Exhibit 99.01

Bill Klesse, Chairman & CEO Barclays CEO Energy and Power Conference September 15 - 16, 2010

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 Largest independent refiner in North America 15 refineries 2.8 million barrels per day (BPD) of throughput capacity Average refinery capacity of 185,000 barrels per day One of the nation's largest fuel retailers with nearly 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 21,000 employees 3

Geographically Diverse Operations 4 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. 315 205 20.6 Houston 145 90 15.1 McKee 170 168 9.5 Memphis 195 180 7.5 Port Arthur 310 290 12.7 Paulsboro 185 166 9.4 Quebec City 235 230 7.7 St. Charles 250 190 15.2 Texas City 245 225 11.1 Three Rivers 100 95 12.4 Wilmington 135 85 15.8 Total or Avg. 2,780 2,390 11.9

High Conversion Refining System High Conversion Refining System 5 Note: CDU = crude distillation unit; conversion capacity is the sum of each company's FCC, hydrocracking, and coking capacity Source: PIRA (CHART) We believe size and conversion ratio matter to competitiveness Provides flexibility to run a wide variety of discounted feedstocks to be processed into a high proportion of high-value light products

Strong Contribution from Retail and Ethanol (CHART) U.S. Retail Performance (Trailing 4Q Avg.) 6 Acquired world-class ethanol plants at an average of 35% of replacement cost Large, efficient plants have competitive advantage on cost Valero initiatives achieving 6% higher ethanol production than prior owners In 2010, retail had best 1st and 2nd quarters in Valero history Consistent improvement in retail earnings with smaller asset base Since 2005, more than doubled total operating income on 10% fewer total sites (CHART) Ethanol Operating Income (millions)

(CHART) (CHART) Solid Financial Health Ended 2Q10 with $2 billion of cash and $4.4 billion of additional liquidity Net debt-to-cap ratio far below credit facility covenant of 60% At 6/30/10, was 28.6% No other coverage-type ratios No borrowings on bank revolver Investment grade credit rating Cash flow primarily to protect balance sheet and to advance economic capital projects Liquidity and access to capital markets enables Valero to take advantage of investment opportunities Net Debt-to-Capitalization Ratio (period-end) Total Liquidity, June 30, 2010 (millions) (Credit Facility, Letters of Credit, etc.) ($3.53/share ) 7

(CHART) (CHART) Continued Global Demand Growth Important to Refining Margins We sell fuels - over 80% of our products are gasoline and diesel fuel Our industry needs economic growth and more people back to work Refining is a global business - global demand growth matters to refiners everywhere 8 Source: Consultant and Valero estimates Source: Consultant and Valero estimates MMBPD MMBPD Forecast Forecast

Refining Industry Margins Bottomed in 2009, Improvement Started in 2010 9 Gulf Coast Gasoline and On-road Diesel Margins vs. WTI Plentiful spare capacity and product inventories squeezed margins in 2009 2010 margins improving from strong global demand and capacity rationalization Expect 2011 will continue on improvement trend per bbl Source: Argus; 2010 year-to-date through September 10 YTD YTD

Sour crude discounts recovering in 2010 due to: OPEC increasing production, some of which is lower-quality and heavier crude Light product demand outpacing heavy product demand growth Supply of low-quality crudes from Latin American has been better than expected Longer term, expect to benefit from Canadian heavy crude oil to Gulf Coast Feedstock Discounts Also Rebounded in 2010 Sour Crude Percentage Discounts below WTI Source: Argus; 2010 year-to-date through September 10 Sour Crude Discounts below WTI (per bbl) Source: Argus; 2010 year-to-date through September 10 10 YTD YTD (CHART) (CHART)

(CHART) (CHART) Rationalization of Industry Capacity Occurring Source: Valero Energy MBPD 11 Source: Valero Energy MBPD We expect additional refining capacity to shut down in the industry

Valero's Strategic Priorities 12 Continue to lower costs Maintain investment grade credit rating Optimize portfolio - continue strategy of the last several years All assets must perform and contribute Paulsboro refinery: continuing to progress on negotiations for potential sale Aruba refinery: conducting maintenance, which provides optionality to operate the refinery under favorable margin conditions Long-term, we expect this refinery will be more valuable to owner of heavy-crude oil reserves Broaden geographic reach - add assets that improve competitiveness Add selective investments in alternative fuels for U.S. market Complete major, value-added capital projects at key refineries Goal: Add long-term shareholder value

Achieving Significant Cost Reductions In 2010, on pace to cut more than $100 million in pre-tax costs in addition to last year's savings of $215 million in pre-tax costs, excluding the benefit from lower energy prices 13 (CHART) (CHART)

Continuing to Make Our Refineries More Competitive 14 1st Quartile 2nd Quartile 1st Quartile 2nd Quartile Industry benchmarking survey shows Valero is continuing to improve on its competitive, low-cost operations Corpus Christi refinery ranked as one of the best facilities on the Gulf Coast for cash costs costs costs costs costs costs costs costs costs Source: Solomon Associates and Valero Energy Source: Solomon Associates and Valero Energy

Opportunity for More Improvement 15 1st Quartile 2nd Quartile 1st Quartile 2nd Quartile We aim to be a 1st-quartile refiner in industry benchmark surveys 3rd Quartile 3rd Quartile 4th Quartile Source: Solomon Associates and Valero Energy Source: Solomon Associates and Valero Energy

Shifting Capital Spending to Economic Growth and Reliability Projects 16 "Stay-in- business" spending 2011 estimated Regulatory spending expected to decline as Benicia air scrubber and MSAT2 projects are completed by year-end 2010 Strategic/economic growth spending is generally flexible and discretionary

Economic Projects Provide Potential for Earnings Growth Large projects have long lead times and were started several years ago Projects have higher implied returns on remaining investment excluding previous spending ("sunk costs") We expect natural gas prices to stay low for years 17 1D&A = depreciation and amortization expense; See Appendix for price assumptions and project descriptions; 2estimated IRR is unlevered; 3Most of project commissioned in 2010 Refinery Project Estimated Com-pletion Date Estimated Cost(millions) Spending thru 2Q10(millions) Estimated Annual Op. Inc. before D&A1 (millions) Estimated IRR2 Memphis FCC Revamp 2Q113 $245 $240 $75 23% St. Charles FCC Revamp 2Q11 $310 $160 $140 30% McKee & Memphis New Hydrogen Plants 4Q11 $170 $1 $155 60% Port Arthur New Hydrocracker 4Q12 $1,525 $530 $485 21% Montreal New Products Pipeline 4Q12 $370 $0 $55 12% St. Charles New Hydrocracker 4Q13 $1,360 $590 $325 16% Total $3,980 $1,521 $1,235

(CHART) Economic Projects Provide Potential for Earnings Growth 18 1D&A = depreciation and amortization expense; 2See Appendix for price assumptions and project descriptions, 3Most of project commissioned in 2010 millions These projects represent over 75% of strategic capital spending in 2010 and 90% in 2011 3 Location: Project, Estimated Completion Date

Valero's Gulf Coast System Well-Positioned for Global Export Opportunities 19 Our large, complex, low-cost refineries on Gulf Coast are competitive Exports typically provide a margin benefit Structural supply-demand imbalance in Latin America provides long-term export opportunity (CHART) 1Based on 803 MBPD of average total U.S. gasoline and diesel exports from 2Q09 - 2Q10 On average, Valero's share of U.S. exports of gasoline and diesel has been 30% of the U.S. total Approximately 25% of Valero's Gulf Coast production was exported Strong export capability increases flexibility to place our products in the highest netback markets domestically or globally

Why Invest in Valero Today? 20

Appendix 21

Competitive, Low-Cost Refining Operations 22 Refining Cash Operating Expenses less Natural Gas Usage ($/bbl) Source: Macquarie Capital

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 23 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.) $245 $245 Cumulative spend thru 2Q10 (mil.) $240 $240 Estimated Incremental Operating Income before D&A2 (mil.) Estimated Incremental Operating Income before D&A2 (mil.) $75 Estimated Unlevered IRR on Total Spend Estimated Unlevered IRR on Total Spend 23% 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 24 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 2Q10 (mil.) $160 $160 Estimated Incremental Operating Income before D&A2 (mil.) Estimated Incremental Operating Income before D&A2 (mil.) $140 Estimated Unlevered IRR on Total Spend Estimated Unlevered IRR on Total Spend 30% Estimated Unlevered IRR on Remaining Spend Estimated Unlevered IRR on Remaining Spend 61% 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense

Hydrogen Plant Projects 25 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 4Q11 4Q11 Estimated total investment (mil.) $170 $170 Cumulative spend thru 2Q10 (mil.) $1 $1 Incremental Operating Income before D&A2 (mil.) Incremental Operating Income before D&A2 (mil.) $155 Unlevered IRR on Total Spend, average Unlevered IRR on Total Spend, average 60% Estimated Unlevered IRR on Remaining Spend, avg. Estimated Unlevered IRR on Remaining Spend, avg. 60% 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 26 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.) $1,525 $1,525 Cumulative spend thru 2Q10 (mil.) $530 $530 Estimated Incremental Operating Income before D&A2 (mil.) Estimated Incremental Operating Income before D&A2 (mil.) $485 Estimated Unlevered IRR on Total Spend Estimated Unlevered IRR on Total Spend 21% Estimated Unlevered IRR on Remaining Spend Estimated Unlevered IRR on Remaining Spend 33% 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 27 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 2Q10 (mil.) $0 $0 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% Estimated Unlevered IRR on Remaining Spend Estimated Unlevered IRR on Remaining 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 28 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date 4Q13 4Q13 Estimated total investment (mil.) $1,360 $1,360 Cumulative spend thru 2Q10 (mil.) $590 $590 Estimated Incremental Operating Income before D&A2 (mil.) Estimated Incremental Operating Income before D&A2 (mil.) $325 Estimated Unlevered IRR on Total Spend Estimated Unlevered IRR on Total Spend 16% Estimated Unlevered IRR on Remaining Spend Estimated Unlevered IRR on Remaining Spend 28% 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense

Project Price Set Assumptions 29 Commodity $/barrel Comments WTI 85.00 Consistent with forward curve WTI - Maya 8.50 10% discount to WTI, historically conservative WTI - USGC HS Gas Oil (3.45) Over 2008 - 2009 average, conservative basis for hydrocracker, FCC projects USGC Gas Crack 6.00 Under 2008 - 2009 average, historically conservative USGC ULSD Crack 11.00 Under 2008 - 2009 average, historically conservative Natural Gas, $/MMBTU (HHV) 5.00 Under 2008 - 2009 average 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 30 Operating Income before D&A1 Sensitivities (^ $MM/YR) 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 - Maya, - $1/BBL 73.2 16 N/A N/A N/A 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

31 Source: Valero and Consultant estimates Note: Base capacity includes capacity creep of 0.1% per year MMBPD (CHART) Global CDU Capacity and Additions

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 closure announcements Chatter coming from large integrated companies about rationalizing capacity Continued announcements of large refinery expansions and new build projects being delayed or canceled 32 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 Aruba Valero 235 2009 Toyama, Japan Nippon Oil 57 2009 Arpechim, Romania Petrom 70 2009 Montreal, Canada Shell 130 2010 *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 For Sale or Under Strategic Review 33 Location Owner CDU Capacity (MBPD) Riechstett, France Petroplus 85 Stanlow, UK Shell 267 Harburg, Germany Shell 93 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 Wilhelmshaven, Germany ConocoPhillips 260 Whitegate, Ireland ConocoPhillips 70 Paulsboro, NJ Valero 185 Mazeikai, Lithuania PKN 190 Various Japanese Locations JX Energy 400 Keihin, Japan Showa Shell 120 Sources: Industry and Consultant reports and Valero estimates

World Demand Favors Diesel World Demand Favors Diesel World Demand MMBPD Diesel demand has declined more than gasoline with the economic downturn, but is expected to recover past prior highs in 2011 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 34

2009 Volume (MBPD) Annual Estimated EPS Sensitivity for $1/barrel change 1 Gasolines and blendstocks 1,101 48% $0.46 Distillate (diesel, heating oil, jet fuel) 748 33% $0.31 Other 432 19% $0.18 Total Products 2,281 100% $0.96 Sweet 632 28% Medium Sour & Acidic 581 26% $0.24 Heavy & Resid 635 28% $0.27 Other 424 19% Total Feedstocks 2,272 100% MBPD MGPD Ethanol2 69 2,800 $0.03 Charges and Yields 1 Assumes 2009 volumes, a 35% tax rate, and 2Q10 wtd. shares outstanding of 567 million 2 Ethanol estimated using volumes of 2.8 mmgpd including the new ethanol plants 35

Investor Relations Contacts For more information, please contact: Ashley Smith Vice President of Investor Relations 210.345.2744 ashley.smith@valero.com Matthew Jackson Investor Analyst 210.345.2564 matthew.jackson@valero.com 36