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AEP | Credit Suisse 2011 Energy Summit

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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.

Published in: Investor Relations
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AEP | Credit Suisse 2011 Energy Summit

  1. 1. Credit Suisse 2011 Energy SummitFebruary 7-8, 2011 1
  2. 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 AnalystSVP 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. 3. Brian X. Tierney - EVP and CFO 3
  4. 4. American Electric Power Serving electric customers inRegulated Electric Utility 11 states – Regulatory and economic diversity – Operating Company ModelFocus on Capital Allocation – Capital for Growth – Return of Capital to Shareholders – Pension FundingStrong Balance Sheet – Stable credit ratings – Capital plan supported by cash flow – Strong liquidity position AEP Fast FactsGrowth Opportunities – Capital for utility platform 5.3 million customers – Transmission projects 39 GW of generation capacity 39,000 miles of transmission linesDividend yield over 5% $17.3B Market Capitalization BBB/Baa2/BBB credit rating 4
  5. 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. 6. Normalized Load Trends AEP Residential Normalized GWh Sales AEP Commercial Normalized GWh Sales %Change vs. Prior Year %Change vs. Prior Year15% 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 Year15% 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. 7. 2011 Guidance and Business Initiatives 2011 Guidance: $3.00 - $3.20 per share 2011 Earnings Drivers Business InitiativesRecovering Economy Operating Transcos in OH,Rate changes (69% secured) OK and MI; filings pending in other statesContinued O&M discipline -$34M decrease net of offsets AEP Eastern System Interconnection AgreementCustomer switching – Ohio2010 SEET at Columbus Bonus DepreciationSouthern Power Capital Allocation 7
  8. 8. AEP Ohio ESP Filing – Core Policy Issues Investment in Ohio Jobs in Ohio Energy Security Supports economic Jobs are a key Secure, reliable and development and component of growth predictable electricity essential tax base potential in Ohio supply is basis for sustained investment and employment in Ohio Without regulatory assurances Fundamental barriers must be over time we could see loss of addressed to attract Volatility in power prices direct & indirect jobs related to investment for Environmental can lead to major loss of power generation, and Compliance and New economic activity over time business relocations to Generation surrounding states Primary objective of ESP: Stabilize rates and support economic development in the state of Ohio Merged Distribution Rate Redesign 29-Month ESP Alternative Long Ohio Growth Components AEP Ohio Period Term Option Fund Included Single merged Generation rates ESP period Jan 1, Alternative longer- Creation of Inclusion of certain AEP Ohio redesigned to 2012 through May term price certainty significant private distribution company resemble market 31,2014 (May 31 option offered for sector economic components while presumed with pricing structures date aligns with qualifying development to pursuing a parallel supporting PJM annual commercial & attract investment distribution base information on an planning cycle) industrial and job growth in rate caseindividual OP/CSP customers AEP Ohio service basis territory 8
  9. 9. Transmission as a Growth Engine Cumulative Capital Spending,Electric Transmission Texas (ETT) After Ownership Division ($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 $150AEP Transmission Company (AEP $2,000 $100Transco) $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 opportunitiesProgress 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 AEPs traditional service territories 9
  10. 10. Earnings and Dividends On-Going EPS History Since 2004 Dividend History Since 2004 $/share $/share3.60 2.003.40 % % 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 $1.643.00 1.60 $1.58 $2.77 $1.502.80 $2.73 $1.40 $1.422.60 1.40 $2.332.40 1.202.202.00 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. 11. Long-term EPS Growth Rate4-6% 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 growth5-7% 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. 12. AEP HighlightsPremier Utility PlatformTraditional and EffectiveRegulatory RelationshipsEnergy Policy Initiatives CreateTechnology Deployment andInvestment OpportunityStrong Value and Total ReturnProposition Mountaineer Plant (WV) 12
  13. 13. Appendix 13
  14. 14. Highly Diversified Regulated Utility Platform2010 On-Going Earnings 2010 Retail Load Contribution Public Service of KentuckySouthwestern 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. 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 = 2,9402 Ohio Companies 49,465 GWh @ $ 56.6 /MWhr = 2,800 49,747 GWh @ $ 56.1 /MWhr = 2,7933 West Regulated Integrated Utilities 42,131 GWh @ $ 31.4 /MWhr = 1,322 41,536 GWh @ $ 32.8 /MWhr = 1,3614 Texas Wires 27,348 GWh @ $ 22.3 /MWhr = 611 27,870 GWh @ $ 22.0 /MWhr = 6145 Off-System Sales 19,172 GWh @ $ 15.6 /MWhr = 299 21,786 GWh @ $ 12.0 /MWhr = 2626 Transmission Revenue - 3rd Party 369 4297 Other Operating Revenue 511 4818 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 21114 Income Taxes (758) (787)15 Utility Operations On-Going Earnings 1,419 1,48316 Transmission Operations On-Going Earnings 10 17 NON-UTILITY OPERATIONS:17 AEP River Operations 40 5118 Generation & Marketing 25 619 Parent & Other On-Going Earnings (43) (61)20 ON-GOING EARNINGS 1,451 1,496 15
  16. 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 2012EInvestment levels greater than depreciation of $1.4B per year cause rate base growth in 2011 and 2012 16
  17. 17. Capitalization & Liquidity70% Total Debt/Capitalization Current Liquidity Summary65% Liquidity Summary Actual 62.5% (unadited) 12/31/10 60.7% ($ in millions) Amount Maturity 59.1% 59.1% Revolving Credit Facility $1,500 Jun-1360% Revolving Credit Facility 1,454 Apr-12 57.2% 57.2% 57.0% 1 Revolving Credit Facility 478 Apr-11 Total Credit Facilities 3,43255% Plus Cash & Cash Equivalents 29450% Less Commercial Paper Outstanding (650)45% Letters of Credit Issued (124) Letters of Credit Issued for VRDNs (477) Net Available Liquidity $2,47540% 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. 18. Cash Flow Guidance $ in millions 2010A 2011ECash 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 7Cash From Operations $ 3,297 $ 3,352Investing 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 $ 294Ending Cash Balance $ 294 $ 2171 Refer to September 30, 2010 10Q Enron Bankruptcy pages 56-57 for futher discussion2 Pro forma to exclude effects of consolidation of AEP Credit ($656M) in 2010 18
  19. 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. 20. Approved Rate Bases & ROEsJurisdiction Rate Base Approved ROE Approved Debt/Equity Effective DateAPCo-Virginia * 10.53% 58/42 8/1/2010 $2,060MMAPCo-West Virginia $1,656MM 10.50% 57/43 7/28/2006KPCo-Kentucky $995MM 10.50% 57/43*** 6/30/2010I&M-Indiana $2,000MM 10.50% 44/56 3/4/2009I&M-Michigan $595MM 10.35% 50/50 10/14/2010PSO-Oklahoma $1,706MM 10.15% 54/46 1/5/2011SWEPCo-Louisiana $649MM ** 50/50 8/1/2010 10.57%SWEPCo-Arkansas $612MM 10.25% 54/46 11/25/2009SWEPCo-Texas $665MM 10.33% 49/51 4/15/2010TCC-Texas $1,566MM 9.96% 60/40 10/17/2007TNC-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

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