UBS Utilities and Natural Gas Conference Boston, MA March 5, 2014

Transcription

1 UBS Utilities and Natural Gas Conference Boston, MA March 5, 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 forwardlooking 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 startup, 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. Investor Relations Contacts Bette Jo Rozsa Managing Director bjrozsa@aep.com Julie Sherwood Director jasherwood@aep.com 2

3 Table of Contents 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 3

4 Capital Spending Forecast Capital & Equity Contributions $ in millions, excluding AFUDC $3.8B/year Regulated Generation Investment - $2.8B Regulated Distribution Investment - $3.3B Transcos: $1,960 17% Competitive Operations: $545 5% Regulated Environmental Generation: $1,402 12% Transmission Joint Ventures: $462 4% Transmission: $2,118 19% Corporate: $277 2% Distribution: $3,312 29% Regulated Transmission Investment - $4.5B Nuclear Generation: $685 6% Regulated Fossil/ Hydro Generation: $699 6% 95% of capital allocated to regulated businesses 4

5 Regulated Rate Base Growth Cumulative change from 2012 base TRANSCOS/TRANSOURCE WIRES COMPANIES VERTICALLY INTEGRATED UTILITIES 2012 Net Regulated Plant = $33.2B 7.1% CAGR in Net Regulated Plant 5

6 Forecasted Growth in Operating Earnings Per Share $3.8B capital investment per year ; 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 6

7 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 Utilize transition period to execute continuous improvement plan 7

8 * Subject to approval by Board of Directors Dividend Targeted payout ratio of 60-70% of consolidated earnings Supported by earnings from regulated operations Declared 415 consecutive quarters 8

9 Financing Plan & 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 Federal Cash Taxes Paid (396) (698) (830) Cash from Securitization* Anticipated Cash Flows Cover Planned Capital Investment While Maintaining Solid Credit Metrics: Capital & Equity Contributions (3,800) (3,800) (3,800) Other Investing Activities (267) (273) (179) Common $2.00/share ** (979) (983) (988) Excess (Required) Capital (641) (1,133) (1,198) Financing ($ 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) 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 Bonus Depreciation $459M Securitization $394M* DRP $300M 3-year total = $1,153M *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 9

10 2014 Operating Earnings Guidance $0.18 $0.00 $0.13 Drivers Transcos $0.09 JVs 0.04 $0.04 ($0.21) Drivers Gen Resources ($0.19) Other (0.02) ($0.07) Drivers Trans. Rev $0.03 Rate Changes 0.02 O&M (0.04) Normal Load (0.01) Driver Int Income ($0.07) Drivers Rate Changes $0.21 OSS 0.05 Depreciation (0.04) O&M (0.02) Weather (0.01) Other (0.01) 2014 Operating Earnings Guidance Range of $ $3.40/sh 10

11 2014 Key Guidance Assumptions & Sensitivities Sensitivities Sensitivity EPS Retail Sales 0.5% +/ Wholesale Market Prices - Regulated $1 MWh +/ Wholesale Market Prices - Competitive $1 MWh +/ O&M Expense (excludes O&M with offsets) 1.0% +/ Effective Income Tax 35.5% 1.0% +/ 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 11

12 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% -5% 0.4% -1.6% 0.0% -0.9% 0% -5% -0.3% 0.3% -0.1% -0.2% -10% 2011A 2012A 2013A 2014E -10% 2011A 2012A 2013A 2014E 5% 0% -5% 4.1% 2.0% AEP Industrial GWh Sales % Change vs. Prior Year 0.0% -0.9% -1.6% -4.5% 1.2% -2.2% 5% 0% -5% 1.5% 0.7% AEP Total Normalized GWh Sales % Change vs. Prior Year -0.5% -0.6% 0.1% -0.8% -1.6% -1.1% -10% Note: Line represents Industrial excluding Ormet 2011A 2012A 2013A 2014E -10% Note: Line represents Retail excluding Ormet 2011A 2012A 2013A 2014E Note: Charts reflect connected load and exclude firm wholesale load & Buckeye Power backup load 12

13 2014 Announced Rate Cases 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 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 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 13

14 Pro-forma Earned ROEs 12 Months Ended 12/31/ % 11.3% 10.7% 8.6% 9.3% 9.5% 7.4% 7.4% Ohio Power APCo KPCo I&M PSO SWEPCO AEP Texas AEPTrans Holdco Regulated Operations ROE of 9.9% for 12 months ended Dec. 31,

15 AEP Transmission Holdco Organizational Structure $6 Net Plant* ($ in millions) $23 Equity Investment in PWT* ($ in millions) $2,194 Net Plant* ($ in millions) $274 Net Plant* ($ in millions) $921 Net Plant* ($ in millions) $331 Net Plant* ($ in millions) $77 Net Plant* ($ in millions) Note: Private placement financing has occurred at Electric Transmission Texas, LLC and AEP Transmission Company, LLC * As of 12/31/

16 AEP 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 $0.51 $0.67 $0.80 $0.65 $0.39 $0.56 EPS Base Case Contribution $/share $0.30 $0.36 $0.43 EPS High Case Contribution $/share $0.16 $0.29 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 16

17 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-2018 Replace obsolete reactors on 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 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 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 Project pipeline excludes investment related to future potential approval of VA Transco 17

18 Transmission Projects/Pipeline SPP & ETT 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 Total Customer 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 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 Total Local Reliability In-Service MULTI Multiple Projects Project pipeline excludes investment related to future potential approval of SW Transco 18

19 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 19

20 AEP Energy Supply Timeline Optimize Revenues/Reduce Costs 2013 Corporate Separation completed December 31, February AEP Ohio load auction: 10% March WV filing to address Wheeling Power capacity/energy needs May RPM 2017/18 Auction 2015 May 31 - ESP II transition ends June - Retire 2,523MW Obtain permanent financing Rationalize Capacity 2016 Fully Competitive Operations May AEP Ohio load auction: 25% September AEP Ohio load auction: 25% November AEP Ohio load auction: 40% Fleet is well-positioned from a cost and operational perspective to participate in the competitive market 20

21 AEP Generation Resources: PJM Fleet Profile Transfer Fuel Profile Retire Retain Gas, CT 5.8% Hydro 0.6% Gas, CC 23.4% Coal, Controlled 70.2% Fixed Resource Requirement RPM AGR has the competitive advantage of fuel and operational diversity 21

22 $ per MWh, Dispatch Cost AEP Generation Resources: Expected Generation $ Dispatch Stack Darby Peak $40 $30 ATC Off Peak Zimmer* Mitchell Waterford Lawrenceburg Conesville Generation from fleet expected to be in the range of million MWh Stuart* Gavin Cardinal $ Installed Capacity (MW) 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 Fleet is well-positioned from a cost and operational perspective to participate in the competitive market 22

23 Energy Sales Opportunities 2014 Energy Sales Opportunity AEP Energy (Retail) Profile Short Term 15-20% Financial Instruments Wholesale Customers (Muni, Co-op, Utility Auction) 15-30% OH 69% MD 1% PA 4% YTD December 2013 Delivered Load NJ 4% IL 22% Residential, 17% C&I, 83% Unswitched AEP Ohio Retail Customers 25-35% Competitive Retail Customers 25-30% 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 23

24 AEP Energy Supply: Earnings & Cost Management Estimated ($ in millions) Range 2016 Range Energy/Capacity Gross Margin $1,100 $825 - $925 $600 -$725 Costs EBITDA $675 $435 - $535 $245 - $370 Capital Expenditures Net Cash Flow* $495 $290 - $390 $65 -$190 * Excludes income taxes, interest and changes in working capital $490 Cost Trend ($ in millions) $425 $60 $40 $355 $5 $430 $385 $ Average Ongoing Disposition Units 24