV Jun-18 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 138/69 kv Upgrade (Phase 1 of 3) OH Jun-18 Marcellus Area Improvements MI Jun-18 Customer Projects Asset Description Transco In-Service Date Ball State Service Upgrades IN Dec-15 Shale Energy Customer Projects (Various) OH/WV Dec-15 West Lima Refinery OH Dec-15 Columbia Gas 138 kv Service WV Jun-16 Nottingham 138 kv New Station/Lines OH Jun-17 Project pipeline excludes investment related to future potential approval of VA Transco or any Order 1000 projects 28

29 Transmission Projects/Pipeline SPP & ERCOT Customer Projects Asset Description Transco/JV In-Service Date Grady POD/Phase 2 OK Dec-2015 Foraker POD OK May-2015 Talawanda POD OK Jun-2016 Darlington II POD OK Jun-2016 Wildhorse POD OK Jun-2016 Prairie Chicken POD OK Jun-2016 Roosevelt POD OK Jun-2016 Local Reliability Projects Asset Description Transco/JV In-Service Date Barney Davis to Naval Base 138 kv ETT Dec-2015 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 Darlington to Roman Nose OK Jun-2016 Iatan-Nashua Transource 2015 Sibley-Nebraska City Transource 2017 Project pipeline excludes investment related to future potential approval of SW Transco or any Order 1000 projects 29

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31 Competitive Business Organizational Structure AEP Co, Inc. AEP Energy Supply AEP Resources AEP Generation Resources (AGR) PJM Generation AEP Energy Partners Wholesale, Trading & Marketing AEP Energy Retail AEP River Operations AEP Energy Supply integrates the competitive generation, wholesale and retail businesses 31

32 AEP Generation Resources Footprint PJM: 7,923 MW Fleet Characteristics 01/01/2015 (excludes 2,470 MW from retiring plants) (MW) Wholly-owned, AEP operated, 69% of fleet Gavin 2,665 Coal, controlled Cardinal 1* 595 Coal, controlled Conesville 5, 6* 810 Coal, FGD only Waterford 840 Gas, CC, SCR Darby 507 Gas, CT Racine 48 Hydro Joint Venture, AEP operated, 4% of fleet Conesville 4* 339 Coal, controlled Capacity by Fuel Type Joint Venture, operated by others, 12% of fleet Zimmer* 330 Coal, controlled Stuart* 603 Coal, controlled Capacity / energy entitlements, 15% of fleet Lawrenceburg 1,186 Gas, CC, SCR Total 7,923 * Part of the proposed PPA filed in Ohio Note: The portfolio also includes AEP Energy Partners assets in ERCOT consisting of the Oklaunion Coal Plant PPA (355MW), Wind Farms (311MW) and Renewable PPAs (177MW) 32

33 AEP Generation Resources: Expected Generation Generation from fleet expected to be in the range of million MWh* * Excludes ~2 million MWh of expected generation from retiring units Fleet is well-positioned from a cost and operational perspective to participate in the competitive market 33

34 Energy Sales Opportunities 2015 Energy Sales Opportunity AEP Energy (Retail) Profile Short Term 20-40% MD 1% PA 5% YTD September 2014 Delivered Load NJ 4% Financial Instruments Wholesale Customers (Muni, Co-op, Utility Auction) 20-40% OH 69% IL 21% C&I 80% Residential 20% Competitive Retail Customers 25-40% Currently serving 223,000 customers Expect to serve 12 TWh of load in 2014 Provide hedging opportunities for AGR Customer growth in western PJM 80% of expected gross margin in 2015 is secured by energy hedges, RPM capacity, and Ohio Electric Security Plan 34

35 AEP Energy Supply: Earnings & Cost Management Estimated (in $ millions) 2014E 2015 Range 2016 Range Energy/Capacity Gross Margin $1,340 $965 - $1,035 $590 - $790 Costs EBITDA $905 $555 - $625 $250 - $450 Capital Expenditures Cash Flow* $725 $413 - $483 $104 - $304 * Excludes income taxes, interest and changes in working capital 35

36 AEP Generation Resources Capitalization & Liquidity Conservatively Capitalized Capitalization as of 9/30/14: Debt: 25% Equity: 75% Total Capitalization: $3.3 billion The corporate separation term loan balance at the end of the 3 rd quarter is $500 million, maturing May Term-loan refinancing options include AEP Holdco support, Pollution Control Bonds or AGR stand-alone financing. Adequate Liquidity Liquidity backstop provided through $3.5B in AEP core credit facilities. Current expiration dates for the two facilities are 2016/17. We are in the process of extending the maturity dates to 2017/18. Near-term financing strategy will preserve flexibility 36

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38 Capital Forecast by Subsidiary ($ in millions - excluding AFUDC) 2015E 2016E 2017E Total Appalachian Power Co. $616 $496 $568 $1,680 Wheeling Power Co. $36 $18 $29 $83 Indiana Michigan Power Co. $510 $494 $496 $1,500 Kentucky Power Co. $103 $93 $78 $274 Ohio Power Co. $395 $405 $458 $1,258 Public Service Co. of OK $394 $311 $223 $928 Southwestern Electric Power Co. $575 $341 $334 $1,250 Texas Central Co. $444 $379 $307 $1,130 Texas North Co. $127 $124 $143 $394 AEP Generating Co. $45 $58 $100 $203 AEP Transmission Holdco $1,005 $954 $962 $2,921 Competitive Operations $151 $155 $196 $502 Other $18 $10 $19 $47 Total Capital & Equity Contributions $4,419 $3,838 $3,913 $12,170 38

39 ($ millions) ($ millions) Appalachian Power / Wheeling Power Company Data Appalachian Power Wheeling Power $11,000 $10,000 $9,000 Projected Rate Base Growth $9,485 $9,681 $8,891 $8,969 $9,175 $9,929 $1,150 $900 Projected Rate Base Growth $903 $901 $881 $872 $8,000 $650 $7,000 $6,000 $5, A 2013A 2014E 2015E 2016E 2017E $400 $150 $182 $ A 2013A 2014E 2015E 2016E 2017E 5% 0% APCo/Wheeling Normalized GWh Sales % Change vs. Prior Year 0.9% 1.5% 1.7% APCo/Wheeling Capital by Function $ in millions, excluding AFUDC Environmental $297 Fossil/Hydro Generation $256 Transmission $ % -0.5% R: +0.5% C: +0.3% I: +4.0% Corporate $72-5% 2012A 2013A YTD E 2015E Distribution $626 39

40 ($ millions) Ohio Power Company Data $6,500 AEP Ohio Projected Rate Base Growth 5% AEP Ohio Normalized GWh Sales % Change vs. Prior Year $5,500 $4,500 $3,500 $2,500 $4,259 $4,466 $4,766 $5,036 $5,315 $5, A 2013A 2014E 2015E 2016E 2017E Note: AEP Ohio rate base represents an estimate of net plant of the company as wires-only for the periods presented 0% -5% -10% -2.2% -1.0% -3.0% -4.8% 1.6% 1.5% -4.0% Note: Line represents growth excluding Ormet AEP Ohio Capital by Function $ in millions, excluding AFUDC Transmission $ % 0.4% R: +0.1% C: -0.3% I: +1.4% 2012A 2013A YTD E 2015E Corporate $122 Distribution $881 40

41 ($ millions) Indiana Michigan Power Company Data $7,000 $6,000 $5,000 $4,729 Indiana Michigan Power Projected Rate Base Growth $5,751 $5,386 $5,056 $6,084 $6,430 5% 0% Indiana Michigan Normalized GWh Sales % Change vs. Prior Year -0.5% -0.5% 0.0% 0.6% R: +1.0% C: -1.3% I: +0.8% 0.3% $4,000 $3, A 2013A 2014E 2015E 2016E 2017E -5% 2012A 2013A YTD E 2015E I&M Capital by Function $ in millions, excluding AFUDC Environmental $172 Transmission $139 Corporate $84 Distribution $382 Nuclear $641 Fossil/Hydro Generation $81 41

42 ($ millions) Kentucky Power Company Data $3,000 Kentucky Power Projected Rate Base Growth 5% Kentucky Power Normalized GWh Sales % Change vs. Prior Year $2,500 $2,000 $1,500 $1,807 $1,920 $1,992 $2,005 $2,001 $1,979 0% -5% -3.8% -3.8% -0.1% 0.1% -0.1% R: -1.0% C: -0.3% I: +0.9% $1, A 2013A 2014E 2015E 2016E 2017E -10% 2012A 2013A YTD E 2015E Kentucky Power Capital by Function $ in millions, excluding AFUDC Environmental $72 Transmission $40 Corporate $20 Fossil/Hydro Generation $28 Distribution $114 42

43 ($ millions) Public Service Company of Oklahoma Data $4,500 $4,000 $3,500 $3,000 $2,500 $2,940 PSO Projected Rate Base Growth $3,774 $3,452 $3,166 $3,983 $4,089 5% 0% 1.1% PSO Normalized GWh Sales % Change vs. Prior Year 0.0% 1.8% 1.8% 2.4% R: +1.0% C: -0.3% I: +7.5% $2, A 2013A 2014E 2015E 2016E 2017E -5% 2012A 2013A YTD E 2015E PSO Capital by Function $ in millions, excluding AFUDC Environmental $140 Transmission $84 Corporate $46 Fossil/Hydro Generation $165 Distribution $493 43

44 ($ millions) Southwestern Electric Power Company Data $7,500 SWEPCO Projected Rate Base Growth 5% SWEPCO Normalized GWh Sales % Change vs. Prior Year $7,000 $6,500 $6,000 $5,500 $5,000 $5,267 $5,533 $5,907 $6,365 $6,556 $6,716 0% 0.0% 0.2% 2.2% 1.4% 0.1% R: +1.7% C: +0.6% I: -2.1% $4, A 2013A 2014E 2015E 2016E 2017E -5% SWEPCO Capital by Function $ in millions, excluding AFUDC 2012A 2013A YTD E 2015E Transmission $259 Environmental $456 Corporate $51 Fossil/Hydro Generation $183 Distribution $300 44

45 ($ millions) ($ millions) AEP Texas Data $5,000 $4,500 $4,000 $3,500 $3,000 $2,912 AEP Texas Central Projected Rate Base Growth $4,183 $3,895 $3,539 $3,203 $4,393 $1,900 $1,700 $1,500 $1,300 $1,100 $900 $1,079 AEP Texas North Projected Rate Base Growth $1,363 $1,282 $1,199 $1,131 $1,461 $2,500 $700 $2, A 2013A 2014E 2015E 2016E 2017E $ A 2013A 2014E 2015E 2016E 2017E AEP Texas Capital by Function $ in millions, excluding AFUDC 10% 5% 0% 1.8% 0.0% 4.6% 4.3% R: +0.5% C: +1.0% I: +1.9% 1.0% Fossil/Hydro Generation $12 Distribution $789 Environmental $11 Transmission $626-5% 2012A 2013A YTD E 2015E Corporate $85 45

46 ($ millions) ($ millions) Other Utility Subsidiaries Data $600 $500 $400 $300 $315 AEP Generating Projected Rate Base Growth $382 $398 $346 $430 $504 $150 $125 $100 $91 Kingsport Power Projected Rate Base Growth $106 $109 $98 $101 $113 $200 $100 $75 $0 2012A 2013A 2014E Excludes Lawrenceburg Plant 2015E 2016E 2017E AEP Generating Capital by Function $ in millions, excluding AFUDC Corporate $1 Fossil/Hydro Generation $35 $ A 2013A 2014E 2015E 2016E 2017E Kingsport Capital by Function $ in millions, excluding AFUDC Corporate/Other $4 Transmission $6 Environmental Generation $168 Distribution $19 46

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