Exhibit 99.01

Investor Presentation May 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 plus pending acquisition of Pembroke expected to close in 3Q11 2.6 million barrels per day (BPD) of throughput capacity, with average capacity of 185,000 BPD Including Pembroke: 2.9 million BPD and an average of 194,000 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

Geographically Diverse Operations 4 Pending 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 acquisition

(CHART) Continued Global Demand Growth Important to Refining Margins Refining is a global business - global demand growth impacts refiners in every market Strong growth in emerging markets is leading the surge in global petroleum demand 2010 - 2012 demand estimated at very high level like 2003 - 2005 5 Source: Consultant and Valero estimates

Simple Refining Margins Bottomed in 2009, Recovery Started in 2010 6 Gulf Coast LLS Margins Margins improving from strong global demand, particularly in emerging markets, and capacity rationalization per bbl Source: Argus; 2011 year-to-date through May 14; LLS prices are roll adjusted

(CHART) Discounted WTI Is Another Discounted Crude Oil for Valero to Process 7 $/barrel Source: Argus; 2011 year-to-date through May 14; LLS prices are roll adjusted Heavy sour and WTI discounts have been strong Mars discounts continue to improve as waterborne sweet crude markets have tightened Valero can process approximately 300,000 BPD of WTI-priced crudes

Key Drivers of Large Feedstock Discounts 8 Light-sweet waterborne crude oils are the marginal feedstock when demand is strong Examples: LLS, Brent, among others Libyan outage has tightened market for these crudes Lower-quality and logistically constrained crude oils seeing wide discounts Maya, WTI, Mars, ANS Significant production of inland crudes with insufficient logistics to major refining centers Expect key drivers of discounts to continue OPEC increasing production of lower-quality heavier crudes Replacements for lost light-sweet production is medium-sour 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 inland crude oils 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 9 9 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

Strong Rebound in Refinery Margins in Most Regions Most Regions Most Regions 10 Source: Argus; 2011 year-to-date through May 14; see Appendix for details on refinery configuration assumptions

Valero's Gulf Coast System Well-Positioned for Global Export Opportunities 11 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 885 MBPD of average total U.S. gasoline and diesel exports from 1Q09 - Feb. 11

(CHART) (CHART) Rationalization of Industry Capacity Continues Source: Valero Energy Note: 2011 and 2012 estimates include announced future capacity closures MBPD 12 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 13 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

Getting Results from Self-Help Initiatives Achieved significant cost savings Annual general and administrative costs have fallen about $100 million since 2006 Refinery cash operating expenses have fallen from a 2008 high of $4.41 per barrel to a recent four-quarter average of $3.69 per barrel, the lowest among our independent refining peers Achieved nearly $660 million in pre-tax cost savings, cost avoidance, and offsets to cost increases since 2007 Goal to achieve 1st quartile industry benchmark performance in refineries Achieved 1st quartile performance in cash operating expenses in 2010 Moved closer to first quartile performance in the categories of reliability, personnel, and energy efficiency 14

Refinery Yield Improvements Contribute to Higher Margin Capture 15 Note: Does not include Aruba, Paulsboro or Delaware City refineries Higher-value products and liquid volume are very important when crude oil prices are high Liquid products generally have a much higher value than solid products like coke and sulfur Valero's focus on liquid volume yield achieved an increase of 0.4% in 2010 versus 2009 Via optimization of refining units, catalysts, and feedstocks Estimated improvement was worth $242 million using 2010 prices In current price environment, each 0.1% improvement generates $60 million in additional EBITDA each year In 2011, continuing to grow liquid volume yield

Valero Increasing Use of Lower-Cost Crude Oils Constantly evaluating opportunities to process lower-cost crude oils In 2010, we ran 86 different crude oils Rapid growth in crude oil from Eagle Ford shale, prices similarly to WTI Current discount of $16 per bbl versus light-sweet alternatives Two of Valero's refineries are positioned to process Eagle Ford crude Three Rivers Refinery Grew from 0 to 25 MBPD in 1Q11 Currently processing 30 MBPD Expect 60 MBPD by the end of 2011 16 Corpus Christi Refinery Eagle Ford crude and condensate Expect to process 25 MBPD in 3Q11 McKee Refinery expansion Planning to expand capacity by 25 MBPD to process the growing amounts of price- advantaged, WTI-like crudes in the Texas Panhandle Valero Three Rivers Refinery

(CHART) (CHART) Financial Strength Provides Opportunity for Growth Investment grade credit rating Ended 1Q11 with $4.1 billion of cash and nearly $4 billion of additional liquidity Paid off $510 million of debt in 1Q11 Net debt-to-cap ratio at 3/31/11 was 19.5%, down from 25% at 12/31/10 and 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 (millions) (Credit Facility, Letters of Credit, etc.) 17 $7.21/sh in cash

Capital Program Focused on Completion of Large Economic Growth Projects 18 "Stay-in- business" spending Preliminary 2012 capital spending is expected to be similar to 2011 as we complete our large economic growth projects

Economic Projects Offer Significant Earnings Growth Potential Potential for significant earnings power and project returns Projects developed based on our "bullish crude, bearish natural gas" price outlook 19 1D&A = depreciation and amortization expense; 2estimated IRR is unlevered and could improve due to pending changes in tax laws regarding accelerated depreciation expense; 3Most of project commissioned in 2010; 4Forward curve as of 5/14/11 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&A1 using 2011 Fwd Curve Prices4 (millions) Memphis FCC Revamp 2Q113 $75 20% $118 St. Charles FCC Revamp 2Q11 $140 30% $127 McKee & Memphis New Hydrogen Plants 1Q12 $105 39% $163 Port Arthur New Hydrocracker 3Q12 $485 21% $763 Montreal New Products Pipeline 4Q12 $55 12% $55 St. Charles New Hydrocracker 4Q12 $325 16% $618 Total $1,185 20% $1,844

Pembroke Acquisition: High-Quality Assets at Attractive Price Valero agreed to acquire Chevron's Pembroke refinery, marketing and logistics assets in the United Kingdom and Ireland for $730 million 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, and close third quarter of 2011 270,000 barrels-per-day refinery with estimated value of $480 million Nelson complexity of 11.8 makes it one of the largest, most complex refineries in Western Europe Refinery value is 14% of estimated replacement cost, compared to Valero's estimated refining value at 28% of replacement cost 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 and ownership interest in 4 major product pipelines and 11 terminals Consistent with Valero's portfolio-upgrading strategy Improves quality and profitability versus our recent divestitures Estimate accretive to EPS by $0.26 per share using 2010 market prices, higher with forward curve Bolt-on acquisition fits well within existing portfolio Adds geographic diversification 20

Pembroke Enhances Valero's Margin Optimization Strategy in the Atlantic Basin 21 Quebec U.S. Gulf Coast Aruba Pembroke

Why Invest in Valero Today? 22

Appendix 23

Valero's Retail Business Continues to Perform Well (CHART) Retail Operating Income Per Store (Trailing 4Q Avg.) (U.S. and Canada) 24 Retail achieved excellent per store results Improvement in retail earnings with smaller asset base = better returns Since 2005, more nearly tripled per store operating income

Strong Contribution from Ethanol 25 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 $471 million, or 63% of ethanol plants purchase prices (CHART) Ethanol Operating Income before Depr. & Amort. Expense (EBITDA, millions)

Impact of Cost Savings Programs Impact of Cost Savings Programs 26 Ongoing cost savings programs have contributed to Valero's competitiveness and improved financial performance millions (CHART)

Valero Has Competitive, Low-Cost Refining Operations 27 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 28 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 29 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 1Q11 (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 $118 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 30 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.) $315 $315 Cumulative spend thru 1Q11 (mil.) $245 $245 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 $127 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense

Hydrogen Plant Projects 31 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 1Q11 (mil.) $40 $40 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 32 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 1Q11 (mil.) $635 $635 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 $763 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 33 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 1Q11 (mil.) $59 $59 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 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.) $1,360 $1,360 Cumulative spend thru 1Q11 (mil.) $615 $615 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 $618 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense

Project Price Set Assumptions 35 Commodity Base Case ($/barrel) 2011 Fwd Curve as of 5/14/11 ($/barrel) WTI 85.00 99.97 WTI - USGC HS Gas Oil -3.45 -16.15 USGC Gas Crack 6.00 19.12 USGC ULSD Crack 11.00 25.42 Natural Gas, $/MMBTU (HHV) 5.00 4.36 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 36 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

37 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 0.5 MMBPD

(CHART) (CHART) Continued Global Demand Growth Important to Refining Margins 38 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 39 Location Owner CDU Capacity Closed (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 Clyde, Australia Shell 75 2011 Harburg, Germany Shell 107 2012

Global Refining Capacity For Sale or Under Strategic Review 40 Location Owner CDU Capacity (MBPD) Stanlow, UK Shell 267 Gothenburg, Sweden Shell 80 Kapolei, HI Chevron 54 Meraux, LA Murphy 125 Superior, WI Murphy 35 Milford Haven, UK Murphy 108 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 41

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 42 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 43

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 44

Gasoline Fundamentals 45 45 (CHART) USGC Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) (CHART) Source: Argus; 2011 data through May 14 Source: DOE weekly data; 2011 data through week ending May 7 Source: DOE weekly data; 2011 data through week ending May 7 Source: DOE weekly data; 2011 data through week ending May 7 U.S. Gasoline Days of Supply (CHART) U.S. Imports of Gasoline and Blendstocks (mbpd)

Distillate Fundamentals 46 46 (CHART) USGC On-road Diesel Crack (per bbl) U.S. Distillate Demand (mmbpd) (CHART) (CHART) Source: Argus; 2011 data through May 14 Source: DOE weekly data; 2011 data through week ending May 7 Source: DOE weekly data; 2011 data through week ending May 7 Source: DOE monthly data; 2011 data through February 2011 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd)

U.S. Transport Indicators: Trucking Indicators 47

(CHART) U.S. Transport Indicators 48 48 Latest data 17 W 2011

(CHART) (CHART) Mexico Statistics Diesel Net Imports (MBPD) Source: PEMEX, latest data Mar-11 Gasoline Net Imports (MBPD) Source: PEMEX, latest data Mar-11 (CHART) Crude Unit Throughput (MBPD) Crude Unit Utilization (CHART) 49 Source: PEMEX, latest data Mar-11 Source: PEMEX, latest data Mar-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 50

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 51