Exhibit 99.01

Investor Presentation November 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 16 refineries including recently acquired Pembroke, U.K. and Meraux, Louisiana refineries 3 million barrels per day (BPD) of throughput capacity, with average capacity of 190,000 BPD Approximately 6,800 branded marketing sites Nearly 1,300 company operated One of the largest renewable fuels companies 10 efficient corn ethanol plants with total of 1.1 billion gallons/year (72,000 BPD) of nameplate production capacity All plants located in resource-advantaged U.S. corn belt Portfolio of investments in next-generation fuels, including renewable diesel from waste cooking oil and cellulosic ethanol Approximately 22,000 employees 3

Meraux Acquisition: Attractive Value for Flexible, High-Quality Assets On October 1, Valero acquired Murphy Oil Corporation's Meraux refinery in Louisiana and offsite logistics assets for $325 million 135 MBPD refinery value estimated at $270 million Off-site logistics assets value estimated at $55 million Inventories estimated at $220 million, net of estimated true-up adjustment Funded with cash on-hand Bolt-on acquisition of flexible, high-quality assets Refinery Nelson complexity of 10.2 and estimated replacement cost of $2.6 billion 4 Low-cost way to add conversion capacity, particularly for ultra-low-sulfur distillates Includes a 34 MBPD hydrocracker, 41 MBPD high-pressure hydrotreater, 12 MBPD DAO hydrotreater, 21 MBPD ROSE, and 38 MBPD FCC Refinery received significant infrastructure investments after hurricane Katrina in 2005 Nearly total replacement of electrical system, including critical motors and substations, tankage, and utilities plus other investments that enhance reliability Excellent potential for synergies with Valero's St. Charles refinery nearby

Pembroke Integration In Progress On August 1, Valero acquired Chevron's Pembroke refinery, marketing and logistics assets in the United Kingdom and Ireland for $730 million Plus working capital, inventories, and other net assets with estimated value of $900 million 270,000 barrels-per-day refinery with estimated value of $480 million One of the largest, most complex refineries in Western Europe Refinery running well at planned rates near capacity 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 Integration of refinery and logistics Progressing the integration of refinery, logistics, and trading operations into Valero's portfolio 5

Acquisitions Enhance Valero's Margin Optimization Strategy in the Atlantic Basin 6

Valero's 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 Meraux 135 135 10.2 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. 3,045 2,579 12.0

(CHART) Continued Global Demand Growth Important to Refining Margins Refining is a global business - global demand growth impacts refiners in every market Growth in emerging markets is taking the lead in global petroleum demand OECD demand growth is expected to remain weak in 2011 and 2012 2011 demand has weakened in 2H11. Expect better growth in 2012 as Western Europe stabilize and global growth recover 8 Source: Consultant and Valero estimates

(CHART) Discounted WTI Is Another Discounted Crude Oil for Valero to Process 9 $/barrel Source: Argus; 2011 year-to-date through November 11; LLS prices are roll adjusted Heavy sour and WTI discounts have been strong 70% of Valero's capacity can process feedstocks that are discounted versus waterborne light-sweet crudes (LLS, Brent) Valero can process approximately 320,000 BPD (or 12% of crude capacity) of light-sweet crudes pricing at a discount to waterborne light-sweet crudes (LLS, Brent)

Strong Rebound in Refinery Margins in Most Regions 10 Source: Argus; 2011 year-to-date through November 11; see Appendix for details on refinery configuration assumptions

Fundamentals Supportive of Margin Outlook Tighter fundamentals for our products are supportive of margins Days of supply for diesel are much lower than last year Exports continue to remain strong and an important part of the demand story Feedstock discounts remain attractive Gasoline fundamentals are weak Good diesel demand combined with strong export levels should support diesel margins Support from low stocks in Europe and continued Latin American refinery issues 11 (CHART) Source: DOE weekly data; 2011 data through week ending November 4 (CHART) Source: DOE weekly data; 2011 data through week ending November 4 U.S. Distillate Days of Supply U.S. Gasoline Days of Supply

Valero's Strategic Priorities 12 Constant focus on safety, environmental, and regulatory compliance Manage overhead and maintain investment grade credit rating Improve margin capture, operating costs, and reliability Complete major, value-added capital projects at key refineries Optimize portfolio - continue "high-grading" strategy of the last several years Successfully integrate new acquisitions into portfolio and capture synergies Evaluate dispositions of poor performing assets Evaluate attractively priced acquisitions that improve competitiveness Add selective investments in retail and alternative fuels Goal: Increase returns to grow long-term shareholder value

Better Better Refining industry benchmark studies show our portfolio continues to improve Our goal is to be a 1st-quartile refiner Out of 80 refineries in U.S. and 12 refineries in Canada that participate in Solomon... Corpus Christi refinery ranked #1 in the U.S. group in Maintenance Cost, #2 in Cash Operating Expense Houston refinery ranked #1 in the U.S. group in Personnel Efficiency, #4 in Maintenance Cost Port Arthur refinery ranked #5 in the U.S. group in Personnel Efficiency, and #6 in Cash Operating Expense Quebec refinery ranked #1 in the Canadian group in both Cash Operating Expense and Maintenance Cost, and #2 in Personnel Efficiency Working diligently on weaker performers to raise entire portfolio Improving Refinery Operations 13 1st Quartile Rank 2nd Quartile 1st Quartile 2nd Quartile 3rd Quartile 3rd Quartile Rank Source: Solomon Associates and Valero Energy; 2011 YTD through September; excludes Aruba, Pembroke , and Meraux

Successful Cost Savings Programs Successful Cost Savings Programs 14 Ongoing cost savings programs have contributed to Valero's competitiveness and improved financial performance 2011 goal is $100 million, but expect to reach $200 million for year millions (CHART)

Refinery Yield Improvements Contribute to Higher Margin Capture 15 Note: Does not include Aruba, Pembroke, Meraux, Paulsboro or Delaware City refineries Higher-value products and liquid volume yield are important with high crude prices Liquid products 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 2011 YTD estimated improvement is $48 million In current price environment, each 0.1% improvement generates about $60 million in additional EBIT each year Expect another 1.4% improvement in 2013 for entire system after hydrocracker projects are operating

Valero Increasing Use of Lower-Cost Crude Oils Constantly evaluating opportunities to process lower-cost, higher-yield crude oils In 2010, we ran 86 different crude oils McKee and Ardmore process WTI or other crudes that price at or below WTI Rapid growth in Eagle Ford shale crude oil production lowered crude costs versus comparable imports Discounts are narrowing as pipeline take away capacity increases Valero's Three Rivers and Corpus Christi refineries are positioned to process Eagle Ford oil Grew processing from 0 to 25 MBPD in 1Q11 2Q11: processed 37 MBPD 3Q11: processed 44 MBPD Expect to process 65 MBPD by the end of 2011 and more than 75 MBPD in 1Q12 Evaluating options for Valero's Houston refinery 16 (CHART) Eagle Ford MBPD Three Rivers Increasing Eagle Ford and Reducing Expensive Crude Imports

Strong Contribution from Ethanol 17 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 just 2 1/2 years, cumulative EBITDA was $671 million, or 89% of ethanol plants purchase prices (CHART) Ethanol Operating Income before Depr. & Amort. Expense (EBITDA, millions)

Retail Business Continues to Perform Well 18 Retail achieved excellent results Improvement in retail earnings with smaller asset base = better returns (CHART) Valero Retail Operating Income (U.S. and Canada)

(CHART) (CHART) Financial Strength Provides Opportunity for Growth Returning cash to shareholders Bought 13.5 million shares for $268 million, or 2% of outstanding shares in 3Q11 Board approved tripling of dividend to $0.15/sh quarterly rate at October meeting Continuing to purchase shares in 4Q11 Investment grade credit rating Paid off $718 million of debt in 1H11 Ended 3Q11 with $2.8 billion of cash and $4.1 billion of additional liquidity Used $586 million of cash for October 1 closing of Meraux acquisition Net debt-to-cap ratio at 9/30/11 was 22% 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 opportunities Net Debt-to-Capitalization Ratio (period-end) Total Liquidity (Credit Facility, Letters of Credit, etc.) 19 $4.97/sh in cash millions

Capital Program Focused on Completion of Large Economic Growth Projects 20 "Stay- in- business" spending 2012 capital spending is expected to be similar to 2011 as we complete our large economic growth projects Expect a significant decline in capital spending after 2012 $1,650 $1,735 $1,770 $1,455 Under Review

Refinery Project Estimated Completion Date Estimated Annual EBITDA Base Case1 (millions) Estimated IRR2 using Base Case Estimated Annual EBITDA1 using 2011 Fwd Curve Prices3 (millions) WTI-based LLS-based Estimated Annual EBITDA1 using 2011 Fwd Curve Prices3 (millions) WTI-based LLS-based Memphis FCC Revamp Complete $75 20% $124 $81 St. Charles FCC Revamp Complete $140 28% $158 $174 McKee & Memphis New Hydrogen Plants 4Q11 $105 39% $157 $179 Port Arthur New Hydrocracker 3Q12 $520 23% $812 $630 St. Charles New Hydrocracker 4Q12 $380 19% $701 $483 Montreal New Products Pipeline 4Q12 $55 12% $55 $55 St. Charles Diamond Green Diesel JV 4Q12 $55 21% $55 $55 Total $1,330 20% $2,063 $1,657 Economic Projects Offer Significant Earnings Growth Potential Projects mainly based on high crude, low natural gas prices outlook 21 1EBITDA = Pretax operating income + depreciation and amortization, excludes interest expense; 2estimated IRR is unlevered; 3Consists of actual through October and forward curve as of 11/10/11 for remainder of 2011; See appendix for prices

Successfully Completed Large FCC Revamps St. Charles Recent test run verified that the revamp design basis is being achieved by the unit Estimated annualized EBITDA benefit of $150 million using 3Q11 prices Improved liquid volume yield Lower energy costs Lower catalyst costs Reliability benefits 22 Before After Memphis FCC unit revamp was mechanically complete in 2Q10 and project completed in August 2011 when full third-party oxygen supply became available Started realizing reliability benefits in 2Q10, reliability represents 15% of project economics Expect full project benefits to be realized in 4Q11 St. Charles FCC

Two Hydrocracker Projects Are Progressing on Schedule and on Budget 23 Recently increased planned operating rates from 50,000 BPD to 60,000 BPD for St. Charles and 57,000 BPD (rolling 12-month average per permit) for Port Arthur No additional capital costs Increased capacity improves economics Expect EBITDA to improve by a combined $93 million annually Project internal rate of return expected to improve by 1.6% at Port Arthur and 2.7% at St. Charles Projects remain on schedule and on budget with full impact expected in 2013 Estimate Port Arthur complete 3Q12 and St. Charles complete 4Q12 St. Charles Site Fractionation Column Port Arthur Site

Why Valero Is an Excellent Buy Today Good fundamentals, particularly for diesel, with potential upside from economic recovery Improved refinery performance as shown in industry surveys Achieved significant overhead cost savings Increased margin capture via liquid volume yields and lower-cost feedstocks Improving competitiveness of refining portfolio Added quality assets at attractive prices while diversifying business mix and geography: Ethanol, Pembroke, Meraux Returning cash to shareholders via buybacks and dividends Goal to pay one of the highest dividend yields in our peer group Progressing on key growth projects that should add significant earnings and cash flow in late 2012 and 2013 Stock price too low on nearly every valuation metric and doesn't reflect improvements to earnings power 24

Appendix 25

Meraux Refinery Utilizes Flexible Feedstock and Product Slate Significant feedstock flexibility Currently processes between 50% and 80% medium sour depending on crude oil economics Remainder typically light sweet grades Pipeline connectivity to LOOP opens ability to process dozens of foreign crude grades in addition to Mars and other U.S. Gulf Coast crudes Can shift product yields between 60/40 and 50/50 mix of gasoline/distillate 40%+ distillate yield is high for typical U.S. refinery Products placed through three main methods: Colonial and Plantation pipelines via equity interest in Collins Pipeline, adjacent product terminal, and refinery dock Refinery produces export-quality diesel that can be loaded via refinery-owned dock Crude oil pipeline expansion in early 2012 Will enable 100% of crude slate to be delivered by pipeline, which frees up capacity at dock facilities to export products 26 (CHART) (CHART)

Meraux One of Highest Conversion Capacity in U.S. Gulf Coast 27 Source: O&G Journal, Conversion capacity consists of FCC, HCU, Coking and ROSE unit capacity; refineries with 50,000 bpd crude throughput minimum

Attractive Acquisition Price for Meraux and Pembroke 28 (CHART) @ $25 per share

Pembroke One of Largest, Most Complex Refineries in Western Europe Source: PIRA, All data based on firm capacities based on period ending 2Q 2011 29

Valero Has High Conversion Refining System Valero Has High Conversion Refining System 30 Note: CDU = crude distillation unit; conversion capacity is the sum of each company's FCC, hydrocracking, and coking capacity Source: PIRA Energy Group 08/05/11 (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

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 31 Favorable margin outlook High crude oil prices support ethanol prices International demand supporting margins 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

Valero's Gulf Coast System Well-Positioned for Global Export Opportunities 32 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 950 MBPD of average total U.S. gasoline and diesel exports from 1Q09 -August 11

(CHART) Valero Has Competitive, Low-Cost Refining Operations 33 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 34 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Timing of full benefit 4Q113 4Q113 Total investment (mil.) $255 $255 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Incremental EBITDA (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 EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI $124 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS $81 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 Estimated annualized EBITDA benefit of $150 million using 3Q11 prices 35 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Completion date 2Q11 2Q11 Total investment (mil.) $330 $330 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Incremental EBITDA (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 28% Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI $158 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS $174 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense

Hydrogen Plant Projects 36 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.) $180 $180 Cumulative spend thru 3Q11 (mil.) $112 $112 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Incremental EBITDA (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 EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI $157 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS $179 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 57,000 barrels/day (rolling 12- month average per permit) hydrocracker plus facilities to process over 150,000 barrels/day of high-acid, heavy sour crudes (e.g. Canadian and Latin American) Creates high-value products from low-value feedstocks plus hydrogen sourced from relatively inexpensive natural gas Unit has volume expansion up to 30%: 1 barrel of feedstocks yields up 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 37 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.) $1,604 $1,604 Cumulative spend thru 3Q11 (mil.) $876 $876 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case $520 Estimated Unlevered IRR on Total Spend, Base Case Estimated Unlevered IRR on Total Spend, Base Case 23% Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI $812 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS $630 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 60,000 barrels/day hydrocracker Creates high-value products from low- value feedstocks plus hydrogen sourced from relatively inexpensive natural gas Unit has volume expansion up to 30%: 1 barrel of feedstocks yields up 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 38 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 3Q11 (mil.) $707 $707 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case $380 Estimated Unlevered IRR on Total Spend, Base Case Estimated Unlevered IRR on Total Spend, Base Case 19% Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - WTI $701 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Fwd Curve - LLS $483 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 39 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 3Q11 (mil.) $141 $141 Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), Base Case $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

Diamond Green Diesel Joint Venture Investment Highlights Building a 9,300 BPD renewable diesel plant adjacent to Valero's St. Charles refinery 50/50 JV project with Darling Int'l, a leading gatherer of used cooking oils and animal fat Uses refinery technology to produce high- quality diesel from low-quality, low-cost cooking oils and fats Diesel production qualifies as biomass- based diesel, a difficult specification under the Renewable Fuels Standard Total project cost of $368 million Valero to provide 14-year term loan for up to $221 million to JV at attractive rates Favorable economics assume conservative $1.25/gal RIN value, when current market is $1.60/gal to $1.70/gal 40 Summary of JV Status and Economics1 Summary of JV Status and Economics1 Summary of JV Status and Economics1 Estimated completion date 4Q12 4Q12 Estimated Partner Equity (mil.) $74 $74 Cumulative Valero project spend thru 3Q11 (mil.) $57 $57 Estimated Valero EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Valero EBITDA (Operating Income before D&A2) (mil.), Base Case $55 Estimated Unlevered IRR on Partner Equity and Loan, Base Case Estimated Unlevered IRR on Partner Equity and Loan, Base Case 21% 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense

Project Price Set Assumptions 41 Commodity Base Case ($/barrel) 2011 Actuals and Fwd Curve as of 11/11/11 ($/barrel) WTI LLS1 2011 Actuals and Fwd Curve as of 11/11/11 ($/barrel) WTI LLS1 Crude oil 85.00 94.94 112.10 Crude oil - USGC HS Gas Oil -3.45 -23.91 -6.74 USGC Gas Crack 6.00 22.46 5.29 USGC ULSD Crack 11.00 30.82 13.65 Natural Gas, $/MMBTU (HHV) 5.00 4.07 4.07 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 1LLS prices are roll adjusted

Project Price Sensitivities 42 EBITDA1 Sensitivities (Delta $ millions/year) Port Arthur HCU St. Charles HCU Memphis & McKee Hydrogen Plants Memphis FCC St. Charles FCC Montreal Products Pipeline Crude oil, + $1/BBL 4 3.6 2.5 0.4 1.4 N/A Crude oil - USGC HS Gas Oil, + $1/BBL 16.7 17.8 N/A N/A N/A N/A USGC Gas Crack, + $1/BBL 12.9 13.3 0.9 3.6 1.7 N/A USGC ULSD Crack, + $1/BBL 18.4 20.8 0.3 (0.7) (1.2) N/A Natural Gas, - $1/MMBTU 18.3 19.7 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% 1Operating income before 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

43 Source: Valero and Consultant Estimates MMBPD (CHART) Global CDU Capacity and Additions New Adds 1.8 MMBPD Closures 0.3 MMBPD New Adds 1.3 MMBPD + Restarts 0.7 MMBPD - Closures 0.8 MMBPD

Key Drivers of Large Feedstock Discounts 44 Light-sweet waterborne crude oils are the marginal feedstock when demand is strong Examples: LLS, Brent, among others Libyan outage plus North Sea maintenance has tightened light-sweet market Lower-quality and logistically constrained crude oils seeing wide discounts Maya, M-100, other heavy-sour grades Significant production of inland crudes with insufficient logistics to major refining centers: WTI, Eagle Ford Expect key drivers of discounts to continue Logistics lagging production growth of inland crude oils 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 New crude production adding heavier supply, particularly from Columbia and Brazil Russian M-100 and other resids coming to market with Russian tax changes Longer term, expect to benefit from Canadian heavy crude oil to Gulf Coast, but timing is uncertain State Department recently delayed permit decision for Keystone XL

(CHART) (CHART) Continued Global Demand Growth Important to Refining Margins 45 Source: Consultant and Valero estimates Source: Consultant and Valero estimates MMBPD MMBPD Forecast Forecast

World Demand Favors Diesel World Demand Favors Diesel World Demand MMBPD History Forecast Source: Consultant, IEA, and Valero estimates 46 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

(CHART) (CHART) Rationalization of Industry Capacity Continues Source: Valero Energy Note: 2011 and 2012 estimates include announced future capacity closures MBPD 47 Source: Valero Energy MBPD As we said previously, refining capacity continues to shut down in the industry, particularly marginal plants with upcoming capital requirements U.S. and Canada

*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 2010-2011 More closures announced Large integrated companies began rationalizing capacity Continued announcements of delays and cancelations of large refinery expansions and new build projects 2012-2014 Future capacity closures announced by owners 48 Location Owner CDU Capacity Closed (MBPD) Year Closed Bakersfield, CA Big West 65 2008 Westville, NJ Sunoco 145 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 Trainer, PA ConocoPhillips 185 2011 Clyde, Australia Shell 75 2011 Porto Marghera, Italy ENI 70 2011 Berre, France LyondellBassel 105 2012 Harburg, Germany Shell 107 2012 Tokuyama, Japan Indemitsu 100 2014

Global Refining Capacity For Sale or Under Strategic Review 49 Location Owner CDU Capacity (MBPD) Gothenburg, Sweden Shell 80 Kapolei, HI Chevron 54 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 Texas City, Texas BP 475 Carson, California BP 265 Kapolei, HI Tesoro 94 Philadelphia Refineries, PA Sunoco 505 Aruba Valero 235 Okinawa, Japan Petrobras/Nansei Sekiyu 100 Sources: Industry and Consultant reports and Valero estimates Also, ConocoPhillips intends to divest "non-core" refineries and reduce their refining capacity by 500,000 barrels per day be the end of 2012

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 50

Gasoline Fundamentals 51 51 (CHART) USGC LLS Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) (CHART) Source: Argus; 2011 data through November 4 Source: DOE weekly data; 2011 data through week ending November 4 Source: DOE weekly data; 2011 data through week ending November 4 Source: DOE weekly data; 2011 data through week ending November 4 U.S. Gasoline Days of Supply (CHART) U.S. Imports of Gasoline and Blendstocks (mbpd)

Distillate Fundamentals 52 52 (CHART) USGC LLS On-road Diesel Crack (per bbl) U.S. Distillate Demand (mmbpd) (CHART) (CHART) Source: Argus; 2011 data through November 4 Source: DOE weekly data; 2011 data through week ending November 4 Source: DOE weekly data; 2011 data through week ending November 4 Source: DOE monthly data; 2011 data through August 2011 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd)

U.S. Transport Indicators: Trucking Indicators 53

(CHART) U.S. Transport Indicators 54 54 Latest data 41 W 2011

(CHART) (CHART) Mexico Statistics Diesel Net Imports (MBPD) Source: PEMEX, latest data Sep-11 Gasoline Net Imports (MBPD) Source: PEMEX, latest data Sep-11 (CHART) Crude Unit Throughput (MBPD) Crude Unit Utilization (CHART) 55 Source: Mexico Secretary of Energy, latest data Aug-11 Source: Mexico Secretary of Energy, latest data Aug-11

Venezuelan Exports to the U.S. 56 (CHART) Source: EIA, August 2011

Assumed Regional Indicator Margins Gulf Coast Indicator: (GC Conv 87 Gasoline Prompt - LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline - LLS) x 40% + (LLS - Maya Formula Pricing) x 40% + (LLS - Mars Month 1) x 40% Mid-con Indicator: [(Group 3 Conv 87 Gasoline prompt - WTI Month 1) x 60% + (Group 3 ULSD 10ppm prompt - WTI Month 1) x 40%] x 60% + [(GC Conv 87 Gasoline Prompt - LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline - LLS) x 40%] x 40% West Coast Indicator: (San Fran CARBOB Gasoline Month 1 - ANS USWC Month 1) x 60% + (San Fran EPA 10 ppm Diesel pipeline - ANS USWC Month 1) x 40% North Atlantic Indicator: (NYH Conv 87 Gasoline Prompt - Dated Brent) x 50% + (NYH ULSD 15 ppm cargo prompt - Dated Brent) x 50% LLS prices are Month 1, adjusted for complex roll 57

Investor Relations Contacts For more information, please contact: Ashley Smith, CFA, CPA Vice President, Investor Relations 210.345.2744 ashley.smith@valero.com Matthew Jackson Investor Relations Specialist 210.345.2564 matthew.jackson@valero.com 58