Exhibit 99.01
| Howard Weil 39th Annual Energy Conference March 27 - 28, 2011 |
| Safe Harbor Statement Statements contained in this presentation that state the Company's or management's expectations or predictions of the future are forward- looking statements intended to be covered by the safe harbor provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. The words "believe," "expect," "should," "estimates," and other similar expressions identify forward-looking statements. It is important to note that actual results could differ materially from those projected in such forward-looking statements. For more information concerning factors that could cause actual results to differ from those expressed or forecasted, see Valero's annual reports on Form 10^K and quarterly reports on Form 10^Q, filed with the Securities and Exchange Commission, and available on Valero's website at www.valero.com. 2 |
| Valero Energy Overview World's largest independent refiner 14 refineries 2.6 million barrels per day (BPD) of throughput capacity Average refinery throughput capacity of 185,000 BPD One of the nation's largest fuel retailers with approximately 5,800 branded marketing sites One of the largest ethanol companies in U.S. 10 large-capacity and efficient plants with total of 1.1 billion gallons/year (72,000 BPD) of production capacity All plants located in resource-advantaged corn belt Approximately 20,000 employees 3 |
| Acquisition of Chevron's Pembroke Refinery, Marketing and Logistics Assets in the U.K. and Ireland Valero has agreed to acquire Chevron's Pembroke refinery, marketing and logistics assets in the United Kingdom and Ireland for $730 million 270,000 barrels-per-day refinery with estimated value of $480 million Nelson complexity of 11.8 Estimated replacement cost of $3.4 billion Marketing and logistics assets with estimated value of $250 million Network of over 1,000 Texaco-branded wholesale sites, plus 14,000-bpd aviation fuels business Ownership interest in 4 major product pipelines and 11 terminals Working capital and inventories with estimated value of $1 billion at current market prices; actual value to be determined at closing Expect to fund transaction with cash on-hand Expect to close early third quarter of 2011, subject to regulatory approvals 4 |
| Strategic Rationale Competitive, high-quality assets One of the largest, most complex refineries in Western Europe Refinery was profitable and cash flow positive in 2009 Well-maintained refinery with cash-operating-costs-per barrel 25% below Valero's 2010 average Largest branded dealer site network in the U.K. and the second largest in Ireland provide a stable outlet for most of Pembroke's production Attractive price $480 million refinery value is 14% of replacement cost, compared to Valero's estimated refining value at 28% of replacement cost $185 per complex barrel, a discount of 60% versus Valero's estimated refining value Marketing and logistics estimated value of $250 million is 3.1x estimated EBITDA of $80 million before G&A 5 |
| Strategic Rationale EPS accretion creates shareholder value Valero estimates earnings accretion of $0.26/share with 2010 market prices and $0.30/share with 2011 forward curve prices Valero estimates $10 to $20 million of annual operating synergies, primarily in trading and optimization Consistent with Valero's portfolio-upgrading strategy Improves quality and profitability versus our recent divestitures Bolt-on acquisition fits well within existing portfolio Refinery scale, flexibility, location, and logistical advantages enhance Valero's optimization and trading strategy in Atlantic Basin Opportunity to competitively supply our U.S. East Coast marketing after we strategically exited refining in that market last year Diversifies portfolio for market and political exposure Advantaged tax, regulatory, and environmental policies versus U.S. 6 |
| Geographically Diverse Operations 7 Refinery Capacities (000 bpd) Capacities (000 bpd) Nelson Index Refinery Total Through-put Crude Oil Nelson Index Aruba 235 235 8.0 Ardmore 90 86 12.0 Benicia 170 145 15.0 Corpus Chris. 325 205 20.6 Houston 160 90 15.1 McKee 170 168 9.5 Memphis 195 180 7.5 Port Arthur 310 290 12.7 Pembroke* 270 220 11.8 Quebec City 235 230 7.7 St. Charles 270 190 15.2 Texas City 245 225 11.1 Three Rivers 100 95 12.4 Wilmington 135 85 15.8 Total or Avg. 2,910 2,444 12.1 Pending *Pending acquisition |
| (CHART) Continued Global Demand Growth Important to Refining Margins Refining is a global business - global demand growth matters to refiners everywhere Strong growth in emerging markets is leading the surge in global petroleum demand estimated at 2.6 million BPD in 2010 8 Source: Consultant and Valero estimates |
| Simple Refining Margins Bottomed in 2009, Recovery Started in 2010 9 Gulf Coast LLS Margins Margins improving from strong global demand, particularly in emerging markets, and capacity rationalization Cold weather and restocking from 4Q10 French strike in OECD countries helped distillate demand and margins per bbl Source: Argus; 2011 year-to-date through March 21 |
| Strong Demand for Waterborne Light-Sweet Crude Oils Creating Large Feedstock Discounts 10 (CHART) $/barrel Source: Argus; 2011 year-to-date through March 21 |
| Strong Demand for Waterborne Light-Sweet Crude Oils Creating Large Feedstock Discounts 11 Light-sweet waterborne crude oils are the marginal feedstock in strong demand Examples: LLS, Brent, among others Lower-quality and logistically constrained crude oils seeing wide discounts Maya, WTI, Mars, ANS Expect key drivers of sour crude discounts to continue OPEC increasing production of lower-quality heavier crudes Light product demand outpacing heavy product demand growth Supply of low-quality crudes from Latin America has been better than expected Logistics lagging production growth of crude oils going to Cushing Longer term, expect to benefit from Canadian heavy crude oil to Gulf Coast |
| Valero Has Significant Leverage to Lower-cost Feedstocks and Wider Throughput Margins 12 12 Gulf Coast 62% (1,600 mbpd) Mid-Con 17% (455 mbpd) West Coast 12% (305 mbpd) Northeast (Canada) 9% (235 mbpd) Throughput Capacity (CHART) Maya/Mars Heavy Sour Coking WTI Cracking ANS Medium Sour Coking Brent Cracking Primary Configuration >80% of Valero's capacity can process feedstocks that are discounted versus waterborne light- sweet crudes (LLS, Brent) See Appendix for details on refinery configuration assumptions |
| Mid-Con Margins Leading the Recovery Mid-Con Margins Leading the Recovery 13 Source: Argus; 2011 year-to-date through March 21; see Appendix for details on refinery configuration assumptions |
| Valero's Gulf Coast System Well-Positioned for Global Export Opportunities 14 Our large, complex refineries on Gulf Coast are competitive due to low-cost operations and feedstocks Structural supply-demand imbalance in Latin America and diesel-shortage in Europe provide higher-margin export opportunities Low-cost natural gas is a competitive cost advantage versus other global refiners (CHART) 1Based on 866 MBPD of average total U.S. gasoline and diesel exports from 1Q09 - Dec. 10 |
| (CHART) (CHART) Rationalization of Industry Capacity Continues Source: Valero Energy Note: 2011 and 2012 estimates include announced future capacity closures MBPD 15 Source: Valero Energy MBPD As we said previously, refining capacity continues to shut down in the industry, particularly marginal plants with upcoming capital requirements |
| Valero's Strategic Priorities 16 Manage overhead and maintain investment grade credit rating Improve margin capture, operating costs, and reliability at refineries Complete major, value-added capital projects at key refineries Optimize portfolio - continue "high-grading" strategy of the last several years Asset Sales: sold underperforming and non-core assets Evaluate attractively priced acquisitions that improve competitiveness via higher margins and lower costs and broaden geographic reach Add selective investments in retail and alternative fuels for U.S. market Goal: Increase returns to grow long-term shareholder value |
| Achieving Significant Cost Reductions 17 (CHART) (CHART) Since beginning of 2007, we have achieved $620 million in pre-tax cost savings In 2011, targeting another $100 million in pre-tax cost savings |
| Continuing to Make Our Refineries More Competitive 18 1st Quartile Industry Rank 2nd Quartile 1st Quartile Industry Rank 2nd Quartile Industry benchmarking survey shows Valero is continuing to improve on its competitive, low-cost operations 2010 was Valero's best companywide performance in five years Corpus Christi refinery ranked as one of the best facilities on the Gulf Coast for costs Source: Solomon Associates and Valero Energy Source: Solomon Associates and Valero Energy Source: Solomon Associates and Valero Energy Source: Solomon Associates and Valero Energy |
| Continuing to Make Our Refineries More Competitive 19 1st Quartile Industry Rank 2nd Quartile 1st Quartile 2nd Quartile Our goal is to be a 1st-quartile refiner in industry benchmark surveys Expect big reliability improvement after major 1Q11 turnarounds, particularly for Port Arthur coke drums and St. Charles FCC revamp 3rd Quartile 3rd Quartile 4th Quartile Industry Rank Source: Solomon Associates and Valero Energy Source: Solomon Associates and Valero Energy |
| Strong Contribution from Retail (CHART) Retail Performance (Trailing 4Q Avg.) (U.S. and Canada) 20 In 2010, retail had best 1st and 2nd quarters and 2nd best year in Valero history Improvement in retail earnings with smaller asset base = better returns Since 2005, more than doubled total operating income on 12% fewer total sites |
| Strong Contribution from Ethanol 21 Large, efficient plants in great location have competitive advantage on costs Acquired world-class ethanol plants at an average of 35% of replacement cost In less than 2 years, cumulative operating income less depr. & amort. expense (EBITDA) was $427 million, or 56% of ethanol plants purchase prices (CHART) Ethanol Operating Income before Depr. & Amort. Expense (EBITDA, millions) |
| (CHART) (CHART) Adding to Financial Strength Investment grade credit rating Ended 4Q10 with $3.3 billion of cash and nearly $4 billion of additional liquidity Net debt-to-cap ratio at 12/31/10 was 25%, far below credit facility covenant of 60% No other coverage-type ratios or borrowings on bank revolver Significant liquidity enables Valero to take advantage of investment opportunities Net Debt-to-Capitalization Ratio (period-end) Total Liquidity, December 31, 2010 (millions) (Credit Facility, Letters of Credit, etc.) ($5.86/share ) 22 |
| Shifting Capital Spending to Economic Growth Projects 23 "Stay-in- business" spending 2011 estimated Regulatory spending estimated to decline as Benicia scrubber and MSAT2 projects were completed in 2010 There are potential benefits of a recently passed tax law allowing 100% deduction on capital projects |
| Economic Growth Projects Mainly Geared Toward High Oil/Low Natural Gas Prices Potential for significant earnings power and project returns Projects developed based on our "bullish crude, bearish natural gas" price outlook These projects represent over 75% of strategic capital spending in 2010 and 90% in 2011 25 mbpd expansion of McKee refinery crude capacity in early phase of engineering 24 1D&A = depreciation and amortization expense; See Appendix for price assumptions and project descriptions; 2estimated IRR is unlevered and could improve due to pending changes in tax laws regarding accelerated depreciation expense; 3Most of project commissioned in 2010 Refinery Project Estimated Completion Date Estimated Annual Op. Inc. before D&A using Base Case1 (millions) Estimated IRR2 using Base Case Estimated Annual Op. Inc. before D&A using 2011 Fwd Curve Prices1 (millions) Memphis FCC Revamp 2Q113 $75 20% $102 St. Charles FCC Revamp 2Q11 $140 30% $129 McKee & Memphis New Hydrogen Plants 1Q12 $105 39% $163 Port Arthur New Hydrocracker 3Q12 $485 21% $755 Montreal New Products Pipeline 4Q12 $55 12% $55 St. Charles New Hydrocracker 4Q12 $325 16% $608 Total $1,185 20% $1,814 |
| Why Invest in Valero Today? 25 |
| Appendix 26 |
| Impact of Cost Savings Programs Impact of Cost Savings Programs 27 Ongoing cost savings programs have contributed to Valero's competitiveness and improved financial performance millions (CHART) |
| Valero Has Competitive, Low-Cost Refining Operations 28 Refining Cash Operating Expenses less Natural Gas Usage ($/bbl) Source: Macquarie Capital (CHART) |
| Valero Has High Conversion Refining System Valero Has High Conversion Refining System 29 Note: CDU = crude distillation unit; conversion capacity is the sum of each company's FCC, hydrocracking, and coking capacity Source: PIRA Energy Group 12/16/10 (CHART) We believe size and conversion ratio matter to competitiveness Provides flexibility to process a wide variety of discounted feedstocks into a high proportion of high-value clean products |
| Memphis FCC Revamp Project Investment Highlights Favorable economics driven by better reliability and gains on margin and volume Improves flexibility to run lower- quality feedstocks Improves FCC reliability and increases run length between turnarounds to four years from 1.5 years Increase in run length drives estimated annualized savings of $0.17/barrel 30 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated timing of full benefit 2Q113 2Q113 Estimated total investment (mil.) $255 $255 Cumulative spend thru 4Q10 (mil.) $255 $255 Estimated Incremental Operating Income before D&A2 (mil.), Base Case Estimated Incremental Operating Income before D&A2 (mil.), Base Case $75 Estimated Unlevered IRR on Total Spend, Base Case Estimated Unlevered IRR on Total Spend, Base Case 20% Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve $102 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense; 3Most of project commissioned in 2010 |
| St. Charles MSCC to FCC Conversion Project Investment Highlights Favorable economics driven by better reliability and gains on margin and volume Improves FCC reliability and increases run length between turnarounds to four years from 1.5 years Adds 5%+ volume expansion through FCC Improves energy efficiency via new power recovery turbine Doubles flexibility of FCC to process lower-priced resid feedstocks, backing out higher-priced VGO 31 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 2Q11 2Q11 Estimated total investment (mil.) $310 $310 Cumulative spend thru 4Q10 (mil.) $210 $210 Estimated Incremental Operating Income before D&A2 (mil.), Base Case Estimated Incremental Operating Income before D&A2 (mil.), Base Case $140 Estimated Unlevered IRR on Total Spend, Base Case Estimated Unlevered IRR on Total Spend, Base Case 30% Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve $129 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense |
| Hydrogen Plant Projects 32 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 1Q12 1Q12 Estimated total investment (mil.) $180 $180 Cumulative spend thru 4Q10 (mil.) $25 $25 Incremental Operating Income before D&A2 (mil.), Base Case Incremental Operating Income before D&A2 (mil.), Base Case $105 Unlevered IRR on Total Spend, average, Base Case Unlevered IRR on Total Spend, average, Base Case 39% Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve $163 Investment Highlights Favorable economics driven by cost savings and gains on margin and volume Reduces cost of hydrogen by using cheaper natural gas instead of more expensive crude oil Natural gas price per mmBtu (energy unit) is approximately 1/3 the price per mmBtu as WTI crude oil Projects will be at the McKee and Memphis refineries Memphis project also includes conversion of a distillate hydrotreater to a mild hydrocracker 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense |
| Port Arthur Hydrocracker Project Investment Highlights Favorable economics driven by margin and volume gains Main unit is 50,000 barrels/day hydrocracker plus facilities to process over 150,000 barrels/day of high-acid, heavy sour Canadian crude Creates high-value products from low- value feedstocks plus hydrogen sourced from relatively inexpensive natural gas Unit has volume expansion of 25%-30%: 1 barrel of feedstocks yields 1.25 to 1.3 barrels of products Main products are high-quality diesel and jet fuel for growing global demand for middle distillates Located at large, Gulf Coast refinery to leverage existing operations and export logistics 33 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 3Q12 3Q12 Estimated total investment (mil.) $1,525 $1,525 Cumulative spend thru 4Q10 (mil.) $600 $600 Estimated Incremental Operating Income before D&A2 (mil.), Base Case Estimated Incremental Operating Income before D&A2 (mil.), Base Case $485 Estimated Unlevered IRR on Total Spend, Base Case Estimated Unlevered IRR on Total Spend, Base Case 21% Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve $755 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense |
| Montreal Pipeline Project Investment Highlights Favorable economics driven by reducing transportation costs and growing volumes New pipeline with 100,000 barrels/day of throughput capacity Planned closure of Shell Montreal refinery allows Valero to place additional products into Montreal and Ontario markets Quebec refinery is largest refinery in the region with 1st-quartile performance and has a cost advantage 34 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 4Q12 4Q12 Estimated total investment (mil.) $370 $370 Cumulative spend thru 4Q10 (mil.) $42 $42 Estimated Incremental Operating Income before D&A2 (mil.) Estimated Incremental Operating Income before D&A2 (mil.) $55 Estimated Unlevered IRR on Total Spend Estimated Unlevered IRR on Total Spend 12% 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense |
| St. Charles Hydrocracker Project Investment Highlights Favorable economics driven by margin and volume gains Main unit is 50,000 barrels/day hydrocracker Creates high-value products from low- value feedstocks plus hydrogen sourced from relatively inexpensive natural gas Unit has volume expansion of 25%-30%: 1 barrel of feedstocks yields 1.25 to 1.3 barrels of products Main products are high-quality diesel and jet fuel for growing global demand for middle distillates Located at large, Gulf Coast refinery to leverage existing operations 35 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 4Q12 4Q12 Estimated total investment (mil.) $1,360 $1,360 Cumulative spend thru 4Q10 (mil.) $600 $600 Estimated Incremental Operating Income before D&A2 (mil.), Base Case Estimated Incremental Operating Income before D&A2 (mil.), Base Case $325 Estimated Unlevered IRR on Total Spend, Base Case Estimated Unlevered IRR on Total Spend, Base Case 16% Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve Estimated Incremental Operating Income before D&A2 (mil.), 2011 Fwd Curve $608 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense |
| Project Price Set Assumptions 36 Commodity Base Case($/barrel) 2011 Fwd Curve as of 3/22/11 ($/barrel) WTI 85.00 101.91 WTI - USGC HS Gas Oil -3.45 -13.00 USGC Gas Crack 6.00 14.50 USGC ULSD Crack 11.00 25.18 Natural Gas, $/MMBTU (HHV) 5.00 4.35 Prices shown below are for illustrating a potential estimate for Valero's economic projects Price assumptions are based on a blend of recent market prices and Valero's price forecast |
| Project Price Sensitivities 37 Operating Income before D&A1 Sensitivities (Delta $ millions/year) Port Arthur HCU St. Charles HCU Memphis & McKee Hydrogen Plants Memphis FCC St. Charles FCC Montreal Products Pipeline WTI, + $1/BBL 3.5 3 2.5 0.4 1.2 N/A WTI - USGC HS Gas Oil, + $1/BBL 14.1 14.1 N/A N/A 0.8 N/A USGC Gas Crack, + $1/BBL 12 12 0.9 3.6 0.6 N/A USGC ULSD Crack, + $1/BBL 16.5 18 0.3 (0.7) (2.0) N/A Natural Gas, - $1/MMBTU 15.2 15.2 6.5 N/A N/A N/A Total Investment IRR to 10% cost 1.3% 1.5% 6.3% 1.9% 2.7% 0.9% 1D&A = depreciation and amortization expense Price sensitivities shown below are for illustrating a potential estimate for Valero's economic projects Price assumptions are based on a blend of recent market prices and Valero's price forecast |
| 38 Source: Valero and Consultant Estimates MMBPD (CHART) Global CDU Capacity and Additions Gross Adds 1.7 MMBPD Closures 0.7 MMBPD Gross Adds 1.8 MMBPD Closures 0.1 MMBPD Gross Adds 1.6 MMBPD Closures 0.4 MMBPD |
| (CHART) (CHART) Continued Global Demand Growth Important to Refining Margins 39 Source: Consultant and Valero estimates Source: Consultant and Valero estimates MMBPD MMBPD Forecast Forecast |
| *Partial closure of refinery captured in capacity Note: This data represents refineries currently closed, ownership may choose to restart or sell listed refinery Sources: Industry and Consultant reports and Valero estimates Global Refining Capacity Rationalization 2008 Limited refinery closures, began seeing key project delays and cancellations 2009 Did not see substantial closure announcements until second half 2010 More closures announced Large integrated companies began rationalizing capacity Continued announcements of delays and cancelations of large refinery expansions and new build projects 2011 and 2012 Additional capacity closures announced 40 Location Owner CDU CapacityClosed(MBPD) Year Closed Bakersfield, CA Big West 65 2008 Westville, NJ Sunoco 145 2009 Delaware City, DE Valero 190 2009 Bloomfield, NM Western 17 2009 Teesside, UK Petroplus 117 2009 Gonfreville, France* Total 100 2009 Dunkirk, France Total 140 2009 Mizushima/Negishi/Oita, Japan* Nippon Oil 205 2009 Toyama, Japan Nihonkai Oil 57 2009 Arpechim, Romania* Petrom 70 2009 Cartagena, Spain* Repsol 100 2009 Bilboa, Spain* Repsol 100 2009 Montreal, Canada Shell 130 2010 Yorktown, Virginia Western 65 2010 Riechstett, France Petroplus 85 2010 Wilhelmshaven, Germany ConocoPhillips 260 2010 Chiba/Yokkaichi/Sakaide, Japan* Cosmo Oil 94 2010 Nadvornaja, Ukraine Privat Group 50 2010 Cremona, Italy Tamoil 94 2011 St. Croix, U.S. Virgin Islands Hovensa 150 2011 Keihin Ohgimachi, Japan Showa Shell 120 2011 Harburg, Germany Shell 107 2012 |
| Global Refining Capacity For Sale or Under Strategic Review 41 Location Owner CDU Capacity (MBPD) Stanlow, UK Shell 267 Gothenburg, Sweden Shell 80 Kapolei, HI Chevron 54 Pembroke, UK Chevron 210 Meraux, LA Murphy 125 Superior, WI Murphy 35 Milford Haven, UK Murphy 108 Lindsey, UK Total 221 Whitegate, Ireland ConocoPhillips 70 Mazeikai, Lithuania PKN 190 Various Japanese Locations JX Energy 400 Incheon, South Korea SK Group 275 Humber, UK ConocoPhillips 220 Texas City, Texas BP 475 Carson, California BP 265 Sources: Industry and Consultant reports and Valero estimates |
| Note: Availability of world CDU capacity assumed to average ~94%; Historical CDU capacity data from the DOE; USGC 5/3/2 = 3*USGC Gasoline+2*USGC ULSD-5*WTI Estimated global spare refining capacity fell from 7 million BPD of at end of 2009 to 5.7 million BPD at end of 2010 (CHART) MMBPD Margin/bbl Golden Age Global Spare Capacity 42 |
| Made Excellent Ethanol Acquisitions Built position for average of only 35% of estimated replacement cost 2Q09: acquired 7 plants with 780 million gallons per year of world-scale capacity in advantaged locations 1Q10: Added 3 plants with 330 million gallons per year of capacity 43 Favorable margin outlook High crude oil prices support ethanol prices 2011 ethanol mandate grows 5% over 2010 Expect demand to outgrow capacity, but blend wall must be addressed To incentivize new builds, margins must be high enough to yield reasonable return on higher-cost, new-build plants Valero's low-cost acquisitions of high-quality plants imply a competitive advantage in any margin environment Provides platform for future production of advanced biofuels |
| U.S. Ethanol Demand BGal/yr We expect ethanol volumes to meet corn RFS requirements, but expect advanced (cellulosic) ethanol to develop more slowly than prescribed Current corn ethanol capacity is approximately 13.7 BGPY (13.1 BGPY operational) and the 2015 RFS for corn-based ethanol is 15 BGPY Source: Consultant and Valero estimates Ethanol Grows as Part of the Fuel Mix 44 |
| World Demand Favors Diesel World Demand Favors Diesel World Demand MMBPD Diesel demand is expected to recover past prior highs and grow rapidly Diesel demand has grown to become much larger than gasoline globally Growing global diesel demand is an export opportunity for U.S. refineries History Forecast Source: Consultant, IEA, and Valero estimates 45 |
| Gasoline Fundamentals 46 46 (CHART) USGC Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) (CHART) Source: Argus; 2011 data through March 18 Source: DOE weekly data; 2011 data through week ending March 18 Source: DOE weekly data; 2011 data through week ending March 18 Source: DOE weekly data; 2011 data through week ending March 18 U.S. Gasoline Days of Supply (CHART) U.S. Imports of Gasoline and Blendstocks (mbpd) |
| Distillate Fundamentals 47 47 (CHART) USGC On-road Diesel Crack (per bbl) U.S. Distillate Demand (mmbpd) (CHART) (CHART) Source: Argus; 2011 data through March 18 Source: DOE weekly data; 2011 data through week ending March 18 Source: DOE weekly data; 2011 data through week ending March 18 Source: DOE monthly data; 2009 data through December 2010 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd) |
| U.S. Transport Indicators: Trucking Indicators 48 |
| (CHART) U.S. Transport Indicators 49 49 Latest data 10 W 2011 |
| (CHART) (CHART) Mexico Statistics Diesel Net Imports (MBPD) Source: PEMEX, latest data Jan-11 Gasoline Net Imports (MBPD) Source: PEMEX, latest data Jan-11 (CHART) Crude Unit Throughput (MBPD) Crude Unit Utilization (CHART) 50 Source: PEMEX, latest data Jan-11 Source: PEMEX, latest data Jan-11 |
| Assumed Refinery Configuration Margins Gulf Coast Heavy-Sour Coking = 0.6*USGC 87 Gasoline + 0.4*USGC On-road Diesel - (0.5*Maya Crude Oil + 0.5* Mars Crude Oil) Mid-Con WTI Cracking = 0.6*Group 3 87 Gasoline + 0.4*Group 3 On-road Diesel - WTI Crude Oil West Coast Medium-Sour Coking = 0.6*CARBOB + 0.4*San Francisco On-Road Diesel - ANS Crude Oil Northeast Light-Sweet Cracking = 0.5*NYH RBOB + 0.5 NYH On-Road Diesel - Brent Crude Oil 51 |
| Investor Relations Contacts For more information, please contact: Ashley Smith Vice President, Investor Relations 210.345.2744 ashley.smith@valero.com Matthew Jackson Investor Analyst 210.345.2564 matthew.jackson@valero.com 52 |