Exhibit 99.01

Investor Presentation August 2012

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 Today World's largest independent refiner 16 refineries 3 million barrels per day (BPD) of throughput capacity, with average capacity of 190,000 BPD (187,000 BPD excluding Aruba) Approximately 6,800 branded marketing sites Nearly 1,300 company operated in U.S. and Canada Announced intention to separate Retail segment 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 Diamond Green Diesel JV under construction (renewable diesel from waste cooking oil and animal fat) 10,000 BPD capacity, 50% to Valero Approximately 22,000 employees 3

Valero's Geographically Diverse Operations 4 Shutdown in March 2012 235,000 bpd capacity Nelson Index of 8

Valero in the Atlantic Basin 5 5

Recently Announced Retail Separation Board of directors has authorized management to pursue a separation of our retail business Reviewing several potential separation transactions including a cash- efficient distribution to shareholders Separation will create operational flexibility and unlock value for our shareholders leaving the two separate companies better-positioned to focus on their industry-specific strategies Investors and analysts have treated Valero mainly as a refiner, ignoring higher potential value of retail segment 6 4.2x 5.2x Source: Factset as of 7/19/12, NTM = Next 12-months consensus estimate EV / NTM EBITDA differential with Valero Energy

Valero's U.S. Retail Segment Network 7 as of June 30, 2012

Valero's Retail Segment Performance 8 Retail achieved record operating income in 2011, and highest quarter on record in 2Q12 Valero Retail Segment EBITDA Number of Valero Retail Segment Sites Note: includes all Canadian motorist sites reported in Canadian results

VLO Well-Positioned to Benefit from Changing Market Trends Atlantic Basin refining closures reducing excess capacity U.S. competitively exporting into growing and undersupplied markets Expect abundant and growing U.S. shale oil and Canadian production to provide feedstock cost advantage, which increases in the future Low-cost U.S. natural gas provides competitive advantage Increasing Valero's yield of distillates, which have higher margins and growth 9

Atlantic Basin Closures Reduce Excess Capacity Capacity closures have been concentrated in the Atlantic Basin: U.S. East Coast, Caribbean, Western Europe (expect more will occur over next several years) Closures combined with poor reliability and low utilization in Latin American refineries and demand growth in Latin America, creates opportunity for competitive refineries to export quality products 10 Sources: Industry and Consultant reports and Valero estimates;

Product Margins Responding to Atlantic Basin Closures 11 With recent closures, Atlantic Basin product margins have increased from prior year levels Market focused on gasoline margin improvements, but more significant impact may be strong diesel support due to tightness in diesel balances U.S. product stocks for the four major products (gasoline, diesel, jet, and resid) are near or below 5-year lows providing margin support Source: Argus /bbl

The transition of the U.S. refining system to being a net exporter to the world market has mitigated the impact of declining domestic demand Large quantities of U.S. diesel and gasoline exports to Latin America and diesel exports to Europe Strong international demand has been "pulling" products and paying higher values than in the U.S. Valero's share of U.S. exports has averaged 20% - 25% U.S. Shifted to Net Exporter 12 U.S. Demand for Refined Products and Net Trade MMBPD U.S. Petroleum Demand Excluding Ethanol and Non- Refinery NGL's (Refined Product Demand) Net Imports Net Exports Implied Total Production of U.S. Refined Products Note: Implied production = Petroleum demand excluding ethanol and non-refinery NGLs minus product net imports Implied Production of U.S. Refined Products for Domestic Use

U.S. Refining Capacity Is Globally Competitive 13 U.S. refiners in PADDs 2, 3, and 4 have higher utilization due to structural advantages of increasing access to discounted crude feedstocks and low-cost energy via natural gas PADD 1 and Europe have lower utilization due to structural disadvantages of higher crude oil and operating costs Planned capacity expansions in PADD 3 will continue to put pressure on marginal refineries in less-competitive regions, including recent restarts of previously closed capacity Asian demand growth has been consuming Asian refining growth Source: EIA and IEA, monthly data through May 2012 Refinery Utilization by PADD, Trailing 12-months These regions have less-competitive capacity

Rapid Growth in U.S. Crude Supply 14 Shale oil production growth and Mid-Continent heavy-up projects are rapidly increasing domestic light, sweet crude supplies This has created a bottleneck of crude oil that has exceeded the capacity of inland refineries and needs to move to markets outside of the Mid- Continent NGLs and condensate supplies also increasing rapidly and must move to market Source: Valero estimates U.S. GC Light/Medium Sweet Imports First 5-months 2012 - 533 MBPD

Rapid Growth in Logistics to U.S. Gulf Coast 15 Logistics capacity to move inland crude from the Mid-Continent and Texas to the U.S. Gulf Coast is expected to expand quickly to debottleneck the inland markets Bakken logistics capacity is primarily unit-trains that can go to any site with unloading capacity Excess logistics capacity will be available, but crude oil and NGL supplies could be higher Source: Company announcements and Valero estimates U.S. GC Light/Medium Sweet Imports First 5- months 2012 - 533 MBPD U.S. GC Light Crude Supply Growth by 2016

Expect U.S. and Canadian Crude Supply to Provide Feedstock Cost Advantage 16 Light/Medium Sweet Crude Imports to U.S. Gulf Coast Movements of inland crude to the U.S. Gulf Coast have caused Gulf Coast light/medium sweet crude imports to decline by about 1 MMBPD since 2010 Expect all Gulf Coast light/medium crude imports could be pushed out of PADD III by 2013 to 2014 Expect LLS will go from structural ~$2/bbl premium to discount under Brent Expect Brent will continue to be marginal crude that sets product prices and sets higher feedstock cost for global, coastal (including U.S. East Coast) light/sweet refiners Also, expect growing volumes of Canadian heavy sours to reach U.S. Gulf Coast Note: Import volumes include light and medium crudes between 28 and 50 API with less than 0.7% sulfur U.S. GC Light/Medium Sweet Imports First 5-months 2012 - 533 MBPD

Valero's Ability to Run Discounted Light Crude Valero has increased its exposure to domestic light crude processing as additional volumes have become available Gulf Coast system including Memphis has the ability to add an additional 125 MBPD of domestic crude throughput by year-end In addition, evaluating potential projects to increase our domestic light crude capacity over 200 MBPD 17

Lower-Cost Natural Gas Provides Structural Advantage to U.S. Refiners 18 Note: Per barrel cost of 600,000 mmBtus/day of natural gas consumption at 90% utilization (2,529 MBPD) of Valero's capacity $1.3 billion higher pre-tax annual costs $2.6 billion higher pre-tax annual costs Expect U.S. natural gas prices will remain low and disconnected from global oil and LNG prices for foreseeable future VLO refinery operations consume up to 600,000 mmBtus/day of natural gas at full utilization, split roughly in half between operating expense and gross margin

Distillates Have Higher Margins and Faster Growth World Product Demand Growth Source: Consultant, IEA, and Valero estimates 19 Distillate (diesel, kero, jet fuel) margins are significantly higher than gasoline Distillate demand growth rate is much higher than gasoline Europe short diesel, but long marginal refining capacity and processing expensive crude oils and natural gas Source: Argus, 2012 YTD through August 24, 2012 /bbl /year

Valero Increasing Distillate Yields 20 Source: Company Reports and EIA, yield data is for 2010; gasoline and distillate as a percent of total production volumes; distillate includes jet fuel Valero's refining system distillate yields are expected to grow from 33% in 2010 to 39% in 2013 Primary driver for increase is the completion of hydrocracker projects in 2012 Recent acquisitions have also increased distillate yields

Refinery Project Estimated Total Investment (millions) Estimated Annual EBITDA Base Case1 (millions) Estimated IRR2 using Base Case Estimated Annual EBITDA1 using 2011 Prices (millions) LLS-based Port Arthur New Hydrocracker $1,510 $520 23% $634 St. Charles New Hydrocracker $1,525 $380 17% $487 Valero's Key Economic Projects Capture the Natural Gas to Crude Oil Spread Projects mainly based on high crude, low natural gas prices outlook Estimate Port Arthur HCU mechanical completion in 3Q12 and operating in 4Q12 Estimate St. Charles HCU mechanical completion late 4Q12/early 1Q13 and operating in 2Q13 21 1EBITDA = Pretax operating income + depreciation and amortization, excludes interest expense; 2estimated IRR is unlevered; See appendix for prices St. Charles Port Arthur

Valero's Hydrocracker Projects Show Profits Under Various Price Sets 22 Note: EBITDA = Pretax operating income + depreciation and amortization, excludes interest expense; see details in appendix million s

Valero's Contribution from Ethanol 23 Large, efficient plants in great location have competitive advantage on costs Acquired competitive, world-class ethanol plants at an average of 35% of replacement cost In 3 years, cumulative EBITDA was $882 million, versus $760 million total purchase price for plants 2012 ethanol margins challenged, industry and Valero reducing rates at marginal plants We continue to expect E10 and E85 to be part of gasoline supply Ethanol EBITDA million s

Better Better Our goal is to be a 1st-quartile refiner Refining industry benchmark studies show our portfolio continues to improve Seven refineries currently operating in 1st quartile for mechanical availability, the most important Solomon metric Saw results from improvement initiatives in 2011 and YTD 2012 First full-year with 1st quartile portfolio performance in mechanical availability Lowest-ever unplanned downtime Best-ever energy efficiency for refining portfolio Working diligently on weaker performers to improve entire portfolio Improving Refinery Operations 24 1st Quartile 2nd Quartile 1st Quartile 2nd Quartile 3rd Quartil e 3rd Quartile Source: Solomon Associates and Valero Energy; excludes Aruba, Pembroke, and Meraux; 2012 YTD through July

Expect Large Decline in Capital Spending After Completion of Key Economic Growth Projects 25 "Stay- in- business" spending 2012 capital high due to estimated completion of economic growth projects, mainly the hydrocrackers Expect a significant decline in capital spending after 2012 $1,715 $1,735 $1,645 $1,460 Total $2,000 to $2,500 Decline $540 to $1,040

Managing Financial Strength and Growing Cash Yield Expect significant contributions of free cash flow from reduced capital spending and earnings from major capital projects in 2013 Returning cash to shareholders Increased quarterly dividend in 3Q12 to $0.175 per share Bought 6.4 million shares for $147 million so far in 2012 and 16.7 million shares for $347 million in 2011 Goal is to have one of the highest cash yields among peers via dividends and buybacks $1.3 billion of cash and $4.7 billion of additional liquidity on June 30 Maintaining investment grade credit rating is a priority Paid off $778 million in 2011 Paid off $858 million of high-interest debt in 2012, but reissued $300 million of tax-exempt bonds in May Net debt-to-cap ratio at 6/30/12 was 25.7% Far below credit facility covenant of 60% No other coverage-type ratios or borrowings on bank revolver 26 Cash Returned to Shareholders Source: EPS estimates from First Call as of 8-8-12

Valero's Strategic Priorities 27 Constant focus on safety, environmental, and regulatory compliance Maintain investment grade credit rating Continue improvement in refining portfolio performance to 1st quartile levels Continue cost reduction efforts Complete major, value-added capital projects Optimize portfolio - continue "high-grading" strategy Evaluate dispositions of poor performing assets Evaluate attractively priced, strategic, and accretive acquisitions that improve competitiveness Continue to return available cash to shareholders, yielding high vs. peer group Goal: Increase long-term shareholder value

We Believe Valero Is an Excellent Buy Today Seeking shareholder value creation via retail separation Well-positioned to benefit from changing market trends Atlantic Basin capacity closures have improved refining fundamentals Benefiting from strong export market Expect abundant U.S. shale and Canadian crude oil production to provide a cost advantage to U.S. Gulf Coast refiners versus global, coastal (including U.S. East Coast) light/sweet refiners Valero's unique projects focus on taking advantage of low-cost natural gas and high distillate demand and margins Improving performance and competitiveness of refining portfolio Key growth projects and falling capital expenditures should contribute significant free cash flow in 2013 Returning more cash to shareholders Goal to have one of the highest cash yields among peers 28

Appendix 29

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 30 Expect margins to improve Recently narrow margins should rationalize less competitive capacity High crude oil prices support ethanol prices International demand supporting margins 2012 corn ethanol mandate grows 4.6% over 2011 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

Attractive Acquisition Prices for Meraux and Pembroke 31 @ $30 per share

Valero Has Competitive, Low-Cost Refining Operations 32 Refining Cash Operating Expenses less Natural Gas Usage ($/bbl) Source: Macquarie Capital

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%, but plan to optimize at 20%: 1 barrel of feedstocks yields up to 1.2 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 mechanical completion date Estimated operation date Mid 3Q12 4Q12 Mid 3Q12 4Q12 Estimated total investment (mil.) (Reduced by $94 mil. from prior estimate) $1,510 $1,510 Cumulative spend thru 1Q 2012 (mil.) $1,300 $1,300 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 Prices - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Prices - LLS $634 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%, but plan to optimize at 20%: 1 barrel of feedstocks yields up to 1.2 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 mechanical completion date Estimated operation date Late 4Q12 /Early 1Q13 2Q13 Late 4Q12 /Early 1Q13 2Q13 Estimated total investment (mil.) (Increased by $165 mil. from prior estimate) $1,525 $1,525 Cumulative spend thru 1Q 2012 (mil.) $1,065 $1,065 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 17% Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Prices - LLS Estimated Incremental EBITDA (Operating Income before D&A2) (mil.), 2011 Prices - LLS $487 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 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.) $370 $370 Cumulative spend thru 1Q 2012 (mil.) $280 $280 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 estimated 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 $1.40/gal to $1.70/gal 36 Summary of JV Status and Economics1 Summary of JV Status and Economics1 Summary of JV Status and Economics1 Estimated mechanical completion date Estimated operation date Late 4Q12 Late 1Q13 Late 4Q12 Late 1Q13 Estimated Partner Equity (mil.) $106 $106 Cumulative Valero project spend thru 1Q2012 (mil.) $120 $120 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 37 Commodity Base Case ($/barrel) 2008 ($/barrel) 2009 ($/barrel) 2010 ($/barrel) 2011 ($/barrel) LLS Crude oil1 85.00 102.07 62.75 81.64 111.09 LLS - USGC HS Gas Oil -3.45 2.03 -2.86 -2.72 -5.75 USGC Gas Crack 6.00 2.47 6.91 5.32 5.11 USGC ULSD Crack 11.00 20.5 7.26 8.94 13.24 Natural Gas, $/MMBTU (NYMEX) 5.00 8.90 4.16 4.38 4.03 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 38 EBITDA1 Sensitivities (Delta $ millions/year) Port Arthur HCU St. Charles HCU Crude oil, + $1/BBL 4 3.6 Crude oil - USGC HS Gas Oil, + $1/BBL 16.7 17.8 USGC Gas Crack, + $1/BBL 12.9 13.3 USGC ULSD Crack, + $1/BBL 18.4 20.8 Natural Gas, - $1/MMBTU 18.3 19.7 Total Investment IRR to 10% cost 1.3% 1.5% 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

12,000 BPD (20%) volume expansion Hydrocracker Unit Operating Costs Hydrocracker Unit Operating Costs Heat, power, labor, etc. $1.50 per barrel (per barrel amount based on hydrocracker unit volumes) (per barrel amount based on hydrocracker unit volumes) Synergies with Plant Synergies with Plant With existing plant ~$1 per barrel (per barrel amount based on hydrocracker unit volumes) (per barrel amount based on hydrocracker unit volumes) Key Drivers for a 60,000 BPD Hydrocracker 39 Key economic driver is the expected significant liquid-volume expansion of 20%, which primarily comes from the hydrogen saturation via the high-pressure, high-conversion design Designed to maximize distillate yields Hydrocracker Unit Products (BPD) Hydrocracker Unit Products (BPD) Distillates (diesel, jet, kero) 44,000 Gasoline and blendstocks 24,000 LPGs 3,000 Low-sulfur VGO 1,000 Total 72,000 Hydrocracker Unit Feedstocks Hydrocracker Unit Feedstocks High-sulfur VGO 60,000 BPD (Internally produced or purchased) (Internally produced or purchased) Hydrogen 124 MMSCF/day (via 40,000 mmbtu/day of natural gas) (via 40,000 mmbtu/day of natural gas)

60,000 BPD Hydrocracker Model Estimates Under Various Price Sets 40 Key Drivers and Prices 2008 Prices 2008 Prices 2009 Prices 2009 Prices 2010 Prices 2010 Prices 2011 Prices 2011 Prices 2Q12 Prices 2Q12 Prices LLS /bbl $102.07 $62.75 $81.64 $111.09 $108.64 LLS - HSVGO /bbl $2.03 -$2.86 -$2.72 -$5.75 -$10.70 GC Gasoline - LLS /bbl $2.47 $6.91 $5.32 $5.11 $8.51 GC Diesel - LLS /bbl $20.50 $7.26 $8.94 $13.24 $14.98 Natural Gas (NYMEX) /mmBtu $8.90 $4.16 $4.38 $4.03 $2.32 Natural Gas to H2 cost factor $/mmBtu 1.5x 1.5x 1.5x 1.5x 1.5 H2 Consumption SCF /bbl 2,050 2,050 2,050 2,050 2,050 GC LSVGO - HSVGO /bbl $4.28 $2.85 $3.21 $3.87 $2.45 GC LPGs - LLS /bbl -$40.02 -$20.11 -$23.97 -$38.30 -$49.64 Feedstocks (Barrels per day) Bbl/day Bbl/day Bbl/day Bbl/day Bbl/day HSVGO 60,000 60,000 60,000 60,000 60,000 Hydrogen 6,709 6,709 6,709 6,709 6,709 Product Yields Distillates (diesel, jet, kero) 61% 43,902 61% 43,902 61% 43,902 61% 43,902 61% 43,902 Gasoline and blendstocks 33% 23,940 33% 23,940 33% 23,940 33% 23,940 33% 23,940 LPGs 4% 3,042 4% 3,042 4% 3,042 4% 3,042 4% 3,042 LSVGO 2% 1,338 2% 1,338 2% 1,338 2% 1,338 2% 1,338 Total Product Yields 100% 72,222 100% 72,222 100% 72,222 100% 72,222 100% 72,222 Volume Expansion on HSVGO 20% 20% 20% 20% 20% Estimated Profit Model Per Bbl $Mil./day Per Bbl $Mil./day Per Bbl $Mil./day Per Bbl $Mil./day Per Bbl $Mil./day Revenues $136.87 $8.2 $82.71 $5.0 $105.85 $6.4 $143.72 $8.6 $142.90 $8.6 Less: Feedstock cost -$109.07 -$6.5 -$69.83 -$4.2 -$88.80 -$5.3 -$120.93 -$7.3 -$121.69 -$7.3 = Gross Margin $27.80 $1.7 $12.88 $0.8 $17.05 $1.0 $22.79 $1.4 $21.21 $1.3 Less: Cash Operating Costs -$1.50 -$0.1 -$1.50 -$0.1 -$1.50 -$0.1 -$1.50 -$0.1 -$1.50 -$0.1 Add: Synergies $1.70 $0.1 $0.55 $0.0 $0.03 $0.0 $0.95 $0.1 $0.95 $0.1 = EBITDA $28.00 $1.7 $11.93 $0.7 $15.57 $0.9 $22.24 $1.3 $20.66 $1.2 Estimated Annual EBITDA ($MM/year) $613 $261 $341 $487 $452

Keystone XL Pipeline Keystone XL Pipeline Presidential Permit Delay TransCanada 1,661 mile pipeline that will bring 700,000 bpd of Canadian oil into U.S. markets Expected to create 20,000 U.S. manufacturing and construction jobs; $5.2 billion tax revenue in Keystone corridor states over 20 years Canadian approval granted; waiting on U.S. regulatory approval Decision postponed until first quarter of 2013 for further analysis of route options (specifically, Nebraska) Cushing to Gulf Coast leg has been separated from the project, and has started construction. Expected to complete late 2013. 41 Source: TransCanada Corporation Western Gateway to Kitimat Trans Mountain to Vancouver Enbridge working to expand capacity to U.S. as well

U.S. Oil and Gas Supplies Increasing Rapidly Sources of Supply for U.S. Total Petroleum Demand Sources of Supply for U.S. Natural Gas Demand Source: EIA Source: EIA MMBPD BCFD 42

Continued Global Demand Growth Important to Refining Margins 43 Source: Consultant and Valero estimates World Petroleum Demand Growth Emerging markets are taking the lead in terms of global petroleum demand growth - but refining is a global business and world growth impacts refiners in every market MMBPD

World Demand MMBPD Global diesel demand, which is already much larger than gasoline globally, expected to grow nearly 3 times as fast as gasoline over the next decade U.S. and European demand remains weak Developing world is leading demand growth Histor y Foreca st Sources: International Energy Agency Annual Statistical Supplement - 2011 Edition, VLO Market Analysis 44 World Demand - Diesel and Gasoline U.S. Demand MMBPD Histor y Foreca st 44 Source: Consultant and Valero estimates W. Europe Demand MMBPD Histor y Foreca st

World Refinery Capacity Growth Significant new global refining additions seen in the next several years Mainly new plants in Asia and the Middle East Some investment in Latin America New capacity announcements from Brazil and Mexico will likely be much smaller and much later than originally announced. Columbia much later. Others will not happen because of costs (Ecuador, Peru, Algeria, Egypt) Net Global Refinery Additions 45 MMBPD Source: Consultant and Valero estimates Net Global Refinery Additions = New Capacity + Restarts- Closures

*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 1The Petit Couronne refinery has reduced capacity by 60 MBPD with Shell to supplying crude via a processing agreement at 100 MBPD starting in mid- June 2The Trainer refinery remains closed, but Delta Airlines has announced its intent to purchase the refinery, which would likely result in a restart of this facility 3The Ingolstadt refinery remians closed, but Gunvor has agreed to purchase the plant and has indicated that it may restart Global Refining Capacity Rationalization 46 Location Owner CDU Capacity Closed (MBPD) Year Closed Perth Amboy, NJ Chevron 80 2008 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 Japan* Nippon Oil 205 2009 Toyama, Japan Nihonkai Oil 57 2009 Arpechim, Romania * Petrom 70 2009 Cartagena* REPSOL 100 2009 Bilboa* REPSOL 100 2009 Arpechim, Romania OMV 70 2010 Japan* Cosmo 94 2010 Nadvornaja, Ukraine Privat Group 50 2010 Montreal, Canada1 Shell 130 2010 Yorktown, Virginia Western 65 2010 Reichstett, France Petroplus 85 2010 Wilhemshaven, Germany Phillips 66 260 2010 Ingolstadt, Germany Bayernoil 90 2010 Cremona, Italy Tamoil 94 2011 St. Croix, U.S.V.I,* Hovensa 150 2011 Location Owner CDU Capacity Closed (MBPD) Year Closed Funshun, China PetroChina 70 2011 Keihin Ohgimachi, Japan Showa Shell 120 2011 Clyde, Australia Shell 75 2011 Trainer, PA2 Phillips 66 185 2011 Porto Marghera, Italy ENI 70 2011 Marcus Hook, PA Sunoco 175 2011 Harburg, Germany Shell 107 2012 Berre, France LyondellBassel 105 2012 Coryton, U.K. Petroplus 220 2012 Petit Couronne, France1* Petroplus 60 2012 Ingolstadt, Germany3 Petroplus 110 2012 St. Croix, U.S.V.I Hovensa 350 2012 Aruba Valero 235 2012 Gela, Italy* ENI 50 2012 Rome, Italy TotalErg 82 2012 Fawley, U.K.* ExxonMobil 80 2012 Paramo, Czech Republic Unipetrol 20 2012 Lisichansk, Ukraine TNK-BP 175 2012 Japan Indemitsu Kosan 100 2014 Japan Nippon 200 2014 Kurnell, Australia Caltex 135 2014

Global Refining Capacity For Sale or Under Strategic Review 47 Location Owner CDU Capacity (MBPD) Gothenburg, Sweden Shell 80 Kapolei, HI Chevron 54 Milford Haven, UK Murphy 108 Whitegate, Ireland Phillips 66 70 Mazeikai, Lithuania PKN 190 Various Japanese Locations JX Energy 400 Incheon, South Korea SK Group 275 Texas City, Texas BP 475 Kapolei, HI Tesoro 94 Philadelphia, PA Sunoco 330 Okinawa, Japan Petrobras/Nansei Sekiyu 100 Brisbane, Australia (Lytton) Caltex 109 Mongstad, Norway Statoil 220 Dartmouth, Canada Imperial Oil 88 Pasadena, TX Petrobras 100 Okinawa, Japan Petrobras 100 Sources: Industry and Consultant reports and Valero estimates

LLS Discount to Brent Improves Gulf Coast Competitiveness 48 Source: Argus Brent 5-3-2 products crack, product prices set by Brent Brent is the marginal Atlantic Basin crude LLS Medium sour (e.g. Mars) Heavy sour (e.g. Maya) Medium and heavy continue to have wide cracks versus products LLS recently flipped from a historical premium to a discount to Brent, but we expect near- term volatility LLS pricing-benefit will accrue to Valero's lighter capacity on the Gulf Coast plus Memphis, which can process ~ 500,000 bpd without new investment Over time, Valero expects: The LLS discount to Brent will become a structural cost advantage, increasing margins versus other Atlantic Basin refiners that process higher priced Brent- type crude

Low-Cost U.S. Natural Gas Provides Competitive Advantage 49 U.S. natural gas trading at a significant discount to Brent crude oil price (on energy equivalent basis) Expect U.S. natural gas prices will remain low and disconnected from global oil and gas prices for foreseeable future VLO refinery operations use up to 600,000 mmBtus/day of natural gas at full utilization, split roughly in half between operating expense and gross margin Source: Argus, 2012 = YTD through July 3, 2012; natural gas price converted to barrels using factor of 6.05x Brent $112/bbl ($18.56/ mmBtu) U.S. NG $15/bbl ($2.54/ mmBtu) Asian LNG $92/bbl ($15.27/ mmBtu) Euro. NG $54/bbl ($8.88/ mmBtu) /bbl

Gasoline Fundamentals 50 USGC LLS Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) Source: Argus; 2012 data through August 24 Source: DOE weekly data; 2012 data through week ending August 17 Source: DOE weekly data; 2012 data through week ending August 17 U.S. Gasoline Days of Supply U.S. Net Imports of Gasoline and Blendstocks (mbpd) Source: DOE monthly data; 2011 data through May 2012

Distillate Fundamentals 51 USGC LLS On-road Diesel Crack (per bbl) U.S. Distillate Demand (mmbpd) Source: Argus; 2012 data through August 24 Source: DOE weekly data; 2012 data through week ending August 17 Source: DOE weekly data; 2012 data through week ending August 17 Source: DOE monthly data; 2011 data through May 2012 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd)

U.S. Transport Indicators: Trucking Indicators 52 ATA data through Apr-12, TSI data through Apr-12

U.S. Transport Indicators 53 Latest data Week 33, 2012

Mexico Statistics Diesel Gross Imports (MBPD) Source: PEMEX, latest data June-12 Gasoline Gross Imports (MBPD) Source: PEMEX, latest data June-12 Crude Unit Throughput (MBPD) Crude Unit Utilization 54 Source: Mexico Secretary of Energy, latest data June-12 Source: Mexico Secretary of Energy, latest data June-12

Venezuelan Exports to the U.S. 55 Source: EIA, May 2012

Competitively Exporting into Growing Markets Source: DOE Petroleum Supply Monthly with data as of May 2012, Latin America includes South and Central America plus Mexico U.S. has become a net exporter of refined products due to growth in developing countries, Atlantic Basin capacity closures, Western European diesel demand, and Latin American refining operating issues U.S. Gulf Coast (PADD III) is largest source of exported products Latin America continues to be the largest U.S. export market, followed by Western Europe Latin American petroleum demand has been increasing 2.5% per year over the past 5 years versus U.S. decreasing 1.8% per year U. S. Product Exports By Destination U. S. Product Exports By Source MMBPD 12 Month Moving Average 56

U.S. Shifted to Net Exporter Net Imports Net Exports Note: Gasoline includes ethanol, MTBE, and other oxygenates; Source: DOE Petroleum Supply Monthly with data as of May 2012 MBPD Diesel net exports continue to rise significantly, with U.S. refiners sending a net of 840 MBPD to other countries in 2012 Gasoline net imports have fallen from almost 1 MMBPD in 2006 to only 170 MBPD in 2012 YTD Still, gasoline and blendstocks are the only product category where the U.S. remains a net importer As a result of the continued shift towards exports, U.S. net exports of petroleum products have increased from 335 MBPD in 2010 to 1485 MBPD in 2012 YTD 57

U.S. Gasoline Exports by Destination Gasoline exports remain at strong levels due to the solid demand from Latin America, including Mexico Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly with data as of May 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report and VLO estimates MBPD 58 12 Month Moving Average

U.S. Gasoline Imports by Source Gasoline imports have declined steadily since 2007 Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly with data as of May 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report and VLO estimates Shutdown of the Atlantic Basin refineries will keep pressure on this trend in 2012 Although the shutdown of U.S. East coast refineries will require more gasoline to balance 59 MBPD 12 Month Moving Average

U.S. Diesel Exports by Destination Diesel exports to Latin America continue to exceed exports to Europe, but over two-thirds of diesel export growth in 2011 was to Europe Source: DOE Petroleum Supply Monthly with data as of May 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report Latin America needs remain high on good demand growth and continued challenges running refineries in key countries 60 MBPD 12 Month Moving Average

U.S. Diesel Imports by Source Diesel imports have fallen slightly in 2012 due to less volume from Latin America Source: DOE Petroleum Supply Monthly with data as of May 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report 61 MBPD 12 Month Moving Average

U.S. Crude and Natural Gas Production - Tight Oil Supply Growth The furthest along in development are in North Dakota (Bakken) and South Texas (Eagle Ford) Each could see 500+ MBPD of growth in the next few years and potentially more thereafter Utica (Ohio) is potentially a large play, but is not as far along in development Permian Basin - potentially huge Source: Map from CERA Shale Oil Plays in North America Expect supply growth will exceed regional demand, and excess will clear toward the Gulf Coast, pushing out imports The new U.S. shale plays are located in places that should provide additional barrels into the Rockies and Gulf Coast - pressuring crude imports and lowering natural gas prices 62

Ethanol and Retail Reconciliation of Operating Income to EBITDA Ethanol (millions) 2Q09 - 4Q09 2010 2011 1Q12 2Q12 Operating Income $165 $209 $396 $9 $5 + Depreciation and amortization expense $18 $36 $39 $10 $9 = EBITDA $183 $245 $435 $19 $14 63 Retail (millions) 2005 2006 2007 2008 2009 2010 2011 2Q12 LTM U.S. Operating Income $81 $113 $154 $260 $170 $200 $213 $252 + U.S. depreciation and amortization expense $60 $60 $59 $70 $70 $73 $77 $78 = U.S. EBITDA $141 $173 $214 $330 $240 $273 $290 $330 Canada Operating Income $73 $69 $95 $109 $123 $146 $168 $140 + Canada depreciation and amortization expense $23 $27 $31 $35 $31 $35 $38 $38 = Canada EBITDA $96 $96 $126 $144 $154 $181 $206 $178

Most Crude Oil Discounts Improving 64 $/barrel Source: Argus; 2012 year-to-date through August 24; LLS prices are roll adjusted

Regional Refinery Indicator Margins 65 Source: Argus; 2012 year-to-date through August 24; see Appendix for details on refinery configuration assumptions

Assumed Regional Indicator Margins Gulf Coast Indicator: (GC Colonial 85 CBOB A grade- LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline prompt - 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 Colonial 85 CBOB A grade 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 - ICE Brent) x 50% + (NYH ULSD 15 ppm cargo prompt - ICE Brent) x 50% LLS prices are Month 1, adjusted for complex roll Prior to 2010, GC Colonial 85 CBOB is substituted for GC 87 Conventional 66

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